Amount after tax of reclassification adjustment from accumulated other comprehensive (income) loss for prior service cost (credit) related to pension and other postretirement benefit plans.

+ References+ Details

Amount after tax of reclassification adjustment from accumulated other comprehensive income (loss) for actuarial gain (loss) related to pension and other postretirement benefit plans.

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Beginning Balances at Dec. 31, 2013

Amount after tax of increase (decrease) in accumulated gain (loss) from derivative instruments designated and qualifying as the effective portion of cash flow hedges and an entity's share of an equity investee's increase (decrease) in deferred hedging gain (loss).

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Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Tax expense recognized on the amortization of prior service cost	$ (7)	$ (6)
Tax expense recognized on the net gain (loss)	62	27
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ 17	$ 0

Condensed Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Property, Plant and Equipment
Regulated energy	$ 779,394	$ 766,855
Unregulated energy	84,386	84,773
Other	19,459	18,497
Total property, plant and equipment	883,239	870,125
Less: Accumulated depreciation and amortization	(198,181)	(193,369)
Plus: Construction work in progress	24,137	13,006
Net property, plant and equipment	709,195	689,762
Current Assets
Cash and cash equivalents	16,170	4,574
Accounts receivable (less allowance for uncollectible accounts of $1,274 and $1,120, respectively)	62,062	53,300
Accrued revenue	12,869	13,617
Propane inventory, at average cost	4,550	7,250
Other inventory, at average cost	4,411	3,699
Storage gas prepayments	910	4,258
Prepaid expenses	4,510	6,652
Income taxes receivable	0	18,806
Mark-to-market energy assets	46	1,055
Regulatory assets	7,472	8,967
Other current assets	294	195
Total current assets	113,294	122,373
Deferred Charges and Other Assets
Investments, at fair value	3,770	3,678
Regulatory assets	78,113	78,136
Goodwill	4,952	4,952
Other intangible assets, net	2,316	2,404
Receivables and other deferred charges	2,067	3,164
Total deferred charges and other assets	91,218	92,334
Total Assets	913,707	904,469
Stockholders' equity
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)	7,119	7,100
Additional paid-in capital	156,749	156,581
Retained earnings	159,446	142,317
Accumulated other comprehensive loss	(5,568)	(5,676)
Deferred compensation obligation	1,715	1,258
Treasury stock	(1,715)	(1,258)
Total stockholders' equity	317,746	300,322
Long-term debt, net of current maturities	158,083	158,486
Total capitalization	475,829	458,808
Current Liabilities
Current portion of long-term debt	9,116	9,109
Short-term borrowing	66,772	88,231
Accounts payable	46,284	44,610
Accrued compensation	4,845	10,076
Accrued interest	3,109	1,352
Dividends payable	3,950	3,939
Accrued Income Taxes, Current	2,946	0
Deferred Tax Liabilities, Net, Current	586	832
Mark-to-market energy liabilities	20	1,018
Regulatory liabilities	18,621	3,268
Customer deposits and refunds	22,307	25,197
Other accrued liabilities	7,797	6,603
Total current liabilities	186,353	194,235
Deferred Credits and Other Liabilities
Deferred income taxes	160,055	160,232
Regulatory liabilities	43,518	43,419
Environmental liabilities	9,147	8,923
Other pension and benefit costs	34,798	35,027
Deferred investment credits and Other liabilities	4,007	3,825
Total deferred credits and other liabilities	251,525	251,426
Other commitments and contingencies (Note 6)
Total Capitalization and Liabilities	$ 913,707	$ 904,469

Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 1,282	$ 1,120
Common stock, par value (in usd per share)	$ 0.4867	$ 0.4867
Common stock, shares authorized	25,000,000	25,000,000

Condensed Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Operating Activities
Net Income	$ 21,109	$ 17,681
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	6,975	6,635
Depreciation and accretion included in other costs	1,689	1,783
Deferred income taxes, net	(496)	(231)
Realized gain on commodity contracts/sales of assets/investments	(840)	(8)
Unrealized loss on investments/commodity contracts	21	31
Employee benefits	300	162
Share-based compensation	537	638
Other, net	4	(1)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	(8,014)	(3,647)
Propane inventory, storage gas and other inventory	5,337	8,243
Increase (Decrease) in Regulatory Assets and Liabilities	(16,185)	(200)
Prepaid expenses and other current assets	2,500	2,185
Accounts payable and other accrued liabilities	2,376	4,821
Income taxes receivable	21,753	11,565
Customer deposits and refunds	(2,890)	(1,735)
Accrued compensation	(5,262)	(3,505)
Other assets and liabilities, net	2,753	1,246
Net cash provided by operating activities	64,037	46,063
Investing Activities
Property, plant and equipment expenditures	(27,508)	(18,528)
Proceeds from sales of assets	198	29
Environmental expenditures	(49)	(26)
Net cash used in investing activities	(27,359)	(18,525)
Financing Activities
Common stock dividends	(3,573)	(3,369)
Purchase of stock for Dividend Reinvestment Plan	27	(341)
Change in cash overdrafts due to outstanding checks	(2,191)	(501)
Net borrowing (repayment) under line of credit agreements	(19,269)	(21,696)
Repayment of long-term debt	(76)	(196)
Net cash used in financing activities	(25,082)	(26,103)
Net Decrease in Cash and Cash Equivalents	11,596	1,435
Cash and Cash Equivalents-Beginning of Period	4,574	3,356
Cash and Cash Equivalents-End of Period	$ 16,170	$ 4,791

Condensed Consolidated Statements of Stockholders' Equity (USD $)
In Thousands, except Share data, unless otherwise specified

Total

Common Stock [Member]

Additional Paid-In Capital [Member]

Retained Earnings [Member]

Accumulated Other Comprehensive Loss [Member]

Deferred Compensation [Member]

Treasury Stock [Member]

$ 278,773

$ 4,691

$ 152,341

$ 124,274

$ (2,533)

$ 1,124

$ (1,124)

Beginning Balances, shares at Dec. 31, 2013

^[1]

14,457,345

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

Net Income

36,092

Other comprehensive loss

(3,143)

Dividend declared, shares

Dividend declared ($0.27 and $1.067 per share for the first quarter of 2015 and for the year ended December 31, 2014 respectively)

(15,675)

Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan

43,367

Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan

1,860

1,844

Conversion of debentures, shares

^[1]

47,313

Conversion of debentures

535

520

Share-based compensation, shares

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

40,686

Share-based compensation and tax benefit

^[2],[3]

1,889

1,876

Stock Split in Form of Stock Dividend Adjustment to Retained Earnings

(9)

2,365

(2,374)

Treasury stock activities

134

(134)

Ending Balances at Dec. 31, 2014

300,322

7,100

156,581

142,317

(5,676)

1,258

(1,258)

Ending Balances, shares at Dec. 31, 2014

^[1]

14,588,711

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

Net Income

21,109

Other comprehensive loss

108

Dividend declared, shares

8,059

Dividend declared ($0.27 and $1.067 per share for the first quarter of 2015 and for the year ended December 31, 2014 respectively)

(3,588)

388

(3,980)

Share-based compensation, shares

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

31,219

Share-based compensation and tax benefit

^[2],[3]

(205)

(220)

Treasury stock activities

457

(457)

Ending Balances at Mar. 31, 2015

$ 317,746

$ 7,119

$ 156,749

$ 159,446

$ (5,568)

$ 1,715

$ (1,715)

Ending Balances, shares at Mar. 31, 2015

^[1]

14,627,989

[1]	Includes 53,442 and 53,125 shares at March 31, 2015 and December 31, 2014, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.
[2]	The shares issued under the SICP are net of shares withheld for employee taxes. For the three months ended March 31, 2015 and for the year ended December 31, 2014, we withheld 12,620 and 12,687 shares, respectively, for taxes.
[3]	Includes amounts for shares issued for Directors’ compensation.

Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2015	Dec. 31, 2014
Deferred compensation plan held Rabbi Trust (in shares)	53,442	53,125
Shares issued under the performance incentive plan withheld for employee taxes (in shares)	12,620	12,687
Cash Dividends Declared Per Share of Common Stock (in usd per share)	$ 0.27	$ 1.07

Summary of Accounting Policies Summary of Accounting Policies (Notes)	3 Months Ended
	Mar. 31, 2015
Accounting Policies [Abstract]
Significant Accounting Policies [Text Block]	Summary of Accounting Policies Basis of Presentation References in this document to the “Company,” “Chesapeake,” “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, 2014. 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. Reclassifications As a result of the sale of our advanced information services subsidiary in October 2014, we changed our operating segments (see Note 7, Segment Information). We reclassified certain amounts in the condensed consolidated income statement and condensed consolidated cash flows statement for the three months ended March 31, 2014 to conform to the current year's presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements. Stock Dividend On July 2, 2014, our Board of Directors approved a three-for-two stock split of our outstanding common stock to be effected in the form of a stock dividend. Each stockholder as of the close of business on the record date, August 13, 2014, received one additional share of common stock for every two shares of common stock owned. The additional shares were distributed on September 8, 2014. All share and per share data in this Form 10-Q are presented on a post-split basis. As a result of the stock split, we reclassified approximately $2.4 million from retained earnings to common stock in September of 2014, which represents $0.4867 par value per share of the shares issued in the stock split. FASB Statements and Other Authoritative Pronouncements 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 April 1, 2015, the FASB proposed to defer the implementation of this standard by one year, which if approved, would result in the new standard being effective for public entities for their 2018 interim and annual financial statements. We are assessing the impact this standard will have on our financial position and results of operations. 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 is effective for our interim and annual financial statements issued beginning January 1, 2016. Early adoption is permitted for financial statements that have not been previously issued. As of March 31, 2015, we had $333,000 of unamortized debt issuance costs included in the accompanying condensed consolidated balance sheets. Upon adoption of ASU 2015-03, this will be presented as a deduction from long-term debt, net of current maturities.

Calculation of Earnings Per Share

The entire disclosure for all significant accounting policies of the reporting entity.

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Calculation of Earnings Per Share

3 Months Ended

Mar. 31, 2015

Earnings Per Share [Abstract]



	Three Months Ended
	March 31,
	2015		2014
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	21,109	$	17,681
Weighted average shares outstanding	14,604,841		14,487,646
Basic Earnings Per Share	$	1.45	$	1.22
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	21,109	$	17,681
Reconciliation of Denominator:
Weighted shares outstanding—Basic	14,604,841		14,487,646
Effect of dilutive securities:
Share-based compensation	51,469		52,505
Adjusted denominator—Diluted	14,656,310		14,540,151
Diluted Earnings Per Share	$	1.44	$	1.22

As discussed in Note 1, Summary of Accounting Policies, previously reported share and per share amounts have been restated in the accompanying condensed consolidated financial statements and related notes to reflect the stock split effected in the form of a stock dividend.

The entire disclosure for earnings per share.

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Acquisitions	3 Months Ended
Acquisitions	Mar. 31, 2015
Business Combinations [Abstract]
Acquisitions	Acquisitions Gatherco Acquisition On April 1, 2015, we completed the merger with Gatherco, in which Gatherco merged with Aspire Energy of Ohio, a newly formed, wholly-owned subsidiary of Chesapeake. 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, and paid $27.6 million in cash. We also acquired $6.7 million of Gatherco's cash at the time of the closing and assumed $1.7 million of Gatherco’s debt, which was paid off shortly after closing. We incurred $1.3 million in transaction costs associated with this merger, $514,000 of which was expensed in the three months ended March 31, 2015. Transactions costs are included in operations expense in the accompanying condensed consolidated statement of income. As a result of this merger, Aspire Energy of Ohio provides natural gas midstream services through 16 gathering systems and over 2,000 miles of pipelines in Central and Eastern Ohio. Aspire Energy of Ohio provides natural gas gathering services and natural gas liquid processing services to over 300 producers, and supplies natural gas to over 6,000 customers in Ohio through the Consumers Gas Cooperative, an independent entity, which Aspire Energy of Ohio manages under an operating agreement. The results of Aspire Energy of Ohio are projected to have a minimal impact on our earnings per share in 2015, since the merger was completed after the first quarter. The first quarter includes key winter months, which have historically represented a significant portion of Gatherco's annual earnings. This acquisition is expected to be accretive to our earnings in the first full year of operations. We are in the process of finalizing our evaluation of the tangible and intangible assets acquired and liabilities assumed, as well as the initial purchase price allocation as of the acquisition date, including the determination of any resulting goodwill. Therefore, this information cannot be provided at this time.

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).

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Rates and Other Regulatory Activities	3 Months Ended
Rates and Other Regulatory Activities	Mar. 31, 2015
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’s 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 There were no significant rates and other regulatory activities in Delaware during the first quarter of 2015. Maryland There were no significant rates and other regulatory activities in Maryland during the first quarter of 2015. Florida On January 16, 2015, Chesapeake's Florida natural gas distribution division filed for approval with the Florida PSC a contract with Peninsula Pipeline, which is one of Chesapeake's subsidiaries, for additional natural gas transportation services in the vicinity of Haines City located in Polk County, Florida. This petition was approved by the Florida PSC at the Agenda Conference on May 5, 2015. Eastern Shore White Oak Mainline Expansion Project: On November 21, 2014, Eastern Shore submitted an application to the FERC for a CP seeking authorization to construct, own, operate and maintain the White Oak mainline expansion project. The project is designed to provide 45,000 Dts/d of firm transportation service to an industrial customer 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. The estimated cost of the project is $29.8 million. On January 22, 2015, the FERC issued a Notice of Intent to Prepare an Environmental Assessment for this project. The FERC solicited public participation with the comment period ending on February 23, 2015.

Environmental Commitments and Contingencies	3 Months Ended
Environmental Commitments and Contingencies	Mar. 31, 2015
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. 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 March 31, 2015, we had approximately $10.1 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 $9.8 million of which has been recovered as of March 31, 2015, leaving approximately $4.2 million in regulatory assets for future recovery of environmental costs from FPU’s customers. In addition to the FPU MGP sites, we had $369,000 in environmental liabilities at March 31, 2015 related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of March 31, 2015, we had approximately $216,000 in regulatory and other assets for future recovery through Chesapeake’s rates. During the first quarter of 2015, we established $273,000 in environmental liabilities related to Chesapeake’s 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’s rates, although we have not yet sought approval for recovery by the Delaware PSC. As of March 31, 2015, we had approximately $252,000 in environmental liability and $273,000 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 currently 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. It is anticipated 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. 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 the MGP at this 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 March 31, 2015, 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 remediation 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 has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement. As of March 31, 2015, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be $24,000. However, 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 to liability for costs exceeding $13.0 million to implement the final remedy for this site, as provided in the Third Participation Agreement, or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of March 31, 2015. 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 new 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 4, 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 Remedial Action Plan approval order which specified that a limited semi-annual monitoring program be conducted. The most recent groundwater-monitoring event was conducted on March 23, 2015. Natural attenuation default criteria were met at all locations sampled. The next semi-annual sampling event is scheduled for September 2015. Although the duration of the FDEP-required limited NAM cannot be determined with certainty, it is anticipated 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. It is anticipated 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 shut-down 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 Semi-Annual RAP Implementation Status Report submitted January 8, 2015. Although specific remedial actions have not yet been identified, we estimate that future remediation costs for the subsurface soils and groundwater at the site should not exceed $443,000, 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. We therefore 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, the DNREC notified us that it will be conducting a facility evaluation of a former MGP site in Seaford, Delaware. In a report issued during January 2015, DNREC provided the evaluation of this site, which found contaminants impacting the groundwater. We are planning to enter this site into the Voluntary Cleanup Program. We estimate the cost of potential remedial actions, based on the findings of the DNREC report, to be $273,000 to $465,000. Other We are in discussions with the MDE regarding 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.

The entire disclosure for environmental loss contingencies, such as presence of hazardous waste, relevant information from reports issued by regulators, and estimated costs to achieve compliance with regulatory requirements. This element may be used for all of an entity's disclosures about environmental loss contingencies.

