Chesapeake Utilities (CPK) 10-Q 9 Aug 18 2018 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2018	Jul. 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	Jun. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q2
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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Operating Revenues
Regulated Energy	$ 70,504	$ 70,996	$ 179,897	$ 168,650
Unregulated Energy and other	66,160	54,088	196,123	141,594
Total Operating Revenues	136,664	125,084	376,020	310,244
Operating Expenses
Regulated Energy cost of sales	20,010	24,167	68,241	64,411
Unregulated Energy and other cost of sales	49,393	40,505	149,219	101,260
Operations	36,281	30,013	68,983	62,502
Maintenance	3,619	3,403	7,211	6,634
Gain From A Settlement	(130)	(130)	(130)	(130)
Depreciation and amortization	9,839	9,094	19,543	17,906
Other taxes	4,404	3,971	9,299	8,501
Total Operating Expenses	123,416	111,023	322,366	261,084
Operating Income	13,248	14,061	53,654	49,160
Other expense, net	(262)	(1,002)	(194)	(1,703)
Interest charges	3,881	3,073	7,545	5,811
Income Before Income Taxes	9,105	9,986	45,915	41,646
Income taxes	2,718	3,940	12,674	16,456
Net Income	$ 6,387	$ 6,046	$ 33,241	$ 25,190
Weighted Average Common Shares Outstanding:
Basic (shares)	16,369,641	16,340,665	16,360,540	16,329,009
Diluted (shares)	16,417,082	16,382,207	16,410,061	16,373,038
Earnings Per Share of Common Stock:
Basic (in dollars per share)	$ 0.39	$ 0.37	$ 2.03	$ 1.54
Diluted (in dollars per share)	0.39	0.37	2.03	1.54
Cash Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.370	$ 0.325	$ 0.695	$ 0.630

Condensed Consolidated Stateme3

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Statement of Comprehensive Income [Abstract]
Net Income	$ 6,387	$ 6,046	$ 33,241	$ 25,190
Other Comprehensive Income (Loss), net of tax:
Amortization of prior service cost, net of tax of $(5), $(8), $(11) and $(16), respectively	(14)	(12)	(28)	(23)
Net gain, net of tax of $41, $69, $80 and $145, respectively	108	101	217	194
Cash Flow Hedges, net of tax:
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $429, $(554), $(327) and $(362), respectively	1,061	(875)	(728)	(537)
Total Other Comprehensive Income (Loss), net of tax	1,155	(786)	(539)	(366)
Comprehensive Income	$ 7,542	$ 5,260	$ 32,702	$ 24,824

Condensed Consolidated Stateme4

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Statement of Comprehensive Income [Abstract]
Amortization of prior service cost, tax	$ (5)	$ (8)	$ (11)	$ (16)
Net gain, tax	41	69	80	145
Unrealized (loss)/gain on commodity contract cash flow hedges, tax	$ 429	$ (554)	$ (327)	$ (362)

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Jun. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment
Regulated Energy		$ 1,174,407	$ 1,073,736
Unregulated Energy		216,125	210,682
Other businesses and eliminations		30,170	27,699
Total property, plant and equipment		1,420,702	1,312,117
Less: Accumulated depreciation and amortization		(287,942)	(270,599)
Plus: Construction work in progress		101,904	84,509
Net property, plant and equipment		1,234,664	1,126,027
Current Assets
Cash and cash equivalents		4,512	5,614
Trade and other receivables (less allowance for uncollectible accounts of $1,076 and $936, respectively)		53,419	77,223
Accrued revenue		12,353	22,279
Propane inventory, at average cost		6,597	8,324
Other inventory, at average cost		4,791	12,022
Regulatory assets		13,330	10,930
Storage gas prepayments		4,365	5,250
Income taxes receivable		6,420	14,778
Prepaid expenses		5,162	13,621
Derivative assets, at fair value		534	1,286
Other current assets		4,560	7,260
Total current assets		116,043	178,587
Deferred Charges and Other Assets
Goodwill		19,604	19,604
Other intangible assets, net		4,277	4,686
Investments, at fair value		7,486	6,756
Regulatory assets		76,427	75,575
Other assets		4,440	3,699
Total deferred charges and other assets		112,234	110,320
Total Assets		1,462,941	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		255,356	253,470
Retained earnings		250,377	229,141
Accumulated other comprehensive loss		(5,718)	(4,272)
Deferred compensation obligation		3,782	3,395
Treasury stock		(3,782)	(3,395)
Total stockholders’ equity	[1]	507,986	486,294
Long-term debt, net of current maturities		241,596	197,395
Total capitalization		749,582	683,689
Current Liabilities
Less: current maturities		9,977	9,421
Short-term borrowing		235,288	250,969
Accounts payable		60,769	74,688
Customer deposits and refunds		32,018	34,751
Accrued interest		1,891	1,742
Dividends payable		6,060	5,312
Accrued compensation		7,953	13,112
Regulatory liabilities		22,194	6,485
Derivative liabilities, at fair value		886	6,247
Other accrued liabilities		11,495	10,273
Total current liabilities		388,531	413,000
Deferred Credits and Other Liabilities
Deferred income taxes		143,147	135,850
Regulatory liabilities		141,499	140,978
Environmental liabilities		8,090	8,263
Other pension and benefit costs		28,996	29,699
Deferred investment tax credits and other liabilities		3,096	3,455
Total deferred credits and other liabilities		324,828	318,245
Environmental and other commitments and contingencies (Note 5 and 6)
Total Capitalization and Liabilities		$ 1,462,941	$ 1,414,934
[1]	Includes 96,204 and 90,961 shares at June 30, 2018 and December 31, 2017, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.

Condensed Consolidated Balance6

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 1,076	$ 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 Stateme7

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Operating Activities
Net Income	$ 33,241	$ 25,190
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	19,543	17,906
Depreciation and accretion included in other costs	4,428	3,939
Deferred income taxes	7,668	12,034
Realized loss on commodity contracts/sale of assets/investments	3,857	2,223
Unrealized (gain) loss on investments/commodity contracts	(114)	184
Employee benefits and compensation	456	819
Share-based compensation	2,247	812
Other, net	(23)	(17)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	32,230	26,862
Propane inventory, storage gas and other inventory	9,844	(2,543)
Regulatory assets/liabilities, net	11,035	4,255
Prepaid expenses and other current assets	11,523	2,129
Accounts payable and other accrued liabilities	(26,152)	(280)
Income taxes receivable	8,358	8,500
Customer deposits and refunds	(2,733)	1,487
Accrued compensation	(5,196)	(3,876)
Other assets and liabilities, net	(1,860)	(3,254)
Net cash provided by operating activities	108,352	96,370
Investing Activities
Property, plant and equipment expenditures	(126,811)	(88,627)
Proceeds from sales of assets	323	185
Environmental expenditures	(173)	(135)
Net cash used in investing activities	(126,661)	(88,577)
Financing Activities
Common stock dividends	(10,301)	(9,636)
(Purchase) issuance of stock under the Dividend Reinvestment Plan	(328)	421
Tax Withholding payments related to net settled stock compensation	(1,210)	(692)
Change in cash overdrafts due to outstanding checks	632	(2,370)
Net repayment under line of credit agreements and short-term borrowing under the Revolver	(16,313)	(61,910)
Proceeds from issuance of long-term debt	74,916	69,800
Repayment of long-term debt, long-term borrowing under the Revolver and capital lease obligation	(30,189)	(5,165)
Net cash provided (used) in financing activities	17,207	(9,552)
Net Decrease in Cash and Cash Equivalents	(1,102)	(1,759)
Cash and Cash Equivalents—Beginning of Period	5,614	4,178
Cash and Cash Equivalents—End of Period	$ 4,512	$ 2,419

Condensed Consolidated Stateme8

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		$ 33,241				33,241
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect		(907)				907	(907)
Other comprehensive income (loss)		(539)					(539)
Dividend declared		(11,414)				(11,414)
Stock Issued During Period, Shares, Dividend Reinvestment Plan				0
Stock Issued During Period, Value, Dividend Reinvestment Plan		(2)		$ 0	(2)
Share-based compensation (shares)	[2],[3]			34,103
Share-based compensation and tax benefit	[2],[3]	1,904		$ 16	1,888
Treasury stock activities		0						387	(387)
Ending Balances (shares) at Jun. 30, 2018	[1],[4]			16,378,545
Ending Balances at Jun. 30, 2018		$ 507,986	[4]	$ 7,971	$ 255,356	250,377	$ (5,718)	$ 3,782	$ (3,782)
Preferred Stock, Shares Authorized		2,000,000
Preferred Stock, Par or Stated Value Per Share		$ 0.01
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative Effect of New Accounting Principle in Period of Adoption		$ (1,498)				$ (1,498)
[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 six months ended June 30, 2018, and for the year ended December 31, 2017, we withheld 16,918 and 10,269 shares, respectively, for taxes.
[4]	Includes 96,204 and 90,961 shares at June 30, 2018 and December 31, 2017, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.

