Document and Entity Information - shares	6 Months Ended
Document and Entity Information - shares	Jun. 30, 2016	Jul. 31, 2016
Entity Information [Line Items]
Entity Registrant Name	CHESAPEAKE UTILITIES CORP
Trading Symbol	CPK
Entity Central Index Key	0000019745
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		15,323,102

Condensed Consolidated Statements of Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Operating Revenues
Regulated Energy	$ 67,395	$ 62,060	$ 156,611	$ 171,642
Unregulated Energy and other	34,947	30,622	92,027	91,121
Total Operating Revenues	102,342	92,682	248,638	262,763
Operating Expenses
Regulated Energy cost of sales	21,635	21,124	56,540	78,253
Unregulated Energy and other cost of sales	22,934	20,272	56,958	55,507
Operations	28,087	26,190	55,246	53,133
Maintenance	2,904	2,727	5,383	5,431
Gain from a settlement	(130)	(1,500)	(130)	(1,500)
Depreciation and amortization	7,780	7,543	15,283	14,518
Other taxes	3,390	3,156	7,236	6,743
Total Operating Expenses	86,600	79,512	196,516	212,085
Operating Income	15,742	13,170	52,122	50,678
Other Expense, net	(8)	(171)	(42)	(38)
Interest charges	2,624	2,485	5,274	4,933
Income Before Income Taxes	13,110	10,514	46,806	45,707
Income taxes	5,081	4,220	18,410	18,304
Net Income	$ 8,029	$ 6,294	$ 28,396	$ 27,403
Weighted Average Common Shares Outstanding:
Basic (shares)	15,315,020	15,235,860	15,300,931	14,922,094
Diluted (shares)	15,352,702	15,280,657	15,342,287	14,970,190
Earnings Per Share of Common Stock:
Basic (in dollars per share)	$ 0.52	$ 0.41	$ 1.86	$ 1.84
Diluted (in dollars per share)	0.52	0.41	1.85	1.83
Cash Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.3050	$ 0.2875	$ 0.5925	$ 0.5575

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Net Income	$ 8,029	$ 6,294	$ 28,396	$ 27,403
Other Comprehensive Income (Loss), net of tax:
Amortization of prior service cost, net of tax of $(8), $(7), $(16) and $(14), respectively	(12)	(10)	(24)	(20)
Net gain, net of tax of $67, $62, $133 and $125, respectively	99	93	200	185
Cash Flow Hedges, net of tax:
Unrealized gain on commodity contract cash flow hedges, net of tax of $313, $4, $322 and $21, respectively	496	6	496	32
Total Other Comprehensive Income	583	89	672	197
Comprehensive Income	$ 8,612	$ 6,383	$ 29,068	$ 27,600

The portion of profit or loss for the period, net of income taxes, which is attributable to the parent.

+ References + Details

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement of Comprehensive Income [Abstract]
Amortization of prior service cost, tax	$ (8)	$ (7)	$ (16)	$ (14)
Net gain, tax	67	62	133	125
Unrealized loss on commodity contract cash flow hedges, tax	$ 313	$ 4	$ 322	$ 21

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Property, Plant and Equipment
Regulated Energy	$ 868,016	$ 842,756
Unregulated Energy	189,034	145,734
Other businesses and eliminations	19,608	18,999
Total property, plant and equipment	1,076,658	1,007,489
Less: Accumulated depreciation and amortization	(229,826)	(215,313)
Plus: Construction work in progress	61,975	62,774
Net property, plant and equipment	908,807	854,950
Current Assets
Cash and cash equivalents	3,266	2,855
Accounts receivable (less allowance for uncollectible accounts of $631 and $909, respectively)	41,851	41,007
Accrued revenue	8,658	12,452
Propane inventory, at average cost	4,285	6,619
Other inventory, at average cost	4,025	3,803
Regulatory assets	7,042	8,268
Storage gas prepayments	5,014	3,410
Income taxes receivable	7,395	24,950
Prepaid expenses	4,184	7,146
Mark-to-market energy assets	405	153
Other current assets	771	1,044
Total current assets	86,896	111,707
Deferred Charges and Other Assets
Goodwill	15,070	14,548
Other intangible assets, net	2,033	2,222
Investments, at fair value	4,325	3,644
Regulatory assets	76,563	77,519
Receivables and other deferred charges	3,353	2,831
Total deferred charges and other assets	101,344	100,764
Total Assets	1,097,047	1,067,421
Stockholders’ equity
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)	7,456	7,432
Additional paid-in capital	191,776	190,311
Retained earnings	185,490	166,235
Accumulated other comprehensive loss	(5,168)	(5,840)
Deferred compensation obligation	2,452	1,883
Treasury stock	(2,452)	(1,883)
Total stockholders’ equity	379,554	358,138
Long-term debt, net of current maturities	143,865	149,006
Total capitalization	523,419	507,144
Current Liabilities
Current portion of long-term debt	12,075	9,151
Short-term borrowing	180,042	173,397
Accounts payable	35,496	39,300
Customer deposits and refunds	27,572	27,173
Accrued interest	1,250	1,311
Dividends payable	4,673	4,390
Accrued compensation	6,742	10,014
Regulatory liabilities	6,808	7,365
Mark-to-market energy liabilities	256	433
Other accrued liabilities	8,978	7,059
Total current liabilities	283,892	279,593
Deferred Credits and Other Liabilities
Deferred income taxes	199,623	192,600
Regulatory liabilities	43,093	43,064
Environmental liabilities	8,765	8,942
Other pension and benefit costs	32,695	33,481
Deferred investment tax credits and other liabilities	5,560	2,597
Total deferred credits and other liabilities	289,736	280,684
Environmental and other commitments and contingencies
Total Capitalization and Liabilities	$ 1,097,047	$ 1,067,421

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 631	$ 909
Common stock, par value (in dollars per share)	$ 0.4867	$ 0.4867
Common stock, shares authorized (shares)	25,000,000	25,000,000

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Operating Activities
Net Income	$ 28,396	$ 27,403
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	15,283	14,518
Depreciation and accretion included in other costs	3,436	3,486
Deferred income taxes, net	6,162	(1,366)
Realized (gain) loss on commodity contracts/sale of assets/investments	664	(686)
Unrealized gain on investments/commodity contracts	(42)	(187)
Employee benefits and compensation	760	601
Share-based compensation	1,264	947
Other, net	24	8
Changes in assets and liabilities:
Accounts receivable and accrued revenue	2,264	20,194
Propane inventory, storage gas and other inventory	663	4,405
Regulatory assets/liabilities, net	519	12,728
Prepaid expenses and other current assets	2,878	3,261
Accounts payable and other accrued liabilities	(4,069)	(16,359)
Income taxes receivable	20,680	19,300
Customer deposits and refunds	399	(3,748)
Accrued compensation	(3,340)	(3,788)
Other assets and liabilities, net	(1,786)	(315)
Net cash provided by operating activities	74,155	80,402
Investing Activities
Property, plant and equipment expenditures	(70,045)	(57,350)
Proceeds from sales of assets	89	49
Payments to Acquire Businesses, Net of Cash Acquired	0	20,930
Environmental expenditures	(177)	(73)
Net cash used in investing activities	(70,133)	(78,304)
Financing Activities
Common stock dividends	(8,453)	(7,532)
Issuance of stock for Dividend Reinvestment Plan	429	417
Change in cash overdrafts due to outstanding checks	1,473	2,367
Net borrowing (repayment) under line of credit agreements	5,166	4,114
Repayment of long-term debt and capital lease obligation	(2,226)	(3,934)
Net cash used in financing activities	(3,611)	(4,568)
Net Increase (Decrease) in Cash and Cash Equivalents	411	(2,470)
Cash and Cash Equivalents—Beginning of Period	2,855	4,574
Cash and Cash Equivalents—End of Period	$ 3,266	$ 2,104

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, 2014

^[1]

14,588,711

Beginning Balances at Dec. 31, 2014

$ 300,322

$ 7,100

$ 156,581

$ 142,317

$ (5,676)

$ 1,258

$ (1,258)

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Net Income

41,140

Other comprehensive loss

(164)

Dividend declared ($1.1325 per share)

(17,222)

Retirement savings plan and dividend reinvestment plan (shares)

43,275

Retirement savings plan and dividend reinvestment plan

2,235

$ 21

2,214

Common stock issued in acquisition (shares)

592,970

Common stock issued in acquisition

30,165

$ 289

29,876

Share-based compensation (shares)

^[1],[2],[3]

45,703

Share-based compensation and tax benefit

^[2],[3]

1,662

$ 22

1,640

Treasury stock activities

625

(625)

Ending Balances (shares) at Dec. 31, 2015

^[1]

15,270,659

Ending Balances at Dec. 31, 2015

358,138

$ 7,432

190,311

166,235

(5,840)

1,883

(1,883)

Increase (Decrease) in Stockholders' Equity [Roll Forward]

Net Income

28,396

Other comprehensive loss

672

Dividend declared ($0.2875 per share) and dividend reinvestment plan (shares)

13,120

Dividend declared ($0.5925 per share) and dividend reinvestment plan

(8,376)

$ 6

759

(9,141)

Share-based compensation (shares)

^[1],[2],[3]

36,099

Share-based compensation and tax benefit

^[2],[3]

724

$ 18

706

Treasury stock activities

569

(569)

Ending Balances (shares) at Jun. 30, 2016

^[1]

15,319,878

Ending Balances at Jun. 30, 2016

$ 379,554

$ 7,456

$ 191,776

$ 185,490

$ (5,168)

$ 2,452

$ (2,452)

[1]	Includes 79,658 and 70,631 shares at June 30, 2016 and December 31, 2015, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.
[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, 2016, and for the year ended December 31, 2015, we withheld 12,031 and 12,620 shares, respectively, for taxes.

Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) (Unaudited) - $ / shares	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Dec. 31, 2015
Statement of Stockholders' Equity [Abstract]
Dividend declared (in dollars per share)	$ 0.3050	$ 0.5925	$ 1.1325
Deferred compensation plan held Rabbi Trust (shares)	79,658	79,658	70,631
Shares issued under the performance incentive plan withheld for employee taxes (shares)		12,031	12,620

Summary of Accounting Policies	6 Months Ended
Summary of Accounting Policies	Jun. 30, 2016
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, 2015. 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. We reclassified certain amounts in the condensed consolidated balance sheet as of December 31, 2015. We have revised the condensed consolidated statement of cash flows for the six months ended June 30, 2015 to reflect only property, plant and equipment expenditures paid in cash within the Investing Activities section. The non-cash expenditures previously included in that section have now been included in the change in accounts payable and other accrued liabilities amount within the Operating Activities section. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements. FASB Statements and Other Authoritative Pronouncements Recently Adopted Accounting Standards Interest - Imputation of Interest (ASC 835-30) - In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. This standard requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. ASU 2015-03 became effective for us on January 1, 2016, and we applied the provisions of this standard on a retrospective basis. As a result of the adoption of this standard, debt issuance costs totaling $312,000 and $333,000 at June 30, 2016 and December 31, 2015, respectively, previously presented as other deferred charges, a non-current asset, are now presented as a deduction from long-term debt, net of current maturities in our condensed consolidated balance sheets. Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (ASC 350-40) - In April 2015, the FASB issued ASU 2015-05, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement. Under the new standard, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense in the period incurred. ASU 2015-05 became effective for us on January 1, 2016, and has been applied on a prospective basis. The standard did not have a material impact on our financial position or results of operations for the quarter. Debt Issuance Costs (ASC 835-30) - In August 2015, the FASB issued ASU 2015-15, Simplifying the Presentation of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This standard clarifies treatment of debt issuance costs associated with line-of-credit arrangements that were not specifically addressed in ASU 2015-03. Issuance costs incurred in connection with line-of-credit arrangements may be treated as an asset and amortized over the term of the line-of-credit arrangement. ASU 2015-15 became effective for us on January 1, 2016. The standard did not have a material impact on our financial position and results of operations. Business Combinations (ASC 805) - In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. The standard eliminates the requirement to restate prior period financial statements for measurement period adjustments. The guidance requires that the cumulative impact of a measurement-period adjustment (including the impact of prior periods) be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 was effective for our interim and annual financial statements issued after January 1, 2016 and was adopted on a prospective basis. Adoption of this standard did not have a material impact on our financial position and results of operations. Balance Sheet Classification of Deferred Taxes (ASC 740) - In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which requires all deferred assets and liabilities along with any related valuation allowance to be classified as noncurrent on the balance sheet for our annual financial statements beginning January 1, 2017 and for our interim financial statements beginning January 1, 2018; however, early adoption is permitted. We adopted this standard in the first quarter of 2016 on a retrospective basis and adjusted the December 31, 2015 balance sheet by eliminating the current deferred income taxes asset and decreasing the noncurrent deferred income taxes liability by $831,000. Recent Accounting Standards Yet to be Adopted Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. On July 9, 2015, the FASB affirmed its proposal to defer the implementation of this standard by one year. For public entities, this standard is effective for 2018 interim and annual financial statements. We are assessing the impact this standard may have on our financial position and results of operations. Inventory (ASC 330) - In July 2015, the FASB issued ASU 2015-11, Inventory. Under this guidance, inventories are required to be measured at the lower of cost or net realizable value. Net realizable value represents the estimated selling price less costs associated with completion, disposal and transportation. ASU 2015-11 will be effective for our interim and annual financial statements issued beginning January 1, 2017; however, early adoption is permitted. The standard is to be adopted on a prospective basis. We are assessing the impact this standard may have on our financial position and results of operations. 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. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are evaluating the effect of this update on our financial position and results of operations. Compensation (ASC 718) - In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which simplifies several aspects of accounting for employee share-based payment transactions, including accounting for income taxes, forfeitures, and statutory tax withholding requirements, and classification in the statement of cash flows. ASU 2016-09 will be effective for our annual and interim financial statements beginning January 1, 2017, although early adoption is permitted. The amendments included in this update are to be applied prospectively except for changes impacting the presentation of the cash flow statement that can be applied prospectively or retrospectively. We are evaluating the effect of this update on our financial position and results of operations.

Calculation of Earnings Per Share

6 Months Ended

Jun. 30, 2016

Earnings Per Share [Abstract]

Calculation of Earnings Per Share



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	8,029	$	6,294	$	28,396	$	27,403
Weighted average shares outstanding	15,315,020		15,235,860		15,300,931		14,922,094
Basic Earnings Per Share	$	0.52	$	0.41	$	1.86	$	1.84

Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	8,029	$	6,294	28,396		27,403
Reconciliation of Denominator:
Weighted shares outstanding—Basic	15,315,020		15,235,860		15,300,931		14,922,094
Effect of dilutive securities:
Share-based compensation	37,682		44,797		41,356		48,096
Adjusted denominator—Diluted	15,352,702		15,280,657		15,342,287		14,970,190
Diluted Earnings Per Share	$	0.52	$	0.41	$	1.85	$	1.83

Acquisitions

6 Months Ended

Jun. 30, 2016

Business Combinations [Abstract]

Acquisitions

Gatherco Merger

On April 1, 2015, we completed the merger in which Gatherco merged with and into Aspire Energy, our then newly formed, wholly-owned subsidiary. Aspire Energy is an unregulated natural gas infrastructure company with approximately 2,500 miles of pipeline systems in 40 counties throughout Ohio. The majority of Aspire Energy’s margin is derived from long-term supply agreements with Columbia Gas of Ohio and Consumers Gas Cooperative, which together serve more than 20,000 end-use customers. Aspire Energy sources gas primarily from 300 conventional producers. Aspire Energy also provides gathering and processing services necessary to maintain quality and reliability to its wholesale markets.

