Chesapeake Utilities (CPK) 10-K5 Mar 152014 FY Annual reportFinancial data

Company Profile

Document_and_Entity_Informatio

Document and Entity Information (USD $)	12 Months Ended
In Millions, except Share data, unless otherwise specified	Dec. 31, 2014	Feb. 28, 2015	Jun. 30, 2014
Document Document And Entity Information [Abstract]
Entity Central Index Key	19745
Current Fiscal Year End Date	-19
Entity Filer Category	Accelerated Filer
Document Type	10-K
Document Period End Date	31-Dec-14
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	FY
Trading Symbol	CPK
Amendment Flag	FALSE
Entity Common Stock, Shares Outstanding	CHESAPEAKE UTILITIES CORP
Entity Well-known Seasoned Issuer	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Public Float			$660.20
Entity Common Stock, Shares Outstanding		14,594,949

Consolidated_Statements_of_Inc

Consolidated Statements of Income (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Revenues
Regulated Energy	$300,442	$264,637	$246,208
Unregulated Energy	184,961	166,723	133,049
Other	13,431	12,946	13,245
Total operating revenues	498,834	444,306	392,502
Operating Expenses
Regulated energy cost of sales	134,560	118,818	111,402
Unregulated energy and other cost of sales	143,556	126,017	101,957
Operations	102,197	91,452	82,387
Maintenance	9,706	7,509	7,423
Asset Impairment Charges	6,881	0	0
Depreciation and amortization	26,316	23,965	22,510
Other taxes	13,339	13,811	10,188
Total operating expenses	436,555	381,572	335,867
Operating Income	62,279	62,734	56,635
Gain (Loss) on Disposition of Business	7,139
Other income, net of other expenses	101	372	271
Interest charges	9,482	8,234	8,747
Income Before Income Taxes	60,037	54,872	48,159
Income taxes	23,945	22,085	19,296
Net Income	$36,092	$32,787	$28,863
Weighted Average Common Shares Outstanding:
Basic (in shares)	14,551,308	14,430,962	14,379,216
Diluted (in shares)	14,604,944	14,543,446	14,507,261
Earnings Per Share of Common Stock:
Basic (in usd per share)	$2.48	$2.27	$2.01
Diluted (in usd per share)	$2.47	$2.26	$1.99
Cash Dividends Declared Per Share of Common Stock (in usd per share)	$1.07	$1.01	$0.96

Consolidated_Statements_of_Com

Consolidated Statements of Comprehensive Income (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Net Income	$36,092	$32,787	$28,863
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(24), $(24) and $(26), respectively	-34	-36	-37
Net gain (loss), net of tax of $(1,997), $1,673 and $(331), respectively	-3,076	2,565	-498
Commodity Contract Cash Flow Hedges [Abstract]
Unrealized loss on commodity contract cash flow hedges, net of tax of $(22), $0 and $0, respectively	-33	0	0
Total Other Comprehensive Income (Loss)	-3,143	2,529	-535
Comprehensive Income	$32,949	$35,316	$28,328

Consolidated_Statements_of_Com1

Consolidated Statements of Comprehensive Income (Parenthetical) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Comprehensive Income [Abstract]
Tax expense recognized on the amortization of prior service cost	($24)	($24)	($26)
Tax expense recognized on the net gain (loss)	-1,997	1,673	-331
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	($33)	$0	$0

Consolidated_Statements_of_Cas

Consolidated Statements of Cash Flows (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Activities
Net Income	$36,092	$32,787	$28,863
Adjustments to reconcile net income to net operating cash:
Asset Impairment Charges	6,881	0	0
Depreciation and amortization	26,316	23,965	22,510
Depreciation and accretion included in other costs	6,577	6,123	5,547
Deferred income taxes, net	22,235	14,860	13,881
Gain (Loss) on Disposition of Assets	7,293	854	-5
Unrealized Gain (Loss) on Commodity Contracts	-501	706	112
Employee benefits and compensation	684	1,119	1,199
Share-based compensation	1,958	1,631	1,419
Other, net	3	-28	-27
Changes in assets and liabilities:
Accounts receivable and accrued revenue	20,683	-21,244	21,549
Propane inventory, storage gas and other inventory	4,177	-4,492	603
Increase (Decrease) in Regulatory Assets and Liabilities	11,014	-2,328	4,968
Prepaid expenses and other current assets	-699	-1,064	-713
Accounts payable and other accrued liabilities	-8,047	18,824	-19,936
Income taxes receivable	-15,936	2,311	2,223
Customer deposits and refunds	-927	-3,362	-1,647
Accrued compensation	37	837	437
Other liabilities	-2,944	-104	-4,192
Net cash provided by operating activities	79,284	72,931	66,641
Investing Activities
Property, plant and equipment expenditures	-97,164	-97,120	-72,776
Increase (Decrease) in Intangible Assets, Current	14	0	0
Proceeds from sale of assets	10,797	199	2,279
Proceeds from sale of investments	0	2,300	630
Acquisitions	0	-20,201	-124
Environmental expenditures	-233	41	-607
Net cash used by investing activities	-86,586	-114,781	-70,598
Financing Activities
Common stock dividends	-13,887	-13,081	-12,335
Purchase of stock for Dividend Reinvestment Plan	-165	-1,342	-1,273
Change in cash overdrafts due to outstanding checks	-921	-1,666	597
Net borrowing (repayment) under line of credit agreements	-16,513	46,133	25,894
Proceeds from issuance of long-term debt	49,975	26,766	0
Repayment of long-term debt and capital lease obligation	-9,969	-14,957	-8,202
Other	0	-8	0
Net cash provided by financing activities	8,520	41,845	4,681
Net Increase (Decrease) in Cash and Cash Equivalents	1,218	-5	724
Cash and Cash Equivalents â€” Beginning of Period	3,356	3,361	2,637
Cash and Cash Equivalents â€” End of Period	$4,574	$3,356	$3,361

Consolidated_Balance_Sheets

Consolidated Balance Sheets (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment
Regulated energy	$766,855	$691,522
Unregulated energy	84,773	76,267
Other	18,497	21,002
Total property, plant and equipment	870,125	788,791
Less: Accumulated depreciation and amortization	-193,369	-174,148
Plus: Construction work in progress	13,006	16,603
Net property, plant and equipment	689,762	631,246
Current Assets
Cash and cash equivalents	4,574	3,356
Accounts receivable (less allowance for uncollectible accounts of $1,120 and $1,635, respectively)	53,300	75,293
Accrued revenue	13,617	13,910
Propane inventory, at average cost	7,250	10,456
Other inventory, at average cost	3,699	4,880
Regulatory assets	8,967	2,436
Storage gas prepayments	4,258	4,318
Income taxes receivable	18,806	2,609
Deferred income taxes	0	1,696
Prepaid expenses	6,652	6,910
Mark-to-market energy assets	1,055	385
Other current assets	195	160
Total current assets	122,373	126,409
Deferred Charges and Other Assets
Goodwill	4,952	4,354
Other intangible assets, net	2,404	2,975
Investments, at fair value	3,678	3,098
Regulatory assets	78,136	66,584
Receivables and other deferred charges	3,164	2,856
Total deferred charges and other assets	92,334	79,867
Total Assets	904,469	837,522
Stockholdersâ€™ equity
Common stock, par value $0.4867 per share (authorized 25,000,000)	7,100	4,691
Additional paid-in capital	156,581	152,341
Retained earnings	142,317	124,274
Accumulated other comprehensive loss	-5,676	-2,533
Deferred compensation obligation	1,258	1,124
Treasury stock	-1,258	-1,124
Total stockholdersâ€™ equity	300,322	278,773
Long-term debt, net of current maturities	158,486	117,592
Total capitalization	458,808	396,365
Current Liabilities
Current portion of long-term debt	9,109	11,353
Short-term borrowing	88,231	105,666
Accounts payable	44,610	53,482
Customer deposits and refunds	25,197	26,140
Accrued interest	1,352	1,235
Dividends payable	3,939	3,710
Deferred Tax Liabilities, Net, Current	832	0
Accrued compensation	10,076	8,394
Regulatory liabilities	3,268	4,157
Mark-to-market energy liabilities	1,018	127
Other accrued liabilities	6,603	7,678
Total current liabilities	194,235	221,942
Deferred Credits and Other Liabilities
Deferred income taxes	160,232	142,597
Regulatory liabilities	43,419	43,912
Environmental liabilities	8,923	9,155
Other pension and benefit costs	35,027	21,000
Deferred investment tax credits and Other liabilities	3,825	2,551
Total deferred credits and other liabilities	251,426	219,215
Total Capitalization and Liabilities	$904,469	$837,522

Consolidated_Balance_Sheets_Pa

Consolidated Balance Sheets (Parenthetical) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Allowance for uncollectible accounts	$1,120	$1,635
Common stock, par value	$0.49	$0.49
Common stock, shares authorized	25,000,000	25,000,000

Consolidated_Statements_of_Sto

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]
Beginning Balances at Dec. 31, 2011	$240,780,000	$4,656,000	$149,403,000	$91,248,000	($4,527,000)	$817,000	($817,000)
Beginning Balances, shares at Dec. 31, 2011		14,350,959
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	28,863,000			28,863,000
Other comprehensive loss	-535,000				-535,000
Stock Issued During Period, Value, Dividend Reinvestment Plan				-13,872,000
Dividends ShareBased Compensation Dividends And Dividends For Reinvestment Plan	-13,879,000	0	-7,000			0
Conversion of Debentures	186,000	5,000	181,000
Conversion of debentures, shares		16,463
Share-based compensation	1,183,000	10,000	1,173,000
Share-based compensation, shares		28,826
Treasury stock activities	0	0				165,000	-165,000
Ending Balances at Dec. 31, 2012	256,598,000	4,671,000	150,750,000	106,239,000	-5,062,000	982,000	-982,000
Ending Balances, shares at Dec. 31, 2012		14,396,248
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	32,787,000			32,787,000
Other comprehensive loss	2,529,000				2,529,000
Stock Issued During Period, Value, Dividend Reinvestment Plan				-14,752,000
Dividends ShareBased Compensation Dividends And Dividends For Reinvestment Plan	-14,758,000		-6,000
Conversion of Debentures	295,000	8,000	287,000
Conversion of debentures, shares		26,075
Share-based compensation	1,322,000	12,000	1,310,000
Share-based compensation, shares		35,022
Treasury stock activities	0					142,000	-142,000
Ending Balances at Dec. 31, 2013	278,773,000	4,691,000	152,341,000	124,274,000	-2,533,000	1,124,000	-1,124,000
Ending Balances, shares at Dec. 31, 2013		14,457,345
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income	36,092,000			36,092,000
Other comprehensive loss	-3,143,000				-3,143,000
Stock Issued During Period, Value, Dividend Reinvestment Plan				-15,675,000
Dividends ShareBased Compensation Dividends And Dividends For Reinvestment Plan	-15,675,000
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan		43,367
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan	1,860,000	16,000	1,844,000
Conversion of Debentures	535,000	15,000	520,000
Conversion of debentures, shares		47,313
Share-based compensation	1,889,000	13,000	1,876,000
Share-based compensation, shares		40,686
Stock Split in Form of Stock Dividend Adjustment to Retained Earnings	-9,000	2,365,000		-2,374,000
Treasury stock activities	0					134,000	-134,000
Ending Balances at Dec. 31, 2014	$300,322,000	$7,100,000	$156,581,000	$142,317,000	($5,676,000)	$1,258,000	($1,258,000)
Ending Balances, shares at Dec. 31, 2014		14,588,711