Condensed Consolidated Stateme9

Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) (Unaudited) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]
Dividend declared (in dollars per share)	$ 0.370	$ 0.695	$ 1.2800
Deferred compensation plan held Rabbi Trust (shares)	96,204	96,204	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			$ (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	6 Months Ended
	Jun. 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 complement 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 the acquired business achieving a 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 assessment 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 have similarly revised the condensed consolidated balance sheet as of December 31, 2017 . These revisions are considered immaterial to our condensed consolidated financial statements. The contingent liability will be re-evaluated each 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 provides 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 that were included in our condensed consolidated statements of income for the three and six months ended June 30, 2018, were not material. The amounts recorded in conjunction with our acquisitions 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. We expect the impact of the adoption of the new revenue standard to be immaterial to our net income on an ongoing basis. 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 six months ended June 30, 2018 and condensed consolidated balance sheet as of June 30, 2018: Three months ended June 30, 2018 Six months ended June 30, 2018 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 $ 70,504 $ 70,728 $ (224 ) $ 179,897 $ 180,780 $ (883 ) Regulated Energy cost of sales 20,010 20,139 (129 ) 68,241 68,942 (701 ) Depreciation and amortization 9,839 9,832 7 19,543 19,521 22 Income before income taxes 9,105 9,207 (102 ) 45,915 46,119 (204 ) Income taxes 2,718 2,746 (28 ) 12,674 12,733 (59 ) Net income 6,387 6,461 (74 ) 33,241 33,386 (145 ) As of June 30, 2018 Balance sheet As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower) (in thousands) Assets Accrued revenues $ 12,353 $ 13,659 $ (1,306 ) Other assets $ 4,440 $ 4,777 $ (337 ) Capitalization Retained earnings $ 250,377 $ 248,734 $ 1,643 The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $204,000 in revenue in the first six months of 2018 to future years and a cumulative adjustment that decreased retained earnings and other assets by $1.6 million at June 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 outside a subtotal of income from operations. 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) changes 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. Recent Accounting Standards Yet to be Adopted Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which provides updated guidance regarding accounting for leases. This update requires a lessee to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. The FASB allows companies to elect several practical expedients, in order to simplify the transition to the new standard. The following three expedients must all be elected together: • An entity need not reassess whether any expired or existing contracts are or contain leases. • An entity need not reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840 will continue to be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will continue to be classified as capital leases). • An entity need not reassess initial direct costs for any existing leases. Other practical expedients that can be elected individually are: • An entity may elect to use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets. • An entity may elect to apply the provisions of the new lease guidance at the effective date, without adjusting the comparative periods presented. We expect to use the practical expedients to assist in implementation of this standard. We have assessed all of our leases and have concluded that we may have some operating leases that qualify for the short-term lease exception. Upon adoption, we will record the right-of-use assets and the lease liabilities related to our operating leases with a lease term in excess of one year. We do not believe that this will have a material impact on our financial position, results of operations or cash flows. In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842 , which provides a practical expedient under Topic 842 to not evaluate existing or expired land easements that were not previously accounted for as leases. We plan to utilize the provided practical expedient for existing and expired land easements and will assess all new or modified land easements and right-of-way agreements, under the guidance of ASU 2016-02, following its adoption. 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. 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. Among other changes to hedge designation, 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 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. For disclosures, ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges, and it 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 intend to adopt the updated hedge accounting standard in 2018, which we expect will reduce the MTM volatility in PESCO’s results due to better alignment of risk management activities and financial reporting, risk component hedging and certain other simplifications of hedge accounting guidance. 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.

Calculation of Earnings Per Sha

Calculation of Earnings Per Share	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Calculation of Earnings Per Share	Calculation of Earnings Per Share Three Months Ended Six Months Ended June 30, June 30, 2018 2017 2018 2017 (in thousands, except shares and per share data) Calculation of Basic Earnings Per Share: Net Income $ 6,387 $ 6,046 $ 33,241 $ 25,190 Weighted average shares outstanding 16,369,641 16,340,665 16,360,540 16,329,009 Basic Earnings Per Share $ 0.39 $ 0.37 $ 2.03 $ 1.54 Calculation of Diluted Earnings Per Share: Reconciliation of Numerator: Net Income $ 6,387 $ 6,046 $ 33,241 $ 25,190 Reconciliation of Denominator: Weighted shares outstanding—Basic 16,369,641 16,340,665 16,360,540 16,329,009 Effect of dilutive securities—Share-based compensation 47,441 41,542 49,521 44,029 Adjusted denominator—Diluted 16,417,082 16,382,207 16,410,061 16,373,038 Diluted Earnings Per Share $ 0.39 $ 0.37 $ 2.03 $ 1.54

Revenue Recognition (Notes)

Revenue Recognition (Notes)	6 Months Ended
	Jun. 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 June 30, 2018 : Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Florida natural gas division $ 6,317 $ — $ — $ 6,317 Delaware natural gas division 11,882 — — 11,882 FPU electric distribution 18,362 — — 18,362 FPU natural gas distribution 18,281 — — 18,281 Maryland natural gas division 4,001 — — 4,001 Sandpiper 4,367 — — 4,367 Total energy distribution 63,210 — — 63,210 Energy transmission Aspire Energy — 5,854 — 5,854 Eastern Shore 14,502 — — 14,502 Peninsula Pipeline 2,968 — — 2,968 Total energy transmission 17,470 5,854 — 23,324 Energy generation Eight Flags — 4,230 — 4,230 Propane delivery Delmarva Peninsula propane delivery — 15,264 — 15,264 Florida propane delivery — 4,942 — 4,942 Total propane delivery — 20,206 — 20,206 Energy services PESCO — 48,798 — 48,798 Other and eliminations Eliminations (10,176 ) (3,248 ) (10,379 ) (23,803 ) Other — 505 194 699 Total other and eliminations (10,176 ) (2,743 ) (10,185 ) (23,104 ) Total operating revenues (1) $ 70,504 $ 76,345 $ (10,185 ) $ 136,664 (1) Includes other revenue (revenues from sources other than contracts with customers) of $(356,000) and $82,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to weather 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 six months ended June 30, 2018 : Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Florida natural gas division $ 12,180 $ — $ — $ 12,180 Delaware natural gas division 43,954 — — 43,954 FPU electric distribution 37,103 — — 37,103 FPU natural gas distribution 41,494 — — 41,494 Maryland natural gas division 14,673 — — 14,673 Sandpiper 13,331 — — 13,331 Total energy distribution 162,735 — — 162,735 Energy transmission Aspire Energy — 17,931 — 17,931 Eastern Shore 30,100 — — 30,100 Peninsula Pipeline 5,065 — — 5,065 Total energy transmission 35,165 17,931 — 53,096 Energy generation Eight Flags — 8,608 — 8,608 Propane delivery Delmarva Peninsula propane delivery — 60,735 — 60,735 Florida propane delivery — 11,576 — 11,576 Total propane delivery — 72,311 — 72,311 Energy services PESCO — 130,357 — 130,357 Other and eliminations Eliminations (18,003 ) (8,494 ) (25,976 ) (52,473 ) Other — 999 387 1,386 Total other and eliminations (18,003 ) (7,495 ) (25,589 ) (51,087 ) Total operating revenues (1) $ 179,897 $ 221,712 $ (25,589 ) $ 376,020 (1) Includes other revenue (revenues from sources other than contracts with customers) of $(945,000) and $155,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to weather 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 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 meter readings at the end of the month, which are 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. Since we bill customers at the end of each month, we do not have any unbilled revenue. 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 opening and closing balances of our trade receivables, contract assets, and contract liabilities are 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 6/30/2018 51,511 1,967 175 Increase (decrease) $ (23,451 ) $ 697 $ (232 ) 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 June 30, 2018 and December 31, 2017, we had a contract liability, which was included in other accrued liabilities in the condensed consolidated balance sheet, of $175,000 and $ 407,000 , respectively, 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 six months ended June 30, 2018, we recognized revenue of $ 84,000 and $336,000 , 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	6 Months Ended
	Jun. 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 rate payers: As a result of the enactment of the TCJA, 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 jurisdictional revenue requirement impacts of changes in the federal corporate income tax laws. In compliance with this 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 ultimate impact of the TCJA on rates charged by our Delaware Division will not have a material effect on our financial position or results of operations. Underserved Area Rates: In December 2017, we filed an application for approval of natural gas expansion service offerings. We requested 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 settlement agreement was presented before the Delaware PSC at its public meeting on July 10, 2018, where it was unanimously passed. CGS: In June 2018, we filed with the Delaware PSC an application requesting approval of the acquisition and subsequent conversion of propane CGS to natural gas 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 rate payers: The Maryland PSC issued an order requiring all Maryland public utilities whose rates are 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. In addition, our Maryland Division and Sandpiper made compliance filings that included preliminary estimates of the annual impact of the change in the statutory federal income tax rate from 35 percent to 21 percent . 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 June. We must also submit an informational filing to the Maryland PSC within 60 days of the refund payment date. Additionally, pursuant to the Maryland PSC’s order, 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 ultimate impact of the TCJA on rates charged by our Maryland Division and Sandpiper will not have a material effect on our financial position or results of operations. Florida Florida Electric Reliability/Modernization Pilot Program: In July 2017, FPU’s electric division 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 FPU’s electrical grid. An interconnection project with FPL, which enables FPU to mitigate fuel costs for its 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, FPU’s electric division 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 FPU’s storm reserve to its pre-storm level of $1.5 million . As a result of these hurricanes and tropical storms, FPU’s storm reserve was depleted and is currently at a deficit of $779,000 . FPU is requesting approval of a surcharge of $1.82 per kilowatt per hour for two years to recover and replenish storm-related costs. At this time, no date for approval of this petition has been scheduled by the Florida PSC. Effect of the TCJA on ratepayers: 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 FPU's electric division, which prescribes the applicability, timing and treatment of the implications of the TCJA, as discussed above. In June, each of our Florida natural gas operations filed a petition and testimony in support of the disposition of the impacts created by the TCJA. We believe that the ultimate impact of the TCJA on rates charged by FPU's electric division and our Florida natural gas operations will not have a material effect on our financial position or results of operations. 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 remainder 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 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 until the rate case settlement is approved by the FERC and customers receive refunds according to the terms of the settlement agreement. Eastern Shore filed an uncontested settlement agreement and a motion to place interim settlement rates into effect beginning on January 1, 2018. 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 ratepayers: 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 , 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 Notice of Proposed Rulemaking that proposed a process to determine which jurisdictional 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 Notice of Proposed Rulemaking 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 Notice of Proposed Rulemaking 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. We plan to file such a request. We believe that the ultimate resolution of this matter will not have a material effect on Eastern Shore’s financial position or results of operations.