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Other Commitments and Contingencies	3 Months Ended
Other Commitments and Contingencies	Mar. 31, 2015
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. Our Delaware and Maryland natural gas distribution divisions have a contract through March 31, 2017 with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage capacity. In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term. Approximately four years remain under this contract. 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. 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’s 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 is contingently liable to FGT and Gulfstream, should any party that acquired the capacity through release fail to pay the capacity charge. In May 2014, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2015. PESCO is currently obtaining and reviewing proposals from suppliers and anticipates executing new agreements before the existing agreements expire. 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 March 31, 2015, FPU was in compliance with all of the requirements of its fuel supply contracts. Corporate Guarantees The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our obligations, including the obligations of our subsidiaries. The maximum authorized liability under such guarantees and letters of credit is $50.0 million. We have issued corporate guarantees to certain vendors of our subsidiaries, the largest portion of which is for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases, respectively, 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 March 31, 2015 was $31.1 million, with the guarantees expiring on various dates through February 28, 2016. Chesapeake also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under the 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). In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million, which expires on September 12, 2015, related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for $1.1 million, which expires on October 31, 2015, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company in 2010, we renewed and decreased the letter of credit for $40,000 to our former primary insurance company, which will expire on June 1, 2015. There have been no draws on these letters of credit as of March 31, 2015. 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. We provided a letter of credit for $2.3 million to TETLP related to the precedent agreement and firm transportation service agreement between our Delaware and Maryland divisions. 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 March 31, 2015, we maintained a liability of $100,000 related to unrecognized income tax benefits and $578,000 related to contingencies for taxes other than income. As of December 31, 2014, we maintained a liability of $100,000 related to unrecognized income tax benefits and $724,000 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.

The entire disclosure for commitments and contingencies.

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Segment Information

3 Months Ended

Mar. 31, 2015

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. 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.

We had previously identified "Other" as a separate reportable segment, which consisted primarily of our advanced information services subsidiary. As a result of the sale of that subsidiary on October 1, 2014, "Other" is no longer a separate reportable segment.

The following table presents financial information about our reportable segments:



	Three Months Ended
	March 31,
	2015		2014
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	109,292	$	101,874
Unregulated Energy segment	60,789		79,874
Other businesses	—		4,589
Total operating revenues, unaffiliated customers	$	170,081	$	186,337
Intersegment Revenues ⁽¹⁾
Regulated Energy segment	$	290	$	292
Unregulated Energy segment	207		99
Other businesses	221		253
Total intersegment revenues	$	718	$	644
Operating Income
Regulated Energy segment	$	22,182	$	21,091
Unregulated Energy segment	15,229		10,858
Other businesses and eliminations	97		(326		)
Total operating income	37,508		31,623
Other income, net of other expenses	133		6
Interest	2,448		2,155
Income before Income Taxes	35,193		29,474
Income taxes	14,084		11,793
Net Income	$	21,109	$	17,681


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



(in thousands)	March 31, 2015		December 31, 2014
Identifiable Assets
Regulated Energy segment	$	788,600	$	796,021
Unregulated Energy segment	89,950		84,732
Other businesses and eliminations	35,157		23,716
Total identifiable assets	$	913,707	$	904,469

Our operations are entirely domestic.

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.

Accumulated Other Comprehensive Income (Loss)

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+ Details

Accumulated Other Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 2015

Equity [Abstract]

Defined benefit pension and postretirement plan items and unrealized gains (losses) of our propane swap agreements and call options, 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 three months ended March 31, 2015 and 2014. 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, 2014	$	(5,643	)	$	(33	)	$	(5,676	)
Other comprehensive loss before reclassifications	—			(7		)	(7		)
Amounts reclassified from accumulated other comprehensive loss	82			33			115
Net current-period other comprehensive income (loss)	82			26			108
As of March 31, 2015	$	(5,561	)	$	(7	)	$	(5,568	)



	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges		Total
(in thousands)
As of December 31, 2013	$	(2,533	)	$	—	$	(2,533	)
Other comprehensive loss before reclassifications	—			—		—
Amounts reclassified from accumulated other comprehensive loss	31			—		31
Net current-period other comprehensive income	31			—		31
As of March 31, 2014	$	(2,502	)	$	—	$	(2,502	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three months ended March 31, 2015 and 2014. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement



	Three Months Ended
	March 31,
	2015			2014
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost ⁽¹⁾	$	17		$	14
Net loss ⁽¹⁾	(154		)	(66		)
Total before income taxes	(137		)	(52		)
Income tax benefit	55			21
Net of tax	$	(82	)	$	(31	)

Gains and losses on commodity contracts cash flow hedges
Propane swap agreements ⁽²⁾	$	12		$	—
Call options ⁽²⁾	(55		)	—
Total before income taxes	(43		)	—
Income tax benefit	17			—
Net of tax	(26		)	—
Total reclassifications for the period	$	(108	)	$	(31	)

⁽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.

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.

Compensation and Retirement Disclosure [Abstract]

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Employee Benefit Plans

3 Months Ended

Mar. 31, 2015

Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three months ended March 31, 2015 and 2014 are set forth in the following tables:



	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended March 31,	2015			2014			2015			2014			2015		2014		2015			2014			2015		2014
(in thousands)
Interest cost	$	102		$	107		$	626		$	647		$	23	$	23	$	11		$	13		$	15	$	17
Expected return on plan assets	(135		)	(133		)	(777		)	(773		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			2		5		(19		)	(19		)	—		—
Amortization of net loss	90			37			114			—			25		12		17			17			2		—
Net periodic cost (benefit)	57			11			(37		)	(126		)	50		40		9			11			17		17
Amortization of pre-merger regulatory asset	—			—			190			190			—		—		—			—			2		2
Total periodic cost	$	57		$	11		$	153		$	64		$	50	$	40	$	9		$	11		$	19	$	19

We expect to record pension and postretirement benefit costs of approximately $1.2 million for 2015. Included in these costs is $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 merger. 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 $3.4 million and $3.6 million at March 31, 2015 and December 31, 2014, respectively. The amortization included in pension expense is also being added to a net periodic loss of $381,000, which will increase our total expected benefit costs to $1.2 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 merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake’s operations is recorded to accumulated other comprehensive income (loss). The following table presents the amounts included in the regulatory asset and accumulated other comprehensive income (loss) that were recognized as components of net periodic benefit cost during the three months ended March 31, 2015 and 2014:



For the Three Months Ended March 31, 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	90		114		25		17			2		248
Total recognized in net periodic benefit cost	$	90	$	114	$	27	$	(2	)	$	2	$	231
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	90	$	22	$	27	$	(2	)	$	—	$	137
Recognized from regulatory asset	—		92		—		—			2		94
Total	$	90	$	114	$	27	$	(2	)	$	2	$	231



For the Three Months Ended March 31, 2014	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	5	$	(19	)	$	—	$	(14	)
Net loss	37		—		12		17			—		66
Total recognized in net periodic benefit cost	$	37	$	—	$	17	$	(2	)	$	—	$	52
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	37	$	—	$	17	$	(2	)	$	—	$	52
Recognized from regulatory asset	—		—		—		—			—		—
Total	$	37	$	—	$	17	$	(2	)	$	—	$	52


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

During the three months ended March 31, 2015, we contributed $104,000 to the Chesapeake Pension Plan and $343,000 to the FPU Pension Plan. We expect to contribute a total of $475,000 and $1.6 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2015, which represent the minimum contribution payments required during the year.

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 months ended March 31, 2015, were $33,000. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake Pension SERP in 2015. Cash benefits paid for the Chesapeake Postretirement Plan, primarily for medical claims for the three months ended March 31, 2015, were $15,000. We have estimated that approximately $79,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2015. Cash benefits paid for the FPU Medical Plan, primarily for medical claims for the three months ended March 31, 2015, were $92,000. We estimate that approximately $207,000 will be paid for such benefits under the FPU Medical Plan in 2015.

The entire disclosure for pension and other postretirement benefits.

+ References+ Details

Investments	3 Months Ended
Investments	Mar. 31, 2015
Investments, Debt and Equity Securities [Abstract]
Investments	Investments The investment balances at March 31, 2015 and December 31, 2014, consist of the Rabbi Trust associated with our Deferred Compensation Plan. We classify these investments as trading securities and report them at their fair value. For the three months ended March 31, 2015 and 2014, we recorded a net unrealized gain of $104,000 and $37,000, respectively, in other income in the condensed consolidated statements of income related to these investments. 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 Rabbi Trust.

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

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

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+ Details

Share-Based Compensation

3 Months Ended

Mar. 31, 2015

Share-Based Compensation

Since May 2, 2013, our non-employee directors and key employees have been granted share-based awards through our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the date it was granted and the number of shares to be issued at the end of the service period.

