Chesapeake Utilities (CPK) 10-Q 7 Nov 13 2013 Q3 Quarterly report Financial data

Document_and_Entity_Informatio

Document and Entity Information	9 Months Ended
	Sep. 30, 2013	Oct. 31, 2013
Entity Information [Line Items]	'	'
Entity Registrant Name	'CHESAPEAKE UTILITIES CORP	'
Trading Symbol	'CPK	'
Entity Central Index Key	'0000019745	'
Current Fiscal Year End Date	'--12-31	'
Entity Filer Category	'Accelerated Filer	'
Document Type	'10-Q	'
Document Period End Date	30-Sep-13	'
Document Fiscal Year Focus	'2013	'
Document Fiscal Period Focus	'Q3	'
Amendment Flag	'false	'
Entity Common Stock, Shares Outstanding	'	9,632,595

Condensed_Consolidated_Stateme

Condensed Consolidated Statements of Income (USD $)	3 Months Ended		9 Months Ended
In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Operating Revenues	'	'	'	'
Regulated energy	$55,680	$52,196	$192,463	$180,045
Unregulated energy	28,262	23,259	119,278	93,323
Other	2,603	2,720	9,678	9,619
Total Operating Revenues	86,545	78,175	321,419	282,987
Operating Expenses	'	'	'	'
Regulated energy cost of sales	22,591	22,102	86,321	81,207
Unregulated energy and other cost of sales	21,795	17,602	90,656	72,056
Operations	21,300	20,804	65,878	60,831
Maintenance	2,146	1,801	5,688	5,635
Depreciation and amortization	6,274	5,767	18,071	17,413
Other taxes	3,719	2,535	10,383	7,753
Total Operating Expenses	77,825	70,611	276,997	244,895
Operating Income	8,720	7,564	44,422	38,092
Other income, net of other expenses	101	-136	413	212
Interest charges	2,026	2,126	6,114	6,657
Income Before Income Taxes	6,795	5,302	38,721	31,647
Income taxes	2,916	2,083	15,617	12,641
Net Income	$3,879	$3,219	$23,104	$19,006
Weighted Average Common Shares Outstanding:	'	'	'	'
Basic (in shares)	9,625,435	9,592,417	9,616,269	9,583,316
Diluted (in shares)	9,702,334	9,676,658	9,692,311	9,673,681
Earnings Per Share of Common Stock:	'	'	'	'
Basic (in usd per share)	$0.40	$0.34	$2.40	$1.98
Diluted (in usd per share)	$0.40	$0.33	$2.39	$1.97
Cash Dividends Declared Per Share of Common Stock (in usd per share)	$0.39	$0.37	$1.14	$1.08

Condensed_Consolidated_Stateme1

Condensed Consolidated Statements of Comprehensive Income (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Net Income	$3,879	$3,219	$23,104	$19,006
Employee Benefits, net of tax:	'	'	'	'
Amortization of prior service cost, net of tax of ($6), ($6), ($18) and ($19), respectively	-9	-9	-27	-28
Net gain, net of tax of $43, $51, $124 and $152, respectively	64	76	186	228
Total other comprehensive income	55	67	159	200
Comprehensive Income	$3,934	$3,286	$23,263	$19,206

Condensed_Consolidated_Stateme2

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $)	3 Months Ended		6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2013	Jun. 30, 2012	Jun. 30, 2013	Jun. 30, 2012
Tax expense recognized on the amortization of prior service cost	($6)	($6)	($18)	($19)
Tax expense recognized on the net gain (loss)	($43)	($51)	($124)	($152)

Condensed_Consolidated_Balance

Condensed Consolidated Balance Sheets (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Property, Plant and Equipment	'	'
Regulated energy	$635,859	$585,429
Unregulated energy	73,816	70,218
Other	21,048	20,067
Total property, plant and equipment	730,723	675,714
Less: Accumulated depreciation and amortization	-171,060	-155,378
Plus: Construction work in progress	50,256	21,445
Net property, plant and equipment	609,919	541,781
Current Assets	'	'
Cash and cash equivalents	1,792	3,361
Accounts receivable (less allowance for uncollectible accounts of $1,215 and $826, respectively)	60,578	53,787
Accrued revenue	7,948	11,688
Propane inventory, at average cost	7,383	7,612
Other inventory, at average cost	3,452	5,841
Regulatory assets	2,063	2,736
Storage gas prepayments	5,309	3,716
Income taxes receivable	724	4,703
Deferred income taxes	837	791
Prepaid expenses	7,357	6,020
Mark-to-market energy assets	379	210
Other current assets	160	132
Total current assets	97,982	100,597
Deferred Charges and Other Assets	'	'
Goodwill	4,716	4,090
Other intangible assets, net	3,075	2,798
Investments, at fair value	2,788	4,168
Regulatory assets	76,179	77,408
Receivables and other deferred charges	2,898	2,904
Total deferred charges and other assets	89,656	91,368
Total Assets	797,557	733,746
Stockholders' equity	'	'
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)	4,685	4,671
Additional paid-in capital	151,676	150,750
Retained earnings	118,330	106,239
Accumulated other comprehensive loss	-4,903	-5,062
Deferred compensation obligation	1,110	982
Treasury stock	-1,110	-982
Total stockholders' equity	269,788	256,598
Long-term debt, net of current maturities	107,344	101,907
Total capitalization	377,132	358,505
Current Liabilities	'	'
Current portion of long-term debt	8,234	8,196
Short-term borrowing	91,297	61,199
Accounts payable	41,013	41,992
Customer deposits and refunds	26,943	29,271
Accrued interest	2,581	1,437
Dividends payable	3,706	3,502
Accrued compensation	6,467	7,435
Regulatory liabilities	4,397	1,577
Mark-to-market energy liabilities	124	331
Other accrued liabilities	10,252	7,226
Total current liabilities	195,014	162,166
Deferred Credits and Other Liabilities	'	'
Deferred income taxes	135,305	125,205
Deferred investment tax credits	84	113
Regulatory liabilities	6,808	5,454
Environmental liabilities	8,838	9,114
Other pension and benefit costs	33,118	33,535
Accrued asset removal cost-Regulatory liability	39,156	38,096
Other liabilities	2,102	1,558
Total deferred credits and other liabilities	225,411	213,075
Other commitments and contingencies (Note 5 and 6)	'	'
Total Capitalization and Liabilities	$797,557	$733,746

Condensed_Consolidated_Balance1

Condensed Consolidated Balance Sheets (Parenthetical) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, except Share data, unless otherwise specified
Statement of Financial Position [Abstract]	'	'
Allowance for uncollectible accounts	$1,215	$826
Common stock, par value (in usd per share)	$0.49	$0.49
Common stock, shares authorized	25,000,000	25,000,000

Condensed_Consolidated_Stateme3

Condensed Consolidated Statements of Cash Flows (USD $)	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012
Operating Activities	'	'
Net Income	$23,104	$19,006
Adjustments to reconcile net income to net cash provided by operating activities:	'	'
Depreciation and amortization	18,071	17,413
Depreciation and accretion included in other costs	4,504	4,079
Deferred income taxes, net	9,947	12,102
(Gain) loss on sale of assets	-142	18
Unrealized (gain) loss on commodity contracts	-277	147
Unrealized gain on investments	217	-401
Realized gain on sales of investments, net	-702	-20
Employee benefits	708	2,268
Share-based compensation	1,246	1,111
Other, net	-84	-21
Changes in assets and liabilities:	'	'
Purchase of investments	-436	-292
Accounts receivable and accrued revenue	-567	36,523
Propane inventory, storage gas and other inventory	-933	3,722
Regulatory assets	-1,158	-456
Prepaid expenses and other current assets	-1,361	-856
Accounts payable and other accrued liabilities	8,174	-20,138
Income taxes receivable	3,980	-1,010
Accrued interest	1,144	1,509
Customer deposits and refunds	-2,559	-1,086
Accrued compensation	-1,060	-554
Regulatory liabilities	4,688	-4,097
Other assets and liabilities, net	-77	-4,502
Net cash provided by operating activities	66,427	64,465
Investing Activities	'	'
Property, plant and equipment expenditures	-68,579	-51,351
Proceeds from sales of assets	154	2,281
Purchase of investments and acquisition	2,300	0
Payments to Acquire Businesses, Gross	-19,367	-124
Environmental expenditures	-276	-345
Net cash used in investing activities	-85,768	-49,539
Financing Activities	'	'
Common stock dividends	-9,716	-9,160
Purchase of stock for Dividend Reinvestment Plan	-1,001	-946
Change in cash overdrafts due to outstanding checks	-2,692	-1,559
Net borrowing (repayment) under line of credit agreements	32,790	-2,393
Proceeds from issuance of long-term debt	7,000	0
Repayment of long-term debt	-8,609	-1,459
Net cash provided by (used in) financing activities	17,772	-15,517
Net Decrease in Cash and Cash Equivalents	-1,569	-591
Cash and Cash Equivalents-Beginning of Period	3,361	2,637
Cash and Cash Equivalents-End of Period	$1,792	$2,046

Condensed_Consolidated_Stateme4

Condensed Consolidated Statements of Stockholders' Equity (USD $)		Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Deferred Compensation [Member]	Treasury Stock [Member]
In Thousands, except Share data, unless otherwise specified
Beginning Balances at Dec. 31, 2011		$240,780	$4,656	$149,403	$91,248	($4,527)	$817	($817)
Beginning Balances, shares at Dec. 31, 2011	[1]	'	9,567,307	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]		'	'	'	'	'	'	'
Net Income		28,863	'	'	28,863	'	'	'
Other comprehensive loss/income		-535	'	'	'	-535	'	'
Dividend Reinvestment Plan		-7	0	-7	'	'	'	'
Dividend Reinvestment Plan, shares		'	0	'	'	'	'	'
Conversion of debentures		186	5	181	'	'	'	'
Conversion of debentures, shares	[1]	'	10,975	'	'	'	'	'
Share-based compensation	[2],[3]	1,011	10	1,001	'	'	'	'
Share-based compensation, shares	[1],[2],[3]	'	19,217	'	'	'	'	'
Tax benefit on share-based compensation		172	'	172	'	'	'	'
Deferred Compensation Plan		0	'	'	'	'	165	-165
Purchase of treasury stock		-45	'	'	'	'	'	-45
Purchase of treasury stock, shares	[1]	'	-1,019	'	'	'	'	'
Sale and distribution of treasury stock		45	'	'	'	'	'	45
Sale and distribution of treasury stock, shares	[1]	'	1,019	'	'	'	'	'
Dividends on share-based compensation		-64	'	'	-64	'	'	'
Cash dividends	[4]	-13,808	'	'	-13,808	'	'	'
Ending Balances at Dec. 31, 2012		256,598	4,671	150,750	106,239	-5,062	982	-982
Ending Balances, shares at Dec. 31, 2012	[1]	'	9,597,499	'	'	'	'	'
Increase (Decrease) in Stockholders' Equity [Roll Forward]		'	'	'	'	'	'	'
Net Income		23,104	'	'	23,104	'	'	'
Other comprehensive loss/income		159	'	'	'	159	'	'
Dividend Reinvestment Plan		-5	0	-5	'	'	'	'
Dividend Reinvestment Plan, shares	[1]	'	0	'	'	'	'	'
Conversion of debentures		88	3	85	'	'	'	'
Conversion of debentures, shares	[1]	'	5,166	'	'	'	'	'
Share-based compensation	[2],[3]	857	11	846	'	'	'	'
Share-based compensation, shares	[1],[2],[3]	'	23,348	'	'	'	'	'
Deferred Compensation Plan		0	'	'	'	'	128	-128
Deferred Compensation Plan, shares		'	0	'	'	'	'	'
Purchase of treasury stock		-38	'	'	'	'	'	-38
Purchase of treasury stock, shares	[1]	'	-763	'	'	'	'	'
Sale and distribution of treasury stock		38	'	'	'	'	'	38
Sale and distribution of treasury stock, shares	[1]	'	'	763	'	'	'	'
Dividends on share-based compensation		-92	'	'	-92	'	'	'
Cash dividends	[4]	-10,921	'	'	-10,921	'	'	'
Ending Balances at Sep. 30, 2013		$269,788	$4,685	$151,676	$118,330	($4,903)	$1,110	($1,110)
Ending Balances, shares at Sep. 30, 2013	[1]	'	9,626,013	'	'	'	'	'
[1]	Includes 34,224 and 33,461 shares at SeptemberB 30, 2013 and DecemberB 31, 2012, respectively, held in a Rabbi Trust related to the Company's Deferred Compensation Plan.
[2]	Includes amounts for shares issued for Directorsb compensation.
[3]	The shares issued under the Performance Incentive Plan (bPIPb) are net of shares withheld for employee taxes. For the nine months ended SeptemberB 30, 2013 and for the year ended DecemberB 31, 2012, the Company withheld 10,411 and 5,670 shares, respectively, for taxes.
[4]	Cash dividends per share for the periods ended SeptemberB 30, 2013 and DecemberB 31, 2012 were $1.135 and $1.440, respectively.

Condensed_Consolidated_Stateme5

Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) (USD $)	3 Months Ended	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Sep. 30, 2013	Dec. 31, 2012
Deferred compensation plan held Rabbi Trust (in shares)	34,224	34,224	33,461
Shares issued under the performance incentive plan withheld for employee taxes (in shares)	'	10,411	5,670
Cash dividends declared per share of common stock (in usd per share)	$0.39	$1.14	$1.44

Summary_of_Accounting_Policies

Summary of Accounting Policies	9 Months Ended
	Sep. 30, 2013
Accounting Policies [Abstract]	'
Summary of Accounting Policies	'
	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 Securities and Exchange Commission (“SEC”) and accounting principles generally accepted in the United States of America (“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, 2012. 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.
	During the third quarter of 2013, we recorded an accrual of $698,000 (424,000, net of tax) due to a contingency for taxes other than income, $248,000, $222,000 and $60,000 of which relate to the years ended December 31, 2012, 2011 and 2010, respectively. This reduced our earnings in the third quarter of 2013 and was reflected in other taxes in the accompanying condensed consolidated statements of income for the three and nine months ended September 30, 2013. All of the amounts are related to our unregulated energy segment.
	We have assessed and reported on subsequent events through the date of issuance of these condensed consolidated financial statements.
	Reclassifications
	We reclassified certain amounts in the condensed consolidated cash flows statement for the nine months ended September 30, 2012 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.
	Financial Accounting Standards Board (“FASB”) Statements and Other Authoritative Pronouncements
	Recent Accounting Standards Yet to be Adopted
	Income Taxes (Accounting Standards Codification ("ASC") 740) - In July 2013, the FASB issued Accounting Standards Update (“ASU”) 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists,” which requires the netting of certain unrecognized tax benefits against a deferred tax asset for a loss or other similar tax carryforward that would apply upon settlement of an uncertain tax position. This ASU is effective prospectively beginning on January 1, 2014 for all unrecognized tax benefits existing at the adoption of this new standard. Retrospective implementation and early adoption of this standard are permitted. We expect the adoption of ASU 2013-11 to have no material impact on our financial position and results of operations.
	Recently Adopted Accounting Standards
	Comprehensive Income (ASC 220) - Effective January 1, 2013, we adopted ASU 2013-02, “Reporting of Amounts Reclassified Out Of Accumulated Other Comprehensive Income,” which requires enhanced disclosures of amounts reclassified out of accumulated other comprehensive income by component. The adoption of ASU 2013-02 had no impact on our financial position and results of operations. See Note 8, "Accumulated Other Comprehensive Income (Loss)," for additional disclosures required under this new standard.
	Balance Sheet (ASC 210) - Effective January 1, 2013, we adopted ASU 2011-11, “Disclosures About Offsetting Assets and Liabilities,” and ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” These new standards require disclosures about offsetting and related arrangements in order to help financial statement users better understand the effect of those arrangements on our financial position. The adoption of ASU 2011-11 and ASU 2013-01 had no material impact on our financial position and results of operations. See Note 12, "Derivative Instruments," for additional disclosures about our offsetting of certain assets and liabilities.