At closing, we issued 592,970 shares of our common stock, valued at $30.2 million, based on the closing price of our common stock as reported on the NYSE on April 1, 2015. In addition, we paid $27.5 million in cash and assumed $1.7 million of existing outstanding debt, which we paid off on the same date. We also acquired $6.8 million of cash on hand at closing.



(in thousands)	Net Purchase Price
Chesapeake Utilities common stock	$	30,164
Cash	27,494
Acquired debt	1,696
Aggregate amount paid in the acquisition	59,354
Less: cash acquired	(6,806		)
Net amount paid in the acquisition	$	52,548

The merger agreement provided for additional contingent cash consideration to Gatherco's shareholders of up to $15.0 million based on a percentage of revenue generated from potential new gathering opportunities during the five-year period following the closing. As of June 30, 2016, there have been no related gathering opportunities developed; therefore, no contingent consideration liability has been recorded. Based on the absence of related gathering opportunities being developed as of June 30, 2016, we are unable to estimate the range of undiscounted contingent liability outcomes at this time.

We incurred $1.3 million in transaction costs associated with this merger, $786,000 of which we incurred in 2014, and the remaining $514,000 we incurred during 2015. Transaction costs were included in operations expense in the accompanying condensed consolidated statements of income. The revenue and net income from this merger for the three months ended June 30, 2016, included in our condensed consolidated statements of income, were $4.8 million and $28,000, respectively. The revenue and net income from this merger for the six months ended June 30, 2016, included in our condensed consolidated statements of income, were $12.8 million and $1.7 million, respectively. This merger was accretive to earnings per share in the first full year of operations, generating $0.03 in additional earnings per share.

The purchase price allocation of the Gatherco merger was as follows:



	Purchase price
(in thousands)	Allocation
Purchase price	$	57,658

Property plant and equipment	53,203
Cash	6,806
Accounts receivable	3,629
Income taxes receivable	3,163
Other assets	425
Total assets acquired	67,226

Long-term debt	1,696
Deferred income taxes	13,409
Accounts payable	3,837
Other current liabilities	745
Total liabilities assumed	19,687
Net identifiable assets acquired	47,539
Goodwill	$	10,119

The excess of the purchase price over the estimated fair values of the assets acquired and the liabilities assumed was recognized as goodwill at the merger date. The goodwill reflects the value paid primarily for opportunities for growth in a new, strategic geographic area. All of the goodwill from this merger was recorded in the Unregulated Energy segment and is not expected to be deductible for income tax purposes.

In December 2015 and during the first quarter of 2016, we adjusted the allocation of the purchase price based on additional information available. The adjustments resulted in a change in the fair value of property, plant and equipment, deferred income tax liabilities, inventory, income taxes receivable and other current liabilities. Goodwill from the merger decreased from $11.1 million to $10.1 million after incorporating these adjustments. The allocation of the purchase price and valuation of assets are final. The valuation of additional contingent cash consideration may be adjusted as additional information becomes available.

- Definition

The entire disclosure for a business combination (or series of individually immaterial business combinations) completed during the period, including background, timing, and recognized assets and liabilities. The disclosure may include leverage buyout transactions (as applicable).

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1497-128463

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1490-128463

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1392-128463

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7008-128479

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1486-128463

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6927-128479

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56956791&loc=d3e4845-128472

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 6
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1500-128463

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 7
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1524-128463

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e7000-128479

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56956791&loc=d3e4922-128472

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=56956791&loc=d3e4934-128472

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 20
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=56956791&loc=d3e4926-128472

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56956515&loc=d3e1383-128463

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 805
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35744584&loc=d3e6996-128479

+ Details

Rates and Other Regulatory Activities	6 Months Ended
Rates and Other Regulatory Activities	Jun. 30, 2016
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 by the Florida PSC as separate entities. Delaware Rate Case Filing: On December 21, 2015, our Delaware division filed an application with the Delaware PSC for a base rate increase and certain other changes to its tariff. We proposed an increase of approximately $4.7 million, or nearly ten percent, in our revenue requirement based on the test period ending March 31, 2016. We also proposed new service offerings to promote growth and a revenue normalization mechanism for residential and small commercial customers. We expect a decision on the application during the first quarter of 2017. Pending the decision, our Delaware division increased rates on an interim basis based on the $2.5 million annualized interim rates approved by the Delaware PSC, effective February 19, 2016. We recognized incremental revenue of approximately $555,000 ($332,000 net of tax) and $878,000 ($526,000 net of tax) for the three and six months ended June 30, 2016, respectively. In addition, our Delaware division requested and received approval on July 26, 2016 from the Delaware PSC to implement revised interim rates of $4.7 million annualized for usage on and after August 1, 2016. Revenue collected prior to a final Delaware PSC decision is subject to refund. Although the final decision is expected during the first quarter of 2017, we cannot predict the revenue requirement the Delaware PSC will ultimately authorize or forecast the timing of a final decision. These rates, which are subject to refund, represent a five percent increase over current rates. Maryland Sandpiper Rate Case Filing: On December 1, 2015, Sandpiper filed an application with the Maryland PSC for a base rate increase and certain other changes to its tariff. We proposed an increase of $950,000, or approximately five percent, in our revenue requirement, based on the test period ended December 31, 2015. We also proposed a stratification of rate classes, based on cost of service, and a revenue normalization mechanism for residential and small commercial customers. The procedural schedule was suspended in early May 2016 to allow for the continuation of settlement discussions between Sandpiper, Maryland PSC Staff and Maryland Office of People's Counsel. We expect a decision on the application during the third quarter of 2016. Florida On September 1, 2015, FPU’s electric division filed to recover the cost of the proposed Florida Power & Light Company interconnect project through FPU's annual Fuel and Purchased Power Cost Recovery Clause filing. The interconnect project will enable FPU's electric division to negotiate a new power purchase agreement that will mitigate fuel costs for its Northeast division. This action was approved by the Florida PSC at its Agenda Conference held on December 3, 2015. On January 22, 2016, the Office of Public Counsel filed an appeal of the Florida PSC's decision with the Florida Supreme Court. Legal briefs have been filed, but no decision has been reached at this time. On February 2, 2016, FPU’s natural gas division filed a petition with the Florida PSC for approval of an amendment to its existing transportation agreement with the City of Lake Worth, located in Palm Beach County, Florida. The amendment allows the city to resell natural gas distributed by FPU to the city’s compressed natural gas station. The city will then resell the natural gas, after compression, to its customers. The amendment to the transportation agreement was approved by the Florida PSC at its Agenda Conference held April 5, 2016. On April 11, 2016, FPU’s natural gas divisions and Chesapeake Utilities' Florida division filed a joint petition for approval to allow FPU and Chesapeake Utilities to expand the cost allocation of the intrastate and unreleased capacity-related components currently embedded in the purchased gas adjustment and operational balancing account, which is currently allocated to a limited number of customers. The proposed new allocation of these costs would include additional customers, primarily transportation customers, benefiting from these costs but not currently paying for them. We expect the petition to be approved by the Florida PSC in late 2016. Eastern Shore White Oak Mainline Expansion Project: On November 21, 2014, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate certain expansion facilities designed to provide 45,000 Dts/d of firm transportation service to an electric power generator in Kent County, Delaware. Eastern Shore proposes to construct approximately 7.2 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and 3,550 horsepower of additional compression at Eastern Shore’s existing Delaware City compressor station in New Castle County, Delaware. On January 22, 2015, the FERC issued a notice of intent to prepare an environmental assessment for this project. In February, April and May 2015, Eastern Shore filed environmental data in response to comments regarding the evaluation of alternate routes for a segment of the pipeline route in the vicinity of the Historic District of Kemblesville, Pennsylvania. On June 2, 2015, a field meeting was conducted to review the proposed route and alternate routes. In response to comments received from the National Park Service and other stakeholders, the FERC requested that Eastern Shore conduct an additional investigation in relation to Eastern Shore's existing right-of-way. On July 9, 2015, the FERC issued a 30-day public scoping notice, in advance of issuing an environmental assessment, in order to solicit comments from the public regarding construction of the Kemblesville loop. On August 18, 2015, Eastern Shore submitted supplemental information to the FERC regarding the results of its investigation of the Kemblesville loop. On November 18, 2015, Eastern Shore filed an amendment to this application, which indicated the preferred pipeline route and shortened the total miles of the proposed pipeline to 5.4 miles. On February 10, 2016, the FERC issued a notice combining the White Oak Mainline Expansion Project and the System Reliability Project into a single environmental assessment. On March 2, 2016, the FERC issued a revised notice, rescheduling the issuance of the combined environmental assessment to April 25, 2016, with a 90-day authorization decision to be issued no later than July 24, 2016. On March 28, 2016, subsequent to the issuance of the schedule, the FERC issued another environmental data request concerning the United States Department of Agriculture and an agricultural conservation easement on a tract of land where the White Oak Mainline Project would install a portion of the pipeline in its existing right-of way. On April 4, 2016, Eastern Shore responded to the data request. Subsequently, Eastern Shore revised the construction workspace configuration to mutual agreement of both parties. On July 21, 2016, the FERC issued a certificate of public convenience and necessity authorizing Eastern Shore to construct and operate the proposed White Oak Mainline Project. The FERC denied Eastern Shore’s request for a pre-determination of rolled-in rate treatment and requires Eastern Shore to comply with 19 environmental conditions. System Reliability Project: On May 22, 2015, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposes to reinforce critical points on its pipeline system. The total project will benefit all of Eastern Shore’s customers by modifying the pipeline system to respond to severe operational conditions experienced during actual winter peak days in 2014 and 2015. Since the project is intended to improve system reliability, Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project. On June 8, 2015, the FERC filed a notice of the application, and the comment period ended on June 29, 2015. Two interested parties filed comments and protests with the FERC. Eastern Shore has filed answers to the comments and protests from the two parties. On September 4, 2015, the FERC issued a notice of intent to prepare an environmental assessment, and Eastern Shore responded to the FERC Staff's environmental data requests. On February 10, 2016, the FERC issued a notice combining the System Reliability Project and White Oak Mainline Expansion project into a single environmental assessment. On March 2, 2016, the FERC issued a revised notice rescheduling the issuance of the combined environmental assessment to April 25, 2016, with the 90-day authorization decision to be issued no later than July 24, 2016. On July 21, 2016, the FERC issued a certificate of public convenience and necessity authorizing Eastern Shore to construct and operate the proposed System Reliability Project. The FERC granted Eastern Shore’s request for a pre-determination of rolled-in rate treatment in its next rate base proceeding and requires Eastern Shore to comply with 19 environmental conditions. TETLP Capacity Expansion Project: On October 13, 2015, Eastern Shore submitted an application to the FERC to make certain measurement and related improvements at its TETLP interconnect facilities, which would enable Eastern Shore to increase natural gas receipts from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. On December 22, 2015, the FERC authorized Eastern Shore to proceed with the project. On March 11, 2016, the capacity expansion project was placed into service. 2017 Expansion Project: On May 12, 2016, Eastern Shore submitted a request to the FERC to initiate the FERC’s pre-filing review procedures for Eastern Shore's 2017 expansion project. The expansion project consists of approximately 33 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional 3,550 horsepower 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. The expansion project is necessary to provide up to 86,437 Dts/d of additional firm natural gas transportation capacity to meet anticipated market demand. On May 17, 2016, the FERC approved Eastern Shore’s request to commence the pre-filing review process. Eastern Shore is currently working through the pre-filing process and anticipates filing a certificate of public convenience and necessity seeking authorization to construct the project in November 2016. 2017 Rate Case Filing In January 2017, Eastern Shore intends to file a base rate proceeding with the FERC as required by the terms of its 2012 settlement agreement.