The table below presents the amounts included in net income related to share-based compensation expense for the three months ended March 31, 2015 and 2014:



	Three Months Ended
	March 31,
	2015			2014
(in thousands)
Awards to non-employee directors	$	150		$	124
Awards to key employees	387			514
Total compensation expense	537			638
Less: tax benefit	(217		)	(257		)
Share-based compensation amounts included in net income	$	320		$	381

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 date of the grant. 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 2014, each of our non-employee directors received an annual retainer of 1,209 shares of common stock under the SICP. At March 31, 2015, there was $50,000 of unrecognized compensation expense related to these awards. This expense was fully recognized over the directors' remaining service periods ending April 30, 2015.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the three months ended March 31, 2015:



	Number of Shares		Weighted Average Fair Value
Outstanding—December 31, 2014	123,038		$	32.60
Granted	29,763		$	48.90
Vested	(43,839	)	$	28.01
Expired	(2,520	)	$	28.83
Outstanding—March 31, 2015	106,442		$	38.17

In January 2015, our Board of Directors granted awards of 29,763 shares to key employees under the SICP. The shares granted in January 2015 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2017. 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 date each award is granted. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

At March 31, 2015, the aggregate intrinsic value of the SICP awards granted to key employees was $5.4 million. At March 31, 2015, there was $2.3 million of unrecognized compensation cost related to these awards, which is expected to be recognized during 2015 through 2017.

Derivative Instruments and Hedging Activities Disclosure [Abstract]

The entire disclosure for compensation-related costs for equity-based compensation, which may include disclosure of policies, compensation plan details, allocation of equity compensation, incentive distributions, equity-based arrangements to obtain goods and services, deferred compensation arrangements, employee stock ownership plan details and employee stock purchase plan details.

+ References+ Details

Derivative Instruments

3 Months Ended

Mar. 31, 2015

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. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory or cash flow hedges of its future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of March 31, 2015, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Hedging Activities in 2015

In March 2015, Sharp entered into a put option to protect against a decline in propane prices and related potential inventory losses associated with 630,000 gallons committed to be purchased for the propane price cap program in the upcoming heating season. The put option is exercised if propane prices fall below the strike price of $0.4950 per gallon in December 2015 through February 2016. We will receive the difference between the market price and the strike price during those months. We paid $43,000 to purchase the put option. We accounted for the put option as a fair value hedge, and there is no ineffective portion of this hedge. As of March 31, 2015, the put option had a fair value of $38,000. The change in fair value of the put option effectively reduced our propane inventory balance.

In March 2015, 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 receives the difference between the index prices (Mont Belvieu prices in December 2015 through February 2016) and the swap price of $0.5950 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 March 31, 2015, the swap agreement had a liability fair value of $12,000. The change in the fair value of the swap agreement is recorded as unrealized gain/loss in other comprehensive income (loss).

Hedging Activities in 2014

In August and October 2014, Sharp entered into call options to protect against an increase in propane prices associated with 1.3 million gallons we expected to purchase at market-based prices to supply the demands of our propane price cap program customers. The retail price that we can charge to those customers during the heating season is capped at a pre-determined level. We would have exercised the call options if the propane prices had risen above the strike price of $1.0875 per gallon in December 2014 through February of 2015 and $1.0650 per gallon in January through March 2015. In that event, we would have received the difference between the market price and the strike price during those months. We paid $98,000 to purchase the call options, which expired without exercise as the market prices were below the strike prices. We accounted for the call options as cash flow hedges.

In May 2014, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 630,000 gallons we expected to purchase for the upcoming heating season. Under these swap agreements, Sharp would have received the difference between the index prices (Mont Belvieu prices in December 2014 through February 2015) and the swap prices of $1.1350, $1.0975 and $1.0475 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 those 630,000 gallons purchased for the upcoming heating season. We had initially accounted for them as cash flow hedges as the swap agreements met all the requirements. We paid $1.1 million, representing the difference between the market prices and strike prices during those months for the swap agreements. At December 31, 2014, we elected to discontinue hedge accounting on the swap agreements and reclassified $735,000 of unrealized loss from other comprehensive loss to propane cost of sales. Subsequently, we accounted for them as derivative instruments on a mark-to-market basis with the change in the fair value reflected in current period earnings.

In May 2014, Sharp entered into put options to protect against declines in propane prices and related potential inventory losses associated with 630,000 gallons purchased for the propane price cap program in the upcoming heating season. We exercised the put options because the propane prices fell below the strike prices of $1.0350, $0.9975, and $0.9475 per gallon, for each option agreement in December 2014 through February 2015, respectively. We paid $128,000 to purchase the put options and we received $868,000, representing the difference between the market prices and strike prices during those months. We accounted for them as fair value hedges.

Commodity Contracts for Trading Activities

Xeron engages in trading activities using forward and futures contracts. 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 statement of income for the period of change. As of March 31, 2015, we had the following outstanding trading contracts, which we accounted for as derivatives:



	Quantity in	Estimated Market		Weighted Average
At March 31, 2015	Gallons	Prices		Contract Prices
Forward Contracts
Sale	420,000	$	0.4788	$	0.4788
Purchase	421,000	$	0.4775	$	0.4789

Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the second quarter of 2015.

Xeron has 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 March 31, 2015, Xeron had a right to offset $1.9 million and $2.3 million of accounts receivable and accounts payable, respectively, with these two counterparties. At December 31, 2014, Xeron had a right to offset $1.6 million and $1.2 million of accounts receivable and accounts payable, respectively, 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 March 31, 2015 and December 31, 2014, are as follows:



	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2015		December 31, 2014
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	8	$	407
Derivatives designated as fair value hedges
Put option(s)	Mark-to-market energy assets	38		622
Derivatives designated as cash flow hedges
Call option	Mark-to-market energy assets	—		26
Total asset derivatives		$	46	$	1,055



	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2015		December 31, 2014
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	8	$	283
Propane swap agreements	Mark-to-market energy liabilities	—		735
Derivatives designated as cash flow hedges
Propane swap agreement	Mark-to-market energy liabilities	12		—
Total liability derivatives		$	20	$	1,018

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 March 31,
(in thousands)	(Loss) on Derivatives	2015			2014
Derivatives not designated as hedging instruments
Realized gain on forward contracts ⁽¹⁾	Revenue	$	277		$	1,246
Unrealized loss on forward contracts	Revenue	(125		)	(68		)
Call option	Cost of sales	—			137
Propane swap agreements	Cost of sales	(717		)	—
Derivatives designated as fair value hedges
Put options	Cost of sales	506			(20		)
Put option ⁽²⁾	Propane Inventory	(3		)	—
Derivatives designated as cash flow hedges
Propane swap agreement	Other Comprehensive loss	(12		)	—
Call options	Cost of sales	(81		)	—
Total		$	(155	)	$	1,295


⁽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 put 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.

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.

Fair Value of Financial Instruments

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+ Details

Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]

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 March 31, 2015 and December 31, 2014:



			Fair Value Measurements Using:
As of March 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—guaranteed income fund	$	280	$	—	$	—	$	280
Investments—other	$	3,490	$	3,490	$	—	$	—
Mark-to-market energy assets, incl. put/call options	$	46	$	—	$	46	$	—
Liabilities:
Mark-to-market energy liabilities incl. swap agreements	$	20	$	—	$	20	$	—



			Fair Value Measurements Using:
As of December 31, 2014	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—guaranteed income fund	$	287	$	—	$	—	$	287
Investments—other	$	3,391	$	3,391	$	—	$	—
Mark-to-market energy assets, incl. put/call options	$	1,055	$	—	$	1,055	$	—
Liabilities:
Mark-to-market energy liabilities, incl. swap agreements	$	1,018	$	—	$	1,018	$	—

The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of March 31, 2015 and December 31, 2014:

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- 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 and swap agreements—The fair value of the propane put/call options and swap agreements are determined 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 three months ended March 31, 2015 and 2014:



	Three Months Ended March 31,
	2015			2014
(in thousands)
Beginning Balance	$	287		$	458
Purchases and adjustments	(5		)	(94		)
Transfers	(3		)	—
Investment income	1			1
Ending Balance	$	280		$	365

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

At March 31, 2015, 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 March 31, 2015, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of $161.4 million. This compares to a fair value of $182.2 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, 2014, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of $161.5 million, compared to the estimated fair value of $180.7 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

Calculation of Basic and Diluted Earnings Per Share

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

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Long-Term Debt

Our outstanding long-term debt is shown below:



	March 31,			December 31,
(in thousands)	2015			2014
FPU secured first mortgage bonds ⁽¹⁾:
9.08% bond, due June 1, 2022	$	7,971		$	7,969
Uncollateralized senior notes:
6.64% note, due October 31, 2017	8,182			8,182
5.50% note, due October 12, 2020	12,000			12,000
5.93% note, due October 31, 2023	27,000			27,000
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	238			314
Capital lease obligation	5,808			6,130
Total long-term debt	167,199			167,595
Less: current maturities	(9,116		)	(9,109		)
Total long-term debt, net of current maturities	$	158,083		$	158,486