Consolidated_Statements_of_Sto1

Consolidated Statements of Stockholders' Equity Consolidated Statements of Stockholders' Equity (Parenthetical) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Statement of Stockholders' Equity [Abstract]
Shares Held In Trust For Deferred Compensation Plan	53,125	51,743	50,192
Dividends Declared	$1.07	$1.01	$0.96
Shares Issued Under Performance Incentive Plan Withheld For Employee Taxes	12,687	15,616.50	8,505

Organization_and_Basis_of_Pres

Organization and Basis of Presentation	12 Months Ended
Organization and Basis of Presentation	Dec. 31, 2014
Text Block [Abstract]
Organization and Basis of Presentation	ORGANIZATION AND BASIS OF PRESENTATION
	Chesapeake, incorporated in 1947 in Delaware, is a diversified energy company engaged in regulated energy and unregulated energy businesses. Our regulated energy businesses consist of: (a) regulated natural gas distribution operations in central and southern Delaware, Maryland’s eastern shore and Florida; (b) regulated natural gas transmission operations on the Delmarva Peninsula, in Pennsylvania and in Florida; and (c) regulated electric distribution operations serving customers in northeast and northwest Florida. Our unregulated energy businesses primarily include: (a) propane distribution operations in Delaware, the eastern shore of Maryland and Virginia, southeastern Pennsylvania and Florida; (b) our propane wholesale marketing operation, which markets propane to major independent oil and petrochemical companies, wholesale resellers and retail propane companies located primarily in the southeastern United States; and (c) our natural gas marketing operation providing natural gas supplies directly to commercial and industrial customers in Florida, Delaware and Maryland. On October 1, 2014, we completed the sale of BravePoint, our advanced information services subsidiary. BravePoint provided information-technology-related business services and solutions for both enterprise and e-business applications.
	Our consolidated financial statements as of December 31, 2014 and 2013 and for the years ended December 31, 2014, 2013 and 2012 have been prepared in compliance with the rules and regulations of the SEC and GAAP. Our consolidated financial statements include the accounts of Chesapeake and its wholly-owned subsidiaries. We do not have any ownership interests in investments accounted for using the equity method or any variable interests in a variable interest entity. All intercompany accounts and transactions have been eliminated in consolidation. We have assessed and reported on subsequent events through the date of issuance of these consolidated financial statements.
	On July 2, 2014, our Board of Directors approved a three-for-two stock split of our outstanding common stock to be effected in the form of a stock dividend. Each stockholder as of the close of business on the record date, August 13, 2014, received one additional share of common stock for every two shares of common stock owned. The additional shares were distributed on September 8, 2014. All share and per share data in this Form 10-K are presented on a post-split basis. As a result of the stock split, we reclassified approximately $2.4 million from retained earnings to common stock, which represents $0.4867 par value per share of the shares issued in the stock split.
	We reclassified certain amounts in the consolidated balance sheet as of December 31, 2013 and consolidated statements of cash flows for the years ended December 31, 2013 and 2012 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our consolidated financial statements.

Summary_of_Significant_Account

Summary of Significant Accounting Policies	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Summary of Significant Accounting Policies	SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make estimates in measuring assets and liabilities and related revenues and expenses. These estimates involve judgments with respect to, among other things, various future economic factors that are difficult to predict and are beyond our control; therefore, actual results could differ from these estimates.

	Property, Plant and Equipment
	Property, plant and equipment are stated at original cost less accumulated depreciation or fair value, if impaired. Costs include direct labor, materials and third-party construction contractor costs, AFUDC, and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged against income as incurred, and the costs of major renewals and betterments are capitalized. Upon retirement or disposition of property owned by the unregulated businesses, the gain or loss, net of salvage value, is charged to income. Upon retirement or disposition of property within the regulated businesses, the gain or loss, net of salvage value, is charged to accumulated depreciation. A summary of property, plant and equipment by classification as of December 31, 2014 and 2013 is provided in the following table:


		As of December 31,
	(in thousands)	2014				2013
	Property, plant and equipment
	Regulated Energy
	Natural gas distribution – Delmarva	$	193,071			$	179,724

	Natural gas distribution – Florida	234,344				199,289

	Natural gas transmission – Delmarva	243,560				226,244

	Natural gas transmission – Florida	18,240				15,919

	Electric distribution – Florida	77,640				70,346

	Unregulated Energy
	Propane distribution—Delmarva	60,877				54,865

	Propane distribution – Florida	23,142				20,829

	Other unregulated energy	754				573

	Other	18,497				21,002

	Total property, plant and equipment	870,125				788,791

	Less: Accumulated depreciation and amortization	(193,369		)		(174,148		)
	Plus: Construction work in progress	13,006				16,603

	Net property, plant and equipment	$	689,762			$	631,246

	Contributions or Advances in Aid of Construction
	Customer contributions or advances in aid of construction reduce property, plant and equipment unless the amounts are refundable to customers. Contributions or advances may be refundable to customers after a number of years based on the amount of revenues generated from the customers or the duration of the service provided to the customers. Refundable contributions or advances are recorded initially as liabilities. The amounts that are determined to be non-refundable reduce property, plant and equipment at the time of such determination. During the years ended December 31, 2014 and 2013, there were $813,000 and $785,000, respectively, of non-refunded contributions or advances reducing property, plant and equipment.
	Allowed Funds Used During Construction
	Some of the additions to our regulated property, plant and equipment include AFUDC, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects. AFUDC is capitalized in rate base for rate making purposes when the completed projects are placed in service. During the years ended December 31, 2014, 2013, and 2012, we recorded $58,000, $131,000, and $111,000, respectively, of AFUDC, all of which were related to short-term debt and reflected as a reduction of interest charges.
	Asset Used in Leases
	Property, plant and equipment for the Florida natural gas transmission operation includes $1.4 million of assets, consisting primarily of mains, measuring equipment and regulation station equipment used by Peninsula Pipeline to provide natural gas transmission service pursuant to a contract with a third party. This contract is accounted for as an operating lease due to the exclusive use of the assets by the customer. The service under this contract commenced in January 2009 and generates $264,000 in annual revenue for a term of 20 years. Accumulated depreciation for these assets totaled $435,000 and $363,000 at December 31, 2014 and 2013, respectively.
	Capital Lease Asset
	Property, plant and equipment for our Delmarva natural gas distribution operation includes a capital lease asset of $6.1 million and $7.0 million, net of amortization, at December 31, 2014 and 2013, respectively, related to Sandpiper's capacity, supply and operating agreement. See Note 20, Other Commitments and Contingencies for additional information. At December 31, 2014 and 2013, accumulated amortization for the capital lease asset was $996,000 and $147,000, respectively. For the years ended December 31, 2014 and 2013, we recorded $848,000 and $147,000, respectively in amortization of the capital lease asset which was included in our fuel cost recovery mechanisms.
	Jointly-owned pipeline
	Property, plant and equipment for the Florida natural gas transmission operation also includes $6.7 million of assets, which consists of the 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida, jointly owned by Peninsula Pipeline and Peoples Gas. The amount included in property, plant and equipment represents Peninsula Pipeline’s 45-percent ownership of this pipeline. This 16-mile pipeline was placed in service in December 2012. Accumulated depreciation for this pipeline totaled $584,000 and $361,000, at December 31, 2014 and 2013, respectively.
	Impairment of long-lived assets
	We periodically evaluate whether events or circumstances have occurred which indicate that other long-lived assets may not be fully recoverable. When such events or circumstances are present, we record an impairment loss equal to the excess of the assets' carrying value over its fair value if any.
	At December 31, 2014, we recorded a $6.5 million pre-tax, non-cash impairment loss related to uncertainty around the implementation of a customer billing system. We recorded $6.4 million of this impairment loss in the Regulated Energy segment, with the remaining $19,000 included in the Unregulated Energy segment. This impairment represents all of the capitalized costs associated with this project. Prior to December 31, 2014, these costs were included in construction work in progress. We are engaged in negotiations with the system vendor regarding the implementation, and are considering several options to recover these costs, including regulatory proceedings. The outcome cannot be predicted at this time. We will record a gain contingency if and when any recovery from the vendor is realizable or establish a regulatory asset if future recovery through rates is probable, respectively.

	Depreciation and Accretion Included in Operations Expenses
	We compute depreciation expense for our regulated operations by applying composite, annual rates, as approved by the regulators. The following table shows the average depreciation rates used during the years ended December 31, 2014, 2013 and 2012:


		2014		2013		2012
	Natural gas distribution – Delmarva	2.50%		2.50%		2.50%
	Natural gas distribution – Florida	2.90%		3.40%		3.30%
	Natural gas transmission – Delmarva	2.70%		2.70%		2.70%
	Natural gas transmission – Florida	4.00%		4.80%		4.40%
	Electric distribution – Florida	3.80%		3.60%		3.80%
	During 2014, the Florida PSC approved new depreciation rates for our Florida natural gas distribution operations (see Note 18, Rates and Other Regulatory Activities, for additional information), which lowered their depreciation rates effective January 1, 2014.
	For our unregulated operations, we compute depreciation expense on a straight line basis over the following estimated useful lives of the assets:


Asset Description	Useful Life
Propane distribution mains	10-37 years
Propane bulk plants and tanks	10-40 years
Propane equipment	5-33 years
Meters and meter installations	5-33 years
Measuring and regulating station equipment	5-37 years
Office furniture and equipment	3-10 years
Transportation equipment	4-20 years
Structures and improvements	5-45 years
Other	Various

We report certain depreciation and accretion in operations expense, rather than depreciation and amortization expense, in the accompanying consolidated statements of income in accordance with industry practice and regulatory requirements. Depreciation and accretion included in operations expense consists of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, 2014, 2013 and 2012, we reported $6.6 million, $6.1 million and $5.5 million, respectively, of depreciation and accretion in operations expenses.

Regulated Operations
We account for our regulated operations in accordance with ASC Topic 980, Regulated Operations, which includes accounting principles for companies whose rates are determined by independent third-party regulators. When setting rates, regulators often make decisions, the economics of which require companies to defer costs or revenues in different periods than may be appropriate for unregulated enterprises. When this situation occurs, a regulated company defers the associated costs as regulatory assets on the balance sheet and records them as expense on the income statement as it collects revenues. Further, regulators can also impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future as regulatory liabilities. If we were required to terminate the application of these regulatory provisions to our regulated operations, all such deferred amounts would be recognized in the statement of income at that time, which could have a material impact on our financial position, results of operations and cash flows.
At December 31, 2014 and 2013, the regulated utility operations had recorded the following regulatory assets and liabilities included in our consolidated balance sheets. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.