Environmental Commitments and C

Environmental Commitments and Contingencies	6 Months Ended
	Jun. 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 have also been in discussions with the MDE regarding another former MGP site located in Cambridge, Maryland. As of June 30, 2018 , we had approximately $9.5 million in environmental liabilities related to FPU’s MGP sites in Key West, Pensacola, Sanford and West Palm Beach, Florida. 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. Approximately $11.3 million has been recovered as of June 30, 2018 , leaving approximately $2.7 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	6 Months Ended
	Jun. 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 2.2 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 2.2 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 fuel 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 fuel 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 June 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 its retail 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 June 30, 2018 was approximately $72.5 million , with the guarantees expiring on various dates through June 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 June 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 June 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	6 Months Ended
	Jun. 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 Six Months Ended June 30, June 30, 2018 2017 2018 2017 (in thousands) Operating Revenues, Unaffiliated Customers Regulated Energy segment $ 67,731 $ 68,815 $ 173,685 $ 165,261 Unregulated Energy segment and other businesses 68,933 56,269 202,335 144,983 Total operating revenues, unaffiliated customers $ 136,664 $ 125,084 $ 376,020 $ 310,244 Intersegment Revenues (1) Regulated Energy segment $ 2,773 $ 2,181 $ 6,212 $ 3,389 Unregulated Energy segment 7,412 6,780 19,377 10,791 Other businesses 194 159 387 387 Total intersegment revenues $ 10,379 $ 9,120 $ 25,976 $ 14,567 Operating Income Regulated Energy segment $ 14,304 $ 14,086 $ 41,015 $ 37,481 Unregulated Energy segment 490 2 14,174 11,577 Other businesses and eliminations (1,546 ) (27 ) (1,535 ) 102 Total operating income 13,248 14,061 53,654 49,160 Other expense, net (262 ) (1,002 ) (194 ) (1,703 ) Interest charges 3,881 3,073 7,545 5,811 Income before Income Taxes 9,105 9,986 45,915 41,646 Income taxes 2,718 3,940 12,674 16,456 Net Income $ 6,387 $ 6,046 $ 33,241 $ 25,190 (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. (in thousands) June 30, 2018 December 31, 2017 Identifiable Assets Regulated Energy segment $ 1,199,672 $ 1,121,673 Unregulated Energy segment 227,191 259,041 Other businesses and eliminations 36,078 34,220 Total identifiable assets $ 1,462,941 $ 1,414,934 Our operations are entirely domestic.

Stockholder's Equity - Accumula

Stockholder's Equity - Accumulated Other Comprehensive Income (Loss)	6 Months Ended
	Jun. 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 June 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 June 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 — (1,440 ) (1,440 ) Amounts reclassified from accumulated other comprehensive income 189 712 901 Net current-period other comprehensive income/(loss) 189 (728 ) (539 ) Stranded tax reclassification to retained earnings (1,022 ) 115 (907 ) As of June 30, 2018 $ (5,576 ) $ (142 ) $ (5,718 ) 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 ) 837 828 Amounts reclassified from accumulated other comprehensive income/(loss) 180 (1,374 ) (1,194 ) Net prior-period other comprehensive income/(loss) 171 (537 ) (366 ) As of June 30, 2017 $ (5,189 ) $ (55 ) $ (5,244 ) The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and six months ended June 30, 2018 and 2017 . Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement. Three Months Ended Six Months Ended June 30, June 30, 2018 2017 2018 2017 (in thousands) Amortization of defined benefit pension and postretirement plan items: Prior service credit (1) $ 19 $ 20 $ 39 $ 39 Net loss (1) (149 ) (170 ) (297 ) (339 ) Total before income taxes (130 ) (150 ) (258 ) (300 ) Income tax benefit 36 61 69 120 Net of tax $ (94 ) $ (89 ) $ (189 ) $ (180 ) Gains and losses on commodity contracts cash flow hedges: Propane swap agreements (2) $ (181 ) $ 77 $ (645 ) $ 465 Natural gas swaps (2) (31 ) — (481 ) — Natural gas futures (2) (161 ) 631 137 1,781 Total before income taxes (373 ) 708 (989 ) 2,246 Income tax benefit (expense) 105 (273 ) 277 (872 ) Net of tax (268 ) 435 (712 ) 1,374 Total reclassifications for the period $ (362 ) $ 346 $ (901 ) $ 1,194 (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	6 Months Ended
	Jun. 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 six months ended June 30, 2018 and 2017 are set forth in the following tables: Chesapeake FPU Chesapeake SERP Chesapeake FPU For the Three Months Ended June 30, 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Interest cost $ 98 $ 103 $ 592 $ 624 $ 21 $ 22 $ 9 $ 11 $ 13 $ 13 Expected return on plan assets (138 ) (127 ) (774 ) (700 ) — — — — — — Amortization of prior service credit — — — — — — (19 ) (20 ) — — Amortization of net loss 88 106 108 131 25 22 15 17 — — Net periodic cost (benefit) (1) 48 82 (74 ) 55 46 44 5 8 13 13 Amortization of pre-merger regulatory asset — — 191 191 — — — — 2 2 Total periodic cost $ 48 $ 82 $ 117 $ 246 $ 46 $ 44 $ 5 $ 8 $ 15 $ 15 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan For the Six Months Ended June 30, 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Interest cost $ 195 $ 206 $ 1,184 $ 1,247 $ 42 $ 44 $ 19 $ 21 $ 26 $ 26 Expected return on plan assets (276 ) (254 ) (1,549 ) (1,399 ) — — — — — — Amortization of prior service credit — — — — — — (39 ) (39 ) — — Amortization of net loss 176 213 217 262 50 44 30 32 — — Net periodic cost (benefit) (1) 95 165 (148 ) 110 92 88 10 14 26 26 Amortization of pre-merger regulatory asset — — 381 381 — — — — 4 4 Total periodic cost $ 95 $ 165 $ 233 $ 491 $ 92 $ 88 $ 10 $ 14 $ 30 $ 30 (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 $913,000 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 $942,000 and approximately $1.3 million at June 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 June 30, 2018 and 2017 : For the Three Months Ended June 30, 2018 Chesapeake FPU Chesapeake SERP Chesapeake FPU Total (in thousands) Prior service credit $ — $ — $ — $ (19 ) $ — $ (19 ) Net loss 88 108 25 15 — 236 Total recognized in net periodic benefit cost 88 108 25 (4 ) — 217 Recognized from accumulated other comprehensive loss (1) 88 21 25 (4 ) — 130 Recognized from regulatory asset — 87 — — — 87 Total $ 88 $ 108 $ 25 $ (4 ) $ — $ 217 For the Three Months Ended June 30, 2017 Chesapeake FPU Chesapeake SERP Chesapeake FPU Total (in thousands) Prior service credit $ — $ — $ — $ (20 ) $ — $ (20 ) Net loss 106 131 22 17 — 276 Total recognized in net periodic benefit cost 106 131 22 (3 ) — 256 Recognized from accumulated other comprehensive loss (1) 106 25 22 (3 ) — 150 Recognized from regulatory asset — 106 — — — 106 Total $ 106 $ 131 $ 22 $ (3 ) $ — $ 256 For the Six Months Ended June 30, 2018 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ (39 ) $ — $ (39 ) Net loss 176 217 50 30 — 473 Total recognized in net periodic benefit cost 176 217 50 (9 ) — 434 Recognized from accumulated other comprehensive loss (1) 176 41 50 (9 ) — 258 Recognized from regulatory asset — 176 — — — 176 Total $ 176 $ 217 $ 50 $ (9 ) $ — $ 434 For the Six Months Ended June 30, 2017 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ (39 ) $ — $ (39 ) Net loss 213 262 44 32 — 551 Total recognized in net periodic benefit cost 213 262 44 (7 ) — 512 Recognized from accumulated other comprehensive loss (1) 213 50 44 (7 ) — 300 Recognized from regulatory asset — 212 — — — 212 Total $ 213 $ 262 $ 44 $ (7 ) $ — $ 512 (1) See Note 8 , Stockholder's Equity . During the three and six months ended June 30, 2018 , we contributed approximately $126,000 and $198,000 , respectively, to the Chesapeake Pension Plan and approximately $539,000 and $848,000 , 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 six months ended June 30, 2018 , were approximately $38,000 and $76,000 , 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 the three and six months ended June 30, 2018 , were approximately $7,000 and $18,000 , respectively. 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 six months ended June 30, 2018 , were approximately $13,000 and $24,000 , respectively. We estimate that approximately $88,000 will be paid for such benefits under the FPU Medical Plan in 2018 .

Investments

Investments	6 Months Ended
	Jun. 30, 2018
Investments, Debt and Equity Securities [Abstract]
Investments	Investments The investment balances at June 30, 2018 and December 31, 2017 , consisted of the following: (in thousands) June 30, December 31, Rabbi trust (associated with the Deferred Compensation Plan) $ 7,465 $ 6,734 Investments in equity securities 21 22 Total $ 7,486 6,756 We classify these investments as trading securities and report them at their fair value. For the three months ended June 30, 2018 and 2017 , we recorded a net unrealized loss of approximately $ 158,000 and a net unrealized gain of approximately $181,000 , respectively, in other expense, net in the condensed consolidated statements of income related to these investments. For the six months ended June 30, 2018 and 2017 , we recorded a net unrealized loss of approximately $113,000 and a net unrealized gain of approximately $433,000 , 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	6 Months Ended
	Jun. 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 six months ended June 30, 2018 and 2017 : Three Months Ended Six Months Ended June 30, June 30, 2018 2017 2018 2017 (in thousands) Awards to non-employee directors $ 135 $ 136 $ 269 $ 271 Awards to key employees 1,190 37 2,575 541 Total compensation expense 1,325 173 2,844 812 Less: tax benefit (363 ) (70 ) (779 ) (327 ) Share-based compensation amounts included in net income $ 962 $ 103 $ 2,065 $ 485 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 six months ended June 30, 2018 : Number of Shares Weighted Average Fair Value Outstanding—December 31, 2017 — $ — Granted 7,128 $ 75.70 Vested (7,128 ) $ 75.70 Outstanding—June 30, 2018 — $ — At June 30, 2018 , there was approximately $450,000 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 six months ended June 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—June 30, 2018 131,741 $ 67.46 (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 June 30, 2018 , the aggregate intrinsic value of the SICP awards granted to key employees was approximately $10.5 million . At June 30, 2018 , there was approximately $3.2 million of unrecognized compensation cost related to these awards, which is expected to be recognized from 2018 through 2020. Stock Options We did not have any stock options outstanding at June 30, 2018 or 2017 , nor were any stock options issued during these periods.