Environmental Commitments and Contingencies	6 Months Ended
Environmental Commitments and Contingencies	Jun. 30, 2016
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, 2016, we had approximately $9.9 million in environmental liabilities, representing our estimate of the future costs associated with all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites. FPU has approval to recover, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to all of its MGP sites, approximately $10.3 million of which has been recovered as of June 30, 2016, leaving approximately $3.7 million in regulatory assets for future recovery of environmental costs from FPU’s customers. In addition to the FPU MGP sites, we had $314,000 in environmental liabilities at June 30, 2016 related to Chesapeake Utilities' MGP sites in Salisbury, Maryland and Winter Haven, Florida, representing our estimate of future costs associated with these sites. As of June 30, 2016, we had approximately $29,000 in regulatory and other assets for future recovery through Chesapeake Utilities' rates. During the first quarter of 2015, we established $273,000 in environmental liabilities related to Chesapeake Utilities' MGP site in Seaford, Delaware, representing our estimate of future costs associated with this site, and recorded a regulatory asset for the same amount for probable future recovery through Chesapeake Utilities' rates via our environmental rider. On February 23, 2016, the Delaware PSC approved an environmental surcharge for the recovery of Chesapeake Utilities' environmental expenses associated with the Seaford site for the period of October 1, 2014 through September 30, 2015. Chesapeake Utilities will file for recovery of its expenses incurred between October 1, 2015 and September 30, 2016 by October 31, 2016. As of June 30, 2016, we had approximately $177,000 in environmental liabilities and $268,000 in regulatory and other assets related to this site. Environmental liabilities for all of 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. West Palm Beach, Florida Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated a MGP. FPU is implementing a remedial plan approved by the FDEP for the east parcel of the West Palm Beach site, which includes installation of monitoring test wells, sparging of air into the groundwater system and extraction of vapors from the subsurface. The Start-Up and Monitoring Report, dated November 30, 2015, was submitted for review and comment. We received a letter dated January 6, 2016 from FDEP, which provided minor comments. On January 12, 2016, FDEP conducted a facility inspection and found no problems or deficiencies. We expect that similar remedial actions will ultimately be implemented for other portions of the site. Estimated costs of remediation for the West Palm Beach site range from approximately $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. We continue to expect that all costs related to these activities will be recoverable from customers through rates. Sanford, Florida FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of this former MGP site. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of June 30, 2016, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements. In December 2014, the EPA issued a preliminary close-out report, documenting the completion of all physical remedial construction activities at the Sanford site. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site. The total cost of the final remedy is estimated to be over $20.0 million, which includes long-term monitoring and the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU advised the other members of the Sanford Group that it is unwilling to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement. The Sanford Group has not requested that FPU contribute to costs beyond the originally agreed upon $650,000 contribution. As of June 30, 2016, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be $24,000. We are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense as to its limited liability for future costs exceeding $13.0 million to implement the final remedy for this site, as provided for in the Third Participation Agreement, or whether the other members of the Sanford Group will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid pursuant to the Third Participation Agreement. No such claims have been made as of June 30, 2016. Key West, Florida FPU formerly owned and operated a MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In 2010, after 17 years of regulatory inactivity, FDEP observed that some soil and groundwater standards were exceeded and requested implementation of additional soil and groundwater fieldwork. The scope of work is limited to the installation of two additional monitoring wells and periodic monitoring of the new and existing wells. The two additional monitoring wells were installed in November 2011, and groundwater monitoring began in December 2011. The first semi-annual report from the monitoring program was issued in May 2012. The data from the June 2012 and September 2012 monitoring events were submitted to the FDEP on October, 2012. FDEP responded on October 9, 2012 that, based on the data, NAM appears to be an appropriate remedy for the site. In October 2012, FDEP issued a RAP approval order, which requires a limited semi-annual NAM. The most recent groundwater-monitoring event was conducted in March 2016. Natural attenuation default criteria were met at all locations sampled and the semi-annual report was submitted on April 18, 2016. FDEP responded with an acceptance letter on April 22, 2016, concurring with FPU’s consultant’s recommendation that semi-annual monitoring should continue at this facility, with the next semi-annual NAM scheduled for the third quarter of 2016. Although the duration of the FDEP-required limited NAM cannot be determined with certainty, we anticipate that total costs to complete the remedial action will not exceed $50,000. The annual cost to conduct the limited NAM program is not expected to exceed $8,000. Pensacola, Florida FPU formerly owned and operated a MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the FDOT. In October 2009, FDEP informed Gulf Power that it would approve a conditional No Further Action determination for the site with the requirement for institutional and engineering controls. On June 16, 2014, FDEP issued a draft memorandum of understanding between FDOT and FDEP to implement site closure with approved institutional and engineering controls for the site. We anticipate that FPU’s share of remaining legal and cleanup costs will not exceed $5,000. Winter Haven, Florida The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a consent order entered into with FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. Groundwater monitoring results have shown a continuing reduction in contaminant concentrations from the sparging system, which has been in operation since 2002. On September 12, 2014, FDEP issued a letter approving shutdown of the sparging operations on the northern portion of the site, contingent upon continued semi-annual monitoring. Groundwater monitoring results on the southern portion of this site indicate that natural attenuation default criteria continue to be exceeded. Plans to modify the monitoring network on the southern portion of the site in order to collect additional data to support the development of a remedial plan were specified in a letter to FDEP, dated October 17, 2014. The well installation and abandonment program was implemented in October 2014, and documentation was reported in the next semi-annual RAP implementation status report, submitted on January 8, 2015. FDEP approved the plan to expand the bio-sparging operations in the southern portion of the site, and additional sparge points were installed and connected to the operating system in the first quarter of 2016. Although specific remedial actions for the site have not yet been identified, we estimate that future remediation costs for the subsurface soils and groundwater at the site should not exceed $425,000, which includes an estimate of $100,000 to implement additional actions, such as institutional controls, at the site. We continue to believe that the entire amount will be recoverable from customers through rates. FDEP previously indicated that we could also be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, and our recent meeting with FDEP, we believe that corrective measures for lake sediments are not warranted and will not be required by FDEP. Therefore, we have not recorded a liability for sediment remediation. Salisbury, Maryland We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized groundwater contamination. In February 2002, the MDE granted permission to permanently decommission the systems used for remediation and to discontinue all on-site and off-site well monitoring, except for one well, which is being maintained for periodic product monitoring and recovery. We anticipate that the remaining costs of the one remaining monitoring well will not exceed $5,000 annually. We cannot predict at this time when the MDE will grant permission to permanently decommission the one remaining monitoring well. Seaford, Delaware In a letter dated December 5, 2013, DNREC notified us that it would be conducting a facility evaluation of a former MGP site in Seaford, Delaware. In a report issued in January 2015, DNREC provided the evaluation, which found several compounds within the groundwater and soil that require further investigation. On September 17, 2015, DNREC approved our application to enter this site into the voluntary cleanup program. A remedial investigation was conducted in December 2015, and the resulting remedial investigation report was submitted to DNREC in May 2016. Based on findings from the remedial investigation, DNREC requested additional investigative work be performed prior to approval of potential remedial actions. We anticipate completing this additional investigative work by the end of 2016. We estimate the cost of potential remedial actions, based on the findings of the DNREC report, to be between $273,000 and $465,000. We also believe these costs will be recoverable from customers through rates. Cambridge, Maryland We are discussing with the MDE a former MGP site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, we have not recorded an environmental liability for this location. Ohio We have completed the investigation, assessment and remediation of eight natural gas pipeline facilities in Ohio that Aspire Energy acquired from Gatherco pursuant to the merger. Gatherco's indemnification obligations for environmental matters apply to remediation costs in excess of a $431,250 deductible and are capped at $1.7 million. Pursuant to the merger agreement, an escrow was established to fund certain claims by Chesapeake Utilities and Aspire Energy for indemnification by Gatherco, including environmental claims. The costs incurred to date associated with remediation activities for these eight facilities is approximately $1.6 million. We have recorded a receivable for the costs incurred, net of the deductible amount, and have submitted our request for reimbursement to the escrow agent. Negotiations are currently underway.

Other Commitments and Contingencies	6 Months Ended
Other Commitments and Contingencies	Jun. 30, 2016
Commitments and Contingencies Disclosure [Abstract]
Other Commitments and Contingencies	Other Commitments and Contingencies Natural Gas, Electric and Propane Supply Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. For our Delaware and Maryland natural gas distribution divisions, we have a contract with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage capacity, which expires on March 31, 2017. In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term, or until May 2019. Sandpiper's current annual commitment is estimated at approximately 6.5 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, or until May 2019. Sharp's current annual commitment is estimated at approximately 6.5 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 natural gas distribution 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. In May 2015, PESCO renewed contracts to purchase natural gas from various suppliers for a one-year term, expiring May 2016, with the total monthly purchase commitment ranging from 9,982 to 13,423 Dts/d. PESCO has renewed these contracts for an additional six-month term, expiring October 2016. FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times and (b) a fixed charge coverage ratio greater than 1.5 times. If FPU fails to comply with either of these ratios, it has 30 days to cure the default or, if the default is not cured, to provide an irrevocable letter of credit. 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 either of these ratios, 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, 2016, FPU was in compliance with all of the requirements of its fuel supply contracts. Corporate Guarantees The Board of Directors has authorized the Company to issue corporate guarantees and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit is $65.0 million. We have issued corporate guarantees to certain of our subsidiaries' vendors, the largest of which are for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event that Xeron or PESCO defaults. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at June 30, 2016 was approximately $53.6 million, with the guarantees expiring on various dates through June 2017. 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). We issued letters of credit totaling approximately $8.1 million related to the electric transmission services for FPU's northwest electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through March 2017. There have been no draws on these letters of credit as of June 30, 2016. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future. Tax-related Contingencies We are subject to various audits and reviews by the federal, state, local and other governmental authorities regarding income taxes and taxes other than income. As of June 30, 2016, we maintained a liability of approximately $50,000 related to unrecognized income tax benefits and approximately $72,000 related to contingencies for taxes other than income. As of December 31, 2015, we maintained a liability of approximately $50,000 related to unrecognized income tax benefits and approximately $310,000 related to contingencies for taxes other than income. 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

6 Months Ended

Jun. 30, 2016

Segment Reporting [Abstract]

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. The segments are evaluated based on their pre-tax operating income. Our operations comprise two reportable segments:


•	Regulated Energy. The Regulated Energy segment includes 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. The Unregulated Energy segment includes propane distribution and wholesale marketing operations, and natural gas marketing operations, which are unregulated as to their rates and services. Effective April 1, 2015, this segment includes Aspire Energy, whose services include natural gas gathering, processing, transportation and supply (See Note 3, Acquisitions, regarding the merger with Gatherco). 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,
	2016			2015			2016			2015
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	66,590		$	61,790		$	155,483		$	171,082
Unregulated Energy segment	35,752			30,892			93,155			91,681
Total operating revenues, unaffiliated customers	$	102,342		$	92,682		$	248,638		$	262,763
Intersegment Revenues ⁽¹⁾
Regulated Energy segment	$	805		$	270		$	1,128		$	560
Unregulated Energy segment	1,052			1,666			1,165			1,873
Other businesses	240			220			466			440
Total intersegment revenues	$	2,097		$	2,156		$	2,759		$	2,873
Operating Income
Regulated Energy segment	$	15,226		$	13,605		$	39,545		$	35,788
Unregulated Energy segment	412			(540		)	12,347			14,689
Other businesses and eliminations	104			105			230			201
Total operating income	15,742			13,170			52,122			50,678
Other Expense, net	(8		)	(171		)	(42		)	(38		)
Interest	2,624			2,485			5,274			4,933
Income before Income Taxes	13,110			10,514			46,806			45,707
Income taxes	5,081			4,220			18,410			18,304
Net Income	$	8,029		$	6,294		$	28,396		$	27,403


⁽¹⁾	All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.



(in thousands)	June 30, 2016		December 31, 2015
Identifiable Assets
Regulated Energy segment	$	892,513	$	872,065
Unregulated Energy segment	192,654		171,840
Other businesses and eliminations	11,880		23,516
Total identifiable assets	$	1,097,047	$	1,067,421

Our operations are entirely domestic.

- Definition

The entire disclosure for reporting segments including data and tables. Reportable segments include those that meet any of the following quantitative thresholds a) it's reported revenue, including sales to external customers and intersegment sales or transfers is 10 percent or more of the combined revenue, internal and external, of all operating segments b) the absolute amount of its reported profit or loss is 10 percent or more of the greater, in absolute amount of 1) the combined reported profit of all operating segments that did not report a loss or 2) the combined reported loss of all operating segments that did report a loss c) its assets are 10 percent or more of the combined assets of all operating segments.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 34
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8981-108599

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 41
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e9038-108599

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 33
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8971-108599

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8595-108599

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8380-108599

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 32
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8933-108599

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 26
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8844-108599

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 35
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8984-108599

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 40
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e9031-108599

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 42
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e9054-108599

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 10
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8538-108599

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 29
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8864-108599

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 31
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8924-108599

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 280
-SubTopic 10
-Section 50
-Paragraph 30
-URI http://asc.fasb.org/extlink&oid=51669610&loc=d3e8906-108599

+ Details

Accumulated Other Comprehensive Income (Loss)

6 Months Ended

Jun. 30, 2016

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

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 comprehensive income (loss). The following tables present the changes in the balance of accumulated other comprehensive loss for the six months ended June 30, 2016 and 2015. All amounts are presented net of tax.



	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2015	$	(5,580	)	$	(260	)	$	(5,840	)
Other comprehensive gain before reclassifications	—			525			525
Amounts reclassified from accumulated other comprehensive loss	176			(29		)	147
Net current-period other comprehensive income	176			496			672
As of June 30, 2016	$	(5,404	)	$	236		$	(5,168	)



	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2014	$	(5,643	)	$	(33	)	$	(5,676	)
Other comprehensive loss before reclassifications	—			(1		)	(1		)
Amounts reclassified from accumulated other comprehensive loss	165			33			198
Net prior-period other comprehensive income	165			32			197
As of June 30, 2015	$	(5,478	)	$	(1	)	$	(5,479	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and six months ended June 30, 2016 and 2015. 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,
	2016			2015			2016			2015
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost ⁽¹⁾	$	20		$	17		$	40		$	34
Net loss ⁽¹⁾	(166		)	(155		)	(333		)	(310		)
Total before income taxes	(146		)	(138		)	(293		)	(276		)
Income tax benefit	58			55			117			111
Net of tax	$	(88	)	$	(83	)	$	(176	)	$	(165	)

Gains and losses on commodity contracts cash flow hedges
Propane swap agreements ⁽²⁾	$	—		$	(10	)	$	(322	)	$	2
Call options ⁽²⁾	—			—			—			(55		)
Natural gas futures ⁽²⁾	211			—			359			—
Total before income taxes	211			(10		)	37			(53		)
Income tax benefit (expense)	(81		)	4			(8		)	21
Net of tax	130			(6		)	29			(32		)
Total reclassifications for the period	$	42		$	(89	)	$	(147	)	$	(197	)

⁽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 and call options are included in cost of sales in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.

- Definition

The entire disclosure for comprehensive income, which includes, but is not limited to, 1) the amount of income tax expense or benefit allocated to each component of other comprehensive income, including reclassification adjustments, 2) the reclassification adjustments for each classification of other comprehensive income and 3) the ending accumulated balances for each component of comprehensive income.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 15
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e689-108580

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=36458714&loc=SL7669619-108580

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e640-108580

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 17
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e716-108580

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 16
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e709-108580

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 505
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.3-04)
-URI http://asc.fasb.org/extlink&oid=27012166&loc=d3e187085-122770

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 11
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e637-108580

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 220
-SubTopic 10
-Section 45
-Paragraph 14
-URI http://asc.fasb.org/extlink&oid=36458714&loc=d3e681-108580

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Reclassification Adjustments
-URI http://asc.fasb.org/extlink&oid=6522872

+ Details

Employee Benefit Plans

6 Months Ended

Jun. 30, 2016

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three and six months ended June 30, 2016 and 2015 are set forth in the following table:



	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended June 30,	2016			2015			2016			2015			2016		2015		2016			2015			2016		2015
(in thousands)
Interest cost	$	105		$	102		$	630		$	626		$	23	$	23	$	11		$	11		$	14	$	15
Expected return on plan assets	(131		)	(135		)	(701		)	(777		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			—		2		(20		)	(19		)	—		—
Amortization of net loss	103			91			128			114			22		25		17			17			—		2
Net periodic cost (benefit)	77			58			57			(37		)	45		50		8			9			14		17
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	77		$	58		$	248		$	154		$	45	$	50	$	8		$	9		$	16	$	19



	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Six Months Ended June 30,	2016			2015			2016			2015			2016		2015		2016			2015			2016		2015
(in thousands)
Interest cost	$	210		$	204		$	1,259		$	1,251		$	46	$	46	$	21		$	22		$	28	$	30
Expected return on plan assets	(261		)	(270		)	(1,402		)	(1,554		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			—		5		(40		)	(39		)	—		—
Amortization of net loss	206			181			257			227			44		50		34			35			—		3
Net periodic cost (benefit)	155			115			114			(76		)	90		101		15			18			28		33
Amortization of pre-merger regulatory asset	—			—			381			381			—		—		—			—			4		4
Total periodic cost	$	155		$	115		$	495		$	305		$	90	$	101	$	15		$	18		$	32	$	37

We expect to record pension and postretirement benefit costs of approximately $1.6 million for 2016. 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 $2.5 million and approximately $2.9 million at June 30, 2016 and December 31, 2015, respectively. The amortization included in pension expense is also being added to a net periodic loss of approximately $802,000, which will increase our total expected benefit costs to approximately $1.6 million.