	As of December 31,
	2014				2013
(in thousands)
Regulatory Assets
Under-recovered purchased fuel and conservation cost recovery (1)	$	6,865			$	1,651

Under-recovered GRIP revenue (1)	1,491				—

Deferred post retirement benefits (2)	19,762				8,578

Deferred transaction and transition costs (3)	—				471

Deferred conversion and development costs (1)	3,745				1,320

Environmental regulatory assets and expenditures (4)	4,452				5,170

Acquisition adjustment (5)	45,607				47,478

Loss on reacquired debt (6)	1,372				1,486

Other	3,809				2,866

Total Regulatory Assets	$	87,103			$	69,020

Regulatory Liabilities
Self insurance (7)	$	1,003			$	1,000

Over-recovered purchased fuel and conservation cost recovery (1)	2,936				2,869

Over-recovered GRIP revenue (1)	—				518

Storm reserve (7)	2,982				2,875

Accrued asset removal cost (8)	39,583				39,510

Deferred gains (9)	—				783

Other	183				514

Total Regulatory Liabilities	$	46,687			$	48,069


(1)	We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets.

(2)	The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. See Note 16, Employee Benefit Plans, for additional information.

(3)	The Florida PSC approved the inclusion of the FPU merger-related costs in our rate base and the recovery of those costs in rates through October 2014. The balance at December 31, 2013 includes the gross-up of this regulatory asset for income tax because a portion of the merger-related costs is not tax-deductible.

(4)	All of our environmental expenditures incurred to date and current estimate of future environmental expenditures have been approved by various PSCs for recovery. See Note 19, Environmental Commitments and Contingencies, for additional information on our environmental contingencies.

(5)	We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. Included in these amounts are $1.3 million of the premium paid by FPU, $34.2 million of the premium paid by Chesapeake in 2009, including the gross up of the amount for income tax, because it is not tax deductible, and $746,000 of the premium paid by FPU in 2010.

(6)	Gains and losses resulting from the reacquisition of long-term debt are amortized over future periods as adjustments to interest expense in accordance with established regulatory practice.

(7)	We have self-insurance and storm reserves that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.

(8)	In accordance with regulatory treatment, our depreciation rates are comprised of two components – historical cost and the estimated cost of removal, net of estimated salvage, of certain regulated properties. We collect these costs in base rates through depreciation expense with a corresponding credit to accumulated depreciation. Because the accumulated estimated removal costs meet the requirements of authoritative guidance related to regulated operations, we have accounted for them as a regulatory liability and have reclassified them from accumulated depreciation to accumulated removal costs in our consolidated balance sheets.

(9)	Pursuant to the Florida PSC order, we were required to defer and amortize, until 2014, certain gains identified during the FPU merger integration.
We monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these assets is no longer probable, we would write off the assets against earnings. We believe that provisions of ASC Topic 980, Regulated Operations, continue to apply to our regulated operations and that the recovery of our regulatory assets is probable.
Operating Revenues
Revenues for our natural gas and electric distribution operations are based on rates approved by the PSC in each state in which they operate. Eastern Shore’s revenues are based on rates approved by the FERC. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have authorized our regulated operations to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to negotiated rates.
For regulated deliveries of natural gas and electricity, we read meters and bill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. We estimate the amount of the unbilled revenue by jurisdiction and customer class. A similar computation is made to accrue unbilled revenues for propane customers with meters and natural gas marketing customers, whose billing cycles do not coincide with our accounting periods.
The propane wholesale marketing operation records trading activity for open contracts on a net mark-to-market basis in our consolidated statements of income. For propane bulk delivery customers without meters we record revenue in the period the products are delivered and/or services are rendered.

All of our natural gas and electric distribution operations, except for two utilities that do not sell natural gas to end-use customers as a result of deregulation, have fuel cost recovery mechanisms. These mechanisms provide a method of adjusting the billing rates to reflect changes in the cost of purchased fuel. The difference between the current cost of fuel purchased and the cost of fuel recovered in billed rates is deferred and accounted for as either unrecovered fuel cost or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year. Chesapeake’s Florida natural gas distribution division and FPU's Indiantown division provide unbundled delivery service to their customers, whereby the customers are permitted to purchase their gas requirements directly from competitive natural gas marketers.
We charge flexible rates to our natural gas distribution industrial interruptible customers to compete with prices of alternative fuels, which these customers are able to use. Neither we nor our interruptible customers are contractually obligated to deliver or receive natural gas on a firm service basis.
We report revenue taxes, such as gross receipts taxes, franchise taxes, and sales taxes, on a net basis.
Cost of Sales
Cost of sales includes the direct costs attributable to the products sold or services provided to our customers. These costs include primarily the variable cost of natural gas, electricity and propane commodities, pipeline capacity costs needed to transport and store natural gas, transmission costs for electricity, transportation costs to transport propane purchases to our storage facilities and, for the period prior to the sale of BravePoint, the direct cost of labor for our advanced information services subsidiary. Depreciation expense is not included in our cost of sales.
Operations and Maintenance Expenses
Operations and maintenance expenses include operations and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, customer service, professional fees and other outside services, insurance expense, minor amounts of depreciation, accretion of cost of removal for future retirements of utility assets, and other administrative expenses.
Cash and Cash Equivalents
Our policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates fair value. Investments with an original maturity of three months or less when purchased are considered cash equivalents.
Accounts Receivable and Allowance for Doubtful Accounts
Accounts receivable consist primarily of amounts due for distribution sales of natural gas, electricity and propane and transportation services to customers. An allowance for doubtful accounts is recorded against amounts due to reduce the receivables balance to the amount we reasonably expect to collect based upon our collections experiences and our assessment of customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such estimates include, but are not limited to, customer credit issues, the level of natural gas, electricity and propane prices and general economic conditions. Accounts are written off when they are deemed to be uncollectible.
Inventories
We use the average cost method to value propane, materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to market values. At December 31, 2014, we reduced our propane inventory value by $681,000 to reflect the lower-of-cost-or-market adjustment.
Goodwill and Other Intangible Assets
Goodwill is not amortized but is tested for impairment at least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives. Please refer to Note 10, Goodwill and Other Intangible Assets, for additional discussion of this subject.
The annual goodwill impairment test as of December 31, 2014 resulted in a $237,000 goodwill impairment loss associated with the Austin Cox acquisition. We also recorded a $175,000 impairment loss on an intangible asset related to a non-compete agreement associated with the same acquisition.
Other Deferred Charges
Other deferred charges include discount, premium and issuance costs associated with long-term debt. Debt issuance costs are deferred and then are amortized to interest expense over the original lives of the respective debt issuances.

Pension and Other Postretirement Plans
Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates, including the fair value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. We review annually the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities with the assistance of third-party actuarial firms. The assumed discount rates, expected returns on plan assets and the mortality assumption are the factors that generally have the most significant impact on our pension costs and liabilities. The assumed discount rates, health care cost trend rates and rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.
The discount rates are utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net pension and postretirement costs. When estimating our discount rates, we consider high quality corporate bond rates, such as Moody’s Aa bond index and the Citigroup yield curve, changes in those rates from the prior year and other pertinent factors, including the expected life of each of our plans and their respective payment options.
The expected long-term rates of return on assets are utilized in calculating the expected returns on the plan assets component of our annual pension plan costs. We estimate the expected returns on plan assets of each of our plans by evaluating expected bond returns, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rates of return on assets.
We estimate the health care cost trend rates used in determining our postretirement net expense based upon actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual reviews of participant census information as of the measurement date.
The mortality assumption used for our pension and postretirement plans is based on the actuarial table that is most reflective of the expected mortality of the plan participants and reviewed periodically.
Actual changes in the fair value of plan assets and the differences between the actual and expected return on plan assets could have a material effect on the amount of pension and postretirement benefit costs that we ultimately recognize. A 0.25 percent decrease in the discount rate could increase our annual pension and postretirement costs by approximately $18,000, and a 0.25 percent increase could decrease our annual pension and postretirement costs by approximately $22,000. A 0.25 percent change in the rate of return could change our annual pension cost by approximately $134,000 and would not have an impact on the postretirement and supplemental executive retirement plans because these plans are not funded.
Income Taxes, Investment Tax Credit Adjustments and Tax-related contingency
Deferred tax assets and liabilities are recorded for the income tax effect of temporary differences between the financial statement basis and tax basis of assets and liabilities and are measured using the enacted income tax rates in effect in the years in which the differences are expected to reverse. Deferred tax assets are recorded net of any valuation allowance when it is more likely than not that such income tax benefits will be realized. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.
We account for uncertainty in income taxes in the financial statements only if it is more likely than not that an uncertain tax position is sustainable based on technical merits. Recognizable tax positions are then measured to determine the amount of benefit recognized in the financial statements. We recognize penalties and interest related to unrecognized tax benefits as a component of other income.
We account for contingencies associated with taxes other than income when the likelihood of a loss is both probable and estimable. In assessing the likelihood of a loss, we do not consider the existence of current inquiries, or the likelihood of future inquiries, by tax authorities as a factor. Our assessment is based solely on our application of the appropriate statutes and the likelihood of a loss assuming the proper inquiries are made by tax authorities.
Financial Instruments
Xeron engages in trading activities using forward and futures contracts, which have been accounted for using the mark-to-market method of accounting. Under mark-to-market accounting, our trading contracts are recorded at fair value as mark-to-market energy assets and liabilities. The changes in fair value of the contracts are recognized as gains or losses in revenues on the consolidated statements of income in the period of change.

Our natural gas, electric and propane distribution operations and natural gas marketing operations enter 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 enter into derivative transactions, such as swaps, put options and call options in order to mitigate the impact of wholesale price fluctuations on its inventory valuation and future purchase commitments. These transactions may be designated as fair value hedges or cash flow hedges, if they meet all of the accounting requirements pursuant to ASC Topic 815, Derivatives and Hedging and we elect to designate the instruments as hedges. If designated as a fair value hedge, the value of the hedging instrument, such as a swap or put option, is recorded at fair value with the effective portion of the gain or loss of the hedging instrument effectively reducing or increasing the value of propane inventory. If designated as a cash flow hedge, the value of the hedging instrument, such as a swap or call option, is recorded at fair value with the effective portion of the gain or loss of the hedging instrument being recorded in comprehensive income. The ineffective portion of the gain or loss of a hedge is recorded in earnings. If the instrument is not designated as a fair value or cash flow hedge or does not meet the accounting requirements of a hedge, it is recorded at fair value with the gain or loss being recorded in earnings.

FASB Statements and Other Authoritative Pronouncements
Recent Accounting Standards Yet to be Adopted
Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. ASU 2014-09 is effective for reporting periods (interim and annual) beginning after December 15, 2016. We are currently assessing the impact this standard will have on our financial position and results of operations.
Recently Adopted Accounting Standards
Presentation of Financial Statements (ASC 205) and Property Plant and Equipment (ASC 360) - In April 2014, the FASB issued ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The new standard limits discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have or will have a major effect on an entity's operations and financial results, and requires additional disclosures related to discontinued operations. Upon adoption of the new standard, fewer disposals are expected to be presented as discontinued operations. We early adopted the provisions of this standard in the third quarter of 2014 and applied them to the sale of BravePoint (see Note 4, Acquisitions and Disposition, for additional details on the sale). As a result, BravePoint is not presented as a discontinued operation in the accompanying consolidated statements of income.
Income Taxes (ASC 740) - In July 2013, the FASB issued 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. ASU 2013-11 became effective for us on January 1, 2014. The adoption of ASU 2013-11 had no material impact on our financial position and results of operations.