Calculation_of_Earnings_Per_Sh

Calculation of Earnings Per Share	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Calculation of Earnings Per Share	'
	Calculation of Earnings Per Share
		Three Months				Nine Months
	For the Periods Ended September 30,	2013		2012		2013		2012
	(in thousands, except shares and per share data)
	Calculation of Basic Earnings Per Share:
	Net Income	$	3,879	$	3,219	$	23,104	$	19,006
	Weighted average shares outstanding	9,625,435		9,592,417		9,616,269		9,583,316
	Basic Earnings Per Share	$	0.4	$	0.34	$	2.4	$	1.98
	Calculation of Diluted Earnings Per Share:
	Reconciliation of Numerator:
	Net Income	$	3,879	$	3,219	$	23,104	$	19,006
	Effect of 8.25% Convertible debentures	11		13		33		41
	Adjusted numerator—Diluted	$	3,890	$	3,232	$	23,137	$	19,047
	Reconciliation of Denominator:
	Weighted shares outstanding—Basic	9,625,435		9,592,417		9,616,269		9,583,316
	Effect of dilutive securities:
	Share-based Compensation	26,123		23,770		23,888		22,684
	8.25% Convertible debentures	50,776		60,471		52,154		67,681
	Adjusted denominator—Diluted	9,702,334		9,676,658		9,692,311		9,673,681
	Diluted Earnings Per Share	$	0.4	$	0.33	$	2.39	$	1.97

Acquisitions

Acquisitions	9 Months Ended
	Sep. 30, 2013
Business Combinations [Abstract]	'
Acquisitions	'
	Acquisitions
	Eastern Shore Gas Company
	On May 31, 2013, upon obtaining the necessary approval from the Maryland Public Service Commission (“PSC”), which is further discussed in Note 4, “Rates and Other Regulatory Activities,” we completed the purchase of the operating assets of Eastern Shore Gas Company and its affiliates (collectively “ESG”). ESG was not related to, or affiliated with, our interstate natural gas transmission subsidiary, Eastern Shore Natural Gas Company ("Eastern Shore"). We paid approximately $16.5 million at the closing of the transaction, which was subject to certain adjustments specified in the asset purchase agreement. During the third quarter of 2013, the purchase price was reduced by $543,000 due to adjustments to property, plant and equipment, propane inventory, accounts receivable and other accrued liabilities. The purchase price included approximately $726,000 of sales tax related to the transaction. We financed the acquisition using unsecured short-term debt.
	Approximately 11,000 residential and commercial underground propane distribution system customers and 500 bulk propane delivery customers acquired in the transaction are being served by our new subsidiary, Sandpiper Energy, Inc. (“Sandpiper”) and our propane distribution subsidiary, Sharpgas, Inc. ("Sharp"), respectively. Sandpiper's operations, which cover all of Worcester County, Maryland, are now subject to rate and service regulation by the Maryland PSC. We are evaluating the potential conversion of some of the underground propane distribution systems to natural gas distribution, where such conversion is both economical and feasible.
	In connection with this acquisition, we recorded $12.6 million in property, plant and equipment, $344,000 in propane inventory, $2.5 million in accounts receivable and accrued revenue and $227,000 in other current liabilities, which included the effect of the purchase price adjustment in the third quarter of 2013. All but insignificant amounts of assets and liabilities are recorded in the regulated energy segment. No goodwill or intangible asset was recorded from this acquisition. The allocation of the purchase price and valuation of assets are preliminary, and we will complete the final purchase price allocation as soon as practicable but no later than one year from the purchase of the assets.
	Sales tax of approximately $726,000 included in the purchase price was expensed as a transaction cost and was reflected in other taxes in the accompanying condensed consolidated statements of income for the nine months ended September 30, 2013. Excluding this $726,000 of sales tax expense, the revenue and net income from this acquisition that were included in our condensed consolidated statements of income for the three months and nine months ended September 30, 2013 were not material.
	At closing, we entered into a capacity, supply and operating agreement with Eastern Gas & Water Investment Company, LLC ("EGWIC"), an affiliate of the seller. Pursuant to this agreement, Sandpiper has access to 13 propane storage tanks in Worcester County, Maryland, with total storage capacity of 570,000 gallons for a six-year period. For this access, Sandpiper has agreed to pay a monthly fee of $42,000 for the first annual period and a monthly fee of $125,000 for the remaining term of the agreement. Sandpiper will also purchase propane supply (initially estimated at approximately 7.4 million gallons of annual contract volume) from EGWIC over the same six-year period. Sandpiper has the option to pay a fixed per-gallon price for some or all of the propane purchases under this agreement or a market-based price using one of two local propane pricing indices. As further discussed in Note 4, “Rates and Other Regulatory Activities,” the cost of the capacity, supply and operating agreement will be recovered as a fuel cost in Sandpiper's new annual Gas Service Rate (“GSR”) filing.
	Due to the specific property involved and the fixed monthly payments for the use of the storage capacity, the capacity portion of the capacity, supply and operating agreement must be accounted for as a capital lease. As a result, we recorded a capital lease asset and capital lease obligation of $7.1 million at the inception of the agreement. During the three and nine months ended September 30, 2013, we recorded approximately $62,000 and $83,000, respectively, for the interest on the capital lease obligation. During the three and nine months ended September 30, 2013, we recorded approximately $63,000 and $84,000, respectively, for the amortization of the capital lease asset. Since the entire amount of the capacity payments is expected to be recovered through the GSR mechanism, the timing and amount of the expense recognition, as well as the presentation of the expenses, will also follow the regulatory accounting.
	Other Acquisitions
	On June 7, 2013, we acquired the operating assets of Austin Cox Home Services, Inc. ("Austin Cox") for approximately $600,000. The purchased assets are used to provide heating, ventilation and air conditioning, plumbing and electrical services to residential, commercial and industrial customers throughout the lower Delmarva Peninsula. In connection with this acquisition, we recorded $105,000 in property, plant and equipment, $94,000 in inventory, $250,000 as an intangible asset related to a non-compete agreement to be amortized over five years beginning in July 2013 and $173,000 in goodwill. Valuation of certain property, plant and equipment and the intangible asset is preliminary and may be adjusted in the future based upon the final valuation, but no later than one year from the date of acquisition. All of the goodwill is expected to be deductible for income tax purposes.
	On February 5, 2013, Flo-Gas Corporation, our Florida propane distribution subsidiary, purchased the propane operating assets of Glades Gas Co., Inc. (“Glades”) for approximately $2.9 million. The purchased assets are used to provide propane distribution service to approximately 3,000 residential and commercial customers in Okeechobee, Glades and Hendry Counties, Florida. In connection with this acquisition, we recorded $1.6 million in property, plant and equipment, $502,000 in propane and other inventory, $300,000 in an intangible asset related to Glades’ customer list to be amortized over 12 years beginning in February 2013 and $453,000 in goodwill. Valuation of certain property, plant and equipment and the intangible asset is preliminary and may be adjusted in the future based upon the final valuation, but no later than one year from the date of acquisition. All of the goodwill is expected to be deductible for income tax purposes.

Rates_and_Other_Regulatory_Act

Rates and Other Regulatory Activities	9 Months Ended
	Sep. 30, 2013
Regulated Operations [Abstract]	'
Rates and Other Regulatory Activities	'
	Rates and Other Regulatory Activities
	Our natural gas distribution operations in Delaware and Maryland, including Sandpiper, are subject to regulation by their respective PSC; Chesapeake’s Florida natural gas distribution division and the natural gas and electric operations of Florida Public Utilities Company (“FPU”) continue to be subject to regulation by the Florida PSC as separate entities. Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the Federal Energy Regulatory Commission (“FERC”); and Peninsula Pipeline Company, Inc. (“Peninsula Pipeline”), our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC.
	Delaware
	Natural Gas Expansion Service Offerings: On June 25, 2012, our Delaware division filed with the Delaware PSC an application for proposed natural gas expansion service offerings in order to increase the availability of natural gas within its Delaware service areas. In this filing, the Delaware division is seeking approval from the Delaware PSC of the following:
	(i)	a monthly fixed charge to customers in portions of eastern Sussex County, Delaware, which will enable the Delaware division to extend its distribution system to provide natural gas service to these customers economically without upfront contributions from these customers;
	(ii)	optional service offerings to customers to facilitate conversions to natural gas, including a conversion finance service to help customers manage their cost of conversion equipment; and
	(iii)	a slight rate increase for all Delaware customers in order to support the additional costs associated with the administration of the proposed service offerings.
	On July 3, 2012, the Delaware PSC opened the docket and set a period for formal interventions to be filed. On January 4, 2013, the Division of the Public Advocate (“DPA”) filed a motion to close the docket on the grounds that the proposed expansion service offerings should only be considered in the context of a full base rate case. On February 6, 2013, the Hearing Examiner assigned to the case issued a report recommending that the Delaware PSC deny the DPA’s motion. Subsequently, the DPA, Delaware PSC staff and our Delaware division reached an agreement in principle, which included the key provisions described above, with the exception of the proposed rate increase for Delaware customers residing outside of the expansion area. In July 2013, we filed the terms of this agreement in principle in supplemental testimony. A public comment hearing was held on September 12, 2013. On September 30, 2013, the parties involved in the agreement in principle submitted a signed settlement agreement, and on November 5, 2013, the Delaware PSC approved the settlement agreement.
	Maryland
	ESG Acquisition: On September 7, 2012, we filed an application with the Maryland PSC for approval of the acquisition of the ESG operating assets and the transfer of the ESG franchises to Chesapeake (see Note 3, “Acquisitions,” for additional information on the ESG acquisition). In this application, we also requested the Maryland PSC to approve the overall regulatory framework we proposed for our operation in Worcester County. The proposed regulatory framework includes: (i) a request for approval of a new gas service tariff and rates applicable to natural gas and propane distribution customers in Worcester County, including the customers currently being served by ESG; (ii) a request for approval of the capacity, supply and operating agreement with ESG for the supply and storage of propane, which will be utilized to serve the ESG system customers; and (iii) a request for approval of the accounting treatment for certain purchased assets.
	On April 8, 2013, the parties finalized a settlement agreement, which was approved by the Maryland PSC, effective May 29, 2013. Under the order, the Maryland PSC granted approval of: (i) the ESG acquisition; (ii) the overall regulatory framework requested; and (iii) recovery of the cost of the capacity, supply and operating agreement with ESG. In addition, the Maryland PSC's order requires us to file a depreciation study within the first year after the acquisition, at which point, the proper amount of the accumulated depreciation associated with the purchased assets in the rate base and the depreciation rates on those assets will be determined and then applied prospectively. The order also requires us to file a base rate case within two and a half years of Sandpiper's new service in Worcester County. The acquisition of the ESG operating assets was completed on May 31, 2013.
	On July 31, 2013, Sandpiper filed an application with the Maryland PSC to revise its tariff to allow, on a temporary basis until the next base rate case, negotiated contract rates for a discrete subset of commercial customers receiving propane service who: (i) experienced rate increases on June 1, 2013, when Sandpiper’s tariff took effect in Worcester County and (ii) do not meet the minimum usage requirement for eligibility for negotiated contract rates under the current tariff. On August 14, 2013, the Maryland PSC considered the application and accepted the proposed tariff revisions, effective August 14, 2013.
	Florida
	Marianna Franchise: On July 7, 2009, the City Commission of Marianna, Florida (the “Marianna Commission”) adopted an ordinance granting a franchise to FPU, effective February 1, 2010, for a period not to exceed ten years for the operation and distribution and/or sale of electric energy (the “Franchise Agreement”). The Franchise Agreement required FPU to develop and implement new time-of-use (“TOU”) and interruptible electric power rates, or other similar rates, mutually agreeable to FPU and the City of Marianna, effective no later than February 17, 2011, and available to all customers within FPU’s northwest division, which includes the City of Marianna. If the rates were not in effect by February 17, 2011, the City of Marianna would have the right to give notice to FPU within 180 days thereafter of its intent to exercise an option in the Franchise Agreement to purchase FPU’s property (consisting of the electric distribution assets) within the City of Marianna. Any such purchase would be subject to approval by the Marianna Commission, which would also need to approve the presentation of a referendum to voters in the City of Marianna for the approval of the purchase and the operation by the City of Marianna of an electric distribution facility. If the purchase were approved by the Marianna Commission and by the referendum, the closing of the purchase would have had to occur within 12 months after the referendum was approved. If the City of Marianna had elected to purchase the Marianna property, the Franchise Agreement would require the City of Marianna to pay FPU the fair market value for such property as determined by three qualified appraisers.
	In accordance with the terms of the Franchise Agreement, FPU developed TOU and interruptible rates, and on December 14, 2010, FPU filed a petition with the Florida PSC for authority to implement such proposed TOU and interruptible rates on or before February 17, 2011. On January 26, 2011, FPU filed a petition with the Florida PSC for approval of an amendment to FPU’s Generation Services Agreement between FPU and Gulf Power Company (“Gulf Power”). The amendment provides for a reduction in the capacity demand quantity, which generates the savings necessary to support the TOU and interruptible rates approved by the Florida PSC. The amendment also extended the current agreement by two years, with a new expiration date of December 31, 2019.
	On February 11, 2011, the Florida PSC issued an order approving FPU’s petition for authority to implement the proposed TOU and interruptible rates, which became effective on February 8, 2011. The City of Marianna objected to the proposed rates and filed a petition protesting the entry of the Florida PSC’s order. On June 21, 2011, the Florida PSC issued an order approving the amendment to FPU's Generation Services Agreement. On July 12, 2011, the City of Marianna filed a protest of this decision and requested a hearing on the amendment. On January 24, 2012, the Florida PSC dismissed with prejudice the protests by the City of Marianna regarding both the TOU and interruptible rates and the amendment to the Generation Services Agreement.
	The City of Marianna filed an appeal with the Florida Supreme Court on March 7, 2012 and with the Florida PSC on March 19, 2012, seeking an appellate review of both of the decisions by the Florida PSC with respect to the protests by the City of Marianna.
	As more fully disclosed in Note 6, “Other Commitments and Contingencies,” on March 2, 2011, the City of Marianna filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida, alleging breaches of the Franchise Agreement by FPU and seeking a declaratory judgment that the City of Marianna has the right to exercise its option to purchase FPU’s property in the City of Marianna in accordance with the terms of the Franchise Agreement. Prior to the scheduled trial date, FPU and the City of Marianna reached an agreement in principle to resolve their dispute, which resulted in the City of Marianna dismissing its legal action with prejudice on February 11, 2013. Subsequently, FPU and the City of Marianna entered into a settlement agreement, which contemplated, among other items, the City of Marianna proceeding with a referendum on the purchase of FPU’s facilities. On April 9, 2013, the referendum took place, and the citizens of the City of Marianna voted, by a wide margin, to reject the purchase of FPU's facilities by the City of Marianna. As a result of the outcome of the referendum and pursuant to the terms of the settlement agreement, FPU’s franchise with the City of Marianna was extended by ten years. Also pursuant to the settlement agreement, the City of Marianna withdrew its appeals before the Florida Supreme Court of the Florida PSC’s orders regarding the implementation of TOU and interruptible rates and the amendment to the Generation Services Agreement between FPU and Gulf Power.
	FPU has incurred approximately $1.9 million of expenses associated with the City of Marianna litigation. In order to seek regulatory recovery of these extraordinary expenses, FPU filed a petition with the Florida PSC on August 27, 2012, for approval to: (i) defer, as a regulatory asset, the expenses associated with the litigation initiated by the City of Marianna; and (ii) amortize over five years, beginning in January 2013, previously expensed as well as future litigation expenses. Although this petition did not request recovery of these expenses, FPU sought deferral treatment of the expenses for regulatory purposes, which could allow future recovery of those expenses. On December 3, 2012, the Florida PSC issued an order approving FPU's request. Since this order does not provide specific recovery of these costs, we did not defer these costs as a regulatory asset at that point until further assurance of recovery can be obtained. Subsequent discussions with the Office of Public Counsel resulted in a settlement agreement on October 11, 2013. Under this settlement agreement, FPU will recover approximately $1.8 million of the total expenses associated with the City of Marianna litigation by retaining the $1.8 million refund received from Gulf Power. This refund represented the higher fuel cost paid by FPU during the City of Marianna franchise dispute as a result of the delay in implementing the amendment to the Generation Service Agreement. Upon reinstatement of the amendment, Gulf Power refunded this amount to FPU pursuant to the terms of the amendment.  The remaining litigation expenses would be amortized over the five-year period beginning in January 2013, as previously approved by the Florida PSC. The Florida PSC approved the settlement agreement on October 24, 2013.
	Upon reaching the settlement agreement and obtaining a recommendation from the Florida PSC Staff supporting the approval of this settlement agreement, we established a regulatory asset of approximately$1.9 million at September 30, 2013 by reversing approximately $1.5 million of expenses recognized in 2011 and 2012 and $376,000 of expenses recognized during 2013. The refund of $1.8 million received from Gulf Power was reflected as a regulatory liability at September 30, 2013.
	Other Matters: We also had developments in the following regulatory matters in Florida:
	On September 28, 2012, FPU provided a letter to the Florida PSC stating its intent to request approval of a $745,800 acquisition adjustment associated with FPU’s purchase of the operating assets of Indiantown Gas Company (“IGC”) in 2010. In this letter, FPU also acknowledged the jurisdiction of the Florida PSC to calculate and dispose of prospective overearnings, if any, occurring after October 1, 2012, as the Florida PSC may determine at the conclusion of the acquisition adjustment proceeding. On December 11, 2012, FPU filed a petition to request approval of this acquisition adjustment associated with FPU’s purchase of IGC’s assets. The Florida PSC has scheduled an agenda on December 3, 2013 for a decision on this matter.
	On December 14, 2012, Peninsula Pipeline filed a petition with the Florida PSC, asking for approval of a transportation service agreement with FPU. The agreement provides for an upstream interconnection of Peninsula Pipeline’s facilities with the Florida Gas Transmission Company (“FGT”) system and a downstream interconnection with FPU’s facilities. At the agenda conference on July 30, 2013, the Florida PSC approved this agreement.
	On July 2, 2013, FPU filed a petition with the Florida PSC for recognition of a regulatory liability for a one-time curtailment gain associated with a change in the FPU Medical Plan. The change in the FPU Medical Plan was implemented effective January 1, 2012 in an effort to conform the benefits offered to FPU's employees to those offered by Chesapeake. The change in the FPU Medical Plan resulted in a total curtailment gain of $892,000, $722,000 of which was allocated to FPU's regulated operations. Since this gain resulted from the merger integration effort, FPU believes that the treatment most consistent with prior regulatory treatment would be to record the gain allocated to the regulated operations as a regulatory liability and amortize that amount over a specified period. This treatment is similar to how merger-related costs and a one-time tax contingency gain were treated. FPU is requesting approval to record regulatory liabilities of $464,000 and $258,000, respectively, in its natural gas and electric operations. FPU also seeks permission to amortize the proposed regulatory liabilities over a 34-month period, beginning January 1, 2012, and ending October 30, 2014. The Florida PSC approved this petition on October 24, 2013. We will record the amortization of this regulatory liability, including immediate recognition in current period earnings of the amortization related to the period prior to the Florida PSC's approval, beginning in the fourth quarter of 2013. This will reduce depreciation and amortization expense.
	Eastern Shore
	The following are regulatory activities involving FERC orders applicable to Eastern Shore and the expansions of Eastern Shore’s transmission system:
	Mainline Expansion Project: On May 14, 2012, Eastern Shore submitted to the FERC an application for a Certificate of Public Convenience and Necessity ("CP") for approval to construct the facilities necessary to deliver additional firm service of 15,040 dekatherms per day (“Dts/d”) to an existing electric power generation customer and to Chesapeake’s Delaware and Maryland divisions. The estimated capital cost of the project is approximately $16.3 million. The filing was publicly noticed on May 25, 2012. Two of Eastern Shore’s existing customers and Chesapeake’s Delaware and Maryland divisions filed motions to intervene in support of the project. One existing customer filed a motion to intervene and protest. On June 28, 2012, Eastern Shore submitted a response to the protest, and on August 31, 2012, the protesting customer filed a reply to Eastern Shore’s response. On October 3, 2012, the US Department of the Interior submitted comments on the FERC’s environmental assessment regarding Eastern Shore’s re-vegetation plan. On October 9, 2012, a non-profit organization also submitted comments on the FERC’s environmental assessment, asserting that the environmental assessment was deficient and requesting the FERC to extend the comment period by 60 days. In February 2013, the FERC approved Eastern Shore’s application and issued a CP. On March 11, 2013, Eastern Shore accepted this CP and filed its environmental compliance plan. On March 21, 2013, the FERC issued a notice to proceed with construction. On November 1, 2013, Eastern Shore commenced service upon completion of construction and receipt of necessary approval by the FERC.
	Daleville Compressor Station Upgrade Filing: On October 12, 2012, Eastern Shore submitted to the FERC an application for a CP, seeking authorization to construct a new gas-fired compressor unit at its existing Daleville Compressor Station located in Chester County, Pennsylvania. The new unit will provide 17,500 Dts/d of additional firm transportation service to two of Eastern Shore’s existing customers. In this application, Eastern Shore also included a description of a second new gas fired compressor unit to be installed at the Daleville Compressor Station, which will replace the three existing compressors that serve as back-up units to existing primary compressor units. Eastern Shore also plans to replace the engine exhaust devices of the existing primary compressor units with air emissions control equipment to comply with new environmental regulations. The replacement compressor unit and new engine exhaust devices will result in improved air emissions, reliability and flexibility on Eastern Shore’s system. Eastern Shore does not need specific FERC approval to construct the replacement compressor unit or emission controls; however, Eastern Shore wants the FERC to be fully advised of these improvement efforts. The estimated capital costs of the project are approximately $12.1 million. On March 4, 2013, the FERC approved this application. On April 19, 2013, the FERC issued a notice to proceed with construction. On November 1, 2013, Eastern Shore commenced service upon completion of construction and receipt of necessary approval by the FERC.
	White Oak Lateral Project Filing: On June 13, 2013, Eastern Shore submitted to the FERC an application for a CP, seeking authorization to construct the White Oak lateral project located in Kent County, Delaware. The project consists of installing approximately 5.5 miles of 16-inch diameter pipeline, metering facilities and miscellaneous appurtenances extending from Eastern Shore's mainline system near its North Dover City Gate Station to the Garrison Oak Technical Park, all located in Dover, Delaware. This project is designed to provide 55,200 Dts/d of delivery lateral firm transportation service to Calpine Energy Services, L.P. ("Calpine") for its proposed 309 megawatt combined-cycle power plant under development. The total cost of the project is estimated to be approximately $11.2 million. Eastern Shore requested that the FERC issue an order granting the CP by December 14, 2013.
	On August 9, 2013, the FERC issued a notice of intent to prepare an environmental assessment for the project. The comment period concluded on September 9, 2013 with no comments being filed in the docket. The environmental assessment was issued on October 4, 2013 and the federal authorization decision deadline is January 2, 2014. Eastern Shore anticipates beginning construction in early 2014 for an in-service date of January 1, 2015.
	Other matters: Eastern Shore also had developments in the following FERC matters:
	On May 31, 2013, Eastern Shore submitted to the FERC a combined filing of its Fuel Retention Percentage (“FRP”) and Cash-Out Refund for a twelve-month period beginning April 2012 and ending March 2013. In this filing, Eastern Shore proposed an FRP rate of 0.24 percent and continuation of its existing zero percent rate for the Cash-Out Surcharge. During the period, Eastern Shore experienced an under-recovery of $285,000 in its Deferred Gas Required for Operations costs and an over-recovery of $146,000 in its Deferred Cash-Out costs. Eastern Shore proposed to incorporate the Cash-Out Refund into its FRP to mitigate the effect of the increase in the FRP to its customers. On June 27, 2013, the FERC issued an order accepting Eastern Shore's submittal of a combined filing to update both its FRP and Cash-Out Refund mechanisms, effective July 1, 2013.