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 table presents the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three and six months ended June 30, 2016 and 2015:



For the Three Months Ended June 30, 2016	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(20	)	$	—	$	(20	)
Net loss	103		128		22		17			—		270
Total recognized in net periodic benefit cost	$	103	$	128	$	22	$	(3	)	$	—	$	250
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	103	$	24	$	22	$	(3	)	$	—	$	146
Recognized from regulatory asset	—		104		—		—			—		104
Total	$	103	$	128	$	22	$	(3	)	$	—	$	250



For the Three Months Ended June 30, 2015	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	2	$	(19	)	$	—	$	(17	)
Net loss	91		114		25		17			2		249
Total recognized in net periodic benefit cost	$	91	$	114	$	27	$	(2	)	$	2	$	232
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	91	$	22	$	27	$	(2	)	$	—	$	138
Recognized from regulatory asset	—		92		—		—			2		94
Total	$	91	$	114	$	27	$	(2	)	$	2	$	232



For the Six Months Ended June 30, 2016	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(40	)	$	—	$	(40	)
Net loss	206		257		44		34			—		$	541
Total recognized in net periodic benefit cost	$	206	$	257	$	44	$	(6	)	$	—	$	501
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	206	$	49	$	44	$	(6	)	$	—	$	293
Recognized from regulatory asset	—		208		—		—			—		208
Total	$	206	$	257	$	44	$	(6	)	$	—	$	501



For the Six Months Ended June 30, 2015	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	5	$	(39	)	$	—	$	(34	)
Net loss	181		227		50		35			3		496
Total recognized in net periodic benefit cost	$	181	$	227	$	55	$	(4	)	$	3	$	462
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	181	$	43	$	55	$	(4	)	$	1	$	276
Recognized from regulatory asset	—		184		—		—			2		186
Total	$	181	$	227	$	55	$	(4	)	$	3	$	462


⁽¹⁾	See Note 8, Accumulated Other Comprehensive Loss.

During the three and six months ended June 30, 2016, we contributed approximately $170,000 and $274,000, respectively, to the Chesapeake Pension Plan and approximately $548,000 and approximately $885,000, respectively, to the FPU Pension Plan. We expect to contribute a total of approximately $508,000 and approximately $1.6 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2016, which represent 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, 2016, were approximately $38,000 and approximately $76,000, respectively. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake Pension SERP in 2016. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three and six months ended June 30, 2016, were approximately $15,000 and approximately $36,000, respectively. We estimate that approximately $82,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2016. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and six months ended June 30, 2016, were approximately $27,000 and approximately $67,000, respectively. We estimate that approximately $149,000 will be paid for such benefits under the FPU Medical Plan in 2016.

Investments

6 Months Ended

Jun. 30, 2016

Investments, Debt and Equity Securities [Abstract]

Investments

The investment balances at June 30, 2016 and December 31, 2015, consisted of the following:




(in thousands)	June 30, 2016		December 31, 2015
Rabbi trust (associated with the Deferred Compensation Plan)	$	4,304	$	3,626
Investments in equity securities	21		18
Total	$	4,325	$	3,644

We classify these investments as trading securities and report them at their fair value. For the three months ended June 30, 2016 and 2015, we recorded a net unrealized gain of approximately $71,000 and approximately $4,000, respectively, in other income in the condensed consolidated statements of income related to these investments. For the six months ended June 30, 2016 and 2015, we recorded an unrealized gain of approximately $53,000 and approximately $107,000, respectively, in other income 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 condensed consolidated balance sheets and is adjusted each month for the gains and losses incurred by the investments in the Rabbi Trust.

- Definition

The entire disclosure for investments in certain debt and equity securities.

+ References + Details

Share-Based Compensation

6 Months Ended

Jun. 30, 2016

Disclosure of Compensation Related Costs, Share-based Payments [Abstract]

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, 2016 and 2015:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
(in thousands)
Awards to non-employee directors	$	145		$	160		$	310		$	311
Awards to key employees	470			250			954			636
Total compensation expense	615			410			1,264			947
Less: tax benefit	(248		)	(165		)	(509		)	(381		)
Share-based compensation amounts included in net income	$	367		$	245		$	755		$	566

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 service period of one year. In May 2016, each of our non-employee directors received an annual retainer of 953 shares of common stock under the SICP for service as a director through the 2017 Annual Meeting of Stockholders.

A summary of the stock activity for our non-employee directors during the six months ended June 30, 2016 is presented below:



	Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2015	—		$	—
Granted	8,577		$	62.90
Vested	(8,577	)	$	62.90
Outstanding— June 30, 2016	—		$	—

At June 30, 2016, there was approximately $450,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service period ending April 30, 2017.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the six months ended June 30, 2016:



	Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2015	110,398		$	38.34
Granted	46,571		$	67.90
Vested	(39,553	)	$	31.79
Expired	(2,325	)	$	42.25
Outstanding— June 30, 2016	115,091		$	51.85

In February 2016, our Board of Directors granted awards of 46,571 shares of common stock to key employees under the SICP. The shares granted in February 2016 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2018. All of these stock awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprise both 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.

At June 30, 2016, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $7.6 million. At June 30, 2016, there was approximately $3.2 million of unrecognized compensation cost related to these awards, which is expected to be recognized from 2016 through 2018.

Derivative Instruments

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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 their 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, 2016, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Hedging Activities in 2016

In June 2016, Sharp entered into a swap agreement to mitigate the risk of fluctuations in wholesale propane index prices associated with 630,000 gallons expected to be purchased for the upcoming heating season. Under the swap agreement, Sharp will receive the difference between the index prices (Mont Belvieu prices in December 2016 through February 2017) and the swap price of $0.5525 per gallon, to the extent the index prices exceed the swap price. If the index prices are lower than the swap price, Sharp will pay the difference. The swap agreement essentially fixes the price of the 630,000 gallons that we expect to purchase for the upcoming heating season. We accounted for the swap agreement as a cash flow hedge, and there is no ineffective portion of this hedge. At June 30, 2016, the swap agreement had a fair value of approximately $23,000. The change in the fair value of the swap agreement is recorded as unrealized gain/loss in other comprehensive income (loss).

In January 2016, PESCO entered into a SCO supplier agreement with Columbia Gas to provide natural gas supply for Columbia Gas to service one of its local distribution customer tranches. PESCO also assumed the obligation to store natural gas inventory to satisfy its obligations under the SCO supplier agreement, which terminates on March 31, 2017.

In conjunction with the SCO supplier agreement, PESCO entered into natural gas futures contracts during the second quarter of 2016 in order to protect its natural gas inventory against market price fluctuations. The contracts expire within one year. We have accounted for these contracts as fair value hedges, and any ineffective portion is reported directly in earnings. We believe these contracts are highly effective at hedging inventory. At June 30, 2016, PESCO had a total of 1,065,000 Dts/d hedged under natural gas futures contracts, with a liability fair value of approximately $233,000. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in earnings and is offset by any associated gain (loss) in the value of the inventory being hedged.

Beginning in October 2015, PESCO entered into natural gas futures contracts associated with the purchase and sale of natural gas to other specific customers. These contracts expire within two years, and we have accounted for them as cash flow hedges. There is no ineffective portion of these hedges. At June 30, 2016, PESCO had a total of 6,090,000 Dts/d hedged under natural gas futures contracts, with an asset fair value of approximately $357,000. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss).

Fair Value Hedges

The impact of our natural gas futures commodity contracts designated as fair value hedges and the related hedged item on our condensed consolidated income statement for the three and six months ended June 30, 2016 is presented below:



	Three Months Ended			Six Months Ended
(in thousands)	June 30, 2016⁽¹⁾			June 30, 2016⁽¹⁾
Commodity contracts	$	(233	)	$	(233	)
Fair value adjustment for natural gas inventory designated as the hedged item	681			681
Total increase in purchased gas cost	$	448		$	448

The increase in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	(83	)	$	(83	)
Timing ineffectiveness	531			531
Total ineffectiveness	$	448		$	448


⁽¹⁾	There were no natural gas futures commodity contracts designated as fair value hedges in 2015.

Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedging instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on purchased gas cost. To the extent that our natural gas inventory does not qualify as a hedged item in a fair-value hedge, or has not been designated as such, the natural gas inventory is valued at the lower of cost or market.

Hedging Activities in 2015

In March, May and June 2015, Sharp paid a total of approximately $143,000 to purchase put options to protect against a decline in propane prices and related potential inventory losses associated with 2.5 million gallons for the propane price cap program in the 2015-2016 heating season. We exercised the put options as propane prices fell below the strike prices of $0.4950, $0.4888 and $0.4500 per gallon in December 2015 through February 2016 and $0.4200 per gallon in January through March 2016. We received approximately $239,000, which represents the difference between the market prices and the strike prices during those months. We accounted for the put options as fair value hedges.

In March, May and June 2015, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 2.5 million gallons purchased in December 2015 through March 2016. Under these swap agreements, Sharp would have received the difference between the index prices (Mont Belvieu prices in December 2015 through March 2016) and the swap prices, which ranged from $0.5200 to $0.5950 per gallon, for each swap agreement, to the extent the index prices exceeded the swap prices. If the index prices were lower than the swap prices, Sharp would pay the difference. These swap agreements essentially fixed the price of the 2.5 million gallons that we purchased during this period. We accounted for the swap agreements as cash flow hedges. Sharp paid approximately $484,000, which represents the difference between the index prices and swap prices during those months of the swap agreements.

Commodity Contracts for Trading Activities

Xeron engages in trading activities using forward and futures contracts for propane and crude oil. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under this method, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statements of income for the period of change. As of June 30, 2016, we had the following outstanding propane and crude oil trading contracts, which we accounted for as derivatives:



	Quantity in	Estimated Market		Weighted Average
At June 30, 2016	Gallons	Prices		Contract Prices
Forward Contracts - Propane
Purchase	421,000	$	0.5375	$	0.5388

	Quantity in	Estimated Market		Weighted Average
At June 30, 2016	Barrels	Prices		Contract Prices
Futures Contracts - Crude Oil
Purchase	20,000	$	48.3300	$	47.9000

Estimated market prices and weighted average contract prices are in dollars per gallon and barrel. All contracts expire by the end of the third quarter of 2016.

Xeron entered into master netting agreements with two counterparties to mitigate exposure to counterparty credit risk. The master netting agreements enable Xeron to net these two counterparties' outstanding accounts receivable and payable, which are presented on a gross basis in the accompanying condensed consolidated balance sheets. At June 30, 2016, Xeron had no accounts receivable or accounts payable balances to offset with these two counterparties. At December 31, 2015, Xeron had a right to offset $431,000 of accounts payable with these two counterparties. At December 31, 2015, Xeron did not have outstanding accounts receivable with these two counterparties.

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, 2016 and December 31, 2015, are as follows:



	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2016		December 31, 2015
Derivatives not designated as hedging instruments
Forward & Future contracts	Mark-to-market energy assets	$	25	$	1
Derivatives designated as fair value hedges
Put options	Mark-to-market energy assets	—		152
Derivatives designated as cash flow hedges
Natural gas futures contracts	Mark-to-market energy assets	357		—
Propane swap agreements	Mark-to-market energy assets	23		—
Total asset derivatives		$	405	$	153



	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2016		December 31, 2015
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	23	$	1
Derivatives designated as fair value hedges
Natural gas futures contracts	Mark-to-market energy liabilities	233		—
Derivatives designated as cash flow hedges
Propane swap agreements	Mark-to-market energy liabilities	—		323
Natural gas futures contracts	Mark-to-market energy liabilities	—		109
Total liability derivatives		$	256	$	433

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	2016			2015			2016			2015
Derivatives not designated as hedging instruments
Realized gain on forward contracts ⁽¹⁾	Revenue	$	88		$	(71	)	275			206
Unrealized gain (loss) on forward contracts ⁽¹⁾	Revenue	1			203			2			78
Propane swap agreements	Cost of sales	—			—			—			18
Derivatives designated as fair value hedges
Put /Call options	Cost of sales	—			—			73			506
Put /Call options ⁽²⁾	Propane Inventory	—			(30		)				(34		)
Natural gas futures contracts	Natural Gas Inventory	(233		)	—			(233		)	—
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	—			—			(364		)	—
Propane swap agreements	Other Comprehensive Gain (Loss)	23			10			23			(2		)
Call options	Cost of sales	—			—			—			(81		)
Natural gas futures contracts	Cost of sales	211			—			359			—
Natural gas futures contracts	Other Comprehensive Gain	786			—			472			—
Total		$	876		$	112		$	607		$	691


⁽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.

- Definition

The entire disclosure for derivative instruments and hedging activities including, but not limited to, risk management strategies, non-hedging derivative instruments, assets, liabilities, revenue and expenses, and methodologies and assumptions used in determining the amounts.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 45
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6441202&loc=d3e80720-113993

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624171-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41620-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624163-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5579240-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4D
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624177-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80784-113994

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41641-113959

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5579245-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4H
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624258-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 30
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=35736893&loc=d3e80748-113994

Reference 12: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4K
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5708775-113959

Reference 13: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4J
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5708773-113959

Reference 14: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4A
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5618551-113959

Reference 15: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5580258-113959

Reference 16: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4E
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624181-113959

Reference 17: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 18: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41638-113959

Reference 19: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

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, 2016 and December 31, 2015:



			Fair Value Measurements Using:
As of June 30, 2016	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	$	475	$	—	$	—	$	475
Investments—mutual funds and other	$	3,829	$	3,829	$	—	$	—
Mark-to-market energy assets, incl. put options and swap agreements	$	405	$	—	$	405	$	—
Liabilities:
Mark-to-market energy liabilities incl. swap agreements	$	256	$	—	$	256	$	—



			Fair Value Measurements Using:
As of December 31, 2015	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	$	18	$	18	$	—	$	—
Investments—guaranteed income fund	$	279	$	—	$	—	$	279
Investments—mutual funds and other	$	3,347	$	3,347	$	—	$	—
Mark-to-market energy assets, incl. put/call options	$	153	$	—	$	153	$	—
Liabilities:
Mark-to-market energy liabilities, incl. swap agreements	$	433	$	—	$	433	$	—

The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of June 30, 2016 and December 31, 2015:

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:

Mark-to-market energy assets and liabilities — These forward contracts are valued using market transactions in either the listed or OTC markets.

Propane put/call options, swap agreements and natural gas futures contracts – 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, 2016 and 2015:



	Six Months Ended June 30,
	2016			2015
(in thousands)
Beginning Balance	$	279		$	287
Purchases and adjustments	112			49
Transfers	88			(3		)
Distribution	(8		)	—
Investment income	4			2
Ending Balance	$	475		$	335

Investment income from the Level 3 investments is reflected in other income (expense) in the accompanying condensed consolidated statements of income.