Earnings_Per_Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Earnings Per Share	3. EARNINGS PER SHARE
	Basic earnings per share are computed by dividing income available for common stockholders by the weighted average number of shares of common stock outstanding during the period. Diluted earnings per share are computed by dividing income available for common stockholders by the weighted average number of shares of common stock outstanding during the period adjusted for the exercise and/or conversion of all potentially dilutive securities, such as convertible debt and share-based compensation. The calculations of both basic and diluted earnings per share are presented in the following table.


		For the Year Ended December 31,
		2014		2013		2012
	(in thousands, except shares and per share data)
	Calculation of Basic Earnings Per Share:
	Net Income	$	36,092	$	32,787	$	28,863

	Weighted average shares outstanding	14,551,308		14,430,962		14,379,216

	Basic Earnings Per Share	$	2.48	$	2.27	$	2.01

	Calculation of Diluted Earnings Per Share:
	Reconciliation of Numerator:
	Net Income	$	36,092	$	32,787	$	28,863

	Effect of 8.25% Convertible debentures	—		43		53

	Adjusted numerator — Diluted	$	36,092	$	32,830	$	28,916

	Reconciliation of Denominator:
	Weighted shares outstanding — Basic	14,551,308		14,430,962		14,379,216

	Effect of dilutive securities:
	Share-based Compensation	53,636		37,866		35,249

	8.25% Convertible debentures (1)	—		74,618		92,796

	Adjusted denominator — Diluted	14,604,944		14,543,446		14,507,261

	Diluted Earnings Per Share	$	2.47	$	2.26	$	1.99

	(1) As of March 1, 2014, we no longer have any outstanding convertible debentures. See Note 12, Long-term debt for additional information.

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

Acquisitions

Acquisitions	12 Months Ended
Acquisitions	Dec. 31, 2014
Text Block [Abstract]
Acquisitions	ACQUISITIONS AND DISPOSITION
	Eastern Shore Gas Company
	On May 31, 2013, the Maryland PSC approved the acquisition of ESG. Upon receiving this approval, we completed the purchase of the operating assets of ESG, which was not related to, or affiliated with, our interstate natural gas transmission subsidiary, 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, and our propane distribution subsidiary, Sharp, respectively. Sandpiper's operations, which cover all of Worcester County, Maryland, are 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 and have begun to convert some of the acquired customers. Although most of these customers are currently being served with propane, we classify Sandpiper's operations as natural gas distribution in the Regulated Energy segment.
	In connection with this acquisition, we recorded $12.6 million in property, plant and equipment, $384,000 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 and the second quarter of 2014. 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, and the allocation of the purchase price and valuation of assets are final.
	The revenue and net income from this acquisition for the year ended December 31, 2014, included in our consolidated statement of income, was $24.3 million and $2.5 million, respectively. The revenue and net income from this acquisition for the year ended December 31, 2013, included in our consolidated statement of income, was $9.8 million and $309,000, respectively.
	Other Acquisitions
	On December 2, 2013, we acquired certain operating assets of the City of Fort Meade, Florida, for approximately $792,000. The purchased assets are used to provide natural gas distribution service in the City of Fort Meade, Florida. In connection with this acquisition we recorded $92,000 in property, plant and equipment, $14,000 in inventory, $14,000 in regulatory asset, $714,000 in goodwill and $42,000 in other current liabilities. These amounts reflect adjustments to the purchase price and the allocation of the purchase price during the fourth quarter of 2014 based on our final valuation, which decreased the value of property, plant and equipment by $578,000 and increased goodwill by $564,000. All of the goodwill is expected to be deductible for income tax purposes. The revenue and net income from this acquisition that were included in our consolidated statements of income for the years ended December 31, 2014 and 2013 were not material.
	On June 7, 2013, we acquired certain operating assets through 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, $30,000 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 $237,000 in goodwill. The revenue and net income from this acquisition included in our consolidated statements of income for the years ended December 31, 2014 and 2013 were not material. As discussed in Note 2, Summary of Significant Accounting Policies, at December 31, 2014, we recorded an impairment charge of $412,000 related to the goodwill and non-compete intangible asset. The impairment charge represented all of the remaining goodwill and intangible asset from this acquisition.
	On February 5, 2013, we purchased the propane operating assets of 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, $231,000 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 $724,000 in goodwill. These amounts reflect an adjustment to the allocation of the purchase price during the first quarter of 2014 based on our final valuation, which decreased the value of propane inventory by $271,000 and increased goodwill by the same amount. All of the goodwill is expected to be deductible for income tax purposes. The revenue and net income from this acquisition, included in our consolidated statements of income for the years ended December 31, 2014 and 2013, were not material.
	Gatherco Acquisition - Subsequent Event
	On January 30, 2015, we entered into a merger agreement to acquire Gatherco. Upon consummation of the transaction, Gatherco will merge into Aspire Energy, a newly formed, wholly-owned subsidiary of Chesapeake. At closing, we expect to issue 593,005 shares of our common stock, valued at $29.9 million, pay $27.6 million in cash and assume Gatherco’s debt, estimated to be $1.7 million. We expect to pay off this debt shortly after closing. Gatherco is a natural gas infrastructure company providing natural gas midstream services. Gatherco’s assets include 16 gathering systems and over 2,000 miles of pipelines in Central and Eastern Ohio. Gatherco provides natural gas gathering services and natural gas liquid processing services to over 300 producers, and supplies natural gas to over 6,000 customers in Ohio through the Consumers Gas Cooperative, an independent entity which Gatherco manages under an operating agreement. The transaction is subject to approval by Gatherco's shareholders and is expected to close in the second quarter of 2015.


	Disposition of BravePoint
	On October 1, 2014, we completed the sale of BravePoint, our advanced information services subsidiary for approximately $12.0 million in cash. We plan to reinvest the proceeds from this sale in our regulated and unregulated energy businesses. We recorded a pre-tax gain of $6.7 million (approximately $4.0 million after-tax) from this sale, which includes the effect of certain costs and expenses associated with the sale. Our consolidated statements of income for the years ended December 31, 2014, 2013 and 2012 included $15.1 million, $19.1 million and $17.5 million of revenue, respectively, and $232,000 of net loss, $155,000 of net loss and $454,000 of net income, respectively, from BravePoint's operations.

Segment_Information

Segment Information	12 Months Ended
	Dec. 31, 2014
Text Block [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 comprise three operating segments:

	•	Regulated Energy. The Regulated Energy segment includes natural gas distribution, natural gas transmission operations and electric distribution operations. All operations in this segment are regulated, as to their rates and services, by the PSCs having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.

	•	Unregulated Energy. The Unregulated Energy segment includes propane distribution and wholesale marketing operations, and natural gas marketing operations, which are unregulated as to their rates and services. Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services.

	•	Other. Prior to September 30, 2014 our “Other” segment consisted primarily of our advanced information services subsidiary. Also included in this segment are our unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations. On October 1, 2014, we sold BravePoint (see Note 4, Acquisitions and Disposition, for further details).

	The following table presents information about our reportable segments.


		For the Year Ended December 31,
		2014			2013			2012
	(in thousands)
	Operating Revenues, Unaffiliated Customers
	Regulated Energy	$	299,345		$	263,573		$	245,042

	Unregulated Energy	184,557			161,760			130,020

	Other	14,932			18,973			17,440

	Total operating revenues, unaffiliated customers	$	498,834		$	444,306		$	392,502

	Intersegment Revenues (1)
	Regulated Energy	$	1,097		$	1,064		$	1,166

	Unregulated Energy	404			4,963			3,029

	Other	979			1,017			917

	Total intersegment revenues	$	2,480		$	7,044		$	5,112

	Operating Income
	Regulated Energy	$	50,451		$	50,084		$	46,999

	Unregulated Energy	11,723			12,353			8,355

	Other	105			297			1,281

	Operating Income	62,279			62,734			56,635

	Gain from sale of businesses	7,139			—			—

	Other income	101			372			271

	Interest charges	9,482			8,234			8,747

	Income Before Income taxes	60,037			54,872			48,159

	Income taxes	23,945			22,085			19,296

	Net Income	$	36,092		$	32,787		$	28,863

	Depreciation and Amortization
	Regulated Energy	$	21,915		$	19,822		$	18,653

	Unregulated Energy	3,994			3,686			3,420

	Other and eliminations	407			457			437

	Total depreciation and amortization	$	26,316		$	23,965		$	22,510

	Capital Expenditures
Regulated Energy	$	84,959		$	95,944		$	69,056

Unregulated Energy	9,648			4,829			3,969

Other	3,450			7,266			5,185

Total capital expenditures	$	98,057		$	108,039		$	78,210



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


	As of December 31,
	2014			2013
Identifiable Assets
Regulated Energy	$	796,021		$	708,950

Unregulated Energy	84,732			100,585

Other	23,716			27,987

Total identifiable assets	$	904,469		$	837,522

Our operations are now entirely domestic. Previously, BravePoint had infrequent transactions in foreign countries, which were denominated and paid primarily in U.S. dollars. These transactions were immaterial to our consolidated revenues.

Supplemental_Cash_Flow_Disclos

Supplemental Cash Flow Disclosures	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Supplemental Cash Flow Disclosures	SUPPLEMENTAL CASH FLOW DISCLOSURES
	Cash paid for interest and income taxes during the years ended December 31, 2014, 2013 and 2012 were as follows:


		For the Year Ended December 31,
		2014		2013		2012
	(in thousands)
	Cash paid for interest	$	8,870	$	7,837	$	8,086

	Cash paid for income taxes	$	17,833	$	10,243	$	3,809

	Non-cash investing and financing activities during the years ended December 31, 2014, 2013, and 2012 were as follows:


		For the Year Ended December 31,
		2014		2013		2012
	(in thousands)
	Capital property and equipment acquired on account, but not paid as of December 31	$	459	$	341	$	7,065

	Retirement Savings Plan	$	602	$	—	$	—

	Conversion of Debentures	$	535	$	295	$	186

	Performance Incentive Plan	$	958	$	355	$	427

	Director Stock Compensation Plan	$	575	$	495	$	443

	Capital Lease Obligation	$	6,130	$	7,126	$	—

Derivative_Instruments

Derivative Instruments	12 Months Ended
	Dec. 31, 2014
Text Block [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 typically either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory or cash flow hedges of its future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of December 31, 2014, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

	Hedging Activities in 2014
	In August and October 2014, Sharp entered into call options to protect against an increase in propane prices associated with 1.3 million gallons we expect to purchase at market-based prices to supply the demands of our propane price cap program customers. The retail price that we can charge to those customers during the upcoming heating season is capped at a pre-determined level. The call options are exercised if the propane prices rise above the strike price of $1.0875 per gallon in December 2014 through February of 2015 and $1.0650 per gallon in January through March 2015. We will receive the difference between the market price and the strike price during those months. We paid $98,000 to purchase the call options, and we accounted for them as cash flow hedges. As of December 31, 2014, the call options had a fair value of $26,000. The change in fair value of the call options was recorded as unrealized loss in other comprehensive income.
	In May 2014, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 630,000 gallons expected to be purchased for the upcoming heating season. Under these swap agreements, Sharp receives the difference between the index prices (Mont Belvieu prices in December 2014 through February 2015) and the swap prices of $1.1350, $1.0975 and $1.0475 per gallon for each swap agreement, to the extent the index prices exceed the swap prices. If the index prices are lower than the swap prices, Sharp will pay the difference. These swap agreements essentially fix the price of those 630,000 gallons purchased for the upcoming heating season. We had initially accounted for them as cash flow hedges as the swap agreements met all the requirements. At December 31, 2014, we elected to discontinue hedge accounting on the swap agreements and reclassified $735,000 of unrealized loss from other comprehensive loss to propane cost of sales. We are now accounting for them as derivative instruments on a mark-to-market basis with the change in the fair value reflected in current period earnings. As of December 31, 2014, we have a mark-to-market liability of $735,000 related to the swap agreements.
	In May 2014, Sharp also entered into put options to protect against declines in propane prices and related potential inventory losses associated with 630,000 gallons purchased for the propane price cap program in the upcoming heating season. The put options are exercised if propane prices fall below the strike prices of $1.0350, $0.9975 and $0.9475 per gallon, for each option agreement in December 2014 through February 2015, respectively. We will receive the difference between the market price and the strike prices during those months. We paid $128,000 to purchase the put options. We accounted for them as fair value hedges, and there is no ineffective portion of these hedges. As of December 31, 2014, the put options had a fair value of $622,000. The change in fair value of the put options effectively reduced our propane inventory balance.
	Hedging Activities in 2013
	In June 2013, Sharp 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. If exercised, we would have received the difference between the market price and the strike price if propane prices had fallen 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 accounted for those options as fair value hedges, and there was no ineffective portion of those hedges. We paid $120,000 to purchase the put options, which expired without exercise as the market prices exceeded the strike prices.