Environmental_Commitments_and_

Environmental Commitments and Contingencies	9 Months Ended
	Sep. 30, 2013
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 remedy 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, and have exposures at six former manufactured gas plant (“MGP”) sites. Those sites are located in Salisbury, Maryland, and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the Maryland Department of Environment (“MDE”) regarding a seventh former MGP site located in Cambridge, Maryland.
	As of September 30, 2013, we had approximately $10.3 million in environmental liabilities related to all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites, representing our estimate of the future costs associated with those sites. FPU has approval to recover up to $14.0 million of its environmental costs related to all of its MGP sites from insurance and from customers through rates, approximately $9.1 million of which has been recovered as of September 30, 2013. We had approximately $4.9 million in regulatory assets for future recovery of environmental costs from FPU’s customers.
	In addition to the FPU MGP sites, we had $100,000 in environmental liabilities at September 30, 2013, related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of September 30, 2013, we had approximately $339,000 in regulatory and other assets for future recovery through Chesapeake’s rates. 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 will be recoverable from customers through rates.
	The following discussion provides details on MGP sites:
	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 Florida Department of Environmental Protection (“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 ultimately will 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. In January 2007, FPU and other responsible parties at the Sanford site (collectively with FPU the “Sanford Group”) signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the United States Environmental Protection Agency (“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 September 30, 2013, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements.
	The total cost of the final remedy is now 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 September 30, 2013, 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 as provided in the Third Participation Agreement to implement the final remedy for this site 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 September 30, 2013.
	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 via e-mail on October 9, 2012, that based on the data, Natural Attenuation Monitoring (“NAM”) appears to be an appropriate remedy for the site. The FDEP issued a Remedial Action Plan approval order, dated October 12, 2012, which specified that a limited semi-annual monitoring program is to be conducted. The annual cost to conduct the limited NAM program is not expected to exceed $8,000. 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.
	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 Florida Department of Transportation (“FDOT”). In October 2009, FDEP informed Gulf Power that FDEP would approve a conditional No Further Action determination for the site, which must include a requirement for institutional and engineering controls. On December 13, 2011, Gulf Power, the City of Pensacola, FDOT and FPU submitted to FDEP a draft covenant for institutional and engineering controls for the site. Upon FDEP’s approval and the subsequent recording of the institutional and engineering controls, no further work is expected to be required of the parties. Assuming FDEP approves the draft institutional and engineering controls, 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. The recent groundwater sampling results show a continuing reduction in contaminant concentrations from the treatment system, which has been in operation since 2002. Currently, we predict that remedial action objectives could be met in approximately two to three years for the area being treated by the remediation system. On August 7, 2012, FDEP issued a letter discussing the need to evaluate further remedial options, which could incorporate risk-management options, including natural attenuation and the use of institutional and engineering controls. Modifications to the existing consent order and the remedial action plan modification could be required to incorporate risk-management options into the remedy for the site. A response letter was submitted to FDEP on May 7, 2013, and the most recent groundwater monitoring report was submitted on June 17, 2013. FDEP issued an additional comment letter, dated September 16, 2013, containing various requests and questions, which we responded to on October 10, 2013. If modifications to the existing consent order and remedial action plan are required, we estimate that future remediation costs could be as much as $443,000, which includes an estimate of $100,000 to implement additional actions, such as institutional controls, at the site. If we are required to incur this cost, we continue to believe that the entire amount will be recoverable from customers through our approved rates.
	The current treatment system at the Winter Haven site does not address impacted soils in the southwest corner of the site. In 2010, we obtained conditional approval from FDEP for a soil excavation plan; however, because the costs associated with shoreline stabilization and dewatering are likely to be substantial, alternatives to this excavation plan are being evaluated.
	FDEP has indicated that we may be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, we object to FDEP’s suggestion that the sediments have been adversely impacted by the former operations of the MGP. Our early estimates indicate that some of the corrective measures discussed by FDEP could cost as much as $1.0 million. We believe that corrective measures for the sediments are not warranted and intend to oppose any requirement that we undertake corrective measures in the offshore sediments. We have not recorded a liability for sediment remediation, as the final resolution of this matter cannot be predicted at this time.
	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.
	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.
	We have investigated a potential environmental matter involving a property we recently purchased in Fernandina Beach, Florida. We determined that there was no contamination at this site; therefore, we have not recorded an environmental liability for this site.

Other_Commitments_and_Continge

Other Commitments and Contingencies	9 Months Ended
	Sep. 30, 2013
Commitments and Contingencies Disclosure [Abstract]	'
Other Commitments and Contingencies	'
	Other Commitments and Contingencies
	Litigation
	On March 2, 2011, the City of Marianna filed a complaint against FPU in the Circuit Court of the Fourteenth Judicial Circuit in and for Jackson County, Florida. In the complaint, the City of Marianna alleged three breaches of the Franchise Agreement by FPU: (i) FPU failed to develop and implement TOU and interruptible rates that were mutually agreed to by the City of Marianna and FPU; (ii) mutually agreed upon TOU and interruptible rates by FPU were not effective or in effect by February 17, 2011; and (iii) FPU did not have such rates available to all of FPU’s customers located within and without the corporate limits of the City of Marianna. The City of Marianna sought a declaratory judgment allowing it to exercise its option under the Franchise Agreement to purchase FPU’s property (consisting of the electric distribution assets) within the City of Marianna. Any such purchase would be subject to approval by the Marianna Commission, which would also need to approve the presentation of a referendum to voters in the City of Marianna related to the purchase and the operation by the City of Marianna of an electric distribution facility. If the purchase were approved by the Marianna Commission and the referendum were approved by the voters, the closing of the purchase had to occur within 12 months after the referendum was approved. On March 28, 2011, FPU filed its answer to the declaratory action by the City of Marianna, in which it denied the material allegations by the City of Marianna and asserted several affirmative defenses. On August 3, 2011, the City of Marianna notified FPU that it was formally exercising its option to purchase FPU’s property. On August 31, 2011, FPU advised the City of Marianna that it had no right to exercise the purchase option under the Franchise Agreement and that FPU would continue to oppose the effort by the City of Marianna to purchase FPU’s property. In December 2011, the City of Marianna filed a motion for summary judgment. On April 3, 2012, the court conducted a hearing on the City of Marianna’s motion for summary judgment. The court subsequently denied in part and granted in part the City of Marianna’s motion after concluding that issues of fact remained for trial with respect to each of the three alleged breaches of the Franchise Agreement.
	Prior to the February 2013 trial date, FPU and the City of Marianna reached an agreement in principle to resolve their dispute, which resulted in the City of Marianna dismissing its legal action with prejudice on February 11, 2013. Subsequently, FPU and the City of Marianna entered into a settlement agreement, which contemplated, among other items, the City of Marianna proceeding with a referendum on the purchase of FPU’s facilities within the City of Marianna. On April 9, 2013, the referendum took place, and the citizens of the City of Marianna voted, by a wide margin, to reject the purchase of FPU’s facilities by the City of Marianna. As a result of the dismissal with prejudice of the legal action by the City of Marianna and the outcome of the referendum on the purchase of FPU’s facilities, we no longer have any contingencies related to claims by the City of Marianna.
	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.
	Natural Gas, Electric and Propane Supply
	Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase gas, electricity and propane from various suppliers. The contracts have various expiration dates. Our Delaware and Maryland natural gas distribution divisions had a contract with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage capacity, which expired on March 31, 2013. On April 1, 2013, our Delaware and Maryland divisions entered into a new contract with a different company to perform similar asset management functions. The new contract expires on March 31, 2015.
	As discussed in Note 3, "Acquisitions," in May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term. Sandpiper's initial annual commitment is estimated at approximately 7.4 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.
	Chesapeake’s Florida natural gas distribution division has firm transportation service contracts with FGT and Gulfstream Natural Gas System, LLC (“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 Peninsula Energy Services Company, Inc. (“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 for the service.
	In May 2013, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2014.
	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 (formerly known as Jacksonville Electric Authority) 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 either ratio is not met by FPU, it has 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken or proposed to be taken to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could result in FPU having to provide an irrevocable letter of credit. As of September 30, 2013, FPU was in compliance with all of the requirements of its fuel supply contracts.
	Sharp, our propane distribution subsidiary, 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 initial annual commitment is estimated at approximately 7.4 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.
	Corporate Guarantees
	The Board of Directors has authorized the Company 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 $45.0 million.
	We have issued corporate guarantees to certain vendors of our subsidiaries, primarily our propane wholesale marketing subsidiary and our natural gas marketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the subsidiary’s default. 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 September 30, 2013 was $31.1 million, with the guarantees expiring on various dates through September 2014.
	Chesapeake 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,” to the condensed consolidated financial statements for further details).
	In addition to the corporate guarantees, we have renewed a letter of credit for $1.0 million, which now expires on September 12, 2014, 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 December 2, 2014, 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 $304,000 to our former primary insurance company, which will expire on June 1, 2014. There have been no draws on these letters of credit as of September 30, 2013. 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 Texas Eastern Transmission, LP (“TETLP”) related to firm transportation service agreements between our Delaware and Maryland divisions and TETLP.
	Tax-related Contingencies
	We are subject to various audits and reviews by the federal, state and local and other regulatory authorities regarding income taxes and taxes other than income. As of September 30, 2013, we maintained a liability of $300,000 related to unrecognized income tax benefits and $780,000 related to contingencies for taxes other than income. As of December 31, 2012, we maintained a liability of $300,000 related to unrecognized income tax benefits and $82,000 related to contingencies for taxes other than income. We recorded an additional accrual in the third quarter of 2013 related to taxes other than income based on our assessment of this contingency.

Segment_Information

Segment Information	9 Months Ended
	Sep. 30, 2013
Segment Reporting [Abstract]	'
Segment Information	'
	Segment Information
	We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income. Our operations are comprised of three operating segments:
	•	Regulated Energy. The regulated energy segment includes natural gas distribution, electric distribution and natural gas transmission 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 natural gas marketing, propane distribution and propane wholesale marketing operations, which are unregulated as to their rates and charges for their services.
	•	Other. The “other” segment consists primarily of the advanced information services operation, unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.
	The following table presents financial information about our reportable segments.
			Three Months						Nine Months
	For the Periods Ended September 30,		2013			2012			2013		2012
	(in thousands)
	Operating Revenues, Unaffiliated Customers
	Regulated Energy		$	55,387		$	51,868		$	191,666	$	179,139
	Unregulated Energy		26,103			21,861			115,367		91,001
	Other		5,055			4,446			14,386		12,846
	Total operating revenues, unaffiliated customers		$	86,545		$	78,175		$	321,419	$	282,986
	Intersegment Revenues (1)
	Regulated Energy		$	293		$	328		$	797	$	906
	Unregulated Energy		2,159			1,398			3,911		2,322
	Other		274			220			743		675
	Total intersegment revenues		$	2,726		$	1,946		$	5,451	$	3,903
	Operating Income
	Regulated Energy		$	10,243		$	7,848		$	36,169	$	33,151
	Unregulated Energy		(1,803		)	(709		)	8,013		4,044
	Other and eliminations		280			425			240		897
	Total operating income		8,720			7,564			44,422		38,092
	Other income, net of other expenses		101			(136		)	413		212
	Interest		2,026			2,126			6,114		6,657
	Income before Income Taxes		6,795			5,302			38,721		31,647
	Income taxes		2,916			2,083			15,617		12,641
	Net Income		$	3,879		$	3,219		$	23,104	$	19,006
	(1)	All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.
	(in thousands)		September 30,			December 31,
			2013			2012
	Identifiable Assets
	Regulated energy		$	683,258		$	615,438
	Unregulated energy		88,032			79,287
	Other		26,267			39,021
	Total identifiable assets		$	797,557		$	733,746
	Our operations are almost entirely domestic. Our advanced information services subsidiary, BravePoint, has infrequent transactions in foreign countries, which are denominated and paid primarily in U.S. dollars. These transactions are immaterial to the consolidated revenues.

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Loss)	9 Months Ended
	Sep. 30, 2013
Equity [Abstract]	'
Accumulated Other Comprehensive Income (Loss)	'
	Accumulated Other Comprehensive Income (Loss)
	The following table presents the changes in the balance of accumulated other comprehensive income (loss) for the three and nine months ended September 30, 2013. Defined benefit pension and postretirement plan items are the only component of our accumulated comprehensive income (loss). All amounts in the following table are presented net of tax.
	For the Periods Ended September 30, 2013		Three Months			Nine Months
	(in thousands)
	Beginning balance		$	(4,958	)	$	(5,062	)
	Other comprehensive loss before reclassifications		—			(6		)
	Amounts reclassified from accumulated other comprehensive loss		55			165
	Net current-period other comprehensive income		55			159
	Ending balance		$	(4,903	)	$	(4,903	)
	The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, 2013.
	For the Periods Ended September 30, 2013		Three Months			Nine Months
	(in thousands)
	Amortization of defined benefit pension and postretirement plan items:
	Prior service cost (1)		$	15		$	45
	Net loss (1)		$	(107	)	$	(320	)
	Total before tax		(92		)	(275		)
	Tax benefit		37			110
	Net of tax		$	(55	)	$	(165	)
	(1)	These amounts are included in the computation of net periodic costs (benefits). See Note 9, “Employee Benefit Plans,” for additional details.
	Amortization of defined benefit pension and postretirement plan items are included in operations expense in the accompanying condensed consolidated statements of income. Tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.