At June 30, 2016, 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, 2016, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of approximately $151.8 million. This compares to a fair value of approximately $174.3 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, 2015, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of approximately $153.7 million, compared to the estimated fair value of approximately $165.1 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

- Definition

The entire disclosure for the fair value of financial instruments (as defined), including financial assets and financial liabilities (collectively, as defined), and the measurements of those instruments as well as disclosures related to the fair value of non-financial assets and liabilities. Such disclosures about the financial instruments, assets, and liabilities would include: (1) the fair value of the required items together with their carrying amounts (as appropriate); (2) for items for which it is not practicable to estimate fair value, disclosure would include: (a) information pertinent to estimating fair value (including, carrying amount, effective interest rate, and maturity, and (b) the reasons why it is not practicable to estimate fair value; (3) significant concentrations of credit risk including: (a) information about the activity, region, or economic characteristics identifying a concentration, (b) the maximum amount of loss the entity is exposed to based on the gross fair value of the related item, (c) policy for requiring collateral or other security and information as to accessing such collateral or security, and (d) the nature and brief description of such collateral or security; (4) quantitative information about market risks and how such risks are managed; (5) for items measured on both a recurring and nonrecurring basis information regarding the inputs used to develop the fair value measurement; and (6) for items presented in the financial statement for which fair value measurement is elected: (a) information necessary to understand the reasons for the election, (b) discussion of the effect of fair value changes on earnings, (c) a description of [similar groups] items for which the election is made and the relation thereof to the balance sheet, the aggregate carrying value of items included in the balance sheet that are not eligible for the election; (7) all other required (as defined) and desired information.

+ References + Details

Long-Term Debt

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Long-Term Debt

Our outstanding long-term debt is shown below:



	June 30,			December 31,
(in thousands)	2016			2015
FPU secured first mortgage bonds ⁽¹⁾:
9.08% bond, due June 1, 2022	$	7,976		$	7,973
Uncollateralized senior notes:
6.64% note, due October 31, 2017	5,455			5,455
5.50% note, due October 12, 2020	10,000			10,000
5.93% note, due October 31, 2023	22,500			24,000
5.68% note, due June 30, 2026	29,000			29,000
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
Promissory notes	168			238
Capital lease obligation	4,153			4,824
Total long-term debt	156,252			158,490
Less: current maturities	(12,075		)	(9,151		)
Less: debt issuance costs	(312		)	(333		)
Total long-term debt, net of current maturities	$	143,865		$	149,006

⁽¹⁾ FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities.

Shelf Agreement

On October 8, 2015, we entered into a Shelf Agreement with Prudential. Under the terms of the Shelf Agreement, we may request that Prudential purchase, over the next three years, up to $150.0 million of our Shelf Notes at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance. Prudential is under no obligation to purchase any of the Shelf Notes. The interest rate and terms of payment of any series of Shelf Notes will be determined at the time of purchase. We currently anticipate the proceeds from the sale of any series of Shelf Notes will be used for general corporate purposes, including refinancing of short-term borrowing and/or repayment of outstanding indebtedness and financing capital expenditures on future projects; however, actual use of such proceeds will be determined at the time of a purchase, and each request for purchase with respect to a series of Shelf Notes will specify the exact use of the proceeds.

On May 13, 2016, we formally requested that Prudential purchase $70.0 million of 3.25 percent Shelf Notes under the Shelf Agreement. On May 20, 2016, Prudential formally accepted and confirmed our request. The closing of the sale and issuance of the Shelf Notes is expected to occur on or before April 28, 2017.

The Shelf Agreement sets forth certain business covenants to which we are subject when any Shelf Note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness or incur liens and encumbrances on any of our property or the property of our subsidiaries.

Short-Term Borrowing	6 Months Ended
Short-Term Borrowing	Jun. 30, 2016
Short-term Borrowing [Abstract]
Short-Term Borrowing	Short-Term Borrowing On October 8, 2015, we entered into the Credit Agreement with the Lenders for a $150.0 million Revolver for a term of five years, subject to the terms and conditions of the Credit Agreement. Borrowings under the Revolver will be used for general corporate purposes, including repayments of short-term borrowings, working capital requirements and capital expenditures. Borrowings under the Revolver will bear interest at: (i) the LIBOR Rate plus an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization, both as defined by the Credit Agreement, or (ii) the base rate plus 0.25 percent or less. Interest will be payable quarterly, and the Revolver is subject to a commitment fee on the unused portion of the facility. We may extend the expiration date for up to two years on any anniversary date of the Revolver, with such extension subject to the Lenders' approval. We may also request the Lenders to increase the Revolver to $200.0 million, with any increase at the sole discretion of each Lender. At June 30, 2016 and December 31, 2015, we had borrowed $40.0 million and $35.0 million, respectively, under the Revolver.

Summary of Accounting Policies (Policies)	6 Months Ended
Summary of Accounting Policies (Policies)	Jun. 30, 2016
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, 2015. 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. We reclassified certain amounts in the condensed consolidated balance sheet as of December 31, 2015. We have revised the condensed consolidated statement of cash flows for the six months ended June 30, 2015 to reflect only property, plant and equipment expenditures paid in cash within the Investing Activities section. The non-cash expenditures previously included in that section have now been included in the change in accounts payable and other accrued liabilities amount within the Operating Activities section. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.
FASB Statements and Other Authoritative Pronouncements	FASB Statements and Other Authoritative Pronouncements Recently Adopted Accounting Standards Interest - Imputation of Interest (ASC 835-30) - In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. This standard requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. ASU 2015-03 became effective for us on January 1, 2016, and we applied the provisions of this standard on a retrospective basis. As a result of the adoption of this standard, debt issuance costs totaling $312,000 and $333,000 at June 30, 2016 and December 31, 2015, respectively, previously presented as other deferred charges, a non-current asset, are now presented as a deduction from long-term debt, net of current maturities in our condensed consolidated balance sheets. Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (ASC 350-40) - In April 2015, the FASB issued ASU 2015-05, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement. Under the new standard, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense in the period incurred. ASU 2015-05 became effective for us on January 1, 2016, and has been applied on a prospective basis. The standard did not have a material impact on our financial position or results of operations for the quarter. Debt Issuance Costs (ASC 835-30) - In August 2015, the FASB issued ASU 2015-15, Simplifying the Presentation of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This standard clarifies treatment of debt issuance costs associated with line-of-credit arrangements that were not specifically addressed in ASU 2015-03. Issuance costs incurred in connection with line-of-credit arrangements may be treated as an asset and amortized over the term of the line-of-credit arrangement. ASU 2015-15 became effective for us on January 1, 2016. The standard did not have a material impact on our financial position and results of operations. Business Combinations (ASC 805) - In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. The standard eliminates the requirement to restate prior period financial statements for measurement period adjustments. The guidance requires that the cumulative impact of a measurement-period adjustment (including the impact of prior periods) be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 was effective for our interim and annual financial statements issued after January 1, 2016 and was adopted on a prospective basis. Adoption of this standard did not have a material impact on our financial position and results of operations. Balance Sheet Classification of Deferred Taxes (ASC 740) - In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which requires all deferred assets and liabilities along with any related valuation allowance to be classified as noncurrent on the balance sheet for our annual financial statements beginning January 1, 2017 and for our interim financial statements beginning January 1, 2018; however, early adoption is permitted. We adopted this standard in the first quarter of 2016 on a retrospective basis and adjusted the December 31, 2015 balance sheet by eliminating the current deferred income taxes asset and decreasing the noncurrent deferred income taxes liability by $831,000. Recent Accounting Standards Yet to be Adopted Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. On July 9, 2015, the FASB affirmed its proposal to defer the implementation of this standard by one year. For public entities, this standard is effective for 2018 interim and annual financial statements. We are assessing the impact this standard may have on our financial position and results of operations. Inventory (ASC 330) - In July 2015, the FASB issued ASU 2015-11, Inventory. Under this guidance, inventories are required to be measured at the lower of cost or net realizable value. Net realizable value represents the estimated selling price less costs associated with completion, disposal and transportation. ASU 2015-11 will be effective for our interim and annual financial statements issued beginning January 1, 2017; however, early adoption is permitted. The standard is to be adopted on a prospective basis. We are assessing the impact this standard may have on our financial position and results of operations. 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. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are evaluating the effect of this update on our financial position and results of operations. Compensation (ASC 718) - In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which simplifies several aspects of accounting for employee share-based payment transactions, including accounting for income taxes, forfeitures, and statutory tax withholding requirements, and classification in the statement of cash flows. ASU 2016-09 will be effective for our annual and interim financial statements beginning January 1, 2017, although early adoption is permitted. The amendments included in this update are to be applied prospectively except for changes impacting the presentation of the cash flow statement that can be applied prospectively or retrospectively. We are evaluating the effect of this update on our financial position and results of operations.

- Definition

The entire disclosure of changes in accounting principles, including adoption of new accounting pronouncements, that describes the new methods, amount and effects on financial statement line items.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6507316

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Direct Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6510796

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 3
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22583-107794

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Indirect Effects of a Change in Accounting Principle
-URI http://asc.fasb.org/extlink&oid=6515603

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22580-107794

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.10-01.(b)(6))
-URI http://asc.fasb.org/extlink&oid=27015980&loc=d3e46468-122699

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Accounting Change
-URI http://asc.fasb.org/extlink&oid=6503790

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 250
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56949863&loc=d3e22499-107794

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Glossary Retrospective Application
-URI http://asc.fasb.org/extlink&oid=6523989

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 13
-URI http://asc.fasb.org/extlink&oid=51655806&loc=d3e765-108305

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 270
-SubTopic 10
-Section 45
-Paragraph 12
-URI http://asc.fasb.org/extlink&oid=51655806&loc=d3e725-108305

+ Details

Calculation of Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2016

Earnings Per Share [Abstract]

Calculation of Basic and Diluted Earnings Per Share



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2016		2015		2016		2015
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	8,029	$	6,294	$	28,396	$	27,403
Weighted average shares outstanding	15,315,020		15,235,860		15,300,931		14,922,094
Basic Earnings Per Share	$	0.52	$	0.41	$	1.86	$	1.84

Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	8,029	$	6,294	28,396		27,403
Reconciliation of Denominator:
Weighted shares outstanding—Basic	15,315,020		15,235,860		15,300,931		14,922,094
Effect of dilutive securities:
Share-based compensation	37,682		44,797		41,356		48,096
Adjusted denominator—Diluted	15,352,702		15,280,657		15,342,287		14,970,190
Diluted Earnings Per Share	$	0.52	$	0.41	$	1.85	$	1.83

Acquisitions (Tables)

6 Months Ended

Jun. 30, 2016

Business Combinations [Abstract]

Merger Consideration paid



(in thousands)	Net Purchase Price
Chesapeake Utilities common stock	$	30,164
Cash	27,494
Acquired debt	1,696
Aggregate amount paid in the acquisition	59,354
Less: cash acquired	(6,806		)
Net amount paid in the acquisition	$	52,548

Purchase price allocation



	Purchase price
(in thousands)	Allocation
Purchase price	$	57,658

Property plant and equipment	53,203
Cash	6,806
Accounts receivable	3,629
Income taxes receivable	3,163
Other assets	425
Total assets acquired	67,226

Long-term debt	1,696
Deferred income taxes	13,409
Accounts payable	3,837
Other current liabilities	745
Total liabilities assumed	19,687
Net identifiable assets acquired	47,539
Goodwill	$	10,119

Segment Information (Tables)

6 Months Ended

Jun. 30, 2016

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,
	2016			2015			2016			2015
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	66,590		$	61,790		$	155,483		$	171,082
Unregulated Energy segment	35,752			30,892			93,155			91,681
Total operating revenues, unaffiliated customers	$	102,342		$	92,682		$	248,638		$	262,763
Intersegment Revenues ⁽¹⁾
Regulated Energy segment	$	805		$	270		$	1,128		$	560
Unregulated Energy segment	1,052			1,666			1,165			1,873
Other businesses	240			220			466			440
Total intersegment revenues	$	2,097		$	2,156		$	2,759		$	2,873
Operating Income
Regulated Energy segment	$	15,226		$	13,605		$	39,545		$	35,788
Unregulated Energy segment	412			(540		)	12,347			14,689
Other businesses and eliminations	104			105			230			201
Total operating income	15,742			13,170			52,122			50,678
Other Expense, net	(8		)	(171		)	(42		)	(38		)
Interest	2,624			2,485			5,274			4,933
Income before Income Taxes	13,110			10,514			46,806			45,707
Income taxes	5,081			4,220			18,410			18,304
Net Income	$	8,029		$	6,294		$	28,396		$	27,403


⁽¹⁾	All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.