	In May 2013, Sharp entered into a call option to protect against an increase in propane prices associated with 630,000 gallons we expected to purchase at market-based prices to supply the demands of our propane price cap program customers. The program capped the retail price at a pre-determined level that we could charge to those customers during the upcoming heating season. The call option was exercised because propane prices rose above the strike price of $0.975 per gallon in January through March of 2014. We accounted for this call option as a derivative instrument on a mark-to-market basis with any change in its fair value being reflected in current period earnings. We paid $72,000 to purchase the call option. In January through March of 2014, we received $209,000, representing the difference between the market price and the strike price during those months.
	Hedging Activities in 2012
	In May 2012, Sharp entered into call options to protect against an increase in propane prices associated with 1.3 million gallons purchased for the propane price cap program for the months of December 2012 through March 2013. The strike prices of these call options ranged from $0.905 per gallon to $0.990 per gallon during this four-month period. We paid $139,000 to purchase the call options, which expired without exercising the options as the market prices were below the strike prices. We accounted for the call options as a fair value hedge. At December 31, 2012, the call options had a fair value of $28,000. There was no ineffective portion of this fair value hedge in 2012.

	Commodity Contracts for Trading Activities
	Xeron engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under the mark-to-market method of accounting, 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 consolidated statements of income in the period of change. As of December 31, 2014 and December 31, 2013, we had the following outstanding trading contracts, which we accounted for as derivatives:



		Quantity in			Estimated Market	Weighted Average
	At December 31, 2014	Gallons			Prices	Contract Prices
	Forward Contracts
	Sale	4,200,000			$0.5400 - $0.7900	$	0.6714

	Purchase	4,201,000			$0.4700 - $1.3176	$	0.6416


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



	At December 31, 2013	Quantity in			Estimated Market	Weighted Average Contract Prices
		Gallons			Prices
	Forward Contracts
	Sale	1,892,000			$0.9900 - $1.4750	$	1.2786

	Purchase	1,991,000			$0.9411 - $1.4600	$	1.2444

	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 consolidated balance sheets. At December 31, 2014, Xeron had a right to offset $1.6 million and $1.2 million of accounts receivable and accounts payable, respectively, with these two counterparties. At December 31, 2013, Xeron had a right to offset $2.8 million and $3.2 million of accounts receivable and accounts payable, respectively, with these two counterparties.
	The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency.
	Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2014 and 2013, are as follows:


		Asset Derivatives
				Fair Value As Of
	(in thousands)	Balance Sheet Location		December 31, 2014			December 31, 2013
	Derivatives not designated as hedging instruments
	Forward contracts	Mark-to-market energy assets		$	407		$	196

	Call option	Mark-to-market energy assets		—			169

	Derivatives designated as fair value hedges
	Put options	Mark-to-market energy assets		622			20

	Derivatives designated as cash flow hedges
	Call options	Mark-to-market energy assets		26			—

	Total asset derivatives			$	1,055		$	385





	Liability Derivatives
			Fair Value As Of
(in thousands)	Balance Sheet Location		December 31, 2014			December 31, 2013
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities		$	283		$	127

Propane swap agreements	Mark-to-market energy liabilities		735			—

Total liability derivatives			$	1,018		$	127



The effects of gains and losses from derivative instruments are as follows:



	Amount of Gain (Loss) on Derivatives:
	Location of Gain		For the Year Ended December 31,
(in thousands)	(Loss) on Derivatives		2014			2013			2012
Derivatives not designated as hedging instruments:
Realized gain on forward contracts and options (1)	Revenue		$	1,423		$	1,127		$	2,695

Unrealized gain (loss) on forward contracts (1)	Revenue		57			217			(339		)

Call Options	Cost of Sales		—			97			—

Propane swap agreements	Cost of Sales		(735		)	—			—

Derivatives designated as fair value hedges:
Put/Call Option	Cost of Sales		235			(28		)	27

Put/Call Option (2)	Propane Inventory		517			(100		)	(40		)

Derivatives designated as cash flow hedges
Propane swap agreements	Cost of Sales		(341		)	—			—

Call Options	Cost of Sales		(17		)	—			—

Call Options	Other Comprehensive Income (Loss)		(55		)	—			—

Total			$	1,084		$	1,313		$	2,343


-1	All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our consolidated statements of income.

-2	As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero and the unrealized gains and losses of this call option effectively changed the value of propane inventory.

Fair_Value_of_Financial_Instru

Fair Value of Financial Instruments	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Fair Value of Financial Instruments	FAIR VALUE OF FINANCIAL INSTRUMENTS
	GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are the following:
	Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;
	Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and
	Level 3: Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity).

	Financial Assets and Liabilities Measured at Fair Value
	The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2014:



					Fair Value Measurements Using:
	(in thousands)	Fair Value			Quoted Prices in			Significant Other		Significant
					Active Markets			Observable		Unobservable
					(Level 1)			Inputs		Inputs
								(Level 2)		(Level 3)
	Assets:
	Investments—guaranteed income fund	$	287		$	—		$	—	$	287

	Investments—other	$	3,391		$	3,391		$	—	$	—

	Mark-to-market energy assets, incl. put/call options	$	1,055		$	—		$	1,055	$	—

	Liabilities:
	Mark-to-market energy liabilities, incl. swap agreements	$	1,018		$	—		$	1,018	$	—



	The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2013:



					Fair Value Measurements Using:
	(in thousands)	Fair Value			Quoted Prices in Active Markets (Level 1)			Significant Other		Significant
								Observable		Unobservable
								Inputs		Inputs
								(Level 2)		(Level 3)
	Assets:
	Investments—guaranteed income fund	$	458		$	—		$	—	$	458

	Investments—other	$	2,640		$	2,640		$	—	$	—

	Mark-to-market energy assets, including put option	$	385		$	—		$	385	$	—

	Liabilities:
	Mark-to-market energy liabilities	$	127		$	—		$	127	$	—


	The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2014 and 2013:


		For the Year Ended December 31,
		2014			2013
	(in thousands)
	Beginning Balance	$	458		$	—

	Transfers in due to change in trustee	—			425

	Purchases and adjustments	76			41

	Transfers	(253		)	(16		)
	Investment income	6			8

	Ending Balance	$	287		$	458


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

The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of December 31, 2014 and 2013:
Level 1 Fair Value Measurements:
Investments- other — The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares.
Level 2 Fair Value Measurements:
Mark-to-market energy assets and liabilities — These forward contracts are valued using market transactions in either the listed or OTC markets.
Propane put/call options and swap agreements – The fair value of the propane put/call options and swap agreements are valued 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 December 31, 2014, 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 December 31, 2014, long-term debt, which includes the current maturities but excludes a capital lease obligation, had a carrying value of $161.5 million, compared to a fair value of $180.7 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, adjusted for duration, optionality and risk profile. At December 31, 2013, long-term debt, which includes the current maturities of long-term debt, had a carrying value of $122.0 million, compared to the estimated fair value of $136.8 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.
Note 16, Employee Benefit Plans, provides the fair value measurement information for our pension plan assets.

Investments

Investments	12 Months Ended
Investments	Dec. 31, 2014
Text Block [Abstract]
Investments	INVESTMENTS

	The investment balances at December 31, 2014 and 2013, consist of the Rabbi Trust(s) associated with deferred compensation plan(s). We classify these investments as trading securities and report them at their fair value. For the years ended December 31, 2014, 2013 and 2012, we recorded net unrealized gains of $237,000, $489,000, and $451,000, respectively, in other income in the consolidated statements of income related to these investments. We have also recorded an associated liability, which is included in other pension and benefit costs in the consolidated balance sheets and is adjusted each month for the gains and losses incurred by the Rabbi Trusts. During 2013, we sold our investments in equity securities and recorded $702,000 of realized gain, $438,000 of which was previously recorded as unrealized gain ($135,000 in 2012 and $304,000 prior to 2012).

Goodwill_and_Other_Intangible_

Goodwill and Other Intangible Assets	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Goodwill and Other Intangible Assets	GOODWILL AND OTHER INTANGIBLE ASSETS
	The carrying value of goodwill as of December 31, 2014 and 2013 was as follows:


		As of December 31,
	(in thousands)	2014		2013
	Regulated Energy segment	$	3,354	$	2,790

	Unregulated Energy segment	1,598		1,564

	Total	$	4,952	$	4,354

	As of December 31, 2014, goodwill in the Regulated Energy segment is comprised of approximately $2.5 million from the FPU merger in October 2009, $170,000 from the purchase of operating assets from IGC in August 2010 and $714,000 from the purchase of Fort Meade in December 2013. During 2013, approximately $576,000 of the $746,000 goodwill that was originally recorded as a result of the IGC acquisition was reclassified to regulatory asset pursuant to the regulatory order which allowed recovery of the amount in rates. As of December 31, 2014, goodwill in the Unregulated Energy segment is comprised of $724,000 from the purchase of the operating assets of Glades in February 2013, $200,000 from the purchase of the operating assets from Crescent in December 2011 and $674,000 related to the premium paid by Sharp from its acquisitions in the late 1980s and 1990s. As discussed in Note 2, Summary of Significant Accounting Policies, at December 31, 2014, we recorded an impairment loss of $237,000 associated with the goodwill resulting from the Austin Cox acquisition in 2013. The impairment loss represents all of the goodwill recorded from the Austin Cox acquisition. The annual impairment testing for 2013 indicated no impairment of goodwill.
	The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2014 and 2013 are as follows:


		As of December 31,
		2014				2013
	(in thousands)	Gross		Accumulated		Gross		Accumulated
		Carrying		Amortization		Carrying		Amortization
		Amount				Amount
	Customer lists	$	3,993	$	1,719	$	3,993	$	1,389

	Non-Compete agreements	103		72		353		87

	Other	270		171		270		165

	Total	$	4,366	$	1,962	$	4,616	$	1,641

	The customer lists acquired in the purchases of the operating assets of Glades in February 2013, Virginia LP in February 2010 and the FPU merger in October 2009 are being amortized over seven to 12 years. The non-compete agreements acquired in the purchase of the operating assets of Virginia LP in February 2010 are being amortized over a seven-year period. The other intangible assets consist of acquisition costs from our propane distribution acquisitions in the late 1980s and 1990s and are being amortized over 40 years. As discussed in Note 2, Summary of Significant Accounting Policies, at December 31, 2014, we recorded an impairment loss of $175,000 for an intangible asset associated with the non-compete agreements acquired in the Austin Cox acquisition in 2013. The impairment loss represents all of the remaining intangible asset from the Austin Cox acquisition.
	For the years ended December 31, 2014, 2013 and 2012, amortization expense of intangible assets was $396,000, $373,000 and $329,000, respectively. Amortization expense of intangible assets is expected to be: $350,000 for 2015, $325,000 for 2016, $323,000 for 2017, $323,000 for 2018, and $323,000 for 2019.