Derivative Instruments

Derivative Instruments	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments	Derivative Instruments We use derivative and non-derivative contracts to engage in trading activities and 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 June 30, 2018 , our natural gas and electric distribution operations did not have any outstanding derivative contracts. Hedging Activities in 2018 PESCO enters into natural gas futures contracts associated with the purchase and sale of natural gas to specific customers. These contracts are effective through March 2022, and we designate and account for them as cash flow hedges. There is no ineffective portion of these hedges. At June 30, 2018 , PESCO had a total of 16.9 million Dts hedged under natural gas futures contracts, with a liability fair value of approximately $779,000 . The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss). In June 2018, Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 1.4 million gallons of propane expected to be purchased from August 2018 through June 2021. Under the futures and swap agreements, Sharp will receive the difference between the index prices (Mont Belvieu prices in August 2018 through June 2021) and the swap prices of $0.76 to $0.875 per gallon, to the extent the index price exceeds the contracted prices. If the index prices are lower than the swap prices, Sharp will pay the difference. At June 30, 2018 , the futures and swap agreements had a fair value asset of approximately $18,000 and a fair value liability of $30,000 . The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss). Hedging Activities in 2017 In 2017, Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 7.7 million gallons of propane expected to be purchased from October 2017 through March 2019, of which positions covering 1.4 million gallons of forecasted future purchases were outstanding as of June 30, 2018 . Under the futures and swap agreements, Sharp will receive the difference between the index prices (Mont Belvieu prices in October 2017 through March 2019) and the swap prices of $0.59 per gallon, to the extent the index price exceeds the contracted price. If the index prices are lower than the swap prices, Sharp will pay the difference. Sharp received approximately $645,000 , which represented the difference between the index prices and the contracted prices in 2018 related to hedging activities originated in 2017 and received $11,000 , which represented the mark-to-market activities for the three months ended June 30, 2018 . At June 30, 2018 , the futures and swap agreements had a fair value asset of approximately $306,000 . The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss). In August 2017, PESCO entered into natural gas swap agreements associated with financial contracts acquired in the ARM acquisition to mitigate the risk of fluctuations in wholesale natural gas prices associated with 844,000 Dts of natural gas PESCO expects to purchase through January 2020. We accounted for these swap agreements as cash flow hedges, which have a fair value liability of approximately $120,000 at June 30, 2018 . The change in fair value of the natural gas swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss). The impact of PESCO's financial instruments that were not designated as hedges in our consolidated financial statements as of June 30, 2018 was a fair value asset of $90,000 and fair value liability of $77,000 , respectively, which was recorded as an increase in gas costs during the six months ended June 30, 2018 associated with 1.1 million and 512,500 Dts of natural gas, respectively. 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 June 30, 2018 and December 31, 2017: At June 30, 2018 (in thousands) Gross amounts Amounts offset Net amounts Accounts receivable $ 5,723 $ 1,288 $ 4,435 Accounts payable $ 10,326 $ 1,288 $ 9,038 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 The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit risk-related contingency. The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of June 30, 2018 and December 31, 2017 , are as follows: Asset Derivatives Fair Value As Of (in thousands) Balance Sheet Location June 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 90 — Derivatives designated as cash flow hedges Natural gas futures contracts Derivative assets, at fair value 120 92 Propane swap agreements Derivative assets, at fair value 324 1,181 Total asset derivatives $ 534 $ 1,286 Liability Derivatives Fair Value As Of (in thousands) Balance Sheet Location June 30, 2018 December 31, 2017 Derivatives not designated as hedging instruments Natural gas futures contracts Derivative liabilities, at fair value $ 77 $ 5,776 Derivatives designated as cash flow hedges Natural gas futures contracts Derivative liabilities, at fair value 779 469 Natural gas swap contracts Derivative liabilities, at fair value — 2 Propane swap agreements Derivative liabilities, at fair value 30 — Total liability derivatives $ 886 $ 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 June 30, For the Six Months Ended June 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 (128 ) 497 (2,963 ) 621 Propane swap agreements Cost of sales (4 ) — (13 ) (4 ) 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 (181 ) 77 (645 ) 465 Propane swap agreements Other comprehensive loss 106 (218 ) (886 ) (775 ) Natural gas futures contracts Cost of sales (161 ) 631 137 1,781 Natural gas swap contracts Cost of sales (31 ) — (481 ) — Natural gas swap contracts Other comprehensive income 523 — 588 — Natural gas futures contracts Other comprehensive loss 861 (1,211 ) (871 ) (124 ) Total $ 985 $ (224 ) $ (5,134 ) $ 2,067 (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.

Fair Value of Financial Instrum

Fair Value of Financial Instruments	6 Months Ended
	Jun. 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 June 30, 2018 and December 31, 2017 : Fair Value Measurements Using: As of June 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 $ 21 $ 21 $ — $ — Investments—guaranteed income fund 671 — — 671 Investments—mutual funds and other 6,794 6,794 — — Total investments 7,486 6,815 — 671 Derivative assets 534 — 534 — Total assets $ 8,020 $ 6,815 $ 534 $ 671 Liabilities: Derivative liabilities $ 886 $ — $ 886 $ — 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 six months ended June 30, 2018 and 2017 : Six Months Ended 2018 2017 (in thousands) Beginning Balance $ 648 $ 561 Purchases and adjustments 54 65 Transfers (24 ) — Distribution (12 ) — Investment income 5 4 Ending Balance $ 671 $ 630 Investment income from the Level 3 investments is reflected in other expense, (net) in the accompanying condensed consolidated statements of income. At June 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 June 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 $250.3 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	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Long-Term Debt	Long-Term Debt Our outstanding long-term debt is shown below: June 30, December 31, (in thousands) 2018 2017 FPU secured first mortgage bonds (1) : 9.08% bond, due June 1, 2022 $ 7,984 $ 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 1,351 2,070 Less: debt issuance costs (488 ) (433 ) Total long-term debt 251,573 206,816 Less: current maturities (9,977 ) (9,421 ) Total long-term debt, net of current maturities $ 241,596 $ 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. As of June 30, 2018, we have issued $70.0 million of 3.25% Prudential Shelf Notes. 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 June 30, 2018, we have $230.0 million of additional potential borrowing capacity under the Prudential and MetLife Shelf Agreements. 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)	6 Months Ended
	Jun. 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 complement 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 the acquired business achieving a 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 assessment 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 have similarly revised the condensed consolidated balance sheet as of December 31, 2017 . These revisions are considered immaterial to our condensed consolidated financial statements. The contingent liability will be re-evaluated each 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 provides 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 that were included in our condensed consolidated statements of income for the three and six months ended June 30, 2018, were not material. The amounts recorded in conjunction with our acquisitions 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. We expect the impact of the adoption of the new revenue standard to be immaterial to our net income on an ongoing basis. 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 six months ended June 30, 2018 and condensed consolidated balance sheet as of June 30, 2018: Three months ended June 30, 2018 Six months ended June 30, 2018 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 $ 70,504 $ 70,728 $ (224 ) $ 179,897 $ 180,780 $ (883 ) Regulated Energy cost of sales 20,010 20,139 (129 ) 68,241 68,942 (701 ) Depreciation and amortization 9,839 9,832 7 19,543 19,521 22 Income before income taxes 9,105 9,207 (102 ) 45,915 46,119 (204 ) Income taxes 2,718 2,746 (28 ) 12,674 12,733 (59 ) Net income 6,387 6,461 (74 ) 33,241 33,386 (145 ) As of June 30, 2018 Balance sheet As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower) (in thousands) Assets Accrued revenues $ 12,353 $ 13,659 $ (1,306 ) Other assets $ 4,440 $ 4,777 $ (337 ) Capitalization Retained earnings $ 250,377 $ 248,734 $ 1,643 The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $204,000 in revenue in the first six months of 2018 to future years and a cumulative adjustment that decreased retained earnings and other assets by $1.6 million at June 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 outside a subtotal of income from operations. 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) changes 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. Recent Accounting Standards Yet to be Adopted Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which provides updated guidance regarding accounting for leases. This update requires a lessee to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. The FASB allows companies to elect several practical expedients, in order to simplify the transition to the new standard. The following three expedients must all be elected together: • An entity need not reassess whether any expired or existing contracts are or contain leases. • An entity need not reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840 will continue to be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will continue to be classified as capital leases). • An entity need not reassess initial direct costs for any existing leases. Other practical expedients that can be elected individually are: • An entity may elect to use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets. • An entity may elect to apply the provisions of the new lease guidance at the effective date, without adjusting the comparative periods presented. We expect to use the practical expedients to assist in implementation of this standard. We have assessed all of our leases and have concluded that we may have some operating leases that qualify for the short-term lease exception. Upon adoption, we will record the right-of-use assets and the lease liabilities related to our operating leases with a lease term in excess of one year. We do not believe that this will have a material impact on our financial position, results of operations or cash flows. In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842 , which provides a practical expedient under Topic 842 to not evaluate existing or expired land easements that were not previously accounted for as leases. We plan to utilize the provided practical expedient for existing and expired land easements and will assess all new or modified land easements and right-of-way agreements, under the guidance of ASU 2016-02, following its adoption. 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. 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. Among other changes to hedge designation, 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 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. For disclosures, ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges, and it 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 intend to adopt the updated hedge accounting standard in 2018, which we expect will reduce the MTM volatility in PESCO’s results due to better alignment of risk management activities and financial reporting, risk component hedging and certain other simplifications of hedge accounting guidance. 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.