(in thousands)	June 30, 2016		December 31, 2015
Identifiable Assets
Regulated Energy segment	$	892,513	$	872,065
Unregulated Energy segment	192,654		171,840
Other businesses and eliminations	11,880		23,516
Total identifiable assets	$	1,097,047	$	1,067,421

Accumulated Other Comprehensive Income (Loss) (Tables)

6 Months Ended

Jun. 30, 2016

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, 2015	$	(5,580	)	$	(260	)	$	(5,840	)
Other comprehensive gain before reclassifications	—			525			525
Amounts reclassified from accumulated other comprehensive loss	176			(29		)	147
Net current-period other comprehensive income	176			496			672
As of June 30, 2016	$	(5,404	)	$	236		$	(5,168	)



	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2014	$	(5,643	)	$	(33	)	$	(5,676	)
Other comprehensive loss before reclassifications	—			(1		)	(1		)
Amounts reclassified from accumulated other comprehensive loss	165			33			198
Net prior-period other comprehensive income	165			32			197
As of June 30, 2015	$	(5,478	)	$	(1	)	$	(5,479	)

Reclassifications out of Accumulated Other Comprehensive Income (Loss)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost ⁽¹⁾	$	20		$	17		$	40		$	34
Net loss ⁽¹⁾	(166		)	(155		)	(333		)	(310		)
Total before income taxes	(146		)	(138		)	(293		)	(276		)
Income tax benefit	58			55			117			111
Net of tax	$	(88	)	$	(83	)	$	(176	)	$	(165	)

Gains and losses on commodity contracts cash flow hedges
Propane swap agreements ⁽²⁾	$	—		$	(10	)	$	(322	)	$	2
Call options ⁽²⁾	—			—			—			(55		)
Natural gas futures ⁽²⁾	211			—			359			—
Total before income taxes	211			(10		)	37			(53		)
Income tax benefit (expense)	(81		)	4			(8		)	21
Net of tax	130			(6		)	29			(32		)
Total reclassifications for the period	$	42		$	(89	)	$	(147	)	$	(197	)

Employee Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2016

Schedule of Net Benefit Costs [Table Text Block]



	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended June 30,	2016			2015			2016			2015			2016		2015		2016			2015			2016		2015
(in thousands)
Interest cost	$	105		$	102		$	630		$	626		$	23	$	23	$	11		$	11		$	14	$	15
Expected return on plan assets	(131		)	(135		)	(701		)	(777		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			—		2		(20		)	(19		)	—		—
Amortization of net loss	103			91			128			114			22		25		17			17			—		2
Net periodic cost (benefit)	77			58			57			(37		)	45		50		8			9			14		17
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	77		$	58		$	248		$	154		$	45	$	50	$	8		$	9		$	16	$	19



	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Six Months Ended June 30,	2016			2015			2016			2015			2016		2015		2016			2015			2016		2015
(in thousands)
Interest cost	$	210		$	204		$	1,259		$	1,251		$	46	$	46	$	21		$	22		$	28	$	30
Expected return on plan assets	(261		)	(270		)	(1,402		)	(1,554		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			—		5		(40		)	(39		)	—		—
Amortization of net loss	206			181			257			227			44		50		34			35			—		3
Net periodic cost (benefit)	155			115			114			(76		)	90		101		15			18			28		33
Amortization of pre-merger regulatory asset	—			—			381			381			—		—		—			—			4		4
Total periodic cost	$	155		$	115		$	495		$	305		$	90	$	101	$	15		$	18		$	32	$	37

Amounts Included in Regulatory asset and AOCI [Table Text Block]



For the Three Months Ended June 30, 2016	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(20	)	$	—	$	(20	)
Net loss	103		128		22		17			—		270
Total recognized in net periodic benefit cost	$	103	$	128	$	22	$	(3	)	$	—	$	250
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	103	$	24	$	22	$	(3	)	$	—	$	146
Recognized from regulatory asset	—		104		—		—			—		104
Total	$	103	$	128	$	22	$	(3	)	$	—	$	250



For the Three Months Ended June 30, 2015	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	2	$	(19	)	$	—	$	(17	)
Net loss	91		114		25		17			2		249
Total recognized in net periodic benefit cost	$	91	$	114	$	27	$	(2	)	$	2	$	232
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	91	$	22	$	27	$	(2	)	$	—	$	138
Recognized from regulatory asset	—		92		—		—			2		94
Total	$	91	$	114	$	27	$	(2	)	$	2	$	232



For the Six Months Ended June 30, 2016	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(40	)	$	—	$	(40	)
Net loss	206		257		44		34			—		$	541
Total recognized in net periodic benefit cost	$	206	$	257	$	44	$	(6	)	$	—	$	501
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	206	$	49	$	44	$	(6	)	$	—	$	293
Recognized from regulatory asset	—		208		—		—			—		208
Total	$	206	$	257	$	44	$	(6	)	$	—	$	501



For the Six Months Ended June 30, 2015	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	5	$	(39	)	$	—	$	(34	)
Net loss	181		227		50		35			3		496
Total recognized in net periodic benefit cost	$	181	$	227	$	55	$	(4	)	$	3	$	462
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	181	$	43	$	55	$	(4	)	$	1	$	276
Recognized from regulatory asset	—		184		—		—			2		186
Total	$	181	$	227	$	55	$	(4	)	$	3	$	462

Share-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2016

Shares awarded to non-employee directors [Line Items]

Schedule of Share-based Compensation, Nonemployee Director Stock Award Plan, Activity [Table Text Block]



	Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2015	—		$	—
Granted	8,577		$	62.90
Vested	(8,577	)	$	62.90
Outstanding— June 30, 2016	—		$	—

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, 2016 and 2015:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
(in thousands)
Awards to non-employee directors	$	145		$	160		$	310		$	311
Awards to key employees	470			250			954			636
Total compensation expense	615			410			1,264			947
Less: tax benefit	(248		)	(165		)	(509		)	(381		)
Share-based compensation amounts included in net income	$	367		$	245		$	755		$	566

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, 2016:



	Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2015	110,398		$	38.34
Granted	46,571		$	67.90
Vested	(39,553	)	$	31.79
Expired	(2,325	)	$	42.25
Outstanding— June 30, 2016	115,091		$	51.85

Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Outstanding Trading Contracts



	Quantity in	Estimated Market		Weighted Average
At June 30, 2016	Gallons	Prices		Contract Prices
Forward Contracts - Propane
Purchase	421,000	$	0.5375	$	0.5388

	Quantity in	Estimated Market		Weighted Average
At June 30, 2016	Barrels	Prices		Contract Prices
Futures Contracts - Crude Oil
Purchase	20,000	$	48.3300	$	47.9000

Estimated market prices and weighted average contract prices are in dollars per gallon and barrel. All contracts expire by the end of the third quarter of 2016.

Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet

air values of the derivative contracts recorded in the condensed consolidated balance sheets as of June 30, 2016 and December 31, 2015, are as follows:



	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2016		December 31, 2015
Derivatives not designated as hedging instruments
Forward & Future contracts	Mark-to-market energy assets	$	25	$	1
Derivatives designated as fair value hedges
Put options	Mark-to-market energy assets	—		152
Derivatives designated as cash flow hedges
Natural gas futures contracts	Mark-to-market energy assets	357		—
Propane swap agreements	Mark-to-market energy assets	23		—
Total asset derivatives		$	405	$	153



	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2016		December 31, 2015
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	23	$	1
Derivatives designated as fair value hedges
Natural gas futures contracts	Mark-to-market energy liabilities	233		—
Derivatives designated as cash flow hedges
Propane swap agreements	Mark-to-market energy liabilities	—		323
Natural gas futures contracts	Mark-to-market energy liabilities	—		109
Total liability derivatives		$	256	$	433



	Three Months Ended			Six Months Ended
(in thousands)	June 30, 2016⁽¹⁾			June 30, 2016⁽¹⁾
Commodity contracts	$	(233	)	$	(233	)
Fair value adjustment for natural gas inventory designated as the hedged item	681			681
Total increase in purchased gas cost	$	448		$	448

The increase in purchased gas cost is comprised of the following:
Basis ineffectiveness	$	(83	)	$	(83	)
Timing ineffectiveness	531			531
Total ineffectiveness	$	448		$	448

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	2016			2015			2016			2015
Derivatives not designated as hedging instruments
Realized gain on forward contracts ⁽¹⁾	Revenue	$	88		$	(71	)	275			206
Unrealized gain (loss) on forward contracts ⁽¹⁾	Revenue	1			203			2			78
Propane swap agreements	Cost of sales	—			—			—			18
Derivatives designated as fair value hedges
Put /Call options	Cost of sales	—			—			73			506
Put /Call options ⁽²⁾	Propane Inventory	—			(30		)				(34		)
Natural gas futures contracts	Natural Gas Inventory	(233		)	—			(233		)	—
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	—			—			(364		)	—
Propane swap agreements	Other Comprehensive Gain (Loss)	23			10			23			(2		)
Call options	Cost of sales	—			—			—			(81		)
Natural gas futures contracts	Cost of sales	211			—			359			—
Natural gas futures contracts	Other Comprehensive Gain	786			—			472			—
Total		$	876		$	112		$	607		$	691

- Definition

Tabular disclosure of pertinent information about a derivative or group of derivatives on a disaggregated basis, such as for individual instruments, or small groups of similar instruments. May include a combination of the type of instrument, risks being hedged, notional amount, hedge designation, related hedged item, inception date, maturity date, or other relevant item.

+ References

Reference 1: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 5
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41641-113959

Reference 2: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624163-113959

Reference 3: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 8
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41678-113959

Reference 4: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41638-113959

Reference 5: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1B
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5580258-113959

Reference 6: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1A
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5579245-113959

Reference 7: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 4C
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5624171-113959

Reference 8: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 25
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=6886632&loc=d3e76258-113986

Reference 9: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 1
-URI http://asc.fasb.org/extlink&oid=56946850&loc=SL5579240-113959

Reference 10: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 815
-SubTopic 10
-Section 50
-Paragraph 2
-URI http://asc.fasb.org/extlink&oid=56946850&loc=d3e41620-113959

Reference 11: http://www.xbrl.org/2003/role/presentationRef
-Publisher FASB
-Name Accounting Standards Codification
-Topic 235
-SubTopic 10
-Section S99
-Paragraph 1
-Subparagraph (SX 210.4-08.(n)(2))
-URI http://asc.fasb.org/extlink&oid=26873400&loc=d3e23780-122690

+ Details

Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2016

Fair Value Disclosures [Abstract]

Financial Assets and Liabilities Measured at Fair Value on Recurring Basis



			Fair Value Measurements Using:
As of June 30, 2016	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	$	475	$	—	$	—	$	475
Investments—mutual funds and other	$	3,829	$	3,829	$	—	$	—
Mark-to-market energy assets, incl. put options and swap agreements	$	405	$	—	$	405	$	—
Liabilities:
Mark-to-market energy liabilities incl. swap agreements	$	256	$	—	$	256	$	—



			Fair Value Measurements Using:
As of December 31, 2015	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	$	18	$	18	$	—	$	—
Investments—guaranteed income fund	$	279	$	—	$	—	$	279
Investments—mutual funds and other	$	3,347	$	3,347	$	—	$	—
Mark-to-market energy assets, incl. put/call options	$	153	$	—	$	153	$	—
Liabilities:
Mark-to-market energy liabilities, incl. swap agreements	$	433	$	—	$	433	$	—

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, 2016 and 2015:



	Six Months Ended June 30,
	2016			2015
(in thousands)
Beginning Balance	$	279		$	287
Purchases and adjustments	112			49
Transfers	88			(3		)
Distribution	(8		)	—
Investment income	4			2
Ending Balance	$	475		$	335

Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2016

Debt Disclosure [Abstract]

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below:



	June 30,			December 31,
(in thousands)	2016			2015
FPU secured first mortgage bonds ⁽¹⁾:
9.08% bond, due June 1, 2022	$	7,976		$	7,973
Uncollateralized senior notes:
6.64% note, due October 31, 2017	5,455			5,455
5.50% note, due October 12, 2020	10,000			10,000
5.93% note, due October 31, 2023	22,500			24,000
5.68% note, due June 30, 2026	29,000			29,000
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
Promissory notes	168			238
Capital lease obligation	4,153			4,824
Total long-term debt	156,252			158,490
Less: current maturities	(12,075		)	(9,151		)
Less: debt issuance costs	(312		)	(333		)
Total long-term debt, net of current maturities	$	143,865		$	149,006

⁽¹⁾ FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities.

Summary of Accounting policies - Additional Information (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Debt issuance costs	$ (312)	$ (333)
Deferred Tax Assets, Net of Valuation Allowance, Current		$ 831

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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Calculation of Basic Earnings Per Share:
Net Income	$ 8,029	$ 6,294	$ 28,396	$ 27,403	$ 41,140
Weighted shares outstanding (shares)	15,315,020	15,235,860	15,300,931	14,922,094
Basic Earnings Per Share (in dollars per share)	$ 0.52	$ 0.41	$ 1.86	$ 1.84
Reconciliation of Numerator:
Net Income	$ 8,029	$ 6,294	$ 28,396	$ 27,403	$ 41,140
Reconciliation of Denominator:
Weighted shares outstanding - Basic (shares)	15,315,020	15,235,860	15,300,931	14,922,094
Effect of dilutive securities:
Share-based compensation (shares)	37,682	44,797	41,356	48,096
Adjusted denominator-Diluted (shares)	15,352,702	15,280,657	15,342,287	14,970,190
Diluted Earnings Per Share (in dollars per share)	$ 0.52	$ 0.41	$ 1.85	$ 1.83

Acquisitions - Additional Information (Detail) $ / shares in Units, $ in Thousands		3 Months Ended		6 Months Ended		12 Months Ended
	Apr. 01, 2015 USD ($) mi	Jun. 30, 2016 USD ($) $ / shares shares	Jun. 30, 2015 USD ($) $ / shares	Jun. 30, 2016 USD ($) $ / shares	Jun. 30, 2015 USD ($) $ / shares	Dec. 31, 2015 USD ($)	Dec. 31, 2014 USD ($)
Business Acquisition [Line Items]
Transaction costs						$ (514)	$ (786)
Revenues		$ 102,342	$ 92,682	$ 248,638	$ 262,763
Net income		$ 8,029	$ 6,294	$ 28,396	$ 27,403	41,140
Diluted (in dollars per share) \| $ / shares		$ 0.52	$ 0.41	$ 1.85	$ 1.83
Goodwill		$ 15,070		$ 15,070		14,548
Gatherco [Member]
Business Acquisition [Line Items]
Number of pipeline miles \| mi	2,500
Number of counties served	40
Number of producers served	300
Number of customers served	20,000
Purchase price		$ 57,658
Shares of common stock issued at closing (shares) \| shares		592,970
Common stock issued at closing	$ 30,200	$ 30,164		30,164
Cash paid	27,500	27,494
Long-term debt	1,696	1,696		1,696
Cash acquired	6,800	6,806		6,806
Additional contingent cash consideration		$ 15,000		15,000
Period for revenue generated from potential new gathering opportunities		5 years
Transaction costs						$ (1,300)
Revenues		$ 4,800		12,800
Net income		$ 28		1,700
Diluted (in dollars per share) \| $ / shares		$ 0.03
Goodwill	$ 11,100	$ 10,119		$ 10,119

Acquisitions - Purchase Considerations (Details) - Gatherco [Member] - USD ($) $ in Thousands		3 Months Ended
	Apr. 01, 2015	Jun. 30, 2016
Business Acquisition [Line Items]
Chesapeake Utilities common stock	$ 30,200	$ 30,164
Cash	27,500	27,494
Acquired debt	1,696	1,696
Purchase price		57,658
Less: cash acquired	$ (6,800)	(6,806)
Gross [Member]
Business Acquisition [Line Items]
Purchase price		59,354
Net [Member]
Business Acquisition [Line Items]
Purchase price		$ 52,548

Acquisitions - Gatherco purchase price allocation (Details) - USD ($) $ in Thousands	3 Months Ended
	Jun. 30, 2016	Dec. 31, 2015	Apr. 01, 2015
Business Acquisition [Line Items]
Goodwill	$ 15,070	$ 14,548
Gatherco [Member]
Business Acquisition [Line Items]
Purchase price	57,658
Property plant and equipment	53,203
Cash	6,806		$ 6,800
Accounts receivable	3,629
Income taxes receivable	3,163
Other assets	425
Total assets acquired	67,226
Long-term debt	1,696		1,696
Deferred income taxes	13,409
Accounts payable	3,837
Other current liabilities	745
Total liabilities assumed	19,687
Net identifiable assets acquired	47,539
Goodwill	$ 10,119		$ 11,100