Income_Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Income Taxes	INCOME TAXES
	We file a consolidated federal income tax return. Income tax expense allocated to our subsidiaries is based upon their respective taxable incomes and tax credits. State income tax returns are filed on a separate company basis in most states where we have operations and/or are required to file. Our returns for tax years after 2011 are subject to examination.
	The IRS performed its examination of Chesapeake's consolidated federal income tax return for 2009 and FPU's consolidated federal income tax return for 2008 and the period from January 1, 2009 to October 28, 2009 (the pre-merger period in 2009, during which FPU was required to file a separate federal income tax return). Both of the IRS examinations were completed in 2012 without any material findings.
	The State of Florida performed its examination of Chesapeake’s state income tax returns for 2008, 2009 and 2010 and completed its examination in 2012 without any material findings.
	The State of Texas performed its examination of Chesapeake’s amended state tax return for 2007. We amended the 2007 Texas state tax return due to a change in the methodology used to calculate the gross receipts used to determine the Texas apportionment. This new methodology was used in Chesapeake’s Texas tax returns for all years after 2006. In 2012, we recorded a total liability of $300,000 associated with the unrecognized tax benefit related to this change in methodology given the unknown outcome of this examination. In 2014, we reduced this liability to $100,000 based on the result of the examination by the State of Texas. We recorded this liability associated with the unrecognized tax benefit as an income tax payable, which reduced the income tax receivable in the accompanying balance sheets at December 31, 2014 and 2013.
	We did not have net operating losses for federal income tax purposes as of December 31, 2014 and 2013. We had state net operating losses of $29.1 million in various states as of December 31, 2014, almost all of which will expire in 2030. We have recorded a deferred tax asset of $1.2 million and $1.4 million related to net operating loss carry-forwards at December 31, 2014 and 2013, respectively. We have not recorded a valuation allowance to reduce the future benefit of the tax net operating losses because we believe they will be fully utilized.

	The following tables provide: (a) the components of income tax expense in 2014, 2013, and 2012; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2014, 2013, and 2012; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2014 and 2013.


		For the Year Ended December 31,
		2014				2013			2012
	(in thousands)
	Current Income Tax Expense
	Federal	$	434			$	4,882		$	3,483

	State	1,311				2,382			1,990

	Investment tax credit adjustments, net	(35		)		(39		)	(58		)
	Total current income tax expense	1,710				7,225			5,415

	Deferred Income Tax Expense (1)
	Property, plant and equipment	20,382				16,758			13,688

	Deferred gas costs	1,614				(209		)	515

	Pensions and other employee benefits	537				(335		)	553

	FPU merger related premium cost and deferred gain	(802		)		(686		)	(509		)
	Net operating loss carryforwards	(112		)		62			740

	Other	616				(730		)	(1,106		)

	Total deferred income tax expense	22,235				14,860			13,881

	Total Income Tax Expense	$	23,945			$	22,085		$	19,296


	(1)	Includes $2.6 million, $2.1 million, and $1.9 million of deferred state income taxes for the years 2014, 2013 and 2012, respectively.



		For the Year Ended December 31,
		2014				2013			2012
	(in thousands)
	Reconciliation of Effective Income Tax Rates
	Continuing Operations
	Federal income tax expense (1)	$	21,121			$	19,205		$	16,745

	State income taxes, net of federal benefit	2,946				3,105			2,571

	ESOP dividend deduction	(267		)		(256		)	(235		)
	Other	145				31			215

	Total Income Tax Expense	$	23,945			$	22,085		$	19,296

	Effective Income Tax Rate	39.88		%		40.25		%	40.07		%

	(1)	Federal income taxes were recorded at 35% for each year represented.




		As of December 31,
	2014				2013
(in thousands)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment	$	152,877			$	134,414

Acquisition adjustment	16,140				16,790

Loss on reacquired debt	529				573

Deferred gas costs	2,222				607

Other	4,507				2,850

Total deferred income tax liabilities	176,275				155,234

Deferred income tax assets:
Pension and other employee benefits	6,532				5,390

Environmental costs	2,313				2,083

Net operating loss carryforwards	1,186				1,444

Self insurance	275				403

Storm reserve liability	1,150				1,109

Other	3,755				3,904

Total deferred income tax assets	15,211				14,333

Deferred Income Taxes Per Consolidated Balance Sheets	$	161,064			$	140,901

LongTerm_Debt

Long-Term Debt	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Long-Term Debt	LONG-TERM DEBT
	Our outstanding long-term debt is shown below:


		As of December 31,
		2014			2013
	(in thousands)
	FPU secured first mortgage bonds:
	9.08% bond, due June 1, 2022	7,969			7,967

	Uncollateralized senior notes:
	7.83% note, due January 1, 2015	—			2,000

	6.64% note, due October 31, 2017	8,182			10,909

	5.50% note, due October 12, 2020	12,000			14,000

	5.93% note, due October 31, 2023	27,000			30,000

	5.68% note, due June 30, 2026	29,000			29,000

	6.43% note, due May 2, 2028	7,000			7,000

	3.73% note, due December 16, 2028	20,000			20,000

	3.88% note, due May 15, 2029	50,000			—

	Convertible debentures:
	8.25% due March 1, 2014	—			646

	Promissory notes	314			445

	Capital lease obligation	6,130			6,978

	Total long-term debt	167,595			128,945

	Less: current maturities	(9,109		)	(11,353		)
	Total long-term debt, net of current maturities	$	158,486		$	117,592

	Annual maturities and principal repayments of consolidated long-term debt, excluding the capital lease obligation, are as follows: $9,109 for 2015; $9,151 for 2016; $12,099 for 2017; $9,421 for 2018; $11,245 for 2019 and $116,600 thereafter. See Note 14, Lease obligations for future payments related to the capital lease obligation.
	Secured First Mortgage Bonds
	FPU’s secured first mortgage bonds are guaranteed by Chesapeake and are secured by a lien covering all of FPU’s property. FPU’s first mortgage bonds contain a restriction that limits the payment of dividends by FPU. It provides that FPU cannot make dividends or other restricted payments in excess of the sum of $2.5 million plus FPU’s consolidated net income accrued on and after January 1, 1992. As of December 31, 2014, FPU’s cumulative net income base was $104.1 million, offset by restricted payments of $37.6 million, leaving $66.5 million of cumulative net income for FPU free of restrictions pursuant to this covenant.
	The dividend restrictions by FPU’s first mortgage bonds resulted in approximately $49.4 million of the net assets of our consolidated subsidiaries being restricted at December 31, 2014. This represents approximately 16 percent of our consolidated net assets. Other than the dividend restrictions by FPU’s first mortgage bonds, there are no legal, contractual or regulatory restrictions on the net assets of our subsidiaries for the purposes of determining the disclosure of parent-only financial statements.
	Uncollateralized Senior Notes
	In September 2013, we entered into the Note Agreement to issue $70.0 million in aggregate of Notes to the Note Holders. In December 2013, we issued Series A Notes, with an aggregate principal amount of $20.0 million, at a rate of 3.73 percent. On May 15, 2014, we issued Series B Notes, with an aggregate principal amount of $50.0 million, at a rate of 3.88 percent. The proceeds received from the issuances of the Notes were used to reduce our short-term borrowings under our lines of credit and to fund capital expenditures.
	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.
	All of our uncollateralized Senior Notes require periodic principal and interest payments as specified in each note. They also contain various restrictions. The most stringent restrictions state that we must maintain equity of at least 40 percent of total capitalization, and the fixed charge coverage ratio must be at least 1.2 times. The most recent Senior Notes issued in December 2013 also contain a restriction that we must maintain an aggregate net book value in our regulated business assets of at least 50 percent of our consolidated total assets. Failure to comply with those covenants could result in accelerated due dates and/or termination of the uncollateralized senior note agreements. As of December 31, 2014, we are in compliance with all of our debt covenants.
	Most of Chesapeake’s uncollateralized Senior Notes contain a “Restricted Payments” covenant as defined in the Note agreements. The most restrictive covenants of this type are included within the 5.68 percent and 6.43 percent Senior Notes, due June 30, 2026 and May 2, 2028, respectively. The covenant provides that we cannot pay or declare any dividends or make any other Restricted Payments in excess of the sum of $10.0 million, plus our consolidated net income accrued on and after January 1, 2003. As of December 31, 2014, the cumulative consolidated net income base was $243.8 million, offset by Restricted Payments of $80.9 million, leaving $162.9 million of cumulative net income free of restrictions.
	Convertible Debentures
	During January and February of 2014, $537,000 of Convertible Debentures were converted to stock at a conversion price of $17.01 per share and $109,000 were redeemed for cash, leaving no outstanding Convertible Debentures as of March 1, 2014. During 2013, Convertible Debentures totaling $296,000 were converted to stock. No Convertible Debentures were redeemed for cash in 2013.

ShortTerm_Borrowing

Short-Term Borrowing	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Short-Term Borrowing	SHORT-TERM BORROWINGS
	At December 31, 2014 and 2013, we had $88.2 million and $105.7 million, respectively, of short-term borrowings outstanding. In December 2014, we entered into a new $35.0 million credit facility with a new lender and increased one of our existing credit facilities by $10.0 million. As a result of these additions, we now have six unsecured bank credit facilities with three financial institutions with $210.0 million in total available credit. The annual weighted average interest rates on our short-term borrowings were 1.15 percent and 1.26 percent for 2014 and 2013, respectively. We incurred commitment fees of $87,000 and $56,000 in 2014 and 2013, respectively.