Employee_Benefit_Plans

Employee Benefit Plans	9 Months Ended
	Sep. 30, 2013
Compensation and Retirement Disclosure [Abstract]	'
Employee Benefit Plans	'
	Employee Benefit Plans
	Net periodic benefit costs for our pension and post-retirement benefits plans for the three and nine months ended September 30, 2013 and 2012 are set forth in the following tables:
			Chesapeake						FPU						Chesapeake					Chesapeake						FPU
			Pension Plan						Pension Plan						Pension SERP					Postretirement						Medical
																				Plan						Plan
	For the Three Months Ended September 30,		2013			2012			2013			2012			2013		2012			2013			2012			2013		2012
	(in thousands)
	Service cost		$	—		$	—		$	—		$	—		$	—	$	—		$	—		$	—		$	—	$	40
	Interest cost		102			125			594			638			21		23			12			15			16		45
	Expected return on plan assets		(126		)	(108		)	(719		)	(658		)	—		—			—			—			—		—
	Amortization of prior service cost		—			(1		)	—			—			5		5			(19		)	(20		)	—		—
	Amortization of net loss		57			85			81			43			16		11			18			18			—		23
	Net periodic cost (benefit)		33			101			(44		)	23			42		39			11			13			16		108
	Amortization of pre-merger regulatory asset		—			—			191			190			—		—			—			—			2		2
	Total periodic cost		$	33		$	101		$	147		$	213		$	42	$	39		$	11		$	13		$	18	$	110
			Chesapeake						FPU						Chesapeake					Chesapeake						FPU
			Pension Plan						Pension Plan						Pension SERP					Postretirement						Medical
																				Plan						Plan
	For the Nine Months Ended September 30,		2013			2012			2013			2012			2013		2012			2013			2012			2013		2012
	(in thousands)
	Service cost		$	—		$	—		$	—		$	—		$	—	$	—		$	—		$	—		$	—	$	120
	Interest cost		307			375			1,782			1,916			62		68			36			45			47		135
	Expected return on plan assets		(378		)	(326		)	(2,156		)	(1,973		)	—		—			—			—			—		—
	Amortization of prior service cost		(1		)	(4		)	—			—			14		15			(58		)	(60		)	—		—
	Amortization of net loss		171			255			243			131			48		34			55			53			—		68
	Net periodic cost (benefit)		99			300			(131		)	74			124		117			33			38			47		323
	Amortization of pre-merger regulatory asset		—			—			571			571			—		—			—			—			6		6
	Total periodic cost		$	99		$	300		$	440		$	645		$	124	$	117		$	33		$	38		$	53	$	329
	We expect to record pension and postretirement benefit costs of approximately $999,000 for 2013. 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 of 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 $4.6 million and $5.2 million at September 30, 2013 and December 31, 2012, respectively.
	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 pursuant to a Florida PSC order. 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 and nine months ended September 30, 2013:
	For Three Months Ended September 30, 2013		Chesapeake			FPU			Chesapeake			Chesapeake			FPU		Total
			Pension			Pension			Pension SERP			Postretirement			Medical
			Plan			Plan						Plan			Plan
	(in thousands)
	Prior service cost (credit)		$	—		$	—		$	5		$	(19	)	$	—	(14		)
	Net loss		57			81			16			18			—		172
	Total recognized in net periodic benefit cost		$	57		$	81		$	21		$	(1	)	$	—	$	158
	Recognized from accumulated other comprehensive loss (1)		$	57		$	15		$	21		$	(1	)	$	—	$	92
	Recognized from regulatory asset		—			66			—			—			—		66
	Total		$	57		$	81		$	21		$	(1	)	$	—	$	158
	For the Nine Months Ended September 30, 2013		Chesapeake			FPU			Chesapeake			Chesapeake			FPU		Total
			Pension			Pension			Pension SERP			Postretirement			Medical
			Plan			Plan						Plan			Plan
	(in thousands)
	Prior service cost (credit)		$	(1	)	$	—		$	14		$	(58	)	$	—	(45		)
	Net loss		171			243			48			55			—		517
	Total recognized in net periodic benefit cost		$	170		$	243		$	62		$	(3	)	$	—	$	472
	Recognized from accumulated other comprehensive loss (1)		$	170		$	46		$	62		$	(3	)	$	—	$	275
	Recognized from regulatory asset		—			197			—			—			—		197
	Total		$	170		$	243		$	62		$	(3	)	$	—	$	472
	(1)	See Note 8, “Accumulated Other Comprehensive Income (Loss).
	During the three and nine months ended September 30, 2013, we contributed $142,000 and $233,000, respectively, to the Chesapeake pension plan. We also contributed $211,000 and $421,000, respectively, to the FPU pension plan during the three and nine months ended September 30, 2013. We expect to contribute a total of $364,000 and $842,000 to the Chesapeake and FPU pension plans, respectively, during 2013, representing minimum contribution payments required in 2013.
	The Chesapeake Pension Supplemental Executive Retirement Plan (“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 Pension SERP for the three and nine months ended September 30, 2013, were $22,000 and $67,000, respectively. We expect to pay total cash benefits of approximately $88,000 under the Chesapeake Pension SERP in 2013. Cash benefits paid for the Chesapeake Postretirement Plan, primarily for medical claims for the three and nine months ended September 30, 2013, were $16,000 and $53,000, respectively. We have estimated that approximately $97,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2013. Cash benefits paid for the FPU Medical Plan, primarily for medical claims for the three and nine months ended September 30, 2013, were $50,000 and $91,000, respectively. We estimate that approximately $258,000 will be paid for such benefits under the FPU Medical Plan in 2013.

Investments

Investments	9 Months Ended
	Sep. 30, 2013
Investments, Debt and Equity Securities [Abstract]	'
Investments	'
	Investments
	The investment balances at September 30, 2013 and December 31, 2012, consist of the following:
	(in thousands)	September 30,		December 31,
		2013		2012
	Rabbi trust (associated with Supplemental Executive Retirement Savings Plan)	$	2,691	$	2,116
	Rabbi trust (associated with certain directors' compensation)	97		39
	Investments in equity securities	—		2,013
	Total	$	2,788	$	4,168
	We classify these investments as trading securities and report them at their fair value. For the three months ended September 30, 2013 and 2012, we recorded a net unrealized loss of $259,000 and a net unrealized gain of $102,000, respectively, in other income in the condensed consolidated statements of income related to these investments. For the nine months ended September 30, 2013 and 2012, we recorded a net unrealized gain of $217,000 and a net unrealized loss of $502,000, 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 Trusts.

ShareBased_Compensation

Share-Based Compensation	9 Months Ended
	Sep. 30, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Share-Based Compensation	'
	Share-Based Compensation
	Effective May 2, 2013, our non-employee directors and key employees are awarded share-based awards through our 2013 stock and incentive compensation plan. Prior to May 2, 2013, our non-employee directors and key employees were awarded share-based awards through our Directors Stock Compensation Plan (“DSCP”) and our Performance Incentive Plan (“PIP”), respectively. 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 each award on the date it was granted.
	The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the DSCP and the PIP for the three and nine months ended September 30, 2013 and 2012:
		Three Months							Nine Months
	For the Periods Ended September 30,	2013				2012			2013			2012
	(in thousands)
	Directors Stock Compensation Plan	$	124			$	111		$	354		$	332
	Performance Incentive Plan	261				304			892			779
	Total compensation expense	385				415			1,246			1,111
	Less: tax benefit	(155		)		(166		)	(502		)	(446		)
	Share-Based Compensation amounts included in net income	$	230			$	249		$	744		$	665
	Directors Stock Compensation Plan
	Shares granted under the DSCP 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 2013, each of our non-employee directors received an annual retainer of 857 shares of common stock under the DSCP. A summary of the stock activity under the DSCP during the nine months ended September 30, 2013 is presented below.
		Number of Shares			Weighted Average Grant date Fair Value
	Outstanding - December 31, 2012	—			—
	Granted	9,427			$	52.49
	Vested	9,427			$	52.49
	Forfeited	—			—
	Outstanding - September 30, 2013	—			—
	At September 30, 2013, there was $288,000 of unrecognized compensation expense related to the DSCP awards. This expense will be recognized over the directors’ remaining service periods ending April 30, 2014.
	Performance Incentive Plan
	The table below presents the summary of the stock activity for the PIP for the nine months ended September 30, 2013:
		Number of Shares			Weighted Average
					Fair Value
	Outstanding—December 31, 2012	84,645			$	37.86
	Granted	23,491			$	44.85
	Vested	24,332			$	33.26
	Expired	3,043			$	39.12
	Outstanding—September 30, 2013	80,761			$	42.3
	In January 2013, the Board of Directors granted awards of 23,491 shares under the PIP, which are multi-year awards that will vest at the end of the three-year service period, or December 31, 2015. These awards are earned based upon the successful achievement of long-term goals, growth and financial results, which are comprised of 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 September 30, 2013, the aggregate intrinsic value of the PIP awards was $4.2 million.

Derivative_Instruments

Derivative Instruments	9 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Derivative Instruments	'
	Derivative Instruments
	We use derivative and non-derivative contracts to engage in trading activities and manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to their customers. Purchases under these contracts 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 in order to mitigate the impact of wholesale price fluctuations. As of September 30, 2013, our natural gas and electric distribution operations did not have any outstanding derivative contracts.
	In June 2013, our propane distribution operation entered into put options to protect against the decline in propane prices and related potential inventory losses associated with 1.3 million gallons purchased for the propane price cap program in the upcoming heating season. The put options are exercised if propane prices fall below the strike prices of $0.830 per gallon in December 2013 through February of 2014, and $0.860 per gallon in January through March 2014. We will receive the difference between the market price and the strike prices during those months. We paid $120,000 to purchase the put options, and we accounted for them as fair value hedges. As of September 30, 2013, the put options had a fair value of $63,000. The change in the fair value of the put options reduced our propane inventory balance.
	In May 2013, our propane distribution operation entered into a call option to protect against an increase in propane prices associated with 630,000 gallons expected to be purchased 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 upcoming heating season, is capped at a pre-determined level. The call option is exercised if the propane prices rise above the strike price of $0.975 per gallon in January through March of 2014. We will receive the difference between the market price and the strike price during those months. We paid $72,000 to purchase the call option, and we accounted for it as a derivative instrument on a mark-to-market basis with any change in its fair value being reflected in current period earnings. As of September 30, 2013, the call option had a fair value of $102,000.
	In May 2012, our propane distribution operation entered into call options to protect against an increase in propane prices associated with 1.3 gallons purchased for the propane price cap program for December 2012 through March 2013. The call options would have been exercised if the propane prices had risen above the strike prices, which ranged from $0.905 per gallon to $0.990 per gallon during that four-month period. We paid $139,000 to purchase the call options, which expired without exercise as the market prices were below the strike prices. We accounted for these call options as a fair value hedge. There was no ineffective portion of this fair value hedge.
	Xeron, Inc. (“Xeron”), our propane wholesale marketing subsidiary, 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 September 30, 2013, we had the following outstanding trading contracts which we accounted for as derivatives:
	At September 30, 2013		Quantity in		Estimated Market		Weighted Average
			Gallons		Prices		Contract Prices
	Forward Contracts
	Sale		1,682,000		$0.9625 - $1.1338		$	1.037
	Purchase		1,682,000		$0.9038 - $1.3176		$	0.9861
	Estimated market prices and weighted average contract prices are in dollars per gallon.
	All contracts expire by the end of the first quarter of 2014.
	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 September 30, 2013, Xeron had a right to offset $2.3 million and $1.1 million of accounts receivable and accounts payable, respectively, with these two counterparties. At December 31, 2012, Xeron had a right to offset $1.2 million and $511,000 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.
	Fair values of the derivative contracts recorded in the condensed consolidated balance sheet as of September 30, 2013 and December 31, 2012, are as follows:
			Asset Derivatives
				Fair Value
	(in thousands)		Balance Sheet Location	30-Sep-13				31-Dec-12
	Derivatives not designated as hedging instruments
	Forward contracts		Mark-to-market energy assets	$	214			$	182
	Call Option		Mark-to-market energy assets	102				$	—
	Derivatives designated as fair value hedges
	Call options (1)		Mark-to-market energy assets	—				28
	Put Options(2)		Mark-to-market energy assets	63				—
	Total asset derivatives			$	379			$	210
			Liability Derivatives
				Fair Value
	(in thousands)		Balance Sheet Location	30-Sep-13				31-Dec-12
	Derivatives not designated as hedging instruments
	Forward contracts		Mark-to-market energy liabilities	$	124			$	331
	Total liability derivatives			$	124			$	331
	(1)	We purchased call options for the propane price cap program in May 2012. The call options expired in March 2013.
	(2)	As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with these put options 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 call option effectively changed the value of propane inventory.
	The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows:
				Amount of Gain (Loss) on Derivatives:
			Location of Gain	For the Three Months Ended September 30,							For the Nine Months Ended September 30,
	(in thousands)		(Loss) on Derivatives	2013				2012			2013			2012
	Derivatives not designated as hedging instruments:
	Unrealized gain (loss) on forward contracts		Revenue	$	86			86			239			(147		)
	Call Option		Cost of sales	38				—			29			—
	Derivatives designated as fair value hedges:
	Put/Call Option		Cost of sales	—				—			(28		)	27
	Put/Call Options		Inventory	(43		)		(2		)	(57		)	(17		)
	Total			$	81			$	84		$	183		$	(137	)
	The effects of trading activities on the condensed consolidated statements of income are the following:
			Location in the	For the Three Months Ended September 30,							For the Nine Months Ended September 30,
	(in thousands)		Statements of Income	2013				2012			2013			2012
	Realized gain on forward contracts and options		Revenue	$	321			$	911		$	506		$	2,233
	Unrealized gain (loss) on forward contracts		Revenue	86				86			239			(147		)
	Total			$	407			$	997		$	745		$	2,086

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
Fair Value of Financial Instruments	'
	Fair Value of Financial Instruments
	GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are the following:
	Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;
	Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and
	Level 3: Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity).
	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 used at September 30, 2013 and December 31, 2012:
					Fair Value Measurements Using:
	30-Sep-13		Fair Value		Quoted Prices in		Significant Other		Significant
					Active Markets		Observable		Unobservable
					(Level 1)		Inputs		Inputs
							(Level 2)		(Level 3)
	(in thousands)
	Assets:
	Investments—guaranteed income fund		$	512	$	—	$	—	$	512
	Investments—other		$	2,276	$	2,276	$	—	$	—
	Mark-to-market energy assets, including put/call options		$	379	$	—	$	379	$	—
	Liabilities:
	Mark-to-market energy liabilities		$	124	$	—	$	124	$	—
					Fair Value Measurements Using:
	December 31, 2012		Fair Value		Quoted Prices in		Significant Other		Significant
	(in thousands)				Active Markets		Observable		Unobservable
					(Level 1)		Inputs		Inputs
							(Level 2)		(Level 3)
	Assets:
	Investments—equity securities		$	2,007	$	2,007	$	—	$	—
	Investments—other		$	2,161	$	2,161	$	—	$	—
	Mark-to-market energy assets, including call options		$	210	$	—	$	210	$	—
	Liabilities:
	Mark-to-market energy liabilities		$	331	$	—	$	331	$	—
	The following table sets forth the summary of the changes in the fair value of Level 3 investments for the nine months ended September 30, 2013:
	At September 30,	2013
	(in thousands)
	Beginning Balance	$	—
	Transfers in due to change in trustee	425
	Purchases and adjustments	98
	Transfers	(16		)
	Investment Income	5
	Ending Balance	$	512
	Investment income from the Level 3 investments is reflected in other income (loss) in the accompanying condensed consolidated statements of income.
	The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of September 30, 2013 and December 31, 2012:
	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 over the counter (“OTC”) markets.
	Propane put/call options—The fair value of the propane put/call options 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.
	At September 30, 2013, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.
	Other Financial Assets and Liabilities
	Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its short maturities and because interest rates approximate current market rates (Level 3 measurement).
	At September 30, 2013, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of $108.5 million. This compares to a fair value of $127.2 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, 2012, long-term debt, including the current maturities, had a carrying value of $110.1 million, compared to the estimated fair value of $133.2 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