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

Summary of Accounting Policies (Policies)	3 Months Ended
Summary of Accounting Policies (Policies)	Mar. 31, 2015
Accounting Policies [Abstract]
Basis of Presentation	Basis of Presentation References in this document to the “Company,” “Chesapeake,” “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, 2014. 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. Reclassifications As a result of the sale of our advanced information services subsidiary in October 2014, we changed our operating segments (see Note 7, Segment Information). We reclassified certain amounts in the condensed consolidated income statement and condensed consolidated cash flows statement for the three months ended March 31, 2014 to conform to the current year's presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements. Stock Dividend On July 2, 2014, our Board of Directors approved a three-for-two stock split of our outstanding common stock to be effected in the form of a stock dividend. Each stockholder as of the close of business on the record date, August 13, 2014, received one additional share of common stock for every two shares of common stock owned. The additional shares were distributed on September 8, 2014. All share and per share data in this Form 10-Q are presented on a post-split basis. As a result of the stock split, we reclassified approximately $2.4 million from retained earnings to common stock in September of 2014, which represents $0.4867 par value per share of the shares issued in the stock split.
New Accounting Pronouncements, Policy [Policy Text Block]	FASB Statements and Other Authoritative Pronouncements 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 April 1, 2015, the FASB proposed to defer the implementation of this standard by one year, which if approved, would result in the new standard being effective for public entities for their 2018 interim and annual financial statements. We are assessing the impact this standard will have on our financial position and results of operations. 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 is effective for our interim and annual financial statements issued beginning January 1, 2016. Early adoption is permitted for financial statements that have not been previously issued. As of March 31, 2015, we had $333,000 of unamortized debt issuance costs included in the accompanying condensed consolidated balance sheets. Upon adoption of ASU 2015-03, this will be presented as a deduction from long-term debt, net of current maturities.

Calculation of Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2015

Earnings Per Share [Abstract]



	Three Months Ended
	March 31,
	2015		2014
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	21,109	$	17,681
Weighted average shares outstanding	14,604,841		14,487,646
Basic Earnings Per Share	$	1.45	$	1.22
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	21,109	$	17,681
Reconciliation of Denominator:
Weighted shares outstanding—Basic	14,604,841		14,487,646
Effect of dilutive securities:
Share-based compensation	51,469		52,505
Adjusted denominator—Diluted	14,656,310		14,540,151
Diluted Earnings Per Share	$	1.44	$	1.22

Segment Information (Tables)

3 Months Ended

Mar. 31, 2015

Segment Reporting [Abstract]

Schedule of Segment Reporting Information by Segment

The following table presents financial information about our reportable segments:



	Three Months Ended
	March 31,
	2015		2014
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	109,292	$	101,874
Unregulated Energy segment	60,789		79,874
Other businesses	—		4,589
Total operating revenues, unaffiliated customers	$	170,081	$	186,337
Intersegment Revenues ⁽¹⁾
Regulated Energy segment	$	290	$	292
Unregulated Energy segment	207		99
Other businesses	221		253
Total intersegment revenues	$	718	$	644
Operating Income
Regulated Energy segment	$	22,182	$	21,091
Unregulated Energy segment	15,229		10,858
Other businesses and eliminations	97		(326		)
Total operating income	37,508		31,623
Other income, net of other expenses	133		6
Interest	2,448		2,155
Income before Income Taxes	35,193		29,474
Income taxes	14,084		11,793
Net Income	$	21,109	$	17,681


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



(in thousands)	March 31, 2015		December 31, 2014
Identifiable Assets
Regulated Energy segment	$	788,600	$	796,021
Unregulated Energy segment	89,950		84,732
Other businesses and eliminations	35,157		23,716
Total identifiable assets	$	913,707	$	904,469

Changes in Accumulated Other Comprehensive Loss

Tabular disclosure of the profit or loss and total assets for each reportable segment. An entity discloses certain information on each reportable segment if the amounts (a) are included in the measure of segment profit or loss reviewed by the chief operating decision maker or (b) are otherwise regularly provided to the chief operating decision maker, even if not included in that measure of segment profit or loss.

+ References+ Details

Accumulated Other Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2015

Equity [Abstract]



	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	—			(7		)	(7		)
Amounts reclassified from accumulated other comprehensive loss	82			33			115
Net current-period other comprehensive income (loss)	82			26			108
As of March 31, 2015	$	(5,561	)	$	(7	)	$	(5,568	)



	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges		Total
(in thousands)
As of December 31, 2013	$	(2,533	)	$	—	$	(2,533	)
Other comprehensive loss before reclassifications	—			—		—
Amounts reclassified from accumulated other comprehensive loss	31			—		31
Net current-period other comprehensive income	31			—		31
As of March 31, 2014	$	(2,502	)	$	—	$	(2,502	)

Reclassifications out of Accumulated Other Comprehensive Income (Loss)



	Three Months Ended
	March 31,
	2015			2014
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost ⁽¹⁾	$	17		$	14
Net loss ⁽¹⁾	(154		)	(66		)
Total before income taxes	(137		)	(52		)
Income tax benefit	55			21
Net of tax	$	(82	)	$	(31	)

Gains and losses on commodity contracts cash flow hedges
Propane swap agreements ⁽²⁾	$	12		$	—
Call options ⁽²⁾	(55		)	—
Total before income taxes	(43		)	—
Income tax benefit	17			—
Net of tax	(26		)	—
Total reclassifications for the period	$	(108	)	$	(31	)

Employee Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2015

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans



	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended March 31,	2015			2014			2015			2014			2015		2014		2015			2014			2015		2014
(in thousands)
Interest cost	$	102		$	107		$	626		$	647		$	23	$	23	$	11		$	13		$	15	$	17
Expected return on plan assets	(135		)	(133		)	(777		)	(773		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			2		5		(19		)	(19		)	—		—
Amortization of net loss	90			37			114			—			25		12		17			17			2		—
Net periodic cost (benefit)	57			11			(37		)	(126		)	50		40		9			11			17		17
Amortization of pre-merger regulatory asset	—			—			190			190			—		—		—			—			2		2
Total periodic cost	$	57		$	11		$	153		$	64		$	50	$	40	$	9		$	11		$	19	$	19



For the Three Months Ended March 31, 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	90		114		25		17			2		248
Total recognized in net periodic benefit cost	$	90	$	114	$	27	$	(2	)	$	2	$	231
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	90	$	22	$	27	$	(2	)	$	—	$	137
Recognized from regulatory asset	—		92		—		—			2		94
Total	$	90	$	114	$	27	$	(2	)	$	2	$	231



For the Three Months Ended March 31, 2014	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	5	$	(19	)	$	—	$	(14	)
Net loss	37		—		12		17			—		66
Total recognized in net periodic benefit cost	$	37	$	—	$	17	$	(2	)	$	—	$	52
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	37	$	—	$	17	$	(2	)	$	—	$	52
Recognized from regulatory asset	—		—		—		—			—		—
Total	$	37	$	—	$	17	$	(2	)	$	—	$	52

Shares awarded to non-employee directors [Line Items]

Tabular disclosure of one or more of the entity's defined benefit pension plans or one or more other defined benefit postretirement plans, separately for pension plans and other postretirement benefit plans including the entity's schedule of fair value of plan assets for defined benefit or other postretirement plans.

+ References+ Details

Share-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2015

Schedule of Compensation Cost for Share-based Payment Arrangements, Allocation of Share-based Compensation Costs by Plan [Table Text Block]

The table below presents the amounts included in net income related to share-based compensation expense for the three months ended March 31, 2015 and 2014:



	Three Months Ended
	March 31,
	2015			2014
(in thousands)
Awards to non-employee directors	$	150		$	124
Awards to key employees	387			514
Total compensation expense	537			638
Less: tax benefit	(217		)	(257		)
Share-based compensation amounts included in net income	$	320		$	381

Awards to non-employee directors [Member]

Shares awarded to non-employee directors [Line Items]

Schedule of Share-based Compensation, Activity [Table Text Block]

Award to key employees [Member]

Shares awarded to non-employee directors [Line Items]

Schedule of Share-based Compensation, Activity [Table Text Block]

The table below presents the summary of the stock activity for awards to key employees for the three months ended March 31, 2015:



	Number of Shares		Weighted Average Fair Value
Outstanding—December 31, 2014	123,038		$	32.60
Granted	29,763		$	48.90
Vested	(43,839	)	$	28.01
Expired	(2,520	)	$	28.83
Outstanding—March 31, 2015	106,442		$	38.17

Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Outstanding Trading Contracts



	Quantity in	Estimated Market		Weighted Average
At March 31, 2015	Gallons	Prices		Contract Prices
Forward Contracts
Sale	420,000	$	0.4788	$	0.4788
Purchase	421,000	$	0.4775	$	0.4789

Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the second quarter of 2015.