Rates and Other Regulatory Activities - Additional Information (Detail) $ in Thousands				1 Months Ended	3 Months Ended		6 Months Ended
	Feb. 19, 2016 USD ($)	Dec. 21, 2015 USD ($)	Oct. 13, 2015 dekatherm / d	Dec. 31, 2015 USD ($)	Jun. 30, 2016 USD ($) mi	Jun. 30, 2015 USD ($)	Jun. 30, 2016 USD ($) dekatherm / d in mi	Jun. 30, 2015 USD ($)	Jul. 21, 2016 mi	May 12, 2016 mi
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Interim Rate Increase (Decrease), Amount \| $	$ 2,500
Revenues \| $					$ 102,342	$ 92,682	$ 248,638	$ 262,763
Public Utilities Interim Requested Rate Increase (Decrease) Percentage	5.00%
DELAWARE
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount \| $		$ 4,700
Public Utilities, Requested Rate Increase (Decrease), Percentage		10.00%
Revenues \| $					555		878
Revenues Net Of Tax \| $					$ 332		$ 526
MARYLAND
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount \| $				$ 950
Public Utilities, Requested Rate Increase (Decrease), Percentage				5.00%
Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Volume The Expansion Project Is Expected to Provide \| dekatherm / d			53,000
Total Capacity After Pipeline Improvements \| dekatherm / d			160,000
White Oak Lateral Mainline Expansion [Member] \| Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Volume The Expansion Project Is Expected to Provide \| dekatherm / d							45,000
Number of pipeline miles \| mi					7.2		7.2
Lateral diamater of pipeline to be installed \| in							16
Horsepower Of Additional Compression							3,550
Miles Of Natural Gas Pipeline \| mi					5.4		5.4
System Reliability Project [Member] \| Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Number of pipeline miles \| mi					10.1		10.1
Lateral diamater of pipeline to be installed \| in							16
2017 Expansion Project [Member] \| Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Volume The Expansion Project Is Expected to Provide \| dekatherm / d							86,437
Number of pipeline miles \| mi										33
Horsepower Of Additional Compression							3,550
Miles Of Natural Gas Pipeline \| mi										17
Subsequent Event [Member] \| System Reliability Project [Member] \| Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Number Of Environmental Conditions \| mi									19

Environmental Commitments and Contingencies - Additional Information (Detail)	3 Months Ended	6 Months Ended
	Jun. 30, 2016 USD ($) site claim	Jun. 30, 2016 USD ($) site claim	Jun. 30, 2015 USD ($)	Dec. 31, 2015 USD ($)
Environmental Commitments And Contingencies [Line Items]
Company's exposure in number of former Manufactured Gas Plant Sites \| site	7
Environmental liabilities	$ 8,765,000	$ 8,765,000		$ 8,942,000
Amount paid for funding requirements		177,000	$ 73,000
Seaford [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	273,000	273,000
Accrual for Environmental Loss Contingencies	177,000	177,000
Regulatory Assets	268,000	268,000
Estimated costs of remediation range, minimum	273,000
Estimated costs of remediation range, maximum	465,000
Winter Haven Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental remediation expense	425,000
Additional remediation costs	100,000	100,000
Salisbury Maryland [Member]
Environmental Commitments And Contingencies [Line Items]
Maximum Costs Of Monitoring Well	5,000
West Palm Beach Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	4,500,000
Estimated costs of remediation range, maximum	15,400,000
Sanford Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, maximum		$ 13,000,000
Cost of remedy for settlements of claims	$ 20,000,000
Loss Contingency, Pending Claims, Number \| claim	2	2
Environmental remediation expense	$ 24,000
Key West Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Period Of Regulatory Inactivity	17 years
Environmental Exit Costs, Anticipated Cost	$ 50,000
Aspire Energy [Member]
Environmental Commitments And Contingencies [Line Items]
Number Of Environmental Sites \| site	8	8
Cost of remedy for settlements of claims	$ 1,600,000
Minimum Environmental Remediation Expenditures	431,250
Business Combination, Indemnification Assets, Range of Outcomes, Value, High	1,700,000	$ 1,700,000
FPU [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	9,900,000	9,900,000
Approval of recovery of environmental costs	14,000,000
Environmental costs recovered	$ 10,300,000
FPU [Member] \| Sanford Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, maximum		650,000
Environmental remediation expense percent	5.00%
FPU [Member] \| Manufactured Gas Plant [Member]
Environmental Commitments And Contingencies [Line Items]
Regulatory Assets	$ 3,700,000	3,700,000
Chesapeake [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	314,000	314,000
Regulatory Assets	29,000	$ 29,000
Maximum [Member] \| Key West Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Anticipated Cost	8,000
Maximum [Member] \| Pensacola Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Anticipated Cost	$ 5,000

Other Commitments and Contingencies - Additional Information (Detail) $ in Thousands, gal in Millions	3 Months Ended
	Jun. 30, 2016 USD ($) dekatherm / d gal	Dec. 31, 2015 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Number of years to purchase propane under contract	6 years
Estimated current annual commitment \| gal	6.5
Monthly purchase commitment, minimum \| dekatherm / d	9,982
Monthly purchase commitment, maximum \| dekatherm / d	13,423
Total liabilities to tangible net worth minimum times	3.75
Fixed charge coverage ratio minimum times	1.5
Time to cure ratio	30 days
Funds from operations interest coverage ratio minimum times	2
Total debt to capital maximum	0.65
Maximum authorized liability under such guarantees and letters of credit	$ 65,000
Aggregate guaranteed amount	53,600
Draws on letters of credit	8,100
Liability related to unrecognized income tax benefits	50	$ 50
Liability related to contingencies for taxes other than income	$ 72	$ 310

Segment Information - Schedule of Segment Reporting Information by Segment (Detail) - USD ($)
$ in Thousands

3 Months Ended

6 Months Ended

12 Months Ended

Jun. 30, 2016

Jun. 30, 2015

Jun. 30, 2016

Jun. 30, 2015

Dec. 31, 2015

Operating Revenues, Unaffiliated Customers

Total operating revenues, unaffiliated customers

$ 102,342

$ 92,682

$ 248,638

$ 262,763

Intersegment Revenues

Total operating revenues, unaffiliated customers

102,342

92,682

248,638

262,763

Operating Income

Total operating income

15,742

13,170

52,122

50,678

Other income, net of other expenses

(8)

(171)

(42)

(38)

Interest

2,624

2,485

5,274

4,933

Income Before Income Taxes

13,110

10,514

46,806

45,707

Income taxes

5,081

4,220

18,410

18,304

Net Income

8,029

6,294

28,396

27,403

$ 41,140

Identifiable Assets

Total identifiable assets

1,097,047

1,067,421

Regulated Energy [Member]

Operating Income

Total operating income

15,226

13,605

39,545

35,788

Identifiable Assets

Total identifiable assets

892,513

872,065

Unregulated Energy [Member]

Operating Income

Total operating income

412

(540)

12,347

14,689

Identifiable Assets

Total identifiable assets

192,654

171,840

Other [Member]

Identifiable Assets

Total identifiable assets

11,880

$ 23,516

Other and eliminations [Member]

Operating Income

Total operating income

104

105

230

201

Operating Revenues, Unaffiliated Customers [Member]

Operating Revenues, Unaffiliated Customers

Total operating revenues, unaffiliated customers

102,342

92,682

248,638

262,763

Intersegment Revenues

Total operating revenues, unaffiliated customers

102,342

92,682

248,638

262,763

Operating Revenues, Unaffiliated Customers [Member] | Regulated Energy [Member]

Operating Revenues, Unaffiliated Customers

Total operating revenues, unaffiliated customers

66,590

61,790

155,483

171,082

Intersegment Revenues

Total operating revenues, unaffiliated customers

66,590

61,790

155,483

171,082

Operating Revenues, Unaffiliated Customers [Member] | Unregulated Energy [Member]

Operating Revenues, Unaffiliated Customers

Total operating revenues, unaffiliated customers

35,752

30,892

93,155

91,681

Intersegment Revenues

Total operating revenues, unaffiliated customers

35,752

30,892

93,155

91,681

Intersegment Revenues [Member]

Operating Revenues, Unaffiliated Customers

Total operating revenues, unaffiliated customers

^[1]

2,097

2,156

2,759

2,873

Intersegment Revenues

Total operating revenues, unaffiliated customers

^[1]

2,097

2,156

2,759

2,873

Intersegment Revenues [Member] | Regulated Energy [Member]

Operating Revenues, Unaffiliated Customers

Total operating revenues, unaffiliated customers

^[1]

805

270

1,128

560

Intersegment Revenues

Total operating revenues, unaffiliated customers

^[1]

805

270

1,128

560

Intersegment Revenues [Member] | Unregulated Energy [Member]

Operating Revenues, Unaffiliated Customers

Total operating revenues, unaffiliated customers

^[1]

1,052

1,666

1,165

1,873

Intersegment Revenues

Total operating revenues, unaffiliated customers

^[1]

1,052

1,666

1,165

1,873

Intersegment Revenues [Member] | Other [Member]

Operating Revenues, Unaffiliated Customers

Total operating revenues, unaffiliated customers

^[1]

240

220

466

440

Intersegment Revenues

Total operating revenues, unaffiliated customers

^[1]

$ 240

$ 220

$ 466

$ 440

[1]	(1) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.

Accumulated Other Comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	$ (5,840)	$ (5,676)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	525	(1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	147	198
Net current-period other comprehensive income (loss)	672	197
Ending balance	(5,168)	(5,479)
UnrealizedGainsLossesFromDefinedBenefitPensionAndPostretirementPlanItems [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	(5,580)	(5,643)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	176	165
Net current-period other comprehensive income (loss)	176	165
Ending balance	(5,404)	(5,478)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	(260)	(33)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	525	(1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(29)	33
Net current-period other comprehensive income (loss)	496	32
Ending balance	$ 236	$ (1)

- Definition

Accumulated change in equity from transactions and other events and circumstances from non-owner sources, net of tax effect, at period end. Excludes Net Income (Loss), and accumulated changes in equity from transactions resulting from investments by owners and distributions to owners. Includes foreign currency translation items, certain pension adjustments, unrealized gains and losses on certain investments in debt and equity securities, other than temporary impairment (OTTI) losses related to factors other than credit losses on available-for-sale and held-to-maturity debt securities that an entity does not intend to sell and it is not more likely than not that the entity will be required to sell before recovery of the amortized cost basis, as well as changes in the fair value of derivatives related to the effective portion of a designated cash flow hedge.

+ References + Details

Accumulated Other Comprehensive Income (Loss) - Reclassifications of Accumulated Other Comprehensive Loss (Detail) - USD ($)
$ in Thousands

3 Months Ended

6 Months Ended

Jun. 30, 2016

Jun. 30, 2015

Jun. 30, 2016

Jun. 30, 2015

Amortization of pension and postretirement items:

Tax benefit

$ (5,081)

$ (4,220)

$ (18,410)

$ (18,304)

Reclassification out of Accumulated Other Comprehensive Income [Member]

Amortization of pension and postretirement items:

Net of tax

(89)

(147)

(197)

Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]

Amortization of pension and postretirement items:

Prior service cost

^[1]

Net loss

^[1]

166

155

333

310

Total before tax

(146)

(138)

(293)

(276)

Tax benefit

117

111

Net of tax

(88)

(83)

(176)

(165)

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

211

(10)

(53)

Tax benefit

(81)

(8)

Net of tax

130

(6)

(32)

Other Comprehensive Income Loss Adjustments AOCI Swap Agreements

(10)

(322)

^[2]

Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax

^[2]

(55)

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

$ 211

$ 0

$ 359

$ 0

[1]	These amounts are included in the computation of net periodic costs (benefits). See Note 9, Employee Benefit Plans, for additional details.
[2]	(2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments, for additional details.

Employee Benefit Plans (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
Employee Benefit Plans (Detail) - USD ($) $ in Thousands	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Defined Benefit Plan Disclosure [Line Items]
Amortization of prior service cost	$ (20)	$ (17)	$ (40)	$ (34)
Amortization of net loss	270	249	541	496
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	105	102	210	204
Expected return on plan assets	(131)	(135)	(261)	(270)
Amortization of prior service cost	0	0	0	0
Amortization of net loss	103	91	206	181
Net periodic cost (benefit)	77	58	155	115
Amortization of pre-merger regulatory asset	0	0	0	0
Total periodic cost	77	58	155	115
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	630	626	1,259	1,251
Expected return on plan assets	(701)	(777)	(1,402)	(1,554)
Amortization of prior service cost	0	0	0	0
Amortization of net loss	128	114	257	227
Net periodic cost (benefit)	57	(37)	114	(76)
Amortization of pre-merger regulatory asset	191	191	381	381
Total periodic cost	248	154	495	305
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	23	23	46	46
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	0	2	0	5
Amortization of net loss	22	25	44	50
Net periodic cost (benefit)	45	50	90	101
Amortization of pre-merger regulatory asset	0	0	0	0
Total periodic cost	45	50	90	101
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	11	11	21	22
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	(20)	(19)	(40)	(39)
Amortization of net loss	17	17	34	35
Net periodic cost (benefit)	8	9	15	18
Amortization of pre-merger regulatory asset	0	0	0	0
Total periodic cost	8	9	15	18
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	14	15	28	30
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	0	0	0	0
Amortization of net loss	0	2	0	3
Net periodic cost (benefit)	14	17	28	33
Amortization of pre-merger regulatory asset	2	2	4	4
Total periodic cost	$ 16	$ 19	$ 32	$ 37

Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Expected pension and postretirement benefit costs			$ 1,600
Expected amortization of pre merger regulatory asset			769
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	$ 77	$ 58	155	$ 115
Contribution to pension plan	170		274
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year			508
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Unamortized balance of regulatory asset	2,500		2,500		$ 2,900
Defined Benefit Plan, Net Periodic Benefit Cost	57	(37)	114	(76)
Contribution to pension plan	548		885
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year			1,600
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	45	50	90	101
Contribution to pension plan	38		76
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year			151
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	8	9	15	18
Contribution to pension plan	15		36
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year			82
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	14	$ 17	28	$ 33
Contribution to pension plan	$ 27		67
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year			149
Consolidated [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost			$ (802)

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, 2016

Jun. 30, 2015

Jun. 30, 2016

Jun. 30, 2015

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Prior service cost (credit)

$ (20)

$ (17)

$ (40)

$ (34)

Net loss

270

249

541

496

Recognized from accumulated other comprehensive loss

146

^[1]

138

^[1]

293

276

^[1]

Recognized from regulatory asset

104

208

186

Total recognized in net periodic benefit cost

250

232

501

462

Chesapeake Pension Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Prior service cost (credit)

Net loss

103

206

181

Recognized from accumulated other comprehensive loss

103

^[1]

206

181

^[1]

Recognized from regulatory asset

Total recognized in net periodic benefit cost

103

206

181

Florida Public Utilities Company Pension Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Prior service cost (credit)

Net loss

128

114

257

227

Recognized from accumulated other comprehensive loss

^[1]

Recognized from regulatory asset

104

208

184

Total recognized in net periodic benefit cost

128

114

257

227

Chesapeake Pension SERP [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Prior service cost (credit)

Net loss

Recognized from accumulated other comprehensive loss

^[1]

Recognized from regulatory asset

Total recognized in net periodic benefit cost

Chesapeake Postretirement Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Prior service cost (credit)

(20)

(19)

(40)

(39)

Net loss

Recognized from accumulated other comprehensive loss

(3)

^[1]

(2)

^[1]

(6)

(4)

^[1]

Recognized from regulatory asset

Total recognized in net periodic benefit cost

(3)

(2)

(6)

(4)

Florida Public Utilities Company Medical Plan [Member]

Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]

Prior service cost (credit)

Net loss

Recognized from accumulated other comprehensive loss

^[1]

Recognized from regulatory asset

Total recognized in net periodic benefit cost

$ 0

$ 2

$ 0

$ 3

[1]	(1) See Note 8, Accumulated Other Comprehensive Loss.