LongTerm_Debt

Long-Term Debt	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
Long-Term Debt	'
	Long-Term Debt
	Our outstanding long-term debt is shown below:
			September 30,			December 31,
	(in thousands)		2013			2012
	FPU secured first mortgage bonds (A) :
	9.57% bond, due May 1, 2018		$	—		$	5,444
	10.03% bond, due May 1, 2018		—			2,994
	9.08% bond, due June 1, 2022		7,966			7,962
	Uncollateralized senior notes:
	7.83% note, due January 1, 2015		4,000			4,000
	6.64% note, due October 31, 2017		13,636			13,636
	5.50% note, due October 12, 2020		16,000			16,000
	5.93% note, due October 31, 2023		30,000			30,000
	5.68% note, due June 30, 2026		29,000			29,000
	6.43% note, due May 2, 2028		7,000			—
	Convertible debentures:
	8.25% due March 1, 2014		854			942
	Promissory note		80			125
	Capital lease obligation		7,042			—
	Total long-term debt		115,578			110,103
	Less: current maturities		(8,234		)	(8,196		)
	Total long-term debt, net of current maturities		$	107,344		$	101,907
	(A)	FPU secured first mortgage bonds are guaranteed by Chesapeake.
	In June 2010, we entered into an agreement with Metropolitan Life Insurance Company and New England Life Insurance Company to issue up to $36.0 million of Chesapeake’s unsecured senior notes. In June 2011, we issued $29.0 million of 5.68 percent unsecured senior notes to permanently finance the redemption of two series of FPU first mortgage bonds in 2010. On May 2, 2013, we issued an additional $7.0 million of 6.43 percent unsecured senior notes under the same agreement. These notes have similar covenants and default provisions as the senior notes issued in June 2011. We used these proceeds to redeem the 9.57 percent and 10.03 percent series of FPU’s first mortgage bonds in May 2013, prior to their respective maturities. The difference between the carrying value of those bonds and the amount paid at redemption totaling $93,000 was deferred as a regulatory asset. We are amortizing this difference over the remaining terms of these bonds as adjustments to interest expense, as allowed by the Florida PSC.
	On September 5, 2013, we entered into a Note Purchase Agreement (the "Note Agreement") with PAR U Hartford Life & Annuity Comfort Trust, The Prudential Insurance Company of America, The Gibraltar Life Insurance Co., Ltd., The Penn Mutual Life Insurance Company, Thrivent Financial for Lutherans, United of Omaha Life Insurance Company, and Companion Life Insurance Company (collectively, the "Note Holders"). Under the terms of the Note Agreement, we will issue $70.0 million in aggregate of unsecured Senior Notes to the Note Holders. Series A of the unsecured Senior Notes ("Series A Notes"), with an aggregate principal amount of $20.0 million, will be issued on December 16, 2013 at a rate of 3.73 percent. Series B of the unsecured Senior Notes ("Series B Notes" and collectively with Series A Notes, the "Notes"), with an aggregate principal amount of $50.0 million, will be issued on May 15, 2014, at a rate of 3.88 percent. The proceeds received from the issuances of the Notes will be used to reduce our short-term borrowings under our lines of credit and to fund capital expenditures.
	Series A Notes require annual principal payments of $2.0 million commencing on December 16, 2019. The entire outstanding principal balance of the Series A Notes is due and payable on December 16, 2028. Semiannual payments for Series A Notes are due on June 16 and December 16 of each year, commencing on June 16, 2014. All accrued but unpaid interest due under the Series A Notes is payable on December 16, 2028. Series B Notes require annual principal payments of $5.0 million commencing on May 15, 2020. The entire outstanding principal balance of the Series B Notes is due and payable on May 15, 2029. Semiannual payments for Series B Notes are due on May 15 and November 15 of each year, commencing on November 15, 2014. All accrued but unpaid interest due under the Series B Notes is payable on May 15, 2029.
	The Notes may be accelerated if the aggregate net book value of our regulated business assets is less than 50 percent of our consolidated total assets. The Notes may also be accelerated upon the occurrence of a default as provided in the Note Agreement. The Note Agreement sets forth certain business and financial covenants to which the Company is subject, including covenants that limit or restrict the Company and its subsidiaries to incur indebtedness and to incur certain liens and encumbrances on any of its property.

ShortTerm_Debt

Short-Term Debt	9 Months Ended
	Sep. 30, 2013
Debt Disclosure [Abstract]	'
Short-Term Debt	'
	Short-Term Debt
	On June 28, 2013, we entered into a $55.0 million committed unsecured, short-term credit facility with Bank of America, N.A., which increases the total short-term loan capacity available from Bank of America, N.A. from $50.0 million to $75.0 million. This facility replaces a $30.0 million committed unsecured, short-term credit facility, which expired on June 28, 2013. This new committed unsecured, short-term facility matures on June 27, 2014. Borrowings under this new credit facility will bear interest at a rate equal to LIBOR plus 125 basis points or Bank of America’s Base Rate (as defined in the term note agreement) plus 125 basis points, with the form of interest rate selected at our discretion. Other terms and conditions of this facility are substantially the same as the former facility available from Bank of America, N.A. We intend to utilize this credit facility for working capital needs, to temporarily fund capital expenditures and general corporate purposes. In addition to the $55.0 million, committed unsecured short-term credit facility, we have a $20.0 million uncommitted unsecured, short-term credit facility with Bank of America, N.A., which was also renewed on June 28, 2013. In addition to the Bank of America, N.A. facilities, Chesapeake has other short-term credit facilities with PNC Bank, N.A. totaling $90.0 million, $70.0 million of which is committed and $20.0 million of which is uncommitted.

Summary_of_Accounting_Policies1

Summary of Accounting Policies (Policies)	9 Months Ended
	Sep. 30, 2013
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 Securities and Exchange Commission (“SEC”) and accounting principles generally accepted in the United States of America (“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, 2012. 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.
	During the third quarter of 2013, we recorded an accrual of $698,000 (424,000, net of tax) due to a contingency for taxes other than income, $248,000, $222,000 and $60,000 of which relate to the years ended December 31, 2012, 2011 and 2010, respectively. This reduced our earnings in the third quarter of 2013 and was reflected in other taxes in the accompanying condensed consolidated statements of income for the three and nine months ended September 30, 2013. All of the amounts are related to our unregulated energy segment.
	We have assessed and reported on subsequent events through the date of issuance of these condensed consolidated financial statements.
Reclassifications	'
	Reclassifications
	We reclassified certain amounts in the condensed consolidated cash flows statement for the nine months ended September 30, 2012 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.
New Accounting Pronouncements, Policy [Policy Text Block]	'
	Income Taxes (Accounting Standards Codification ("ASC") 740) - In July 2013, the FASB issued Accounting Standards Update (“ASU”) 2013-11, “Presentation of an Unrecognized Tax Benefit When a Net Operating Loss Carryforward, a Similar Tax Loss, or a Tax Credit Carryforward Exists,” which requires the netting of certain unrecognized tax benefits against a deferred tax asset for a loss or other similar tax carryforward that would apply upon settlement of an uncertain tax position. This ASU is effective prospectively beginning on January 1, 2014 for all unrecognized tax benefits existing at the adoption of this new standard. Retrospective implementation and early adoption of this standard are permitted. We expect the adoption of ASU 2013-11 to have no material impact on our financial position and results of operations.
Comprehensive Income	'
	ASU 2013-02, “Reporting of Amounts Reclassified Out Of Accumulated Other Comprehensive Income,” which requires enhanced disclosures of amounts reclassified out of accumulated other comprehensive income by component. The adoption of ASU 2013-02 had no impact on our financial position and results of operations.
Offsetting Assets and Liabilities	'
	ASU 2013-01, “Clarifying the Scope of Disclosures about Offsetting Assets and Liabilities.” These new standards require disclosures about offsetting and related arrangements in order to help financial statement users better understand the effect of those arrangements on our financial position. The adoption of ASU 2011-11 and ASU 2013-01 had no material impact on our financial position and results of operations. See Note 12, "Derivative Instruments," for additional disclosures about our offsetting of certain assets and liabilities.

Calculation_of_Earnings_Per_Sh1

Calculation of Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2013
Earnings Per Share [Abstract]	'
Calculation of Basic and Diluted Earnings Per Share	'
		Three Months				Nine Months
	For the Periods Ended September 30,	2013		2012		2013		2012
	(in thousands, except shares and per share data)
	Calculation of Basic Earnings Per Share:
	Net Income	$	3,879	$	3,219	$	23,104	$	19,006
	Weighted average shares outstanding	9,625,435		9,592,417		9,616,269		9,583,316
	Basic Earnings Per Share	$	0.4	$	0.34	$	2.4	$	1.98
	Calculation of Diluted Earnings Per Share:
	Reconciliation of Numerator:
	Net Income	$	3,879	$	3,219	$	23,104	$	19,006
	Effect of 8.25% Convertible debentures	11		13		33		41
	Adjusted numerator—Diluted	$	3,890	$	3,232	$	23,137	$	19,047
	Reconciliation of Denominator:
	Weighted shares outstanding—Basic	9,625,435		9,592,417		9,616,269		9,583,316
	Effect of dilutive securities:
	Share-based Compensation	26,123		23,770		23,888		22,684
	8.25% Convertible debentures	50,776		60,471		52,154		67,681
	Adjusted denominator—Diluted	9,702,334		9,676,658		9,692,311		9,673,681
	Diluted Earnings Per Share	$	0.4	$	0.33	$	2.39	$	1.97

Segment_Information_Tables

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2013
Segment Reporting [Abstract]	'
Schedule of Segment Reporting Information by Segment	'
	The following table presents financial information about our reportable segments.
			Three Months						Nine Months
	For the Periods Ended September 30,		2013			2012			2013		2012
	(in thousands)
	Operating Revenues, Unaffiliated Customers
	Regulated Energy		$	55,387		$	51,868		$	191,666	$	179,139
	Unregulated Energy		26,103			21,861			115,367		91,001
	Other		5,055			4,446			14,386		12,846
	Total operating revenues, unaffiliated customers		$	86,545		$	78,175		$	321,419	$	282,986
	Intersegment Revenues (1)
	Regulated Energy		$	293		$	328		$	797	$	906
	Unregulated Energy		2,159			1,398			3,911		2,322
	Other		274			220			743		675
	Total intersegment revenues		$	2,726		$	1,946		$	5,451	$	3,903
	Operating Income
	Regulated Energy		$	10,243		$	7,848		$	36,169	$	33,151
	Unregulated Energy		(1,803		)	(709		)	8,013		4,044
	Other and eliminations		280			425			240		897
	Total operating income		8,720			7,564			44,422		38,092
	Other income, net of other expenses		101			(136		)	413		212
	Interest		2,026			2,126			6,114		6,657
	Income before Income Taxes		6,795			5,302			38,721		31,647
	Income taxes		2,916			2,083			15,617		12,641
	Net Income		$	3,879		$	3,219		$	23,104	$	19,006
	(1)	All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.
	(in thousands)		September 30,			December 31,
			2013			2012
	Identifiable Assets
	Regulated energy		$	683,258		$	615,438
	Unregulated energy		88,032			79,287
	Other		26,267			39,021
	Total identifiable assets		$	797,557		$	733,746

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Loss) (Tables)	9 Months Ended
	Sep. 30, 2013
Equity [Abstract]	'
Changes in Accumulated Other Comprehensive Loss	'
	The following table presents the changes in the balance of accumulated other comprehensive income (loss) for the three and nine months ended September 30, 2013. Defined benefit pension and postretirement plan items are the only component of our accumulated comprehensive income (loss). All amounts in the following table are presented net of tax.
	For the Periods Ended September 30, 2013		Three Months			Nine Months
	(in thousands)
	Beginning balance		$	(4,958	)	$	(5,062	)
	Other comprehensive loss before reclassifications		—			(6		)
	Amounts reclassified from accumulated other comprehensive loss		55			165
	Net current-period other comprehensive income		55			159
	Ending balance		$	(4,903	)	$	(4,903	)
Reclassifications out of Accumulated Other Comprehensive Income (Loss)	'
	The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, 2013.
	For the Periods Ended September 30, 2013		Three Months			Nine Months
	(in thousands)
	Amortization of defined benefit pension and postretirement plan items:
	Prior service cost (1)		$	15		$	45
	Net loss (1)		$	(107	)	$	(320	)
	Total before tax		(92		)	(275		)
	Tax benefit		37			110
	Net of tax		$	(55	)	$	(165	)
	(1)	These amounts are included in the computation of net periodic costs (benefits). See Note 9, “Employee Benefit Plans,” for additional details.

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables)	9 Months Ended
	Sep. 30, 2013
Compensation and Retirement Disclosure [Abstract]	'
Employee Benefit Plans	'
	Net periodic benefit costs for our pension and post-retirement benefits plans for the three and nine months ended September 30, 2013 and 2012 are set forth in the following tables:
			Chesapeake						FPU						Chesapeake					Chesapeake						FPU
			Pension Plan						Pension Plan						Pension SERP					Postretirement						Medical
																				Plan						Plan
	For the Three Months Ended September 30,		2013			2012			2013			2012			2013		2012			2013			2012			2013		2012
	(in thousands)
	Service cost		$	—		$	—		$	—		$	—		$	—	$	—		$	—		$	—		$	—	$	40
	Interest cost		102			125			594			638			21		23			12			15			16		45
	Expected return on plan assets		(126		)	(108		)	(719		)	(658		)	—		—			—			—			—		—
	Amortization of prior service cost		—			(1		)	—			—			5		5			(19		)	(20		)	—		—
	Amortization of net loss		57			85			81			43			16		11			18			18			—		23
	Net periodic cost (benefit)		33			101			(44		)	23			42		39			11			13			16		108
	Amortization of pre-merger regulatory asset		—			—			191			190			—		—			—			—			2		2
	Total periodic cost		$	33		$	101		$	147		$	213		$	42	$	39		$	11		$	13		$	18	$	110
			Chesapeake						FPU						Chesapeake					Chesapeake						FPU
			Pension Plan						Pension Plan						Pension SERP					Postretirement						Medical
																				Plan						Plan
	For the Nine Months Ended September 30,		2013			2012			2013			2012			2013		2012			2013			2012			2013		2012
	(in thousands)
	Service cost		$	—		$	—		$	—		$	—		$	—	$	—		$	—		$	—		$	—	$	120
	Interest cost		307			375			1,782			1,916			62		68			36			45			47		135
	Expected return on plan assets		(378		)	(326		)	(2,156		)	(1,973		)	—		—			—			—			—		—
	Amortization of prior service cost		(1		)	(4		)	—			—			14		15			(58		)	(60		)	—		—
	Amortization of net loss		171			255			243			131			48		34			55			53			—		68
	Net periodic cost (benefit)		99			300			(131		)	74			124		117			33			38			47		323
	Amortization of pre-merger regulatory asset		—			—			571			571			—		—			—			—			6		6
	Total periodic cost		$	99		$	300		$	440		$	645		$	124	$	117		$	33		$	38		$	53	$	329
Amounts Included in Regulatory Asset and Accumulated Other Comprehensive Income/Loss Recognized as Net Periodic Benefit Cost	'
	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 and nine months ended September 30, 2013:
	For Three Months Ended September 30, 2013		Chesapeake			FPU			Chesapeake			Chesapeake			FPU		Total
			Pension			Pension			Pension SERP			Postretirement			Medical
			Plan			Plan						Plan			Plan
	(in thousands)
	Prior service cost (credit)		$	—		$	—		$	5		$	(19	)	$	—	(14		)
	Net loss		57			81			16			18			—		172
	Total recognized in net periodic benefit cost		$	57		$	81		$	21		$	(1	)	$	—	$	158
	Recognized from accumulated other comprehensive loss (1)		$	57		$	15		$	21		$	(1	)	$	—	$	92
	Recognized from regulatory asset		—			66			—			—			—		66
	Total		$	57		$	81		$	21		$	(1	)	$	—	$	158
	For the Nine Months Ended September 30, 2013		Chesapeake			FPU			Chesapeake			Chesapeake			FPU		Total
			Pension			Pension			Pension SERP			Postretirement			Medical
			Plan			Plan						Plan			Plan
	(in thousands)
	Prior service cost (credit)		$	(1	)	$	—		$	14		$	(58	)	$	—	(45		)
	Net loss		171			243			48			55			—		517
	Total recognized in net periodic benefit cost		$	170		$	243		$	62		$	(3	)	$	—	$	472
	Recognized from accumulated other comprehensive loss (1)		$	170		$	46		$	62		$	(3	)	$	—	$	275
	Recognized from regulatory asset		—			197			—			—			—		197
	Total		$	170		$	243		$	62		$	(3	)	$	—	$	472
	(1)	See Note 8, “Accumulated Other Comprehensive Income (Loss).