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 March 31, 2015 and December 31, 2014, are as follows:



	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2015		December 31, 2014
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	8	$	407
Derivatives designated as fair value hedges
Put option(s)	Mark-to-market energy assets	38		622
Derivatives designated as cash flow hedges
Call option	Mark-to-market energy assets	—		26
Total asset derivatives		$	46	$	1,055



	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2015		December 31, 2014
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	8	$	283
Propane swap agreements	Mark-to-market energy liabilities	—		735
Derivatives designated as cash flow hedges
Propane swap agreement	Mark-to-market energy liabilities	12		—
Total liability derivatives		$	20	$	1,018

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 March 31,
(in thousands)	(Loss) on Derivatives	2015			2014
Derivatives not designated as hedging instruments
Realized gain on forward contracts ⁽¹⁾	Revenue	$	277		$	1,246
Unrealized loss on forward contracts	Revenue	(125		)	(68		)
Call option	Cost of sales	—			137
Propane swap agreements	Cost of sales	(717		)	—
Derivatives designated as fair value hedges
Put options	Cost of sales	506			(20		)
Put option ⁽²⁾	Propane Inventory	(3		)	—
Derivatives designated as cash flow hedges
Propane swap agreement	Other Comprehensive loss	(12		)	—
Call options	Cost of sales	(81		)	—
Total		$	(155	)	$	1,295

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.

Financial Assets and Liabilities Measured at Fair Value on Recurring Basis

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+ Details

Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2015

Fair Value Disclosures [Abstract]



			Fair Value Measurements Using:
As of March 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—guaranteed income fund	$	280	$	—	$	—	$	280
Investments—other	$	3,490	$	3,490	$	—	$	—
Mark-to-market energy assets, incl. put/call options	$	46	$	—	$	46	$	—
Liabilities:
Mark-to-market energy liabilities incl. swap agreements	$	20	$	—	$	20	$	—



			Fair Value Measurements Using:
As of December 31, 2014	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—guaranteed income fund	$	287	$	—	$	—	$	287
Investments—other	$	3,391	$	3,391	$	—	$	—
Mark-to-market energy assets, incl. put/call options	$	1,055	$	—	$	1,055	$	—
Liabilities:
Mark-to-market energy liabilities, incl. swap agreements	$	1,018	$	—	$	1,018	$	—

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 three months ended March 31, 2015 and 2014:



	Three Months Ended March 31,
	2015			2014
(in thousands)
Beginning Balance	$	287		$	458
Purchases and adjustments	(5		)	(94		)
Transfers	(3		)	—
Investment income	1			1
Ending Balance	$	280		$	365

Outstanding Long-Term Debt

Tabular disclosure of financial instruments measured at fair value, including those classified in shareholders' equity measured on a recurring or nonrecurring basis. Disclosures include, but are not limited to, fair value measurements recorded and the reasons for the measurements, level within the fair value hierarchy in which the fair value measurements are categorized and transfers between levels 1 and 2. Nonrecurring fair value measurements are those that are required or permitted in the statement of financial position in particular circumstances.

+ References+ Details

Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2015

Debt Disclosure [Abstract]

Our outstanding long-term debt is shown below:



	March 31,			December 31,
(in thousands)	2015			2014
FPU secured first mortgage bonds ⁽¹⁾:
9.08% bond, due June 1, 2022	$	7,971		$	7,969
Uncollateralized senior notes:
6.64% note, due October 31, 2017	8,182			8,182
5.50% note, due October 12, 2020	12,000			12,000
5.93% note, due October 31, 2023	27,000			27,000
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	238			314
Capital lease obligation	5,808			6,130
Total long-term debt	167,199			167,595
Less: current maturities	(9,116		)	(9,109		)
Total long-term debt, net of current maturities	$	158,083		$	158,486

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

Summary of Accounting Policies Stock Dividend (Details) (USD $) In Thousands, except Per Share data, unless otherwise specified	12 Months Ended
	Dec. 31, 2014	Mar. 31, 2015
Summary Of Accounting Policies [Line Items]
Stock Split in Form of Stock Dividend Adjustment to Retained Earnings	$ 9
Common Stock, Par or Stated Value Per Share	$ 0.4867	$ 0.4867
Common Stock [Member]
Summary Of Accounting Policies [Line Items]
Stock Split in Form of Stock Dividend Adjustment to Retained Earnings	$ (2,365)

Calculation of Earnings Per Share - Calculation of Basic and Diluted Earnings Per Share (Detail) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Calculation of Basic Earnings Per Share:
Net Income	$ 21,109	$ 17,681	$ 36,092
Weighted shares outstanding - Basic (in shares)	14,604,841	14,487,646
Basic Earnings Per Share (in usd per share)	$ 1.45	$ 1.22
Reconciliation of Numerator:
Net Income	$ 21,109	$ 17,681	$ 36,092
Reconciliation of Denominator:
Weighted shares outstanding - Basic (in shares)	14,604,841	14,487,646
Effect of dilutive securities:
Share-based Compensation (in shares)	51,469	52,505
Adjusted denominator-Diluted (in shares)	14,656,310	14,540,151
Diluted Earnings Per Share (in usd per share)	$ 1.44	$ 1.22

Acquisitions - Additional Information (Detail) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Jan. 30, 2015 mi
Business Acquisition [Line Items]
Business Combination, Separately Recognized Transactions, Additional Disclosures, Acquisition Cost Expensed	$ (514)
Gatherco [Member]
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares	592,970
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned		30,164
Payments to Acquire Businesses, Gross	27,600
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents	6,719
Business Combination Recognized Identifiable Assets Acquired And Liabilities To Be Assumed Long Term Debt		1,700
Business Combination, Separately Recognized Transactions, Additional Disclosures, Acquisition Cost Expensed	$ (1,274)
Number Of Gathering Stations		16
Number of Pipeline Miles		2,000.0
Number of Producers Served		300
Number of Customers Served		6,000

Rates and Other Regulatory Activities - Additional Information (Detail) (White Oak Lateral Mainline Expansion [Member], Eastern Shore [Member], USD $)	12 Months Ended
	Dec. 31, 2014 in mi
White Oak Lateral Mainline Expansion [Member] \| Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Volume The Expansion Project Is Expected to Provide	45,000
Number of Pipeline Miles	7.2
Lateral diamater of pipeline to be installed	16
Horsepower Of Additional Compression	3,550
Estimated capital cost	$ 29.8000

Environmental Commitments and Contingencies - Additional Information (Detail) (USD $)	3 Months Ended
	Mar. 31, 2015 site	Mar. 31, 2014	Dec. 31, 2014
Environmental Commitments And Contingencies [Line Items]
Company's exposure in number of former Manufactured Gas Plant Sites	7
Environmental liabilities	$ 9,147,000		$ 8,923,000
Amount paid for funding requirements	49,000	26,000
Seaford [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	300,000
Regulatory Assets	273,000
Estimated costs of remediation range, minimum	300,000
Estimated costs of remediation range, maximum	500,000
Winter Haven Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental remediation expense	443,000
Additional remediation costs	100,000
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
Environmental remediation expense	24,000
FPU [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	10,100,000
Approval of recovery of environmental costs	14,000,000
Environmental costs recovered	9,800,000
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%
Amount paid for funding requirements	650,000
FPU [Member] \| Manufactured Gas Plant [Member]
Environmental Commitments And Contingencies [Line Items]
Regulatory Assets	4,200,000
Chesapeake [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	369,000
Regulatory Assets	$ 216,000

Environmental Commitments and Contingencies - Additional Information 1 (Detail) (USD $)	3 Months Ended
	Mar. 31, 2015
Key West Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Period of regulatory inactivity	17 years
Costs to resolve liability	$ 50,000
Key West Florida [Member] \| Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Costs to resolve liability	8,000
Pensacola Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Costs to resolve liability	5,000
Winter Haven Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental remediation expense	443,000
Additional remediation costs	100,000
Salisbury Maryland [Member]
Environmental Commitments And Contingencies [Line Items]
Monitoring well remaining maximum cost	$ 5,000