Investments - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Investments, Debt and Equity Securities [Abstract]
Unrealized gain, net of other expenses	$ 71	$ 4	$ 53	$ 107

Investments - Schedule of Investments (Details) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Investments schedule [Line Items]
Investments, at fair value	$ 4,325	$ 3,644
Rabbi Trust Associated With Deferred Compensation Plan [Member]
Investments schedule [Line Items]
Investments, at fair value	4,304	3,626
Equity Securities [Member]
Investments schedule [Line Items]
Investments, at fair value	$ 21	$ 18

Share-Based Compensation - Share-Based Compensation Amounts Included in Net Income (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 615	$ 410	$ 1,264	$ 947
Less: tax benefit	(248)	(165)	(509)	(381)
Share-Based Compensation amounts included in net income	367	245	755	566
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	145	160	310	311
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 470	$ 250	$ 954	$ 636

Share-Based Compensation - Summary of Stock Activity under the SICP (Detail)	6 Months Ended
	Jun. 30, 2016 $ / shares shares
Number of Shares
Granted (shares)	953
Award to key employees [Member]
Number of Shares
Outstanding - December 31, 2015 (shares)	110,398
Granted (shares)	46,571
Vested (shares)	(39,553)
Expired (shares)	(2,325)
Outstanding - June 30, 2016 (shares)	115,091.000
Weighted Average Fair Value
Outstanding - December 31, 2015 (in dollars per share) \| $ / shares	$ 38.34
Granted (in dollars per share) \| $ / shares	67.90
Vested (in dollars per share) \| $ / shares	31.79
Expired (in dollars per share) \| $ / shares	42.25
Outstanding - June 30, 2016 (in dollars per share) \| $ / shares	$ 51.85
Awards to non-employee directors [Member]
Number of Shares
Outstanding - December 31, 2015 (shares)	0
Granted (shares)	8,577
Vested (shares)	(8,577)
Outstanding - June 30, 2016 (shares)	0
Weighted Average Fair Value
Outstanding - December 31, 2015 (in dollars per share) \| $ / shares	$ 0.00
Granted (in dollars per share) \| $ / shares	62.90
Vested (in dollars per share) \| $ / shares	62.90
Outstanding - June 30, 2016 (in dollars per share) \| $ / shares	$ 0.00

Share-Based Compensation - Additional Information (Detail) $ in Thousands	6 Months Ended
	Jun. 30, 2016 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards (shares) \| shares	953
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
Granted awards (shares) \| shares	8,577
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards (shares) \| shares	46,571
Vesting period	3 years
Intrinsic value of the SICP awards \| $	$ 7,600

Derivative Instruments - Additional Information (Detail) gal in Thousands, $ in Thousands	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2016 USD ($) Counterparty $ / gal	Jun. 30, 2016 USD ($) Counterparty $ / gal gal	Dec. 31, 2015 USD ($) Counterparty $ / gal gal
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	$ 405	$ 405	$ 153
Energy Marketing Contract Liabilities, Current	256	$ 256	$ 433
Propane Swap Agreement [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| gal		630	2,500
Cash Paid On Derivative Settlement	484
Put Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| gal			2,500
Payments for Derivative Instrument, Financing Activities			$ 143
Cash Received On Derivative Settlement	$ 239
Forward Contracts [Member]
Derivative [Line Items]
Number Of Counterparties With Master Repurchase Agreements \| Counterparty	2	2	2
Accounts Payable Subject To Master Netting Arrangement			$ 431
Mark To Market Energy Assets [Member] \| Future [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| gal		6,090
Energy Marketing Contracts Assets, Current	$ 357	$ 357
Mark To Market Energy Assets [Member] \| Propane [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	23	23
Mark To Market Energy Assets [Member] \| Forward Contracts [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	25	$ 25	1
Mark To Market Energy Liabilities [Member] \| Future [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume \| gal		1,065
Energy Marketing Contract Liabilities, Current	233	$ 233	109
Mark To Market Energy Liabilities [Member] \| Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current			323
Mark To Market Energy Liabilities [Member] \| Forward Contracts [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ 23	$ 23	1
Designated as Hedging Instrument [Member] \| Mark To Market Energy Assets [Member] \| Put Option [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral			$ 152
Strike Price 2 [Member] \| Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements \| $ / gal			0.5950
Strike Price 4 [Member] \| Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements \| $ / gal	0.5525	0.5525	0.5200
Put Option Strike Price 1 [Member] \| Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price \| $ / gal			0.4950
Put Option Strike Price 2 [Member] \| Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price \| $ / gal			0.4888
Put Option Strike Price 3 [Member] \| Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price \| $ / gal			0.4500
Put Option Strike Price 4 [Member] \| Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price \| $ / gal			0.4200

Derivative Instruments - Outstanding Trading Contracts (Details) gal in Thousands, bbl in Thousands	Jun. 30, 2016 gal bbl $ / gal
Sales [Member] \| Minimum [Member] \| Forward Contracts [Member]
Derivative [Line Items]
Estimated Market Prices	0.5213
Sales [Member] \| Maximum [Member] \| Forward Contracts [Member]
Derivative [Line Items]
Estimated Market Prices	0.5213
Purchase [Member] \| Forward Contracts [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount \| gal	421
Weighted Average Contract Prices	0.5388
Purchase [Member] \| Future [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount \| bbl	20
Estimated Market Prices	48.80
Weighted Average Contract Prices	47.9000
Purchase [Member] \| Minimum [Member] \| Forward Contracts [Member]
Derivative [Line Items]
Estimated Market Prices	0.5375
Purchase [Member] \| Maximum [Member] \| Forward Contracts [Member]
Derivative [Line Items]
Estimated Market Prices	0.5375

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 405	$ 153
Energy Marketing Contract Liabilities, Current	256	433
Mark To Market Energy Assets [Member] \| Forward Contracts [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	25	1
Mark To Market Energy Assets [Member] \| Put Option [Member] \| Derivatives designated as fair value hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		152
Mark To Market Energy Assets [Member] \| Future [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	357
Mark To Market Energy Assets [Member] \| Propane [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	23
Mark-to-market energy liabilities [Member] \| Forward Contracts [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	23	1
Mark-to-market energy liabilities [Member] \| Propane Swap Agreement [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current		323
Mark-to-market energy liabilities [Member] \| Future [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 233	$ 109

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, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 876,000	$ 112,000	$ 607	$ 691,000
Revenue [Member] \| Derivatives not designated as hedging instruments [Member] \| Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	1,000	203,000	2,000	78,000
Cost of Sales [Member] \| Derivatives not designated as hedging instruments [Member] \| Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0	0	18,000
Cost of Sales [Member] \| Derivatives designated as fair value hedges [Member] \| Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0	0	(81,000)
Cost of Sales [Member] \| Derivatives designated as fair value hedges [Member] \| Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0		(364,000)
Cost of Sales [Member] \| Derivatives designated as fair value hedges [Member] \| Put/Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0	73,000	506,000
Cost of Sales [Member] \| Derivatives designated as fair value hedges [Member] \| Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	211,000	0	359,000	0
Inventories [Member] \| Derivatives designated as fair value hedges [Member] \| Put/Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	0	(30,000)		(34,000)
Inventories [Member] \| Derivatives designated as fair value hedges [Member] \| Natural Gas Futures [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	(233,000)		(233,000)
Other Comprehensive Income (Loss) [Member] \| Derivatives designated as fair value hedges [Member] \| Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	23,000	10,000	23,000	(2,000)
Other Comprehensive Income (Loss) [Member] \| Derivatives designated as fair value hedges [Member] \| Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	786,000	0	472,000	0
Options [Member] \| Revenue [Member] \| Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 88,000	$ (71,000)	$ 275,000	$ 206,000

Derivative Instruments - Natural Gas Commodity Contracts Fair Value Hedges (Details) - USD ($) $ in Thousands	3 Months Ended	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2016
Derivative [Line Items]
Change in Unrealized Gain (Loss) on Fair Value Hedging Instruments	$ (233)	$ (233)
Change in Unrealized Gain (Loss) on Hedged Item in Fair Value Hedge	681	681
Gain (Loss) on Fair Value Hedges Recognized in Earnings	448	448
Loss on Fair Value Hedge Ineffectiveness	(83)	(83)
Gain on Fair Value Hedge Ineffectiveness	531	531
Gain (Loss) on Fair Value Hedge Ineffectiveness, Net	$ 448	$ 448

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Jun. 30, 2016	Dec. 31, 2015
Assets:
Investments	$ 4,325	$ 3,644
Equity Securities [Member]
Assets:
Investments	21	18
Quoted Prices in Active Markets (Level 1) [Member] \| Mark-to-market energy liabilities [Member]
Liabilities:
Mark-to-market energy liabilities	0	0
Quoted Prices in Active Markets (Level 1) [Member] \| Investments in guaranteed income fund [Member]
Assets:
Investments	0	0
Quoted Prices in Active Markets (Level 1) [Member] \| Equity Securities [Member]
Assets:
Investments	21	18
Quoted Prices in Active Markets (Level 1) [Member] \| Investments - other [Member]
Assets:
Investments	3,829	3,347
Quoted Prices in Active Markets (Level 1) [Member] \| Mark To Market Energy Assets Including Put Option [Member]
Assets:
Mark-to-market energy assets	0	0
Significant Other Observable Inputs (Level 2) [Member] \| Mark-to-market energy liabilities [Member]
Liabilities:
Mark-to-market energy liabilities	256	433
Significant Other Observable Inputs (Level 2) [Member] \| Investments in guaranteed income fund [Member]
Assets:
Investments	0	0
Significant Other Observable Inputs (Level 2) [Member] \| Equity Securities [Member]
Assets:
Investments	0	0
Significant Other Observable Inputs (Level 2) [Member] \| Investments - other [Member]
Assets:
Investments	0	0
Significant Other Observable Inputs (Level 2) [Member] \| Mark To Market Energy Assets Including Put Option [Member]
Assets:
Mark-to-market energy assets	405	153
Significant Unobservable Inputs (Level 3) [Member] \| Mark-to-market energy liabilities [Member]
Assets:
Mark-to-market energy assets	0	0
Significant Unobservable Inputs (Level 3) [Member] \| Investments in guaranteed income fund [Member]
Assets:
Investments	475	279
Significant Unobservable Inputs (Level 3) [Member] \| Equity Securities [Member]
Assets:
Investments	0	0
Significant Unobservable Inputs (Level 3) [Member] \| Investments - other [Member]
Assets:
Investments	0	0
Recurring [Member] \| Mark-to-market energy liabilities [Member]
Liabilities:
Mark-to-market energy liabilities	256	433
Recurring [Member] \| Investments in guaranteed income fund [Member]
Assets:
Investments	475	279
Recurring [Member] \| Equity Securities [Member]
Assets:
Investments	21	18
Recurring [Member] \| Investments - other [Member]
Assets:
Investments	3,829	3,347
Recurring [Member] \| Mark To Market Energy Assets Including Put Option [Member]
Assets:
Mark-to-market energy assets	$ 405	$ 153

Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 279	$ 287
Purchases and adjustments	112	49
Transfers	(88)	(3)
Distribution	(8)	0
Investment Income	4	2
Ending Balance	$ 475	$ 335

Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Long-term debt including current maturities	$ 151.8	$ 153.7
Fair value of long-term debt	$ 174.3	$ 165.1

Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($)
$ in Thousands

Jun. 30, 2016

Dec. 31, 2015

Debt Instrument [Line Items]

Total long-term debt

$ 151,800

$ 153,700

Capital lease obligation

4,153

4,824

Total Long-term debt

156,252

158,490

Less: current maturities

(12,075)

(9,151)

Less: debt issuance costs

(312)

(333)

Total long-term debt, net of current maturities

143,865

149,006

9.08% bond, due June 1, 2022 [Member]

Debt Instrument [Line Items]

Total long-term debt

^[1]

7,976

7,973

6.64% note, due October 31, 2017 [Member]

Debt Instrument [Line Items]

Total long-term debt

5,455

5.50% note, due October 12, 2020 [Member]

Debt Instrument [Line Items]

Total long-term debt

10,000

5.93% note, due October 31, 2023 [Member]

Debt Instrument [Line Items]

Total long-term debt

22,500

24,000

5.68% note, due June 30, 2026 [Member]

Debt Instrument [Line Items]

Total long-term debt

29,000

Uncollateralized Senior Notes Due On May Two Thousand Twenty Eight [Member]

Debt Instrument [Line Items]

Total long-term debt

7,000

Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]

Debt Instrument [Line Items]

Total long-term debt

20,000

Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member]

Debt Instrument [Line Items]

Total long-term debt

50,000

Promissory note [Member]

Debt Instrument [Line Items]

Total long-term debt

$ 168

$ 238

[1]	FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities.

Long-Term Debt - Outstanding Long-Term Debt- Supplemental Information (Detail)	6 Months Ended
	Jun. 30, 2016
9.08% bond, due June 1, 2022 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	9.08%
Debt instrument, maturity date	Jun. 01, 2022
6.64% note, due October 31, 2017 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.64%
Debt instrument, maturity date	Oct. 31, 2017
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 02, 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

Long-Term Debt - Additional Information (Detail) - Notes Payable, Other Payables [Member] - Shelf Notes [Member] - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	May 13, 2016
Debt Instrument [Line Items]
Period to purchase	3 years
Senior notes	$ 150.0	$ 70.0
Maturity date term	20 years
Debt Instrument, Interest Rate, Stated Percentage		3.25%

Short-Term Borrowing - Additional Information (Details) - USD ($)		3 Months Ended	6 Months Ended
	Oct. 08, 2015	Jun. 30, 2016	Jun. 30, 2016	Dec. 31, 2015
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Current borrowing capacity	$ 150,000,000.0
Expiration period	5 years
Expiration period from anniversary (up to)		2 years
Maximum borrowing capacity		$ 200,000,000.0	$ 200,000,000.0
Uncommitted Line Of Credit Facility One [Member]
Short-term Debt [Line Items]
Line of credit		$ 40,000,000	$ 40,000,000	$ 35,000,000
London Interbank Offered Rate (LIBOR) [Member] \| Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Interest rate			125.00%
Base Rate [Member] \| Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Interest rate			25.00%