Summary of Accounting Policie25

Summary of Accounting Policies Impact of Adoption of ASC 606 (Tables)	6 Months Ended
	Jun. 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 six months ended June 30, 2018 and condensed consolidated balance sheet as of June 30, 2018: Three months ended June 30, 2018 Six months ended June 30, 2018 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 $ 70,504 $ 70,728 $ (224 ) $ 179,897 $ 180,780 $ (883 ) Regulated Energy cost of sales 20,010 20,139 (129 ) 68,241 68,942 (701 ) Depreciation and amortization 9,839 9,832 7 19,543 19,521 22 Income before income taxes 9,105 9,207 (102 ) 45,915 46,119 (204 ) Income taxes 2,718 2,746 (28 ) 12,674 12,733 (59 ) Net income 6,387 6,461 (74 ) 33,241 33,386 (145 ) As of June 30, 2018 Balance sheet As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower) (in thousands) Assets Accrued revenues $ 12,353 $ 13,659 $ (1,306 ) Other assets $ 4,440 $ 4,777 $ (337 ) Capitalization Retained earnings $ 250,377 $ 248,734 $ 1,643

Calculation of Earnings Per S26

Calculation of Earnings Per Share (Tables)	6 Months Ended
	Jun. 30, 2018
Earnings Per Share [Abstract]
Calculation of Basic and Diluted Earnings Per Share	Three Months Ended Six Months Ended June 30, June 30, 2018 2017 2018 2017 (in thousands, except shares and per share data) Calculation of Basic Earnings Per Share: Net Income $ 6,387 $ 6,046 $ 33,241 $ 25,190 Weighted average shares outstanding 16,369,641 16,340,665 16,360,540 16,329,009 Basic Earnings Per Share $ 0.39 $ 0.37 $ 2.03 $ 1.54 Calculation of Diluted Earnings Per Share: Reconciliation of Numerator: Net Income $ 6,387 $ 6,046 $ 33,241 $ 25,190 Reconciliation of Denominator: Weighted shares outstanding—Basic 16,369,641 16,340,665 16,360,540 16,329,009 Effect of dilutive securities—Share-based compensation 47,441 41,542 49,521 44,029 Adjusted denominator—Diluted 16,417,082 16,382,207 16,410,061 16,373,038 Diluted Earnings Per Share $ 0.39 $ 0.37 $ 2.03 $ 1.54

Revenue Recognition (Tables)

Revenue Recognition (Tables)	6 Months Ended
	Jun. 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 June 30, 2018 : Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Florida natural gas division $ 6,317 $ — $ — $ 6,317 Delaware natural gas division 11,882 — — 11,882 FPU electric distribution 18,362 — — 18,362 FPU natural gas distribution 18,281 — — 18,281 Maryland natural gas division 4,001 — — 4,001 Sandpiper 4,367 — — 4,367 Total energy distribution 63,210 — — 63,210 Energy transmission Aspire Energy — 5,854 — 5,854 Eastern Shore 14,502 — — 14,502 Peninsula Pipeline 2,968 — — 2,968 Total energy transmission 17,470 5,854 — 23,324 Energy generation Eight Flags — 4,230 — 4,230 Propane delivery Delmarva Peninsula propane delivery — 15,264 — 15,264 Florida propane delivery — 4,942 — 4,942 Total propane delivery — 20,206 — 20,206 Energy services PESCO — 48,798 — 48,798 Other and eliminations Eliminations (10,176 ) (3,248 ) (10,379 ) (23,803 ) Other — 505 194 699 Total other and eliminations (10,176 ) (2,743 ) (10,185 ) (23,104 ) Total operating revenues (1) $ 70,504 $ 76,345 $ (10,185 ) $ 136,664 (1) Includes other revenue (revenues from sources other than contracts with customers) of $(356,000) and $82,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to weather 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 six months ended June 30, 2018 : Regulated Energy Unregulated Energy Other and Eliminations Total Energy distribution Florida natural gas division $ 12,180 $ — $ — $ 12,180 Delaware natural gas division 43,954 — — 43,954 FPU electric distribution 37,103 — — 37,103 FPU natural gas distribution 41,494 — — 41,494 Maryland natural gas division 14,673 — — 14,673 Sandpiper 13,331 — — 13,331 Total energy distribution 162,735 — — 162,735 Energy transmission Aspire Energy — 17,931 — 17,931 Eastern Shore 30,100 — — 30,100 Peninsula Pipeline 5,065 — — 5,065 Total energy transmission 35,165 17,931 — 53,096 Energy generation Eight Flags — 8,608 — 8,608 Propane delivery Delmarva Peninsula propane delivery — 60,735 — 60,735 Florida propane delivery — 11,576 — 11,576 Total propane delivery — 72,311 — 72,311 Energy services PESCO — 130,357 — 130,357 Other and eliminations Eliminations (18,003 ) (8,494 ) (25,976 ) (52,473 ) Other — 999 387 1,386 Total other and eliminations (18,003 ) (7,495 ) (25,589 ) (51,087 ) Total operating revenues (1) $ 179,897 $ 221,712 $ (25,589 ) $ 376,020 (1) Includes other revenue (revenues from sources other than contracts with customers) of $(945,000) and $155,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to weather normalization for Maryland division and Sandpiper and late fees.
Contract with Customer, Asset and Liability [Table Text Block]	The opening and closing balances of our trade receivables, contract assets, and contract liabilities are 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 6/30/2018 51,511 1,967 175 Increase (decrease) $ (23,451 ) $ 697 $ (232 )

Environmental Commitments and28

Environmental Commitments and Contingencies Summary of Environmental Liabilities (Tables)	6 Months Ended
	Jun. 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)	6 Months Ended
	Jun. 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 Six Months Ended June 30, June 30, 2018 2017 2018 2017 (in thousands) Operating Revenues, Unaffiliated Customers Regulated Energy segment $ 67,731 $ 68,815 $ 173,685 $ 165,261 Unregulated Energy segment and other businesses 68,933 56,269 202,335 144,983 Total operating revenues, unaffiliated customers $ 136,664 $ 125,084 $ 376,020 $ 310,244 Intersegment Revenues (1) Regulated Energy segment $ 2,773 $ 2,181 $ 6,212 $ 3,389 Unregulated Energy segment 7,412 6,780 19,377 10,791 Other businesses 194 159 387 387 Total intersegment revenues $ 10,379 $ 9,120 $ 25,976 $ 14,567 Operating Income Regulated Energy segment $ 14,304 $ 14,086 $ 41,015 $ 37,481 Unregulated Energy segment 490 2 14,174 11,577 Other businesses and eliminations (1,546 ) (27 ) (1,535 ) 102 Total operating income 13,248 14,061 53,654 49,160 Other expense, net (262 ) (1,002 ) (194 ) (1,703 ) Interest charges 3,881 3,073 7,545 5,811 Income before Income Taxes 9,105 9,986 45,915 41,646 Income taxes 2,718 3,940 12,674 16,456 Net Income $ 6,387 $ 6,046 $ 33,241 $ 25,190 (1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues. (in thousands) June 30, 2018 December 31, 2017 Identifiable Assets Regulated Energy segment $ 1,199,672 $ 1,121,673 Unregulated Energy segment 227,191 259,041 Other businesses and eliminations 36,078 34,220 Total identifiable assets $ 1,462,941 $ 1,414,934

Stockholder's Equity - Accumul

Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) (Tables)	6 Months Ended
	Jun. 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 — (1,440 ) (1,440 ) Amounts reclassified from accumulated other comprehensive income 189 712 901 Net current-period other comprehensive income/(loss) 189 (728 ) (539 ) Stranded tax reclassification to retained earnings (1,022 ) 115 (907 ) As of June 30, 2018 $ (5,576 ) $ (142 ) $ (5,718 ) 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 ) 837 828 Amounts reclassified from accumulated other comprehensive income/(loss) 180 (1,374 ) (1,194 ) Net prior-period other comprehensive income/(loss) 171 (537 ) (366 ) As of June 30, 2017 $ (5,189 ) $ (55 ) $ (5,244 )
Reclassifications out of Accumulated Other Comprehensive Income (Loss)	The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and six months ended June 30, 2018 and 2017 . Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement. Three Months Ended Six Months Ended June 30, June 30, 2018 2017 2018 2017 (in thousands) Amortization of defined benefit pension and postretirement plan items: Prior service credit (1) $ 19 $ 20 $ 39 $ 39 Net loss (1) (149 ) (170 ) (297 ) (339 ) Total before income taxes (130 ) (150 ) (258 ) (300 ) Income tax benefit 36 61 69 120 Net of tax $ (94 ) $ (89 ) $ (189 ) $ (180 ) Gains and losses on commodity contracts cash flow hedges: Propane swap agreements (2) $ (181 ) $ 77 $ (645 ) $ 465 Natural gas swaps (2) (31 ) — (481 ) — Natural gas futures (2) (161 ) 631 137 1,781 Total before income taxes (373 ) 708 (989 ) 2,246 Income tax benefit (expense) 105 (273 ) 277 (872 ) Net of tax (268 ) 435 (712 ) 1,374 Total reclassifications for the period $ (362 ) $ 346 $ (901 ) $ 1,194

Employee Benefit Plans (Tables)