Other Commitments and Contingencies - Additional Information (Detail) (USD $)	3 Months Ended
	Mar. 31, 2015 gal	Dec. 31, 2014
Other Contingencies And Commitments [Line Items]
Number of years to purchase propane under contract	6 years
Annual Estimate Of Volume Of Propane To Be Purchased	6,500,000
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
Document Period End Date	Mar. 31, 2015
Maximum authorized liability under such guarantees and letters of credit	$ 50,000,000
Aggregate guaranteed amount	31,100,000
Draws on letters of credit	0
Liability for Uncertain Tax Positions, Noncurrent	100,000	100,000
Unrecognized Tax Benefits	578,000	700,000
September 12, 2013 [Member]
Other Contingencies And Commitments [Line Items]
Amount of letter of credit to our current primary insurance company	1,000,000
December 2, 2013 [Member]
Other Contingencies And Commitments [Line Items]
Amount of letter of credit to our current primary insurance company	1,100,000
June 1, 2014 [Member]
Other Contingencies And Commitments [Line Items]
Amount of letter of credit to our current primary insurance company	40,000
TETLP Letter of Credit [Member] \| Texas Eastern Transmission, LP [Member]
Other Contingencies And Commitments [Line Items]
Amount of letter of credit to our current primary insurance company	$ 2,300,000

Segment Information - Schedule of Segment Reporting Information by Segment (Detail) (USD $)
In Thousands, unless otherwise specified

3 Months Ended

12 Months Ended

Mar. 31, 2015

Mar. 31, 2014

Dec. 31, 2014

$ 170,081

$ 186,337

170,081

186,337

Other income, net of other expenses

37,508

31,623

133

Interest

2,448

2,155

Income Before Income Taxes

35,193

29,474

Income taxes

14,084

11,793

Net Income

21,109

17,681

36,092

913,707

904,469

Regulated Energy [Member]

22,182

21,091

788,600

796,021

Unregulated Energy [Member]

15,229

10,858

89,950

84,732

Other [Member]

35,157

23,716

Other and eliminations [Member]

(326)

Operating Revenues, Unaffiliated Customers [Member]

170,081

186,337

170,081

186,337

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

109,292

101,874

109,292

101,874

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

60,789

79,874

60,789

79,874

Operating Revenues, Unaffiliated Customers [Member] | Other [Member]

4,589

4,589

Intersegment Revenues [Member]

718

^[1]

644

^[1]

718

^[1]

644

^[1]

Intersegment Revenues [Member] | Regulated Energy [Member]

290

^[1]

292

^[1]

290

^[1]

292

^[1]

Intersegment Revenues [Member] | Unregulated Energy [Member]

207

^[1]

207

^[1]

Intersegment Revenues [Member] | Other [Member]

221

^[1]

253

^[1]

$ 221

^[1]

$ 253

^[1]

[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, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	$ (7)	$ 0
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	(5,676)	(2,533)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	115	31
Net current-period other comprehensive income (loss)	108	31
Ending balance	(5,568)	(2,502)
UnrealizedGainsLossesFromDefinedBenefitPensionAndPostretirementPlanItems [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	(5,643)	(2,533)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	82	31
Net current-period other comprehensive income (loss)	82	31
Ending balance	(5,561)	(2,502)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(7)	0
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	(33)	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	33	0
Net current-period other comprehensive income (loss)	26	0
Ending balance	$ (7)	$ 0

Amortization of pension and postretirement items:

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 $)

3 Months Ended

Mar. 31, 2015

Mar. 31, 2014

Tax benefit

$ (14,084,000)

$ (11,793,000)

Reclassification out of Accumulated Other Comprehensive Income [Member]

Amortization of pension and postretirement items:

Net of tax

(108,000)

(31,000)

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

Amortization of pension and postretirement items:

Prior service cost

17,000

14,000

^[1]

Net loss

154,000

66,000

^[1]

Total before tax

(137,000)

(52,000)

Tax benefit

55,000

21,000

Net of tax

(82,000)

(31,000)

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

(43,000)

Tax benefit

17,000

Net of tax

(26,000)

Other Comprehensive Income Loss Adjustments AOCI Swap Agreements

12,000

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

$ (55,000)

$ 0

[1]	These amounts are included in the computation of net periodic costs (benefits). See Note 9, Employee Benefit Plans, for additional details.

Amount before tax of reclassification adjustment from accumulated other comprehensive (income) loss for prior service cost (credit) related to pension and other postretirement benefit plans.

+ References+ Details

Amount before tax of reclassification adjustment from accumulated other comprehensive income (loss) for actuarial gain (loss) related to pension and other postretirement benefit plans.

+ References+ Details

Employee Benefit Plans - Employee Benefit Plans (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Document Period End Date	Mar. 31, 2015
Amortization of prior service cost	$ (17)	$ (14)
Amortization of net loss	248	66
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	15	17
Expected return on plan assets	0	0
Amortization of prior service cost	0	0
Amortization of net loss	2	0
Net periodic cost (benefit)	17	17
Amortization of pre-merger regulatory asset	2	2
Total periodic cost	19	19
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	11	13
Expected return on plan assets	0	0
Amortization of prior service cost	(19)	(19)
Amortization of net loss	17	17
Net periodic cost (benefit)	9	11
Amortization of pre-merger regulatory asset	0	0
Total periodic cost	9	11
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	23	23
Expected return on plan assets	0	0
Amortization of prior service cost	2	5
Amortization of net loss	25	12
Net periodic cost (benefit)	50	40
Amortization of pre-merger regulatory asset	0	0
Total periodic cost	50	40
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	626	647
Expected return on plan assets	(777)	(773)
Amortization of prior service cost	0	0
Amortization of net loss	114	0
Net periodic cost (benefit)	(37)	(126)
Amortization of pre-merger regulatory asset	190	190
Total periodic cost	153	64
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	102	107
Expected return on plan assets	(135)	(133)
Amortization of prior service cost	0	0
Amortization of net loss	90	37
Net periodic cost (benefit)	57	11
Amortization of pre-merger regulatory asset	0	0
Total periodic cost	$ 57	$ 11

Employee Benefit Plans - Additional Information (Detail) (USD $)	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Document Period End Date	Mar. 31, 2015
Expected pension and postretirement benefit costs	$ 1,150,000
Expected amortization of pre merger regulatory asset	769,000
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	17,000	17,000
Contribution to pension plan	92,000
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	207,000
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	9,000	11,000
Contribution to pension plan	15,000
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	79,000
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	50,000	40,000
Contribution to pension plan	33,000
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	151,000
Consolidated [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	(381,000)
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	57,000	11,000
Contribution to pension plan	104,000
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	475,000
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Unamortized balance of regulatory asset	3,400,000		3,600,000
Defined Benefit Plan, Net Periodic Benefit Cost	(37,000)	(126,000)
Contribution to pension plan	343,000
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	$ 1,551,000

Employee Benefit Plans - Amounts Included in Regulatory Asset and Accumulated Other Comprehensive Income/Loss Recognized as Net Periodic Benefit Cost (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	$ (17)	$ (14)
Net loss	248	66
Recognized from accumulated other comprehensive loss	137	52
Recognized from regulatory asset	94	0
Total recognized in net periodic benefit cost	231	52
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	0	0
Net loss	90	37
Recognized from accumulated other comprehensive loss	90	37
Recognized from regulatory asset	0	0
Total recognized in net periodic benefit cost	90	37
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	0	0
Net loss	114	0
Recognized from accumulated other comprehensive loss	22	0
Recognized from regulatory asset	92	0
Total recognized in net periodic benefit cost	114	0
Chesapeake Pension SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	2	5
Net loss	25	12
Recognized from accumulated other comprehensive loss	27	17
Recognized from regulatory asset	0	0
Total recognized in net periodic benefit cost	27	17
Chesapeake Postretirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	(19)	(19)
Net loss	17	17
Recognized from accumulated other comprehensive loss	(2)	(2)
Recognized from regulatory asset	0	0
Total recognized in net periodic benefit cost	(2)	(2)
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	0	0
Net loss	2	0
Recognized from accumulated other comprehensive loss	0	0
Recognized from regulatory asset	2	0
Total recognized in net periodic benefit cost	$ 2	$ 0

Investments - Schedule of Investment (Detail) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Investment [Line Items]
Investments, at fair value	$ 3,770	$ 3,678