Investments_Tables

Investments (Tables)	9 Months Ended
	Sep. 30, 2013
Investments, Debt and Equity Securities [Abstract]	'
Schedule of Investment	'
	The investment balances at September 30, 2013 and December 31, 2012, consist of the following:
	(in thousands)	September 30,		December 31,
		2013		2012
	Rabbi trust (associated with Supplemental Executive Retirement Savings Plan)	$	2,691	$	2,116
	Rabbi trust (associated with certain directors' compensation)	97		39
	Investments in equity securities	—		2,013
	Total	$	2,788	$	4,168

ShareBased_Compensation_Tables

Share-Based Compensation (Tables)	9 Months Ended
	Sep. 30, 2013
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]	'
Share-Based Compensation Amounts Included in Net Income	'
	The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the DSCP and the PIP for the three and nine months ended September 30, 2013 and 2012:
		Three Months							Nine Months
	For the Periods Ended September 30,	2013				2012			2013			2012
	(in thousands)
	Directors Stock Compensation Plan	$	124			$	111		$	354		$	332
	Performance Incentive Plan	261				304			892			779
	Total compensation expense	385				415			1,246			1,111
	Less: tax benefit	(155		)		(166		)	(502		)	(446		)
	Share-Based Compensation amounts included in net income	$	230			$	249		$	744		$	665
Stock Options Activity	'
	A summary of the stock activity under the DSCP during the nine months ended September 30, 2013 is presented below.
		Number of Shares			Weighted Average Grant date Fair Value
	Outstanding - December 31, 2012	—			—
	Granted	9,427			$	52.49
	Vested	9,427			$	52.49
	Forfeited	—			—
	Outstanding - September 30, 2013	—			—
Summary of Stock Activity under PIP	'
	The table below presents the summary of the stock activity for the PIP for the nine months ended September 30, 2013:
		Number of Shares			Weighted Average
					Fair Value
	Outstanding—December 31, 2012	84,645			$	37.86
	Granted	23,491			$	44.85
	Vested	24,332			$	33.26
	Expired	3,043			$	39.12
	Outstanding—September 30, 2013	80,761			$	42.3

Derivative_Instruments_Tables

Derivative Instruments (Tables)	9 Months Ended
	Sep. 30, 2013
Derivative Instruments and Hedging Activities Disclosure [Abstract]	'
Outstanding Trading Contracts	'
	As of September 30, 2013, we had the following outstanding trading contracts which we accounted for as derivatives:
	At September 30, 2013		Quantity in		Estimated Market		Weighted Average
			Gallons		Prices		Contract Prices
	Forward Contracts
	Sale		1,682,000		$0.9625 - $1.1338		$	1.037
	Purchase		1,682,000		$0.9038 - $1.3176		$	0.9861
Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet	'
	Fair values of the derivative contracts recorded in the condensed consolidated balance sheet as of September 30, 2013 and December 31, 2012, are as follows:
			Asset Derivatives
				Fair Value
	(in thousands)		Balance Sheet Location	30-Sep-13				31-Dec-12
	Derivatives not designated as hedging instruments
	Forward contracts		Mark-to-market energy assets	$	214			$	182
	Call Option		Mark-to-market energy assets	102				$	—
	Derivatives designated as fair value hedges
	Call options (1)		Mark-to-market energy assets	—				28
	Put Options(2)		Mark-to-market energy assets	63				—
	Total asset derivatives			$	379			$	210
			Liability Derivatives
				Fair Value
	(in thousands)		Balance Sheet Location	30-Sep-13				31-Dec-12
	Derivatives not designated as hedging instruments
	Forward contracts		Mark-to-market energy liabilities	$	124			$	331
	Total liability derivatives			$	124			$	331
	(1)	We purchased call options for the propane price cap program in May 2012. The call options expired in March 2013.
	(2)	As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with these put options 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 call option effectively changed the value of propane inventory.
Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements	'
	The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows:
				Amount of Gain (Loss) on Derivatives:
			Location of Gain	For the Three Months Ended September 30,							For the Nine Months Ended September 30,
	(in thousands)		(Loss) on Derivatives	2013				2012			2013			2012
	Derivatives not designated as hedging instruments:
	Unrealized gain (loss) on forward contracts		Revenue	$	86			86			239			(147		)
	Call Option		Cost of sales	38				—			29			—
	Derivatives designated as fair value hedges:
	Put/Call Option		Cost of sales	—				—			(28		)	27
	Put/Call Options		Inventory	(43		)		(2		)	(57		)	(17		)
	Total			$	81			$	84		$	183		$	(137	)
Effects of Trading Activities on Condensed Consolidated Statements of Income	'
	The effects of trading activities on the condensed consolidated statements of income are the following:
			Location in the	For the Three Months Ended September 30,							For the Nine Months Ended September 30,
	(in thousands)		Statements of Income	2013				2012			2013			2012
	Realized gain on forward contracts and options		Revenue	$	321			$	911		$	506		$	2,233
	Unrealized gain (loss) on forward contracts		Revenue	86				86			239			(147		)
	Total			$	407			$	997		$	745		$	2,086

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Tables)	9 Months Ended
	Sep. 30, 2013
Fair Value Disclosures [Abstract]	'
Financial Assets and Liabilities Measured at Fair Value on Recurring Basis	'
	The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at September 30, 2013 and December 31, 2012:
					Fair Value Measurements Using:
	30-Sep-13		Fair Value		Quoted Prices in		Significant Other		Significant
					Active Markets		Observable		Unobservable
					(Level 1)		Inputs		Inputs
							(Level 2)		(Level 3)
	(in thousands)
	Assets:
	Investments—guaranteed income fund		$	512	$	—	$	—	$	512
	Investments—other		$	2,276	$	2,276	$	—	$	—
	Mark-to-market energy assets, including put/call options		$	379	$	—	$	379	$	—
	Liabilities:
	Mark-to-market energy liabilities		$	124	$	—	$	124	$	—
					Fair Value Measurements Using:
	December 31, 2012		Fair Value		Quoted Prices in		Significant Other		Significant
	(in thousands)				Active Markets		Observable		Unobservable
					(Level 1)		Inputs		Inputs
							(Level 2)		(Level 3)
	Assets:
	Investments—equity securities		$	2,007	$	2,007	$	—	$	—
	Investments—other		$	2,161	$	2,161	$	—	$	—
	Mark-to-market energy assets, including call options		$	210	$	—	$	210	$	—
	Liabilities:
	Mark-to-market energy liabilities		$	331	$	—	$	331	$	—
Summary of Changes in Fair Value of Investments	'
	The following table sets forth the summary of the changes in the fair value of Level 3 investments for the nine months ended September 30, 2013:
	At September 30,	2013
	(in thousands)
	Beginning Balance	$	—
	Transfers in due to change in trustee	425
	Purchases and adjustments	98
	Transfers	(16		)
	Investment Income	5
	Ending Balance	$	512

LongTerm_Debt_Tables

Long-Term Debt (Tables)	6 Months Ended
	Jun. 30, 2013
Debt Disclosure [Abstract]	'
Outstanding Long-Term Debt	'
	Our outstanding long-term debt is shown below:
			September 30,			December 31,
	(in thousands)		2013			2012
	FPU secured first mortgage bonds (A) :
	9.57% bond, due May 1, 2018		$	—		$	5,444
	10.03% bond, due May 1, 2018		—			2,994
	9.08% bond, due June 1, 2022		7,966			7,962
	Uncollateralized senior notes:
	7.83% note, due January 1, 2015		4,000			4,000
	6.64% note, due October 31, 2017		13,636			13,636
	5.50% note, due October 12, 2020		16,000			16,000
	5.93% note, due October 31, 2023		30,000			30,000
	5.68% note, due June 30, 2026		29,000			29,000
	6.43% note, due May 2, 2028		7,000			—
	Convertible debentures:
	8.25% due March 1, 2014		854			942
	Promissory note		80			125
	Capital lease obligation		7,042			—
	Total long-term debt		115,578			110,103
	Less: current maturities		(8,234		)	(8,196		)
	Total long-term debt, net of current maturities		$	107,344		$	101,907
	(A)	FPU secured first mortgage bonds are guaranteed by Chesapeake.

Summary_of_Accounting_Policies2

Summary of Accounting Policies Summary of Accounting Policies (Details) (USD $)	3 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013
Quantifying Misstatement in Current Year Financial Statements [Line Items]	'
Accrual For Taxes Other Than Income Contingency, Gross	$698
Accrual For Taxes Other Than Income Contingency, Net of Tax	-424
2012 Contingency [Member]	'
Quantifying Misstatement in Current Year Financial Statements [Line Items]	'
Accrual For Taxes Other Than Income Contingency, Gross	248
2011 Contingency [Member]	'
Quantifying Misstatement in Current Year Financial Statements [Line Items]	'
Accrual For Taxes Other Than Income Contingency, Gross	222
2010 Contingency [Member]	'
Quantifying Misstatement in Current Year Financial Statements [Line Items]	'
Accrual For Taxes Other Than Income Contingency, Gross	$60

Calculation_of_Earnings_Per_Sh2

Calculation of Earnings Per Share - Calculation of Basic and Diluted Earnings Per Share (Detail) (USD $)	3 Months Ended		9 Months Ended		12 Months Ended
In Thousands, except Share data, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
Calculation of Basic Earnings Per Share:	'	'	'	'	'
Net Income	$3,879	$3,219	$23,104	$19,006	$28,863
Weighted shares outstanding - Basic (in shares)	9,625,435	9,592,417	9,616,269	9,583,316	'
Basic Earnings Per Share (in usd per share)	$0.40	$0.34	$2.40	$1.98	'
Reconciliation of Numerator:	'	'	'	'	'
Net Income	3,879	3,219	23,104	19,006	28,863
Effect of 8.25% Convertible debentures	11	13	33	41	'
Adjusted numerator-Diluted	$3,890	$3,232	$23,137	$19,047	'
Reconciliation of Denominator:	'	'	'	'	'
Weighted shares outstanding - Basic (in shares)	9,625,435	9,592,417	9,616,269	9,583,316	'
Effect of dilutive securities:	'	'	'	'	'
Share-based Compensation (in shares)	26,123	23,770	23,888	22,684	'
8.25% Convertible debentures (in shares)	50,776	60,471	52,154	67,681	'
Adjusted denominator-Diluted (in shares)	9,702,334	9,676,658	9,692,311	9,673,681	'
Diluted Earnings Per Share (in usd per share)	$0.40	$0.33	$2.39	$1.97	'

Calculation_of_Earnings_Per_Sh3

Calculation of Earnings Per Share - Calculation of Basic and Diluted Earnings Per Share (Parenthetical) (Detail) (8.25% Convertible debentures [Member])	3 Months Ended		9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
8.25% Convertible debentures [Member]	'	'	'	'
Calculation Of Numerator And Denominator In Earnings Per Share [Line Items]	'	'	'	'
Debt Instrument, Interest Rate During Period	8.25%	8.25%	8.25%	8.25%

Acquisitions_Additional_Inform

Acquisitions - Additional Information (Detail) (USD $)

0 Months Ended

3 Months Ended

9 Months Ended

9 Months Ended

6 Months Ended

9 Months Ended

6 Months Ended

9 Months Ended

12 Months Ended

31-May-13

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Jun. 07, 2013

Dec. 31, 2012

Sep. 30, 2013

Jun. 30, 2013

Sep. 30, 2013

Jun. 30, 2013

Sep. 30, 2013

Dec. 31, 2013

Feb. 05, 2013

gal

Natural Gas [Member]

Eastern Shore Gas Company [Member]

Austin Cox [Member]

Propane Acquisition [Member]

Propane Acquisition [Member]

Propane Acquisition [Member]

Propane Acquisition [Member]

sites

Customer

Customer

Business Acquisition [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchase Price Adjustment

'

$543,000

'

'

'

'

'

'

'

'

'

'

'

Transaction costs, tax

726,000

'

'

'

'

'

'

'

'

'

'

'

'

Number of residential and commercial customers receiving propane gas distribution service

'

'

'

'

'

'

'

11,000

'

3,000

'

'

'

Minimum number of customers to whom gas distribution systems and bulk delivery service provided

'

'

'

'

'

'

'

500

'

'

'

'

'

Purchase price allocated to property, plant and equipment

12,600,000

'

'

'

105,000

'

'

'

'

'

'

'

1,600,000

Purchase price allocated to propane and other inventory

344,000

'

'

'

94,000

'

'

'

'

'

'

'

502,000

Receivables

2,500,000

'

'

'

'

'

'

'

'

'

'

'

'

Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net

227,000

'

'

'

'

'

'

'

'

'

'

'

'

Number of leased propane tanks

13

'

'

'

'

'

'

'

'

'

'

'

'

Storage capacity of leased propane tanks

570,000

'

'

'

'

'

'

'

'

'

'

'

'

Duration of lease of propane tanks

'6 years

'

'

'

'

'

'

'

'

'

'

'

'

Monthly fee payment in year one

42,000

'

'

'

'

'

'

'

'

'

'

'

'

Monthly fee payment, year two to six

125,000

'

'

'

'

'

'

'

'

'

'

'

'

Annual Estimate Of Volume Of Propane To Be Purchased

7,400,000

'

'

'

'

'

'

'

'

'

'

'

'

Number of years to purchase propane under contract

'6 years

'

'

'

'

'

'

'

'

'

'

'

'

Capital Lease Obligations

7,100,000

7,042,000

7,042,000

'

'

0

'

'

'

'

'

'

'

Amortization expense

'

62,000

83,000

'

'

'

'

'

'

'

'

'

'

Capital lease asset

7,100,000

'

'

'

'

'

'

'

'

'

'

'

'

Amortization of leased asset

'

63,000

84,000

'

'

'

'

'

'

'

'

'

'

Purchase price allocated to intangible assets related to customer list

'

'

'

'

250,000

'

'

'

'

'

'

'

300,000

Acquired Finite-lived Intangible Assets, Weighted Average Useful Life

'

'

'5 years

'

'

'

'

'

'

'

'12 years

'

'

Purchase price allocated to goodwill

'

'

'

'

173,000

'

'

'

'

'

'

'

'

Payments to Acquire Businesses, Gross

'

'

-19,367,000

-124,000

'

'

16,500,000

'

600,000

'

'

2,900,000

'

Sales Tax

'

726,000

726,000

'

'

'

'

'

'

'

'

'

'

Goodwill

'

$4,716,000

$4,716,000

'

'

$4,090,000

'

'

'

'

'

'

$453,000

Rates_and_Other_Regulatory_Act1

Rates and Other Regulatory Activities - Additional Information (Detail) (USD $)

0 Months Ended

9 Months Ended

12 Months Ended

6 Months Ended

9 Months Ended

0 Months Ended

6 Months Ended

0 Months Ended

Jun. 13, 2013

31-May-13

Oct. 12, 2012

Oct. 09, 2012

Jan. 02, 2012

Sep. 30, 2013

Mar. 31, 2013

Sep. 28, 2012

25-May-12

Jun. 30, 2013

Sep. 30, 2013

Oct. 12, 2012

14-May-12

Jun. 30, 2013

Jun. 30, 2013

14-May-12

mi

compressor_station

Customer

Florida [Member]

Florida [Member]

Eastern Shore [Member]

Eastern Shore [Member]

Natural Gas Operations [Member]

Electric Operations [Member]

Mainline Expansion Project [Member]

MW

in

Investment In Affiliates [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Duration of right to give notice to FPU

'

'

'

'

'

'

'

'

'

'180 days

'180 days

'

'

'

'

'

Duration of closing of the purchase

'

'

'

'

'

'

'

'

'

'

'12 months

'

'

'

'

'

Period of extension granted by court

'

'

'

'60 days

'

'

'

'

'

'

'

'

'

'

'

'

Number of compressors

'

'

3

'

'

'

'

'

'

'

'

'

'

'

'

'

Period of current agreement exceeds

'

'

'

'

'

'

'

'

'

'

'2 years

'

'

'

'

'

Amortization period of regulatory asset

'

'

'

'

'

'

'

'

'

'

'Five years

'

'

'

'

'

Period to file case

'

'2 years 6 months

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Additional lateral capacity

'

'

'

'

'

'

'

'

'

'

'

'

15,040

'

'

'

Estimated capital cost

$11,200,000

'

'

'

'

'

'

'

'

'

'

$12,100,000

'

'

'

$16,300,000

Number of Customers Filing Motion

'

'

'

'

'

'

'

'

2

'

'

'

'

'

'

'

Legal fees

'

'

'

'

'

1,900,000

'

'

'

'

'

'

'

'

'

'

FranchiseDisputeLitigationExpensesThatRecoveryIsAllowed

'

'

'

'

'

1,800,000

'

'

'

'

'

'

'

'

'

'

RefundAmountToBeAppliedToRecoverLitigationExpenses

'

'

'

'

'

1,800,000

'

'

'

'

'

'

'

'

'

'

RegulatoryAssetAmountApprovedForFranchiseDispute

'

'

'

'

'

2,000,000

'

'

'

'

'

'

'

'

'

'

Litigation Expenses Recognized in Prior Periods Deferred As Regulatory Asset

'

'

'

'

'

1,500,000

'

'

'

'

'

'

'

'

'

'

Litigation Expenses Recognized in Current Period Deferred As Regulatory Asset

'

'

'

'

'

376,000

'

'

'

'

'

'

'

'

'

'

Regulatory Liability Related To Fuel Cost Refund

'

'

'

'

'

-2,000,000

'

'

'

'

'

'

'

'

'

'

Acquisition adjustments goodwill amount requested to be reclassified as regulatory assets

'

'

'

'

'

'

'

745,800

'

'

'

'

'

'

'

'

Net periodic benefit curtailment gain

'

'

'

'

892,000

'

'

'

'

'

'

'

'

'

'

'

Defined benefit plan recognized net gain loss due to curtailments recorded as regulatory liability

'

'

'

'

722,000

'

'

'

'

'

'

'

'

464,000

258,000

'

Amortization period for the curtailment gain regulatory liability

'

'

'

'

'34 months

'

'

'

'

'

'

'

'

'

'

'

White Oak lateral capacity of firm transportation service

55,200

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

White Oak lateral length of pipeline to be installed

5.5

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Lateral diamater of pipeline to be installed

16

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Filing period for fuel retention percentage and cash out surcharge

'

'

'

'

'

'

'12 months

'

'

'

'

'

'

'

'

'

Cycle power of the Calpine Project proposed power plant

309

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

New plant capacity volume

'

'

17,500

'

'

'

'

'

'

'

'

'

'

'

'

'

Proposed fuel retention percentage rate

'

'

'

'

'

'

0.24%

'

'

'

'

'

'

'

'

'

Cash-Our Surcharge

'

'

'

'

'

'

0.00%

'

'

'

'

'

'

'

'

'

Deferred gas required for operations underrecovery regulatory balance

'

'

'

'

'

'

285,000

'

'

'

'

'

'

'

'

'

Deferred cash out costs overrecovery regulatory balance

'

'

'

'

'

'

$146,000

'

'

'

'

'

'

'

'

'

Environmental_Commitments_and_1

Environmental Commitments and Contingencies - Additional Information (Detail) (USD $)	9 Months Ended
	Sep. 30, 2013	Sep. 30, 2012	Dec. 31, 2012
	sites
Environmental Commitments And Contingencies [Line Items]	'	'	'
Company's exposure in number of former Manufactured Gas Plant Sites	6	'	'
Environmental liabilities	$8,838,000	'	$9,114,000
Amount paid for funding requirements	276,000	345,000	'
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	10,300,000	'	'
Approval of recovery of environmental costs	14,000,000	'	'
Environmental costs recovered	9,100,000	'	'
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 for future recovery of environmental costs	4,900,000	'	'
Chesapeake [Member]	'	'	'
Environmental Commitments And Contingencies [Line Items]	'	'	'
Environmental liabilities	100,000	'	'
Regulatory assets for future recovery of environmental costs	$339,000	'	'