Employee Benefit Plans (Tables)	6 Months Ended
	Jun. 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 six months ended June 30, 2018 and 2017 are set forth in the following tables: Chesapeake FPU Chesapeake SERP Chesapeake FPU For the Three Months Ended June 30, 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Interest cost $ 98 $ 103 $ 592 $ 624 $ 21 $ 22 $ 9 $ 11 $ 13 $ 13 Expected return on plan assets (138 ) (127 ) (774 ) (700 ) — — — — — — Amortization of prior service credit — — — — — — (19 ) (20 ) — — Amortization of net loss 88 106 108 131 25 22 15 17 — — Net periodic cost (benefit) (1) 48 82 (74 ) 55 46 44 5 8 13 13 Amortization of pre-merger regulatory asset — — 191 191 — — — — 2 2 Total periodic cost $ 48 $ 82 $ 117 $ 246 $ 46 $ 44 $ 5 $ 8 $ 15 $ 15 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan For the Six Months Ended June 30, 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017 (in thousands) Interest cost $ 195 $ 206 $ 1,184 $ 1,247 $ 42 $ 44 $ 19 $ 21 $ 26 $ 26 Expected return on plan assets (276 ) (254 ) (1,549 ) (1,399 ) — — — — — — Amortization of prior service credit — — — — — — (39 ) (39 ) — — Amortization of net loss 176 213 217 262 50 44 30 32 — — Net periodic cost (benefit) (1) 95 165 (148 ) 110 92 88 10 14 26 26 Amortization of pre-merger regulatory asset — — 381 381 — — — — 4 4 Total periodic cost $ 95 $ 165 $ 233 $ 491 $ 92 $ 88 $ 10 $ 14 $ 30 $ 30
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 June 30, 2018 and 2017 : For the Three Months Ended June 30, 2018 Chesapeake FPU Chesapeake SERP Chesapeake FPU Total (in thousands) Prior service credit $ — $ — $ — $ (19 ) $ — $ (19 ) Net loss 88 108 25 15 — 236 Total recognized in net periodic benefit cost 88 108 25 (4 ) — 217 Recognized from accumulated other comprehensive loss (1) 88 21 25 (4 ) — 130 Recognized from regulatory asset — 87 — — — 87 Total $ 88 $ 108 $ 25 $ (4 ) $ — $ 217 For the Three Months Ended June 30, 2017 Chesapeake FPU Chesapeake SERP Chesapeake FPU Total (in thousands) Prior service credit $ — $ — $ — $ (20 ) $ — $ (20 ) Net loss 106 131 22 17 — 276 Total recognized in net periodic benefit cost 106 131 22 (3 ) — 256 Recognized from accumulated other comprehensive loss (1) 106 25 22 (3 ) — 150 Recognized from regulatory asset — 106 — — — 106 Total $ 106 $ 131 $ 22 $ (3 ) $ — $ 256 For the Six Months Ended June 30, 2018 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ (39 ) $ — $ (39 ) Net loss 176 217 50 30 — 473 Total recognized in net periodic benefit cost 176 217 50 (9 ) — 434 Recognized from accumulated other comprehensive loss (1) 176 41 50 (9 ) — 258 Recognized from regulatory asset — 176 — — — 176 Total $ 176 $ 217 $ 50 $ (9 ) $ — $ 434 For the Six Months Ended June 30, 2017 Chesapeake Pension Plan FPU Pension Plan Chesapeake SERP Chesapeake Postretirement Plan FPU Medical Plan Total (in thousands) Prior service credit $ — $ — $ — $ (39 ) $ — $ (39 ) Net loss 213 262 44 32 — 551 Total recognized in net periodic benefit cost 213 262 44 (7 ) — 512 Recognized from accumulated other comprehensive loss (1) 213 50 44 (7 ) — 300 Recognized from regulatory asset — 212 — — — 212 Total $ 213 $ 262 $ 44 $ (7 ) $ — $ 512

Investments (Tables)

Investments (Tables)	6 Months Ended
	Jun. 30, 2018
Investments, Debt and Equity Securities [Abstract]
Investments schedule [Table Text Block]	The investment balances at June 30, 2018 and December 31, 2017 , consisted of the following: (in thousands) June 30, December 31, Rabbi trust (associated with the Deferred Compensation Plan) $ 7,465 $ 6,734 Investments in equity securities 21 22 Total $ 7,486 6,756

Share-Based Compensation (Table

Share-Based Compensation (Tables)	6 Months Ended
	Jun. 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 six months ended June 30, 2018 and 2017 : Three Months Ended Six Months Ended June 30, June 30, 2018 2017 2018 2017 (in thousands) Awards to non-employee directors $ 135 $ 136 $ 269 $ 271 Awards to key employees 1,190 37 2,575 541 Total compensation expense 1,325 173 2,844 812 Less: tax benefit (363 ) (70 ) (779 ) (327 ) Share-based compensation amounts included in net income $ 962 $ 103 $ 2,065 $ 485
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 six months ended June 30, 2018 : Number of Shares Weighted Average Fair Value Outstanding—December 31, 2017 — $ — Granted 7,128 $ 75.70 Vested (7,128 ) $ 75.70 Outstanding—June 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 six months ended June 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—June 30, 2018 131,741 $ 67.46

Derivative Instruments (Tables)

Derivative Instruments (Tables)	6 Months Ended
	Jun. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Offsetting Assets and Liabilities [Table Text Block]	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 June 30, 2018 and December 31, 2017: At June 30, 2018 (in thousands) Gross amounts Amounts offset Net amounts Accounts receivable $ 5,723 $ 1,288 $ 4,435 Accounts payable $ 10,326 $ 1,288 $ 9,038 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 The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit risk-related contingency.
Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet	The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of June 30, 2018 and December 31, 2017 , are as follows: Asset Derivatives Fair Value As Of (in thousands) Balance Sheet Location June 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 90 — Derivatives designated as cash flow hedges Natural gas futures contracts Derivative assets, at fair value 120 92 Propane swap agreements Derivative assets, at fair value 324 1,181 Total asset derivatives $ 534 $ 1,286 Liability Derivatives Fair Value As Of (in thousands) Balance Sheet Location June 30, 2018 December 31, 2017 Derivatives not designated as hedging instruments Natural gas futures contracts Derivative liabilities, at fair value $ 77 $ 5,776 Derivatives designated as cash flow hedges Natural gas futures contracts Derivative liabilities, at fair value 779 469 Natural gas swap contracts Derivative liabilities, at fair value — 2 Propane swap agreements Derivative liabilities, at fair value 30 — Total liability derivatives $ 886 $ 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 June 30, For the Six Months Ended June 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 (128 ) 497 (2,963 ) 621 Propane swap agreements Cost of sales (4 ) — (13 ) (4 ) 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 (181 ) 77 (645 ) 465 Propane swap agreements Other comprehensive loss 106 (218 ) (886 ) (775 ) Natural gas futures contracts Cost of sales (161 ) 631 137 1,781 Natural gas swap contracts Cost of sales (31 ) — (481 ) — Natural gas swap contracts Other comprehensive income 523 — 588 — Natural gas futures contracts Other comprehensive loss 861 (1,211 ) (871 ) (124 ) Total $ 985 $ (224 ) $ (5,134 ) $ 2,067 (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.

Fair Value of Financial Instr35

Fair Value of Financial Instruments (Tables)	6 Months Ended
	Jun. 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 June 30, 2018 and December 31, 2017 : Fair Value Measurements Using: As of June 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 $ 21 $ 21 $ — $ — Investments—guaranteed income fund 671 — — 671 Investments—mutual funds and other 6,794 6,794 — — Total investments 7,486 6,815 — 671 Derivative assets 534 — 534 — Total assets $ 8,020 $ 6,815 $ 534 $ 671 Liabilities: Derivative liabilities $ 886 $ — $ 886 $ — 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 six months ended June 30, 2018 and 2017 : Six Months Ended 2018 2017 (in thousands) Beginning Balance $ 648 $ 561 Purchases and adjustments 54 65 Transfers (24 ) — Distribution (12 ) — Investment income 5 4 Ending Balance $ 671 $ 630

Long-Term Debt (Tables)

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2018
Debt Disclosure [Abstract]
Outstanding Long-Term Debt	Our outstanding long-term debt is shown below: June 30, December 31, (in thousands) 2018 2017 FPU secured first mortgage bonds (1) : 9.08% bond, due June 1, 2022 $ 7,984 $ 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 1,351 2,070 Less: debt issuance costs (488 ) (433 ) Total long-term debt 251,573 206,816 Less: current maturities (9,977 ) (9,421 ) Total long-term debt, net of current maturities $ 241,596 $ 197,395 (1) FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities.

Summary of Accounting policie37

Summary of Accounting policies - Additional Information (Details) $ in Thousands	6 Months Ended
	Jun. 30, 2018USD ($)
Summary of Accounting Policies [Abstract]
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 1,600
Delay of Revenue Recognition Due To Implementation of New Standard	$ 204

Summary of Accounting Policie38

Summary of Accounting Policies Acquisitions Additional information (Details)	12 Months Ended
	Dec. 31, 2017USD ($)	Jun. 30, 2018USD ($)
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 Policie39

Summary of Accounting Policies Summary of Effect of Adoption on Consolidated Financial Statements (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Item Effected [Line Items]
Accrued revenue	$ 12,353		$ 12,353		$ 22,279
Regulated Energy Operating Revenue	70,504	$ 70,996	179,897	$ 168,650
Regulated Energy cost of sales	20,010	24,167	68,241	64,411
Depreciation and amortization	9,839	9,094	19,543	17,906
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	9,105	9,986	45,915	41,646
Income taxes	2,718	3,940	12,674	16,456
Net Income	6,387	$ 6,046	33,241	$ 25,190	58,124
Other assets	4,440		4,440		3,699
Retained earnings	250,377		250,377		$ 229,141
Calculated under Revenue Guidance in Effect before Topic 606 [Member]
Item Effected [Line Items]
Accrued revenue	13,659		13,659
Regulated Energy Operating Revenue	70,728		180,780
Regulated Energy cost of sales	20,139		68,942
Depreciation and amortization	9,832		19,521
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	9,207		46,119
Income taxes	2,746		12,733
Net Income	6,461		33,386
Other assets	4,777		4,777
Retained earnings	248,734		248,734
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)	(224)		(883)
Regulated Energy cost of sales	(129)		(701)
Depreciation and amortization	7		22
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	(102)		(204)
Income taxes	(28)		(59)
Net Income	(74)		(145)
Other assets	(337)		(337)
Retained earnings	$ 1,643		$ 1,643