Investments - Additional Information (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Investments, Debt and Equity Securities [Abstract]
Unrealized gain, net of other expenses	$ (104)	$ 37

Share-Based Compensation - Share-Based Compensation Amounts Included in Net Income (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 537	$ 638
Less: tax benefit	(217)	(257)
Share-Based Compensation amounts included in net income	320	381
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	150	124
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 387	$ 514

Share-Based Compensation - Summary of Stock Activity under the SICP (Detail) (USD $)	3 Months Ended
	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Shares, Granted	1,209
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Shares, Outstanding - December 31, 2014	123,038
Number of Shares, Granted	29,763
Number of Shares, Vested	(43,839)
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expired In Period	(2,520)
Number of Shares, Outstanding - March 31, 2015	106,442.000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Fair Value, Outstanding - December 31, 2014	$ 32.60
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	$ 48.90
Weighted Average Fair Value, Vested	$ 28.01
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expirations Weighted Average Grant Date Fair Value	$ 28.83
Weighted Average Fair Value, Outstanding - March 31, 2015	$ 38.17

Share-Based Compensation - Additional Information (Detail) (USD $)	3 Months Ended
	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards, shares	1,209
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$ 2,300,000
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	50,000
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards, shares	29,763
Vesting period	3 years
Intrinsic value of the SICP awards	$ 5,400,000

Derivative Instruments Outstanding Trading Contracts (Details) (Forward Contracts [Member])	Mar. 31, 2015 gal
Sales [Member]
Derivative [Line Items]
Quantity In Gallons	420,000
Weighted Average Contract Prices	0.4788
Sales [Member] \| Minimum [Member]
Derivative [Line Items]
Estimated Market Prices	0.4788
Sales [Member] \| Maximum [Member]
Derivative [Line Items]
Estimated Market Prices	0.4788
Purchase [Member]
Derivative [Line Items]
Quantity In Gallons	421,000
Weighted Average Contract Prices	0.4789
Purchase [Member] \| Minimum [Member]
Derivative [Line Items]
Estimated Market Prices	0.4775
Purchase [Member] \| Maximum [Member]
Derivative [Line Items]
Estimated Market Prices	0.4775

Derivative Instruments - Additional Information (Detail) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2015 gal	Dec. 31, 2014 gal
Propane Swap Agreement [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	630,000	630,000
Strike Price Per Gallon For The Propane Swap Agreements	0.595
Cash Paid On Derivative Settlement	$ 1,057,000
Other Comprehensive Income Loss Adjustments AOCI Swap Agreements		735,000
Call options [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume		1,260,000
Payments for Derivative Instrument, Financing Activities		98,000
Put Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	630,000	630,000
Derivative, Price Risk Option Strike Price	0.4950
Payments for Derivative Instrument, Financing Activities	43,000	128,000
Cash Received On Derivative Settlement	868,000
Forward Contracts [Member]
Derivative [Line Items]
Number Of Counterparties With Master Repurchase Agreements	2	2
Accounts Receivable Subject To Master Netting Arrangement	1,900,000	1,600,000
Accounts Payable Subject To Master Netting Arrangement	2,300,000	1,235,000
Mark To Market Energy Liabilities [Member] \| Propane Swap Agreement [Member]
Derivative [Line Items]
Cash Flow Hedge Derivative Instrument Liabilities at Fair Value	12,000
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	$ 38,000
Strike Price 1 [Member] \| Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements		1.1350
Strike Price 2 [Member] \| Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements		1.0975
Strike Price 3 [Member] \| Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements		1.0475
Put Option Strike Price 1 [Member] \| Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price		1.0350
Put Option Strike Price 2 [Member] \| Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price		0.9975
Put Option Strike Price 3 [Member] \| Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price		0.9475
Strike Price 1 [Member] \| Call options [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price	1.0875
Strike Price 2 [Member] \| Call options [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price	1.0650

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 20	$ 1,018
Energy Marketing Contracts Assets, Current	46	1,055
Mark To Market Energy Assets [Member] \| Forward Contracts [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	8	407
Mark To Market Energy Assets [Member] \| Call options [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	0	26
Mark To Market Energy Assets [Member] \| Put Option [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	38	622
Mark-to-market energy liabilities [Member] \| Forward Contracts [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	8	283
Mark-to-market energy liabilities [Member] \| Propane Swap Agreement [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 12	$ 735

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	$ (155)	$ 1,295
Revenue [Member] \| Derivatives not designated as hedging instruments [Member] \| Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	(125)	(68)
Cost of Sales [Member] \| Derivatives not designated as hedging instruments [Member] \| Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives		137
Gain (Loss) on Sale of Derivatives	0
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	(717)	0
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	(12)	0
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	506
Inventories [Member] \| Derivatives designated as fair value hedges [Member] \| Put/Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives		0
Derivative, Gain (Loss) on Derivative, Net		(20)
Inventory [Member] \| Derivatives designated as fair value hedges [Member] \| Put/Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	(3)
Other Comprehensive Income (Loss) [Member] \| Derivatives designated as fair value hedges [Member] \| Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	(81)	0
Options [Member] \| Revenue [Member] \| Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Sale of Derivatives	$ 277	$ 1,246

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Assets:
Investments	$ 3,770	$ 3,678
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] \| Investments - other [Member]
Assets:
Investments	3,490	3,391
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	20	1,018
Significant Other Observable Inputs (Level 2) [Member] \| Investments in guaranteed income fund [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	46	1,055
Significant Unobservable Inputs (Level 3) [Member] \| Mark-to-market energy liabilities [Member]
Assets:
Mark-to-market energy assets	0	0	0
Significant Unobservable Inputs (Level 3) [Member] \| Investments in guaranteed income fund [Member]
Assets:
Investments	280	287
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	20	1,018
Recurring [Member] \| Investments in guaranteed income fund [Member]
Assets:
Investments	280	287
Recurring [Member] \| Investments - other [Member]
Assets:
Investments	3,490	3,391
Recurring [Member] \| Mark To Market Energy Assets Including Put Option [Member]
Assets:
Mark-to-market energy assets	$ 46	$ 1,055

Fair value, after the effects of master netting arrangements, of a financial asset or other contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes assets not subject to a master netting arrangement and not elected to be offset.

+ References+ Details

Fair value, after the effects of master netting arrangements, of a financial liability or contract with one or more underlyings, notional amount or payment provision or both, and the contract can be net settled by means outside the contract or delivery of an asset. Includes liabilities not subject to a master netting arrangement and not elected to be offset.

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Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 287	$ 458
Purchases and adjustments	(5)	(94)
Transfers	(3)	0
Investment Income	1	1
Ending Balance	$ 280	$ 365

Fair Value of Financial Instruments - Additional Information (Detail) (USD $)	Mar. 31, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Long-term debt including current maturities	$ 161,400,000	$ 161,500,000
Fair value of long-term debt	182,200,000	180,700,000
Total Long-term debt	$ 167,199,000	$ 167,595,000

Carrying amount of long-term debt, net of unamortized discount or premium, including current and noncurrent amounts. Includes, but not limited to, notes payable, bonds payable, debentures, mortgage loans and commercial paper. Excludes capital lease obligations.

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Long-Term Debt - Outstanding Long-Term Debt (Detail) (USD $)
In Thousands, unless otherwise specified

Mar. 31, 2015

Dec. 31, 2014

Capital Lease Obligations

$ 161,400

$ 161,500

5,808

6,130

Total Long-term debt

167,199

167,595

Less: current maturities

(9,116)

(9,109)

Total long-term debt, net of current maturities

158,083

158,486

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

7,971

^[1]

7,969

^[1]

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

8,182

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

12,000

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

27,000

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

29,000

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

7,000

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

20,000

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

50,000

Promissory note [Member]

$ 238

$ 314

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

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Long-Term Debt - Outstanding Long-Term Debt (Parenthetical) (Detail)	3 Months Ended
	Mar. 31, 2015
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) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2015	Mar. 31, 2014	Dec. 31, 2014
Debt Instrument [Line Items]
Total long-term debt	$ 161,400		$ 161,500
Repayments of Long-term Debt	76	196
5.68% note, due June 30, 2026 [Member]
Debt Instrument [Line Items]
Total long-term debt	29,000		29,000
Long-term debt, interest percentage	5.68%
Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member]
Debt Instrument [Line Items]
Total long-term debt	50,000		50,000
Long-term debt, interest percentage	3.88%
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Total long-term debt	$ 20,000		$ 20,000
Long-term debt, interest percentage	3.73%