Environmental_Commitments_and_2

Environmental Commitments and Contingencies - Additional Information 1 (Detail) (USD $)	9 Months Ended	12 Months Ended
	Sep. 30, 2013	Dec. 31, 2010
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	'
Corrective measures cost	1,000,000	'
Winter Haven Florida [Member] | Minimum [Member]	'	'
Environmental Commitments And Contingencies [Line Items]	'	'
Remedial action time period	'2 years	'
Winter Haven Florida [Member] | Maximum [Member]	'	'
Environmental Commitments And Contingencies [Line Items]	'	'
Remedial action time period	'3 years	'
Salisbury Maryland [Member]	'	'
Environmental Commitments And Contingencies [Line Items]	'	'
Monitoring well remaining maximum cost	$5,000	'

Other_Commitments_and_Continge1

Other Commitments and Contingencies - Additional Information (Detail) (USD $)	0 Months Ended		6 Months Ended
	31-May-13	Mar. 02, 2011	Jun. 30, 2013	Sep. 30, 2013	Apr. 09, 2013	Dec. 31, 2012
	gal	claim			contingency
Other Contingencies And Commitments [Line Items]	'	'	'	'	'	'
Number of breaches claimed	'	3	'	'	'	'
Purchase period upon voter approval	'	'12 months	'	'	'	'
Number of contingencies	'	'	'	'	0	'
Number of years to purchase propane under contract	'6 years	'	'	'	'	'
Annual Estimate Of Volume Of Propane To Be Purchased	7,400,000	'	'	'	'	'
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	'	'	'
Maximum authorized liability under such guarantees and letters of credit	'	'	$45,000,000	'	'	'
Aggregate guaranteed amount	'	'	31,100,000	'	'	'
Draws on letters of credit	'	'	0	'	'	'
Liability for Uncertain Tax Positions, Noncurrent	'	'	'	300,000	'	300,000
Accrual For Taxes Other Than Income Contingencies	'	'	'	780,000	'	-82,000
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	'	'	1,094,000	'	'	'
June 1, 2014 [Member]	'	'	'	'	'	'
Other Contingencies And Commitments [Line Items]	'	'	'	'	'	'
Amount of letter of credit to our current primary insurance company	'	'	304,000	'	'	'
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_o

Segment Information - Schedule of Segment Reporting Information by Segment (Detail) (USD $)	3 Months Ended				6 Months Ended	9 Months Ended				12 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012		Jun. 30, 2013	Sep. 30, 2013		Sep. 30, 2012		Dec. 31, 2012
					segment
Segment Reporting Information [Line Items]	'		'		'	'		'		'
Number of operating segments	'		'		3	'		'		'
Operating Revenues, Unaffiliated Customers	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	$86,545		$78,175		'	$321,419		$282,987		'
Intersegment Revenues	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	86,545		78,175		'	321,419		282,987		'
Operating Income	'		'		'	'		'		'
Total operating income	8,720		7,564		'	44,422		38,092		'
Other income, net of other expenses	101		-136		'	413		212		'
Interest	2,026		2,126		'	6,114		6,657		'
Income Before Income Taxes	6,795		5,302		'	38,721		31,647		'
Income taxes	2,916		2,083		'	15,617		12,641		'
Net Income	3,879		3,219		'	23,104		19,006		28,863
Identifiable Assets	'		'		'	'		'		'
Total identifiable assets	797,557		'		797,557	797,557		'		733,746
Regulated Energy [Member]	'		'		'	'		'		'
Operating Income	'		'		'	'		'		'
Total operating income	10,243		7,848		'	36,169		33,151		'
Identifiable Assets	'		'		'	'		'		'
Total identifiable assets	'		'		683,258	'		'		615,438
Unregulated Energy [Member]	'		'		'	'		'		'
Operating Income	'		'		'	'		'		'
Total operating income	-1,803		-709		'	8,013		4,044		'
Identifiable Assets	'		'		'	'		'		'
Total identifiable assets	'		'		88,032	'		'		79,287
Other [Member]	'		'		'	'		'		'
Identifiable Assets	'		'		'	'		'		'
Total identifiable assets	'		'		26,267	'		'		39,021
Other and eliminations [Member]	'		'		'	'		'		'
Operating Income	'		'		'	'		'		'
Total operating income	280		425		'	240		897		'
Operating Revenues, Unaffiliated Customers [Member]	'		'		'	'		'		'
Operating Revenues, Unaffiliated Customers	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	86,545		78,175		'	321,419		282,986		'
Intersegment Revenues	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	86,545		78,175		'	321,419		282,986		'
Operating Revenues, Unaffiliated Customers [Member] | Regulated Energy [Member]	'		'		'	'		'		'
Operating Revenues, Unaffiliated Customers	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	55,387		51,868		'	191,666		179,139		'
Intersegment Revenues	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	55,387		51,868		'	191,666		179,139		'
Operating Revenues, Unaffiliated Customers [Member] | Unregulated Energy [Member]	'		'		'	'		'		'
Operating Revenues, Unaffiliated Customers	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	26,103		21,861		'	115,367		91,001		'
Intersegment Revenues	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	26,103		21,861		'	115,367		91,001		'
Operating Revenues, Unaffiliated Customers [Member] | Other [Member]	'		'		'	'		'		'
Operating Revenues, Unaffiliated Customers	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	5,055		4,446		'	14,386		12,846		'
Intersegment Revenues	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	5,055		4,446		'	14,386		12,846		'
Intersegment Revenues [Member]	'		'		'	'		'		'
Operating Revenues, Unaffiliated Customers	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	2,726		1,946	[1]	'	5,451		3,903		'
Intersegment Revenues	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	2,726		1,946	[1]	'	5,451		3,903		'
Intersegment Revenues [Member] | Regulated Energy [Member]	'		'		'	'		'		'
Operating Revenues, Unaffiliated Customers	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	293	[1]	328	[1]	'	797	[1]	906	[1]	'
Intersegment Revenues	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	293	[1]	328	[1]	'	797	[1]	906	[1]	'
Intersegment Revenues [Member] | Unregulated Energy [Member]	'		'		'	'		'		'
Operating Revenues, Unaffiliated Customers	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	2,159	[1]	1,398	[1]	'	3,911	[1]	2,322	[1]	'
Intersegment Revenues	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	2,159	[1]	1,398	[1]	'	3,911	[1]	2,322	[1]	'
Intersegment Revenues [Member] | Other [Member]	'		'		'	'		'		'
Operating Revenues, Unaffiliated Customers	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	274	[1]	220	[1]	'	743	[1]	675	[1]	'
Intersegment Revenues	'		'		'	'		'		'
Total operating revenues, unaffiliated customers	$274	[1]	$220	[1]	'	$743	[1]	$675	[1]	'
[1]	All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Detail) (USD $)	3 Months Ended	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2013
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]	'	'
Beginning balance	($4,958)	($5,062)
Other comprehensive loss before reclassifications	0	-6
Amounts reclassified from accumulated other comprehensive loss	55	165
Net current-period other comprehensive income (loss)	55	159
Ending balance	($4,903)	($4,903)

Accumulated_Other_Comprehensiv3

Accumulated Other Comprehensive Income (Loss) - Reclassifications of Accumulated Other Comprehensive Loss (Detail) (USD $)	3 Months Ended			9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012	Sep. 30, 2013		Sep. 30, 2012
Amortization of pension and postretirement items:	'		'	'		'
Tax benefit	$2,916		$2,083	$15,617		$12,641
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]	'		'	'		'
Amortization of pension and postretirement items:	'		'	'		'
Prior service cost	15	[1]	'	45	[1]	'
Net loss	107	[1]	'	320	[1]	'
Total before tax	-92		'	-275		'
Tax benefit	-37		'	-110		'
Net of tax	($55)		'	($165)		'
[1]	These amounts are included in the computation of net periodic costs (benefits). See Note 9, bEmployee Benefit Plans,b for additional details.

Employee_Benefit_Plans_Employe

Employee Benefit Plans - Employee Benefit Plans (Detail) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Amortization of prior service cost	($14)	'	($45)	'
Amortization of net loss	172	'	517	'
Chesapeake Pension Plan [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Interest cost	102	125	307	375
Expected return on plan assets	-126	-108	-378	-326
Amortization of prior service cost	0	-1	-1	-4
Amortization of net loss	57	85	171	255
Net periodic cost (benefit)	33	101	99	300
Total periodic cost	33	101	99	300
FPU Pension Plan [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Interest cost	594	638	1,782	1,916
Expected return on plan assets	-719	-658	-2,156	-1,973
Amortization of net loss	81	43	243	131
Net periodic cost (benefit)	-44	23	-131	'
Amortization of pre-merger regulatory asset	191	190	571	571
Total periodic cost	147	213	440	645
Chesapeake Pension SERP [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Interest cost	21	23	62	68
Amortization of prior service cost	5	5	14	15
Amortization of net loss	16	11	48	34
Net periodic cost (benefit)	42	39	124	'
Total periodic cost	42	39	124	117
Chesapeake Postretirement Plan [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Interest cost	12	15	36	45
Amortization of prior service cost	-19	-20	-58	-60
Amortization of net loss	18	18	55	53
Net periodic cost (benefit)	11	13	33	38
Total periodic cost	11	13	33	38
FPU Medical Plan [Member]	'	'	'	'
Defined Benefit Plan Disclosure [Line Items]	'	'	'	'
Service cost	0	40	0	120
Interest cost	16	45	47	135
Amortization of net loss	0	23	0	68
Net periodic cost (benefit)	16	108	47	323
Amortization of pre-merger regulatory asset	2	2	6	6
Total periodic cost	$18	$110	$53	$329

Employee_Benefit_Plans_Additio

Employee Benefit Plans - Additional Information (Detail) (USD $)

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

12 Months Ended

3 Months Ended

9 Months Ended

12 Months Ended

3 Months Ended

9 Months Ended

12 Months Ended

3 Months Ended

9 Months Ended

12 Months Ended

Sep. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2013

Sep. 30, 2013

Sep. 30, 2013

Dec. 31, 2013

Chesapeake Pension Plan [Member]

Chesapeake Pension Plan [Member]

Chesapeake Pension Plan [Member]

Chesapeake Pension Plan [Member]

FPU Pension Plan [Member]

FPU Pension Plan [Member]

FPU Pension Plan [Member]

Chesapeake Pension SERP [Member]

Chesapeake Pension SERP [Member]

Chesapeake Pension SERP [Member]

Chesapeake Postretirement Plan [Member]

Chesapeake Postretirement Plan [Member]

Chesapeake Postretirement Plan [Member]

FPU Medical Plan [Member]

FPU Medical Plan [Member]

FPU Medical Plan [Member]

Defined Benefit Plan Disclosure [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected pension and postretirement benefit costs

$999,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Expected amortization of pre merger regulatory asset

769,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Unamortized balance of regulatory asset

'

'

4,600,000

4,600,000

5,200,000

'

'

'

'

'

'

'

'

'

'

'

'

Contribution to pension plan

'

'

142,000

233,000

'

211,000

421,000

'

22,000

67,000

'

16,000

53,000

'

50,000

91,000

'

Additional contribution to pension plan

'

$364,000

'

'

'

'

'

$842,000

'

'

$88,000

'

'

$97,000

'

'

$258,000

Employee_Benefit_Plans_Amounts

Employee Benefit Plans - Amounts Included in Regulatory Asset and Accumulated Other Comprehensive Income/Loss Recognized as Net Periodic Benefit Cost (Detail) (USD $)	3 Months Ended			9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013		Sep. 30, 2012	Sep. 30, 2013		Sep. 30, 2012
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]	'		'	'		'
Prior service cost (credit)	($14)		'	($45)		'
Net loss	172		'	517		'
Recognized from accumulated other comprehensive loss	92	[1]	'	275	[1]	'
Recognized from regulatory asset	66		'	197		'
Total recognized in net periodic benefit cost	158		'	472		'
Chesapeake Pension Plan [Member]	'		'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]	'		'	'		'
Prior service cost (credit)	0		-1	-1		-4
Net loss	57		85	171		255
Recognized from accumulated other comprehensive loss	57	[1]	'	170	[1]	'
Total recognized in net periodic benefit cost	57		'	170		'
FPU Pension Plan [Member]	'		'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]	'		'	'		'
Net loss	81		43	243		131
Recognized from accumulated other comprehensive loss	15	[1]	'	46	[1]	'
Recognized from regulatory asset	66		'	197		'
Total recognized in net periodic benefit cost	81		'	243		'
Chesapeake Pension SERP [Member]	'		'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]	'		'	'		'
Prior service cost (credit)	5		5	14		15
Net loss	16		11	48		34
Recognized from accumulated other comprehensive loss	21	[1]	'	62	[1]	'
Total recognized in net periodic benefit cost	21		'	62		'
Chesapeake Postretirement Plan [Member]	'		'	'		'
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]	'		'	'		'
Prior service cost (credit)	-19		-20	-58		-60
Net loss	18		18	55		53
Recognized from accumulated other comprehensive loss	-1	[1]	'	-3	[1]	'
Total recognized in net periodic benefit cost	($1)		'	($3)		'
[1]	See Note 8, bAccumulated Other Comprehensive Income (Loss).

Investments_Schedule_of_Invest

Investments - Schedule of Investment (Detail) (USD $)	Sep. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Investment [Line Items]	'	'
Investments, at fair value	$2,788	$4,168
Investments in equity securities [Member]	'	'
Investment [Line Items]	'	'
Investments, at fair value	0	2,013
Rabbi trust (associated with certain director's compensation) [Member]	'	'
Investment [Line Items]	'	'
Investments, at fair value	97	39
Rabbi trust (associated with Supplemental Executive Retirement Savings Plan) [Member]	'	'
Investment [Line Items]	'	'
Investments, at fair value	$2,691	$2,116

Investments_Additional_Informa

Investments - Additional Information (Detail) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Investments, Debt and Equity Securities [Abstract]	'	'	'	'
Unrealized gain, net of other expenses	($259)	($102)	($217)	$502

ShareBased_Compensation_ShareB

Share-Based Compensation - Share-Based Compensation Amounts Included in Net Income (Detail) (USD $)	3 Months Ended		9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Total compensation expense	$385	$415	$1,246	$1,111
Less: tax benefit	-155	-166	-502	-446
Share-Based Compensation amounts included in net income	230	249	744	665
Directors Stock Compensation Plan [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Total compensation expense	124	111	354	332
Performance Incentive Plan [Member]	'	'	'	'
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'
Total compensation expense	$261	$304	$892	$779

ShareBased_Compensation_Additi

Share-Based Compensation - Additional Information (Detail) (USD $)	1 Months Ended			9 Months Ended	1 Months Ended	9 Months Ended
	31-May-13	Jan. 31, 2013	Sep. 30, 2013	Sep. 30, 2013	Jan. 31, 2013	Sep. 30, 2013
				Directors Stock Compensation Plan [Member]	Performance Incentive Plan [Member]	Performance Incentive Plan [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]	'	'	'	'	'	'
Amortization of expense equally over a service period	'	'	'	'1 year	'	'
Non-employee directors annual retainer, in shares	857	'	'	'	'	'
Unrecognized compensation expense related to the DSCP awards	'	'	$288,000	'	'	'
Granted awards, shares	'	'	'	9,427	23,491	23,491
Vesting period	'	'3 years	'	'	'	'
Intrinsic value of PIP awards	'	'	'	'	'	$4,200,000

ShareBased_Compensation_Summar

Share-Based Compensation - Summary of Stock Activity under PIP (Detail) (USD $)	1 Months Ended	9 Months Ended
	Jan. 31, 2013	Sep. 30, 2013
Directors Stock Compensation Plan [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, 2012	0	0
Number of Shares, Granted	'	9,427
Number of Shares, Vested	'	9,427
Number of Shares, Forfeited	'	0
Number of Shares, Outstanding - June 30, 2013	'	0
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, 2012	$0	$0
Weighted Average Fair Value, Granted	'	$52.49
Weighted Average Fair Value, Vested	'	$52.49
Weighted Average Fair Value, Forfeited	'	$0
Weighted Average Fair Value, Outstanding - June 30, 2013	'	$0
Performance Incentive Plan [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, 2012	84,645	84,645
Number of Shares, Granted	23,491	23,491
Number of Shares, Vested	'	24,332
Number of Shares, Expired	'	3,043
Number of Shares, Outstanding - June 30, 2013	'	80,761
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, 2012	$37.86	$37.86
Weighted Average Fair Value, Granted	'	$44.85
Weighted Average Fair Value, Vested	'	$33.26
Weighted Average Fair Value, Expired	'	$39.12
Weighted Average Fair Value, Outstanding - June 30, 2013	'	$42.30

Derivative_Instruments_Additio

Derivative Instruments - Additional Information (Detail) (USD $)

Sep. 30, 2013

Jun. 30, 2013

31-May-13

Dec. 31, 2012

Jun. 30, 2013

31-May-13

31-May-12

31-May-13

31-May-13

Jun. 30, 2013

Jun. 30, 2013

Jun. 30, 2013

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Jun. 30, 2013

Dec. 31, 2012

Counterparty

Counterparty

Call options [Member]

Call options [Member]

Call options [Member]

Call options [Member]

Call options [Member]

Put Option [Member]

Put Option [Member]

Put Option [Member]

Mark To Market Energy Assets [Member]

Mark To Market Energy Assets [Member]

Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member]

Designated as Hedging Instrument [Member]

gal

gal

gal

Minimum [Member]

Maximum [Member]

Minimum [Member]

Maximum [Member]

Call options [Member]

Call options [Member]

Mark To Market Energy Assets [Member]

Mark To Market Energy Assets [Member]

Mark To Market Energy Assets [Member]

Mark To Market Energy Assets [Member]

Mark To Market Energy Assets [Member]

Call options [Member]

Call options [Member]

Put Option [Member]

Put Option [Member]

Put Option [Member]

Derivative [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Purchase quantity for propane price cap

'

'

'

'

1,300,000

630,000

1,300,000

'

'

'

'

'

'

'

'

'

'

'

'

Strike price of put option

'

'

0.975

'

'

'

'

0.905

0.99

'

0.83

0.86

'

'

'

'

'

'

'

Payment to purchase put option

'

'

'

'

'

'

'

'

'

$120,000

'

'

'

'

'

'

'

'

'

Derivative asset, fair value, net

379,000

'

'

210,000

'

'

'

'

'

'

'

'

'

'

0

[1]

28,000

[1]

63,000

[2]

63,000

[2]

0

[2]

Payment to purchase call options

'

'

'

'

'

72,000

139,000,000

'

'

'

'

'

'

'

'

'

'

'

'

Fair value of call options

'

102,000

'

'

'

'

'

'

'

'

'

'

102,000

0

'

'

'

'

'

Ineffective portion of this fair value hedge

'

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Number of counterparties under master netting agreements

2

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Rights to offset accounts receivable

2,300,000

'

'

1,200,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Rights to offset accounts payable

$1,100,000

'

'

$511,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

We purchased call options for the propane price cap program in May 2012. The call options expired in March 2013.