Calculation of Earnings Per S40

Calculation of Earnings Per Share - Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Calculation of Basic Earnings Per Share:
Net Income	$ 6,387	$ 6,046	$ 33,241	$ 25,190	$ 58,124
Weighted shares outstanding (shares)	16,369,641	16,340,665	16,360,540	16,329,009
Basic Earnings Per Share (in dollars per share)	$ 0.39	$ 0.37	$ 2.03	$ 1.54
Reconciliation of Numerator:
Net Income	$ 6,387	$ 6,046	$ 33,241	$ 25,190	$ 58,124
Reconciliation of Denominator:
Weighted shares outstanding - Basic (shares)	16,369,641	16,340,665	16,360,540	16,329,009
Effect of dilutive securities:
Share-based compensation (shares)	47,441	41,542	49,521	44,029
Adjusted denominator-Diluted (shares)	16,417,082	16,382,207	16,410,061	16,373,038
Diluted Earnings Per Share (in dollars per share)	$ 0.39	$ 0.37	$ 2.03	$ 1.54

Revenue Recognition Additional

Revenue Recognition Additional Information (Details) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Revenues	$ 136,664,000	$ 125,084,000	$ 376,020,000	$ 310,244,000
Contract with Customer, Liability, Current	175,000		175,000		$ 407,000
Contract with Customer, Liability, Revenue Recognized	84,000		336,000
Regulated Energy [Member] | Other [Member]
Revenues	(356,000)		(945,000)
Unregulated Energy [Member] | Other [Member]
Revenues	$ 82,000		$ 155,000

Revenue Recognition Disegragati

Revenue Recognition Disegragation of Revenue (Details) - USD ($) $ in Thousands		3 Months Ended	6 Months Ended
		Jun. 30, 2018	Jun. 30, 2018
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]	$ 136,664	$ 376,020
Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(23,104)	(51,087)
Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]	70,504	179,897
Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]	76,345	221,712
Other Segments And Intersegments Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(10,185)	(25,589)
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]	(10,185)	(25,589)
Other [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(2,743)	(7,495)
Eliminations [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(10,176)	(18,003)
Energy Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		63,210	162,735
Energy Distribution [Member] | Florida Natural Gas Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		6,317	12,180
Energy Distribution [Member] | Florida Public Utilities Company [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		18,281	41,494
Energy Distribution [Member] | Maryland Natural Gas [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		4,001	14,673
Energy Distribution [Member] | Delaware natural gas division [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		11,882	43,954
Energy Distribution [Member] | FPU Electric Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		18,362	37,103
Energy Distribution [Member] | Sandpiper [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		4,367	13,331
Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		23,324	53,096
Energy Transmission [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		17,470	35,165
Energy Transmission [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		5,854	17,931
Energy Transmission [Member] | Aspire [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		5,854	17,931
Energy Transmission [Member] | Eastern Shore Gas Company [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		14,502	30,100
Energy Transmission [Member] | Peninsula Pipeline [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,968	5,065
Energy Generation [Member] | Eight Flags [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		4,230	8,608
Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		20,206	72,311
Propane Delivery [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		20,206	72,311
Propane Delivery [Member] | Delmarva Peninsula Propane Delivery [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		15,264	60,735
Propane Delivery [Member] | Florida Propane [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		4,942	11,576
Energy Services [Member] | PESCO [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		48,798	130,357
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(23,803)	(52,473)
Eliminations [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(10,176)	(18,003)
Eliminations [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(3,248)	(8,494)
Eliminations [Member] | Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(10,379)	(25,976)
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		699	1,386
Other [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		505	999
Other [Member] | Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		$ 194	$ 387
[1]	(1) Includes other revenue (revenues from sources other than contracts with customers) of $(356,000) and $82,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to weather normalization for Maryland division and Sandpiper and late fees.

Revenue Recognition Contract Ba

Revenue Recognition Contract Balances with Customers (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Receivables from Customers	$ 51,511	$ 74,962
Contract with Customer, Asset, Net, Noncurrent	1,967	1,270
Contract with Customer, Liability, Current	175	$ 407
Increase (Decrease) in Receivables	(23,451)
Increase (Decrease) in Other Noncurrent Assets	697
Increase (Decrease) in Other Current Liabilities	$ (232)

Rates and Other Regulatory Ac44

Rates and Other Regulatory Activities - Additional Information (Detail)	6 Months Ended	12 Months Ended
	Jun. 30, 2018USD ($)dekatherm / dunitmi	Dec. 31, 2017USD ($)
Rates and Other Regulatory Activities [Line Items]
Effective Income Tax Rate Reconciliation, at Federal Statutory Income Tax Rate, Percent	21.00%	35.00%
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	800,000
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
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 and45

Environmental Commitments and Contingencies - Additional Information (Detail)	6 Months Ended
	Jun. 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	$ 8,090,000	$ 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	9,500,000
Approval of recovery of environmental costs	14,000,000
Environmental costs recovered	11,300,000
FPU [Member] | Manufactured Gas Plant [Member]
Environmental Commitments And Contingencies [Line Items]
Regulatory Assets for future recovery of environmental costs	$ 2,700,000

Other Commitments and Conting46

Other Commitments and Contingencies - Additional Information (Detail) gal in Millions, $ in Millions	6 Months Ended
	Jun. 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	2.2
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	$ 72.5
Draws on letters of credit	$ 5

Segment Information - Schedule

Segment Information - Schedule of Segment Reporting Information by Segment (Detail) $ in Thousands		3 Months Ended		6 Months Ended		12 Months Ended
		Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Jun. 30, 2018USD ($)	Jun. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments		2
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		$ 136,664	$ 125,084	$ 376,020	$ 310,244
Intersegment Revenues
Total operating revenues, unaffiliated customers		136,664	125,084	376,020	310,244
Operating Income
Total operating income		13,248	14,061	53,654	49,160
Other expense, net		(262)	(1,002)	(194)	(1,703)
Interest		3,881	3,073	7,545	5,811
Income Before Income Taxes		9,105	9,986	45,915	41,646
Income taxes		2,718	3,940	12,674	16,456
Net Income		6,387	6,046	33,241	25,190	$ 58,124
Identifiable Assets
Total identifiable assets		1,462,941		1,462,941		1,414,934
Regulated Energy [Member]
Operating Income
Total operating income		14,304	14,086	41,015	37,481
Identifiable Assets
Total identifiable assets		1,199,672		1,199,672		1,121,673
Unregulated Energy [Member]
Operating Income
Total operating income		490	2	14,174	11,577
Identifiable Assets
Total identifiable assets		227,191		227,191		259,041
Other [Member]
Identifiable Assets
Total identifiable assets		36,078		36,078		$ 34,220
Other and eliminations [Member]
Operating Income
Total operating income		(1,546)	(27)	(1,535)	102
Operating Revenues, Unaffiliated Customers [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		136,664	125,084	376,020	310,244
Intersegment Revenues
Total operating revenues, unaffiliated customers		136,664	125,084	376,020	310,244
Operating Revenues, Unaffiliated Customers [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		67,731	68,815	173,685	165,261
Intersegment Revenues
Total operating revenues, unaffiliated customers		67,731	68,815	173,685	165,261
Operating Revenues, Unaffiliated Customers [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		68,933	56,269	202,335	144,983
Intersegment Revenues
Total operating revenues, unaffiliated customers		68,933	56,269	202,335	144,983
Intersegment Revenues [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	10,379	9,120	25,976	14,567
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	10,379	9,120	25,976	14,567
Intersegment Revenues [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	2,773	2,181	6,212	3,389
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	2,773	2,181	6,212	3,389
Intersegment Revenues [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	7,412	6,780	19,377	10,791
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	7,412	6,780	19,377	10,791
Intersegment Revenues [Member] | Other [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	194	159	387	387
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	$ 194	$ 159	$ 387	$ 387
[1]	All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.

Stockholder's Equity - Accumu48

Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 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	(1,440)	828
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	901	(1,194)
Net current-period other comprehensive income (loss)	(539)	(366)
Ending balance	(5,718)	(5,244)
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	189	180
Net current-period other comprehensive income (loss)	189	171
Ending balance	(5,576)	(5,189)
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	(1,440)	837
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	712	(1,374)
Net current-period other comprehensive income (loss)	(728)	(537)
Ending balance	(142)	$ (55)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	$ 115

Stockholder's Equity - Accum49

Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) - Reclassifications of Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands		3 Months Ended			6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017		Jun. 30, 2018		Jun. 30, 2017
Amortization of pension and postretirement items:
Derivative, Gain (Loss) on Derivative, Net		$ 985	$ (224)		$ (5,134)		$ 2,067
Tax benefit		(2,718)	(3,940)		(12,674)		(16,456)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Amortization of pension and postretirement items:
Net of tax		(362)	346		(901)		1,194
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	20		39		39
Net loss	[1]	(149)	(170)		(297)		(339)
Total before tax		(130)	(150)		(258)		(300)
Tax benefit		36	61		69		120
Net of tax		(94)	(89)		(189)		(180)
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		(373)	708		(989)		2,246
Tax benefit		105	(273)		277		(872)
Net of tax		(268)	435		(712)		1,374
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		$ (181)	77	[2]	(645)	[2]	465	[2]
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]				(481)
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]		$ 631		$ 137		$ 1,781
[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	12 Months Ended
	Dec. 31, 2017	Jun. 30, 2018
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	$ (10)

Employee Benefit Plans (Detail)

Employee Benefit Plans (Detail) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Defined Benefit Plan Disclosure [Line Items]
Amortization of prior service cost		$ (19)	$ (20)	$ (39)	$ (39)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		236	276	473	551
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		9	11	19	21
Amortization of prior service cost		(19)	(20)	(39)	(39)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		15	17	30	32
Net periodic cost (benefit)	[1]	5	8	10	14
Total periodic cost		5	8	10	14
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		13	13	26	26
Net periodic cost (benefit)	[1]	13	13	26	26
Amortization of pre-merger regulatory asset		2	2	4	4
Total periodic cost		15	15	30	30
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		592	624	1,184	1,247
Expected return on plan assets		(774)	(700)	(1,549)	(1,399)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		108	131	217	262
Net periodic cost (benefit)	[1]	(74)	55	(148)	110
Amortization of pre-merger regulatory asset		191	191	381	381
Total periodic cost		117	246	233	491
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		21	22	42	44
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		25	22	50	44
Net periodic cost (benefit)	[1]	46	44	92	88
Total periodic cost		46	44	92	88
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		98	103	195	206
Expected return on plan assets		(138)	(127)	(276)	(254)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		88	106	176	213
Net periodic cost (benefit)	[1]	48	82	95	165
Total periodic cost		$ 48	$ 82	$ 95	$ 165
[1]	See Note 8, Stockholder's Equity.

Employee Benefit Plans - Additi

Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Expected pension and postretirement benefit costs		$ 913
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	$ 942	942	$ 1,300
Contribution to pension plan	539	848
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	126	198
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	76
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	7	18
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	13	24
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		6 Months Ended
		Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		$ (19)	$ (20)	$ (39)	$ (39)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		236	276	473	551
Recognized from accumulated other comprehensive loss	[1]	130	150	258	300
Recognized from regulatory asset		87	106	176	212
Total recognized in net periodic benefit cost		217	256	434	512
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		88	106	176	213
Recognized from accumulated other comprehensive loss	[1]	88	106	176	213
Total recognized in net periodic benefit cost		88	106	176	213
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)		108	131	217	262
Recognized from accumulated other comprehensive loss	[1]	21	25	41	50
Recognized from regulatory asset		87	106	176	212
Total recognized in net periodic benefit cost		108	131	217	262
Chesapeake Pension SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		25	22	50	44
Recognized from accumulated other comprehensive loss	[1]	25	22	50	44
Total recognized in net periodic benefit cost		25	22	50	44
Chesapeake Postretirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		(19)	(20)	(39)	(39)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		15	17	30	32
Recognized from accumulated other comprehensive loss	[1]	(4)	(3)	(9)	(7)
Total recognized in net periodic benefit cost		$ (4)	$ (3)	$ (9)	$ (7)
[1]	See Note 8, Stockholder's Equity.

Investments - Schedule of Inves

Investments - Schedule of Investments (Details) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Investments schedule [Line Items]
Investments, at fair value	$ 7,486	$ 6,756
Rabbi Trust Associated With Deferred Compensation Plan [Member]
Investments schedule [Line Items]
Investments, at fair value	7,465	6,734
Equity Securities [Member]
Investments schedule [Line Items]
Investments, at fair value	$ 21	$ 22

Investments - Additional Inform

Investments - Additional Information (Detail) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017
Investments, Debt and Equity Securities [Abstract]
Unrealized gain (loss), net of other expenses	$ 158,000	$ 181,000	$ 113,000	$ 433,000

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		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018	Jun. 30, 2017	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 1,325	$ 173	$ 2,844	$ 812
Less: tax benefit	(363)	(70)	(779)	(327)
Share-Based Compensation amounts included in net income	962	103	$ 2,065	485
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	136	$ 269	271
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	$ 1,190	$ 37	$ 2,575	$ 541
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 67.46		$ 67.46		$ 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)	6 Months Ended
	Jun. 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 - June 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 - June 30, 2018 (in dollars per share) | $ / shares	67.46
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	6 Months Ended		12 Months Ended
	Jun. 30, 2018USD ($)unitshares	Jun. 30, 2017USD ($)	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 | $	$ 3,200
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 | $	$ 450
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
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 | $	$ 10,500
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) Mcf in Thousands, $ in Thousands, gal in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2018USD ($)$ / galgalMcf	Dec. 31, 2017USD ($)gal
Derivative [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	$ 1,288	$ 2,391
Energy Marketing Contracts Assets, Current	534	1,286
Energy Marketing Contract Liabilities, Current	(886)	(6,247)
Accounts Payable Subject To Master Netting Arrangement	$ 1,288	2,391
Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | Mcf	500
Hedging Liability [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ (779)	(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] | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	(120)
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	324	1,181
Energy Marketing Contract Liabilities, Current	(30)	0
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	$ 18
Not Designated as Hedging Instrument [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | Mcf	1,100
Not Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	$ 90
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	$ (77)	$ (5,776)
PESCO [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | Mcf	16,900
2017 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal	1.4
2017 [Member] | Natural Gas Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | Mcf	844
2017 [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal		7.7
Derivative, Cash Received on Hedge	$ 11
2017 [Member] | Strike Price 4 [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements | $ / gal	0.5900
2017 [Member] | Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	$ 306
2018 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal	1.4
2018 [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Derivative, Cash Received on Hedge	$ 645
2018 [Member] | Strike Price Minimum [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements | $ / gal	0.76
2018 [Member] | Strike Price 2 [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements | $ / gal	0.875
Gross [Member]
Derivative [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	$ 5,723	$ 8,283
Accounts Payable Subject To Master Netting Arrangement	10,326	16,643
Net [Member]
Derivative [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	4,435	5,892
Accounts Payable Subject To Master Netting Arrangement	$ 9,038	$ 14,252

Derivative Instruments - Fair V

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 534	$ 1,286
Energy Marketing Contract Liabilities, Current	886	6,247
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	90
Mark To Market Energy Assets [Member] | Natural Gas Futures [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	120
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	324	1,181
Energy Marketing Contract Liabilities, Current	30	0
Hedging Asset [Member] | Natural Gas Futures [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current		92
Energy Marketing Contract Liabilities, Current	120
Mark-to-market energy liabilities [Member] | Natural Gas Futures [Member] | Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	77	5,776
Mark-to-market energy liabilities [Member] | Propane Swap Agreement [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	18
Hedging Liability [Member] | Natural Gas Swaps [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	0	2
Hedging Liability [Member] | Natural Gas Futures [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 779	$ 469

Derivative Instruments - Effect

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements (Detail) - USD ($)	3 Months Ended		6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017	Jun. 30, 2018		Jun. 30, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 985,000	$ (224,000)	$ (5,134,000)		$ 2,067,000
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	(128,000)	497,000	(2,963,000)		621,000
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	(4,000)	0	(13,000)		(4,000)
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(161,000)	631,000	137,000		1,781,000
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(31,000)	0	(481,000)		0
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	(181,000)	77,000	(645,000)		465,000
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	523,000	0	588,000		0
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	106,000	(218,000)	(886,000)		(775,000)
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	$ 861,000	$ (1,211,000)	$ (871,000)		$ (124,000)
[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.

Fair Value of Financial Instr62

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Jun. 30, 2018	Dec. 31, 2017
Assets:
Investments	$ 7,486	$ 6,756
Liabilities:
Energy Marketing Contract Liabilities, Current	886	6,247
Equity Securities [Member]
Assets:
Investments	21	22
Quoted Prices in Active Markets (Level 1) [Member]
Assets:
Assets, Fair Value Disclosure	6,815	6,108
Quoted Prices in Active Markets (Level 1) [Member] | Equity Securities [Member]
Assets:
Investments	21	22
Quoted Prices in Active Markets (Level 1) [Member] | Investments - other [Member]
Assets:
Investments	6,794	6,086
Quoted Prices in Active Markets (Level 1) [Member] | Total Investments [Member]
Assets:
Investments	6,815	6,108
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Assets, Fair Value Disclosure	534	1,286
Liabilities:
Energy Marketing Contract Liabilities, Current	886	6,247
Significant Other Observable Inputs (Level 2) [Member] | Mark To Market Energy Assets incl. natural gas and swap agreements[Member]
Assets:
Derivative assets	534	1,286
Significant Unobservable Inputs (Level 3) [Member]
Assets:
Assets, Fair Value Disclosure	671	648
Significant Unobservable Inputs (Level 3) [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	671	648
Significant Unobservable Inputs (Level 3) [Member] | Total Investments [Member]
Assets:
Investments	671	648
Recurring [Member]
Assets:
Assets, Fair Value Disclosure	8,020	8,042
Liabilities:
Energy Marketing Contract Liabilities, Current	886	6,247
Recurring [Member] | Equity Securities [Member]
Assets:
Investments	21	22
Recurring [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	671	648
Recurring [Member] | Investments - other [Member]
Assets:
Investments	6,794	6,086
Recurring [Member] | Total Investments [Member]
Assets:
Investments	7,486	6,756
Recurring [Member] | Mark To Market Energy Assets incl. natural gas and swap agreements[Member]
Assets:
Derivative assets	$ 534	$ 1,286

Fair Value of Financial Instr63

Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2018	Jun. 30, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 648	$ 561
Purchases and adjustments	54	65
Transfers	24	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	(12)	0
Investment Income	5	4
Ending Balance	$ 671	$ 630

Fair Value of Financial Instr64

Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Jun. 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	$ 250.3	$ 215.4

Long-Term Debt - Outstanding Lo

Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands		Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total long-term debt		$ 250,700		$ 205,200
Capital lease obligation		1,351		2,070
Total Long-term debt		251,573		206,816
Less: current maturities		(9,977)		(9,421)
Less: debt issuance costs		(488)		(433)
Total long-term debt, net of current maturities		241,596		197,395
9.08% bond, due June 1, 2022 [Member]
Debt Instrument [Line Items]
Total long-term debt	[1]	7,984		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
Uncollateralized Senior Notes Due On May Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Total long-term debt		7,000		7,000
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Total long-term debt		20,000		20,000
Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [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 66

Long-Term Debt - Outstanding Long-Term Debt- Supplemental Information (Detail)	6 Months Ended
	Jun. 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
Uncollateralized Senior Notes Due On May Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.43%
Debt instrument, maturity date	May 2, 2028
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.73%
Debt instrument, maturity date	Dec. 16, 2028
Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.88%
Debt instrument, maturity date	May 15, 2029
Uncollateralized Senior Note Due on Two Thousand Thirty Two [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.25%
Debt instrument, maturity date	Apr. 30, 2032
Uncollateralized Senior Note Due on Two Thousand Thirty Eight [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	6 Months Ended
	Jun. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Nov. 30, 2017
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 250,700		$ 205,200
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] | Shelf Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Prudential [Member]
Debt Instrument [Line Items]
Senior notes	$ 150,000
Prudential [Member] | Notes Payable, Other Payables [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
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
Prudential and Metlife [Member]
Debt Instrument [Line Items]
Senior notes	$ 230,000
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%