[2]

As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with these put options 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 call option effectively changed the value of propane inventory.

Derivative_Instruments_Outstan

Derivative Instruments - Outstanding Trading Contracts (Detail) (Forward Contracts [Member])	Sep. 30, 2013
	gal
Sale [Member]	'
Derivative [Line Items]	'
Quantity in Gallons	1,682,000
Weighted Average Contract Prices (in usd per contract)	1.037
Purchase [Member]	'
Derivative [Line Items]	'
Quantity in Gallons	1,682,000
Weighted Average Contract Prices (in usd per contract)	0.9861
Minimum [Member] | Sale [Member]	'
Derivative [Line Items]	'
Estimated Market Prices (in usd per contract)	0.8225
Minimum [Member] | Purchase [Member]	'
Derivative [Line Items]	'
Estimated Market Prices (in usd per contract)	0.8275
Maximum [Member] | Sale [Member]	'
Derivative [Line Items]	'
Estimated Market Prices (in usd per contract)	0.9625
Maximum [Member] | Purchase [Member]	'
Derivative [Line Items]	'
Estimated Market Prices (in usd per contract)	1.3176

Derivative_Instruments_Fair_Va

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) (USD $)	Sep. 30, 2013		Jun. 30, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified
Derivatives, Fair Value [Line Items]	'		'		'
Derivatives asset not designated as hedging instruments, Call Option, Derivatives assets	'		$102		'
Derivatives designated as fair value hedges, Asset derivatives	379		'		210
Derivatives not designated as hedging instruments, Liability derivatives	124		'		331
Mark-to-market energy assets [Member] | Forward Contracts [Member]	'		'		'
Derivatives, Fair Value [Line Items]	'		'		'
Derivatives asset not designated as hedging instruments, Forward contracts, Asset Derivatives	214		'		182
Mark-to-market energy assets [Member] | Call options [Member]	'		'		'
Derivatives, Fair Value [Line Items]	'		'		'
Derivatives asset not designated as hedging instruments, Call Option, Derivatives assets	102		'		0
Mark-to-market energy assets [Member] | Call options [Member] | Derivatives designated as fair value hedges [Member]	'		'		'
Derivatives, Fair Value [Line Items]	'		'		'
Derivatives designated as fair value hedges, Asset derivatives	0	[1]	'		28	[1]
Mark-to-market energy assets [Member] | Put Option [Member] | Derivatives designated as fair value hedges [Member]	'		'		'
Derivatives, Fair Value [Line Items]	'		'		'
Derivatives designated as fair value hedges, Asset derivatives	63	[2]	63	[2]	0	[2]
Mark-to-market energy liabilities [Member] | Forward Contracts [Member]	'		'		'
Derivatives, Fair Value [Line Items]	'		'		'
Derivatives not designated as hedging instruments, Liability derivatives	$124		'		$331
[1]	We purchased call options for the propane price cap program in May 2012. The call options expired in March 2013.
[2]	As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with these put options 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 call option effectively changed the value of propane inventory.

Derivative_Instruments_Effects

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements (Detail) (USD $)

3 Months Ended

6 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

3 Months Ended

9 Months Ended

In Thousands, unless otherwise specified

Sep. 30, 2013

Sep. 30, 2012

Jun. 30, 2012

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Sep. 30, 2013

Sep. 30, 2012

Derivatives not designated as hedging instruments [Member]

Derivatives not designated as hedging instruments [Member]

Derivatives not designated as hedging instruments [Member]

Derivatives not designated as hedging instruments [Member]

Derivatives designated as fair value hedges [Member]

Derivatives designated as fair value hedges [Member]

Derivatives designated as fair value hedges [Member]

Derivatives designated as fair value hedges [Member]

Revenue [Member]

Revenue [Member]

Revenue [Member]

Revenue [Member]

Revenue [Member]

Revenue [Member]

Revenue [Member]

Revenue [Member]

Cost of Sales [Member]

Cost of Sales [Member]

Cost of Sales [Member]

Cost of Sales [Member]

Call Option [Member]

Call Option [Member]

Call Option [Member]

Call Option [Member]

Put/Call Option [Member]

Put/Call Option [Member]

Put/Call Option [Member]

Put/Call Option [Member]

Forward Contracts [Member]

Forward Contracts [Member]

Forward Contracts [Member]

Forward Contracts [Member]

Derivatives not designated as hedging instruments [Member]

Derivatives not designated as hedging instruments [Member]

Derivatives not designated as hedging instruments [Member]

Derivatives not designated as hedging instruments [Member]

Derivatives designated as fair value hedges [Member]

Derivatives designated as fair value hedges [Member]

Derivatives designated as fair value hedges [Member]

Derivatives designated as fair value hedges [Member]

Forward Contracts [Member]

Forward Contracts [Member]

Forward Contracts [Member]

Forward Contracts [Member]

Put/Call Option [Member]

Put/Call Option [Member]

Put/Call Option [Member]

Put/Call Option [Member]

Derivative Instruments, Gain (Loss) [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Gain (Loss) on derivatives

$81

$84

($137)

$183

$38

$0

$29

$0

($43)

($2)

($57)

($17)

$86

$86

$239

($147)

$86

$86

$239

($147)

$0

$0

($28)

$27

Derivative_Instruments_Effects1

Derivative Instruments - Effects of Trading Activities on Condensed Consolidated Statements of Income (Detail) (USD $)	3 Months Ended		6 Months Ended	9 Months Ended
In Thousands, unless otherwise specified	Sep. 30, 2013	Sep. 30, 2012	Jun. 30, 2012	Sep. 30, 2013	Sep. 30, 2012
Trading Activity, Gains and Losses, Net [Line Items]	'	'	'	'	'
Unrealized gain (loss) on forward contracts Revenue	$81	$84	($137)	$183	'
Total	407	997	'	745	2,086
Revenue [Member] | Forward Contracts [Member]	'	'	'	'	'
Trading Activity, Gains and Losses, Net [Line Items]	'	'	'	'	'
Unrealized gain (loss) on forward contracts Revenue	86	86	'	239	-147
Revenue [Member] | Forward Contracts [Member] | Options [Member]	'	'	'	'	'
Trading Activity, Gains and Losses, Net [Line Items]	'	'	'	'	'
Realized gain on forward contracts and options	$321	$911	'	$506	$2,233

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $)	Sep. 30, 2013	Jun. 30, 2013	Dec. 31, 2012
In Thousands, unless otherwise specified
Assets:	'	'	'
Investments	$2,788	'	$4,168
Mark-to-market energy assets	'	102	'
Investments in equity securities [Member]	'	'	'
Assets:	'	'	'
Investments	0	'	2,013
Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member] | Mark-to-market energy liabilities [Member]	'	'	'
Liabilities:	'	'	'
Mark-to-market energy liabilities	'	124	331
Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member] | Investments in equity securities [Member]	'	'	'
Assets:	'	'	'
Investments	'	'	2,007
Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member] | Investments in guaranteed income fund [Member]	'	'	'
Assets:	'	'	'
Investments	'	512	'
Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member] | Investments - other [Member]	'	'	'
Assets:	'	'	'
Investments	'	2,276	2,161
Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member] | Mark-to-market energy assets [Member]	'	'	'
Assets:	'	'	'
Mark-to-market energy assets	'	379	'
Recurring [Member] | Estimate of Fair Value, Fair Value Disclosure [Member] | Mark-to-market energy assets, including call options [Member]	'	'	'
Assets:	'	'	'
Mark-to-market energy assets	'	'	210
Recurring [Member] | Quoted Prices in Active Markets (Level 1) [Member] | Mark-to-market energy liabilities [Member]	'	'	'
Liabilities:	'	'	'
Mark-to-market energy liabilities	'	0	0
Recurring [Member] | Quoted Prices in Active Markets (Level 1) [Member] | Investments in equity securities [Member]	'	'	'
Assets:	'	'	'
Investments	'	'	2,007
Recurring [Member] | Quoted Prices in Active Markets (Level 1) [Member] | Investments in guaranteed income fund [Member]	'	'	'
Assets:	'	'	'
Investments	'	0	'
Recurring [Member] | Quoted Prices in Active Markets (Level 1) [Member] | Investments - other [Member]	'	'	'
Assets:	'	'	'
Investments	'	2,276	2,161
Recurring [Member] | Quoted Prices in Active Markets (Level 1) [Member] | Mark-to-market energy assets [Member]	'	'	'
Assets:	'	'	'
Mark-to-market energy assets	'	0	'
Recurring [Member] | Quoted Prices in Active Markets (Level 1) [Member] | Mark-to-market energy assets, including call options [Member]	'	'	'
Assets:	'	'	'
Mark-to-market energy assets	'	'	0
Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mark-to-market energy liabilities [Member]	'	'	'
Liabilities:	'	'	'
Mark-to-market energy liabilities	'	124	331
Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Investments in equity securities [Member]	'	'	'
Assets:	'	'	'
Investments	'	'	0
Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Investments in guaranteed income fund [Member]	'	'	'
Assets:	'	'	'
Investments	'	0	'
Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Investments - other [Member]	'	'	'
Assets:	'	'	'
Investments	'	0	0
Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mark-to-market energy assets [Member]	'	'	'
Assets:	'	'	'
Mark-to-market energy assets	'	379	'
Recurring [Member] | Significant Other Observable Inputs (Level 2) [Member] | Mark-to-market energy assets, including call options [Member]	'	'	'
Assets:	'	'	'
Mark-to-market energy assets	'	'	210
Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mark-to-market energy liabilities [Member]	'	'	'
Liabilities:	'	'	'
Mark-to-market energy liabilities	'	0	0
Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Investments in equity securities [Member]	'	'	'
Assets:	'	'	'
Investments	'	'	0
Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Investments in guaranteed income fund [Member]	'	'	'
Assets:	'	'	'
Investments	'	512	'
Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Investments - other [Member]	'	'	'
Assets:	'	'	'
Investments	'	0	0
Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mark-to-market energy assets [Member]	'	'	'
Assets:	'	'	'
Mark-to-market energy assets	'	0	'
Recurring [Member] | Significant Unobservable Inputs (Level 3) [Member] | Mark-to-market energy assets, including call options [Member]	'	'	'
Assets:	'	'	'
Mark-to-market energy assets	'	'	$0

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) (USD $)	6 Months Ended
In Thousands, unless otherwise specified	Jun. 30, 2013
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]	'
Beginning Balance	$0
Transfers in due to change in trustee	425
Purchases and adjustments	98
Transfers	-16
Investment Income	5
Ending Balance	$512

Fair_Value_of_Financial_Instru4

Fair Value of Financial Instruments - Additional Information (Detail) (USD $)	Sep. 30, 2013	Jun. 30, 2013	Dec. 31, 2012
Fair Value Disclosures [Abstract]	'	'	'
Long-term debt including current maturities	'	$108,500,000	'
Fair value of long-term debt	'	127,200,000	133,200,000
Total Long-term debt	$115,578,000	'	$110,103,000

LongTerm_Debt_Outstanding_Long

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

Sep. 30, 2013

Jun. 30, 2013

31-May-13

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Jun. 30, 2011

Sep. 30, 2013

2-May-13

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

Sep. 30, 2013

Dec. 31, 2012

In Thousands, unless otherwise specified

9.57% bond, due May 1, 2018 [Member]

9.57% bond, due May 1, 2018 [Member]

10.03% bond, due May 1, 2018 [Member]

10.03% bond, due May 1, 2018 [Member]

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

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

7.83% note, due January 1, 2015 [Member]

7.83% note, due January 1, 2015 [Member]

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

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

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

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

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

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

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

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

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

6.43% note, due May 2, 2028 [Member]

6.43% note, due May 2, 2028 [Member]

6.43% note, due May 2, 2028 [Member]

8.25% due March 1, 2014 [Member]

8.25% due March 1, 2014 [Member]

Promissory note [Member]

Promissory note [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total long-term debt

'

$108,500

'

'

$0

[1]

$5,444

[1]

$0

[1]

$2,994

[1]

$7,966

[1]

$7,962

[1]

$4,000

$4,000

$13,636

$13,636

$16,000

$16,000

$30,000

$30,000

$29,000

$29,000

$29,000

$7,000

$7,000

$0

$854

$942

$80

$125

Capital Lease Obligations

7,042

'

7,100

0

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total Long-term debt

115,578

'

'

110,103

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Less: current maturities

-8,234

'

'

-8,196

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Total long-term debt, net of current maturities

$107,344

$107,344

'

$101,907

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

[1]

FPU secured first mortgage bonds are guaranteed by Chesapeake.

LongTerm_Debt_Outstanding_Long1

Long-Term Debt - Outstanding Long-Term Debt (Parenthetical) (Detail)

9 Months Ended

9 Months Ended

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Sep. 30, 2013

Jun. 30, 2011

Sep. 30, 2013

Sep. 30, 2013

2-May-13

9.57% bond, due May 1, 2018 [Member]

10.03% bond, due May 1, 2018 [Member]

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

7.83% note, due January 1, 2015 [Member]

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

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

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

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

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

8.25% due March 1, 2014 [Member]

6.43% note, due May 2, 2028 [Member]

6.43% note, due May 2, 2028 [Member]

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

Long-term debt, interest percentage

'

9.57%

10.03%

9.08%

7.80%

6.64%

5.50%

5.93%

5.68%

5.68%

8.25%

6.43%

6.40%

Debt instrument, maturity date

2-May-28

1-May-18

1-May-18

1-Jun-22

1-Jan-15

31-Oct-17

12-Oct-20

31-Oct-23

30-Jun-26

'

1-Mar-14

'

'

LongTerm_Debt_Additional_Infor

Long-Term Debt - Additional Information (Detail) (USD $)

9 Months Ended

Sep. 30, 2013

Sep. 30, 2012

Jun. 30, 2013

31-May-13

Jun. 30, 2011

Jun. 30, 2010

Sep. 30, 2013

Dec. 31, 2012

Jun. 30, 2011

Sep. 05, 2013

Sep. 30, 2013

2-May-13

Dec. 31, 2012

31-May-13

31-May-13

Sep. 05, 2013

Sep. 05, 2013

series

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

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

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

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

Unsecured senior notes 6.43% [Member]

Unsecured senior notes 6.43% [Member]

Unsecured senior notes 6.43% [Member]

First mortgage bond one [Member]

First mortgage bond two [Member]

Aggregate Unsecured Senior Notes [Member]

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

Debt Instrument [Line Items]

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Long term debt maximum borrowing capacity

'

'

'

'

'

$36,000,000

'

'

'

$50,000,000

'

'

'

'

'

$70,000,000

$20,000,000

Total long-term debt

'

'

108,500,000

'

'

'

29,000,000

29,000,000

29,000,000

'

7,000,000

7,000,000

0

'

'

'

'

Long-term debt, interest percentage

'

'

'

'

'

'

5.68%

'

5.68%

3.88%

6.43%

6.40%

'

9.57%

10.03%

'

3.73%

Number of series

'

'

'

'

2

'

'

'

'

'

'

'

'

'

'

'

'

Amount paid in excess of carrying value deferred as regulatory asset

'

'

'

93,000

'

'

'

'

'

'

'

'

'

'

'

'

'

Repayments of Long-term Debt

8,609,000

1,459,000

'

'

'

'

'

'

'

'

'

'

'

'

'

'

'

Scheduled Repayment of Long Term Debt

'

'

'

'

'

'

'

'

'

$5,000,000

'

'

'

'

'

'

$2,000,000

ShortTerm_Debt_Additional_deta

Short-Term Debt Additional details (Details) (USD $)	Jun. 30, 2013	Jun. 28, 2013	Jun. 27, 2013	Jun. 28, 2013	Jun. 30, 2013	Sep. 30, 2013	Sep. 30, 2013
In Millions, unless otherwise specified				Bank of America [Member]	PNC Bank [Member]	LIBOR [Member]	Base Rate [Member]
						Bank of America [Member]	Bank of America [Member]
Line of Credit Facility [Line Items]	'	'	'	'	'	'	'
Line of credit facility, maximum borrowing capacity	'	'	'	$75	$90	'	'
Debt instrument, description of variable rate basis	'	'	'	'	'	1.25%	1250.00%
Committed lines of credit	70	55	'	'	'	'	'
Line of credit facility, current borrowing capacity	'	'	50	'	'	'	'
Uncommitted lines of credit	$20	$20	$30	'	'	'	'