						Outstanding borrowings at
	(in thousands)	Total Facility		Interest Rate	Expiration Date	31-Dec-14		31-Dec-13		Available at December 31, 2014
	Bank Credit Facility
	Committed revolving credit facility A	$	55,000	LIBOR plus 1.25 percent	June 26, 2015	$	20,000	$	35,000	$	35,000

	Committed revolving credit facility B	30,000		LIBOR plus 1.25 percent (1)	October 31, 2015	16,040		17,554		13,960

	Committed revolving credit facility C	35,000		LIBOR plus 0.85 percent	December 22, 2015	—		—		35,000

	Short-term revolving credit Note D	50,000		LIBOR plus 0.80 percent (3)	October 31, 2015	50,000		40,000		—

	Uncommitted revolving credit facility E	20,000		Rate offered by the bank	June 26, 2015	—		—		20,000

	Uncommitted revolving credit facility F (2)	20,000		Rate offered by the bank	October 31, 2015	—		10,000		20,000

	Total short term credit facilities	$	210,000			$	86,040	$	102,554	$	123,960

	Book overdrafts(4)					2,191		3,112

	Total short-term borrowing					$	88,231	$	105,666

	(1) This facility bears interest at LIBOR for the applicable period plus 1.25 percent, if requested three days prior to the advance date. If requested and
	advanced on the same day, this facility bears interest at a base rate plus 1.25 percent.
	(2) We have issued $4.4 million in letters of credit under this credit facility as of December 31, 2014. There have been no draws on these letters of credit,
	and we do not anticipate that they will be drawn upon by the counter-parties. We expect that the letters of credit will be renewed to the
	extent necessary in the future.
	(3) At our discretion, the borrowings under this facility can bear interest at the lender's base rate plus 0.80 percent.
	(4) If presented, these book overdrafts would be funded through the bank revolving credit facilities.
	These bank credit facilities are available to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. We are currently authorized by our Board of Directors to borrow up to $200.0 million of short-term debt, as required, from these short-term lines of credit.
	The availability of funds under our credit facilities is subject to conditions specified in the respective credit agreements, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in these agreements. We are required by the financial covenants in our revolving credit facilities to maintain, at the end of each fiscal year:

	•	a funded indebtedness ratio of no greater than 65 percent; and

	•	a fixed charge coverage ratio of at least 1.20 to 1.0.
	We are in compliance with all of our debt covenants.

Lease_Obligations

Lease Obligations	12 Months Ended
Lease Obligations	Dec. 31, 2014
Text Block [Abstract]
Lease Obligations	LEASE OBLIGATIONS
	We have entered into several operating lease arrangements for office space, equipment and pipeline facilities. Rent expense related to these leases for 2014, 2013 and 2012 was $1.8 million, $1.6 million and $1.4 million, respectively. Future minimum payments under our current lease agreements for the years 2015 through 2019 are $1.1 million, $942,000, $338,000, $293,000, and $228,000, respectively; and approximately $2.3 million thereafter, with an aggregate total of approximately $5.2 million.
	For the years ended December 31, 2014 and 2013, we paid $1.1 million for a capital lease arrangement related to Sandpiper's capacity, supply and operating agreement. Future minimum payments under this lease arrangement are $1.5 million for 2015 through 2018 and $625,000 in 2019, with an aggregate total of $6.6 million.

Accumulated_Other_Comprehensiv

Accumulated Other Comprehensive Income (Loss)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	ACCUMULATED OTHER COMPREHENSIVE INCOME (LOSS)
	Defined benefit pension and postretirement plan items and unrealized gains (losses) of our propane swap agreements and call options, designated as commodity contracts cash flow hedges, are the components of our accumulated comprehensive income (loss). The following table presents the changes in the balance of accumulated other comprehensive loss for the years ended December 31, 2014 and 2013. All amounts in the following table are presented net of tax.



			Defined Benefit Pension and Postretirement Plan Items				Commodity Contracts Cash Flow Hedges			Total
	(in thousands)
	As of December 31, 2013		$	(2,533	)		$	—		$	(2,533	)

	Other comprehensive loss before reclassifications		(3,242		)		(482		)	(3,724		)
	Amounts reclassified from accumulated other comprehensive loss		132				449			581

	Net current-period other comprehensive loss		(3,110		)		(33		)	(3,143		)
	As of December 31, 2014		$	(5,643	)		$	(33	)	$	(5,676	)



			Defined Benefit Pension and Postretirement Plan Items				Commodity Contracts Cash Flow Hedges			Total
	(in thousands)
	As of December 31, 2012		$	(5,062	)		$	—		$	(5,062	)

	Other comprehensive income before reclassifications		2,251				—			2,251

	Amounts reclassified from accumulated other comprehensive loss		278				—			278

	Net current-period other comprehensive income		2,529				—			2,529

	As of December 31, 2013		$	(2,533	)		$	—		$	(2,533	)

	The following table presents amounts reclassified out of accumulated other comprehensive loss for the years ended December 31, 2014 and 2013.


	For the Year Ended December 31,	2014				2013
	(in thousands)
	Amortization of defined benefit pension and postretirement plan items:
	Prior service cost (1)	$	58			$	60

	Net gain (1)	(279		)		(523		)
	Total before income taxes	(221		)		(463		)
	Income tax benefit	89				185

	Net of tax	$	(132	)		$	(278	)

	Gains and losses on commodity contracts cash flow hedges
	Propane swap agreements (2)	$	(735	)		$	—

	Call options (2)	(17		)		—

	Total before income taxes	(752		)		—

	Income tax benefit	303				—

	Net of tax	$	(449	)		$	—


	Total reclassifications for the period	$	(581	)		$	(278	)


	-1	These amounts are included in the computation of net periodic benefits. See Note 16, Employee Benefit Plans, for additional details.

	(2)	These amounts are included in the effects of gains and losses from derivative instruments. See Note 7, Derivative Instruments, for additional details.
	Amortization of defined benefit pension and postretirement plan items is included in operations expense and gains and losses on propane swap agreements and call options are included in cost of sales in the accompanying consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying consolidated statements of income.

Employee_Benefit_Plans

Employee Benefit Plans	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Employee Benefit Plans	EMPLOYEE BENEFIT PLANS
	We measure the assets and obligations of the defined benefit pension plans and other postretirement benefits plans to determine the plans’ funded status as of the end of the year as an asset or a liability on our consolidated balance sheets. We record as a component of other comprehensive income/loss or a regulatory asset the changes in funded status that occurred during the year that are not recognized as part of net periodic benefit costs.
	Defined Benefit Pension Plans
	We sponsor three defined benefit pension plans: the Chesapeake Pension Plan, the FPU Pension Plan and the Chesapeake SERP.
	The Chesapeake Pension Plan was closed to new participants, effective January 1, 1999, and was frozen with respect to additional years of service and additional compensation, effective January 1, 2005. Benefits under the Chesapeake Pension Plan were based on each participant’s years of service and highest average compensation, prior to the freezing of the plan.
	The FPU Pension Plan covers eligible FPU non-union employees hired before January 1, 2005 and union employees hired before the respective union contract expiration dates in 2005 and 2006. Prior to the merger, the FPU Pension Plan was frozen with respect to additional years of service and additional compensation, effective December 31, 2009.
	The Chesapeake SERP was frozen with respect to additional years of service and additional compensation as of December 31, 2004. Benefits under the Chesapeake SERP were based on each participant’s years of service and highest average compensation, prior to the freezing of the plan.
	In January 2011, a former executive officer retired and received lump-sum pension distribution from the Chesapeake Pension Plan. Based upon the funding status of the Chesapeake Pension Plan at the time, which did not meet or exceed 110 percent of the benefit obligation as required per the Department of Labor regulations, our former executive officer was required to deposit property equal to 125 percent of the restricted portion of his lump sum distribution into an escrow. Each year, an amount equal to the value of payments that would have been paid to him if he had elected the life annuity form of distribution becomes unrestricted. Property equal to the life annuity amount is returned to him from the escrow account. These same regulations will apply to the top 20 highest compensated employees taking distributions from the Chesapeake Pension Plan.

	The following schedule sets forth the funded status at December 31, 2014 and 2013 and the net periodic cost for the years ended December 31, 2014, 2013 and 2012 for the Chesapeake and FPU Pension Plans:



		Chesapeake								FPU
		Pension Plan								Pension Plan
	At December 31,	2014				2013				2014				2013
	(in thousands)
	Change in benefit obligation:
	Benefit obligation — beginning of year	$	10,268			$	11,933			$	55,876			$	64,512

	Interest cost	425				405				2,613				2,367

	Actuarial loss (gain)	1,891				(1,092		)		12,785				(8,007		)

	Benefits paid	(603		)		(978		)		(3,101		)		(2,996		)
	Benefit obligation — end of year	11,981				10,268				68,173				55,876

	Change in plan assets:
	Fair value of plan assets — beginning of year	8,743				8,430				44,337				41,954

	Actual return on plan assets	305				967				1,485				4,747

	Employer contributions	633				324				2,356				632

	Benefits paid	(603		)		(978		)		(3,101		)		(2,996		)
	Fair value of plan assets — end of year	9,078				8,743				45,077				44,337

	Reconciliation:
	Funded status	(2,903		)		(1,525		)		(23,096		)		(11,539		)
	Accrued pension cost	$	(2,903	)		$	(1,525	)		$	(23,096	)		$	(11,539	)
	Assumptions:

	Discount rate	3.5		%		4.25		%		3.75		%		4.75		%
	Expected return on plan assets	6		%		6		%		7		%		7		%



		Chesapeake												FPU
		Pension Plan												Pension Plan
	For the Years Ended December 31,	2014				2013				2012				2014				2013				2012
	(in thousands)
	Components of net periodic pension cost:
	Interest cost	$	425			$	405			$	458			$	2,613			$	2,367			$	2,577

	Expected return on assets	(516		)		(486		)		(418		)		(3,089		)		(2,866		)		(2,627		)
	Amortization of prior service cost	—				(1		)		(5		)		—				—				—

	Amortization of actuarial loss	176				322				255				8				330				196

	Net periodic pension cost	85				240				290				(468		)		(169		)		146

	Amortization of pre-merger regulatory asset	—				—				—				761				761				761

	Total periodic cost	$	85			$	240			$	290			$	293			$	592			$	907

Assumptions:
Discount rate	4.25		%		3.5		%		4.25		%		4.75		%		3.75		%		4.5		%
Expected return on plan assets	6		%		6		%		6		%		7		%		7		%		7		%

Included in the net periodic costs for the FPU Pension Plan is continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU's regulated operations for the changes in funded status that occurred but was not recognized as part of net periodic cost prior to the merger with Chesapeake in October 2009. This was previously deferred as a regulatory asset by FPU prior to the merger to be recovered through rates pursuant to an order by the Florida PSC. The unamortized balance of this regulatory asset was $3.6 million and $4.3 million at December 31, 2014 and 2013, respectively.
The following sets forth the funded status at December 31, 2014 and 2013 and the net periodic cost for the years ended December 31, 2014, 2013 and 2012 for the Chesapeake SERP:


At December 31,	2014				2013
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	2,210			$	2,352

Interest cost	92				81

Actuarial loss (gain)	437				(134		)

Benefits paid	(89		)		(89		)
Benefit obligation — end of year	2,650				2,210

Change in plan assets:
Fair value of plan assets — beginning of year	—				—

Employer contributions	89				89

Benefits paid	(89		)		(89		)
Fair value of plan assets — end of year	—				—

Reconciliation:
Funded status	(2,650		)		(2,210		)
Accrued pension cost	$	(2,650	)		$	(2,210	)
Assumptions:
Discount rate	3.5		%		4.25		%



For the Years Ended December 31,	2014				2013				2012
(in thousands)
Components of net periodic pension cost:
Interest cost	$	92			$	81			$	90

Amortization of prior service cost	19				19				19

Amortization of actuarial loss	47				64				46

Net periodic pension cost	$	158			$	164			$	155

Assumptions:
Discount rate	4.25		%		3.5		%		4.25		%
Our funding policy provides that payments to the trustee of each qualified plan shall be equal to at least the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The following schedule summarizes the assets of the Chesapeake Pension Plan and the FPU Pension Plan, by investment type, at December 31, 2014, 2013 and 2012:


	Chesapeake									FPU
	Pension Plan									Pension Plan
At December 31,	2014			2013			2012			2014			2013			2012
Asset Category
Equity securities	51.42	%		54.4	%		52.07	%		52.62	%		55.02	%		52.81	%
Debt securities	37.31	%		36.54	%		38	%		37.69	%		36.54	%		38.04	%
Other	11.27	%		9.06	%		9.93	%		9.69	%		8.44	%		9.15	%
Total	100	%		100	%		100	%		100	%		100	%		100	%
The investment policy of both the Chesapeake and FPU Pension Plans is designed to provide the capital assets necessary to meet the financial obligations of the plans. The investment goals and objectives are to achieve investment returns that, together with contributions, will provide funds adequate to pay promised benefits to present and future beneficiaries of the plans, earn a long-term investment return in excess of the growth of the Plans’ retirement liabilities, minimize pension expense and cumulative contributions resulting from liability measurement and asset performance, and maintain a diversified portfolio to reduce the risk of large losses.
The following allocation range of asset classes is intended to produce a rate of return sufficient to meet the Plans’ goals and objectives:


Asset Allocation Strategy
Asset Class	Minimum			Maximum
	Allocation			Allocation
	Percentage			Percentage
Domestic Equities (Large Cap, Mid Cap and Small Cap)	14	%		32	%
Foreign Equities (Developed and Emerging Markets)	13	%		25	%
Fixed Income (Inflation Bond and Taxable Fixed)	26	%		40	%
Alternative Strategies (Long/Short Equity and Hedge Fund of Funds)	6	%		14	%
Diversifying Assets (High Yield Fixed Income, Commodities, and Real Estate)	7	%		19	%
Cash	0	%		5	%
Due to periodic contributions and different asset classes producing varying returns, the actual asset values may temporarily move outside of the intended ranges. The investments are monitored on a quarterly basis, at a minimum, for asset allocation and performance.

At December 31, 2014, the assets of the Chesapeake Pension Plan and the FPU Pension Plan were comprised of the following investments:


	Fair Value Measurement Hierarchy
Asset Category	Level 1				Level 2				Level 3				Total
(in thousands)
Equity securities
U.S. Large Cap (1)	$	4,069			$	4,028			$	—			$	8,097

U.S. Mid Cap (1)	1,733				1,714				—				3,447

U.S. Small Cap (1)	873				821				—				1,694

International (2)	9,621				—				—				9,621

Alternative Strategies (3)	5,531				—				—				5,531

	21,827				6,563				—				28,390

Debt securities
Fixed income (4)	17,717				—				—				17,717

High Yield (4)	2,658				—				—				2,658

	20,375				—				—				20,375

Other
Commodities (5)	1,819				—				—				1,819

Real Estate (6)	2,427				—				—				2,427

Guaranteed deposit (7)	—				—				1,144				1,144

	4,246				—				1,144				5,390

Total Pension Plan Assets	$	46,448			$	6,563			$	1,144			$	54,155


(1)	Includes funds that invest primarily in United States common stocks.

(2)	Includes funds that invest primarily in foreign equities and emerging markets equities.

(3)	Includes funds that actively invest in both equity and debt securities, funds that sell short securities and funds that provide long-term capital appreciation. The funds may invest in debt securities below investment grade.

(4)	Includes funds that invest in investment grade and fixed income securities.

(5)	Includes funds that invest primarily in commodity-linked derivative instruments and fixed income securities.

(6)	Includes funds that invest primarily in real estate.

(7)	Includes investment in a group annuity product issued by an insurance company.

At December 31, 2013, the assets of the Chesapeake Pension Plan and the FPU Pension Plan were comprised of the following investments:



	Fair Value Measurement Hierarchy
Asset Category	Level 1				Level 2				Level 3				Total
(in thousands)
Equity securities
U.S. Large Cap (1)	$	3,964			$	4,118			$	—			$	8,082

U.S. Mid Cap (1)	—				3,412				—				3,412

U.S. Small Cap (1)	—				1,736				—				1,736

International (2)	10,687				—				—				10,687

Alternative Strategies (3)	5,235				—				—				5,235

	19,886				9,266				—				29,152

Debt securities
Inflation Protected (4)	2,462				—				—				2,462

Fixed income (5)	—				14,305				—				14,305

High Yield (5)	—				2,629				—				2,629

	2,462				16,934				—				19,396

Other
Commodities (6)	1,939				—				—				1,939

Real Estate (7)	1,991				—				—				1,991

Guaranteed deposit (8)	—				—				602				602

	3,930				—				602				4,532

Total Pension Plan Assets	$	26,278			$	26,200			$	602			$	53,080


(1)	Includes funds that invest primarily in United States common stocks.

(2)	Includes funds that invest primarily in foreign equities and emerging markets equities.

(3)	Includes funds that actively invest in both equity and debt securities, funds that sell short securities and funds that provide long-term capital appreciation. The funds may invest in debt securities below investment grade.

(4)	Includes funds that invest primarily in inflation-indexed bonds issued by the U.S. government.

(5)	Includes funds that invest in investment grade and fixed income securities.

(6)	Includes funds that invest primarily in commodity-linked derivative instruments and fixed income securities.

(7)	Includes funds that invest primarily in real estate.

(8)	Includes investment in a group annuity product issued by an insurance company.

At December 31, 2014 and 2013, all of the investments classified under Level 1 of the fair value measurement hierarchy were recorded at fair value based on unadjusted quoted prices in active markets for identical investments. The Level 2 investments were recorded at fair value based on net asset value per unit of the investments, which used significant observable inputs although those investments were not traded publicly and did not have quoted market prices in active markets. The Level 3 investments were recorded at fair value based on the contract value of annuity products underlining guaranteed deposit accounts, which was calculated using discounted cash flow models. The contract value of these products represented deposits made to the contract, plus earnings at guaranteed crediting rates, less withdrawals and fees.
The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2014 and 2013:


	For the Year Ended December 31,
	2014				2013
(in thousands)
Balance, beginning of year	$	602			$	710

Purchases	1,811				618

Transfers in	2,390				3,175

Disbursements	(3,704		)		(3,966		)
Investment income	45				65

Balance, end of year	$	1,144			$	602

Other Postretirement Benefits Plans
We sponsor two defined benefit plans: the Chesapeake Postretirement Plan and the FPU Medical Plan. In March 2011, new plan provisions for the FPU Medical Plan were adopted in a continuing effort to standardize FPU’s benefits with those offered by Chesapeake. The new plan provisions, which became effective January 1, 2012, require eligible employees retiring in 2012 through 2014 to pay a portion of the total benefit costs based on the year they retire. Participants retiring in 2015 and after will be required to pay the full benefit costs associated with participation in the FPU Medical Plan. The change in the FPU Medical Plan resulted in a curtailment gain of $892,000. Since we determined that the non-recurring gain resulted from the FPU merger and the related integration, we determined that the appropriate accounting treatment for the portion of the gain allocated to FPU's regulated operations prescribed deferral as a regulatory liability and amortization over a future period, as specified by the Florida PSC. We recorded $170,000 of this curtailment gain in 2012, which was allocated to FPU's unregulated operations. We deferred $722,000 of this curtailment gain and included it as a regulatory liability. We amortized and recorded as a credit to amortization expense $212,000 and $510,000 of the deferred curtailment gain during 2014 and 2013, respectively.
The following sets forth the funded status at December 31, 2014 and 2013 and the net periodic cost for the years ended December 31, 2014, 2013, and 2012:


	Chesapeake								FPU
	Postretirement Plan								Medical Plan
At December 31,	2014				2013				2014				2013
(in thousands)
Change in benefit obligation:
Benefit obligation — beginning of year	$	1,262			$	1,415			$	1,519			$	1,774

Interest cost	39				47				69				63

Plan participants contributions	106				92				97				104

Actuarial loss (gain)	6				(108		)		375				(165		)

Benefits paid	(175		)		(184		)		(348		)		(257		)
Benefit obligation — end of year	1,238				1,262				1,712				1,519

Change in plan assets:
Fair value of plan assets — beginning of year	—				—				—				—

Employer contributions(1)	69				92				251				153

Plan participants contributions	106				92				97				104

Benefits paid	(175		)		(184		)		(348		)		(257		)
Fair value of plan assets — end of year	—				—				—				—

Reconciliation:
Funded status	(1,238		)		(1,262		)		(1,712		)		(1,519		)
Accrued postretirement cost	$	(1,238	)		$	(1,262	)		$	(1,712	)		$	(1,519	)
Assumptions:
Discount rate	3.5		%		4.25		%		3.75		%		4.75		%

(1)	Chesapeake’s Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period.

Net periodic postretirement benefit costs for 2014, 2013, and 2012 include the following components:


	Chesapeake												FPU
	Postretirement Plan												Medical Plan
For the Years Ended December 31,	2014				2013				2012				2014				2013				2012
(in thousands)
Components of net periodic postretirement cost:
Service cost	$	—			$	—			$	—			$	—			$	—			$	1

Interest cost	39				47				55				69				63				79

Amortization of:
Actuarial loss	55				74				73				—				—				—

Prior service cost	(77		)		(77		)		(77		)		—				—				—

Net periodic cost	17				44				51				69				63				80

Curtailment gain	—				—				—				—				—				(892		)

Amortization of pre-merger regulatory asset	—				—				—				8				8				8

Net periodic cost	$	17			$	44			$	51			$	77			$	71			$	(804	)

Assumptions
Discount rate	4.25		%		3.5		%		4.25		%		4.75		%		3.75		%		4.5		%
Similar to the FPU Pension Plan, continued amortization of the FPU postretirement benefit regulatory asset related to the unrecognized cost prior to the merger with Chesapeake was included in the net periodic cost. The unamortized balance of this regulatory asset was $46,000 and $54,000 at December 31, 2014 and 2013, respectively.
The following table presents the amounts not yet reflected in net periodic benefit cost and included in accumulated other comprehensive income/loss or as a regulatory asset as of December 31, 2014:


(in thousands)	Chesapeake				FPU				Chesapeake				Chesapeake				FPU				Total
	Pension				Pension				SERP				Postretirement				Medical
	Plan				Plan								Plan				Plan
Prior service cost (credit)	$	—			$	—			$	9			$	(832	)		$	—			$	(823	)

Net loss	4,410				19,679				1,050				924				233				26,296

Total	$	4,410			$	19,679			$	1,059			$	92			$	233			$	25,473

Accumulated other comprehensive loss pre-tax(1)	$	4,410			$	3,739			$	1,059			$	92			$	44			$	9,344

Post-merger regulatory asset	—				15,940				—				—				189				16,129

Subtotal	4,410				19,679				1,059				92				233				25,473

Pre-merger regulatory asset	—				3,587				—				—				46				3,633

Total unrecognized cost	$	4,410			$	23,266			$	1,059			$	92			$	279			$	29,106


(1)	The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2014 is net of income tax benefits of $3.7 million.

Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs after the merger with Chesapeake related to its regulated operations, which is included in the above table as post-merger regulatory asset. FPU also continues to maintain and amortize a portion of the unrecognized pension and postretirement benefit costs prior to the merger with Chesapeake related to its regulated operations, which is shown as a pre-merger regulatory asset.
The amounts in accumulated other comprehensive income/loss and recorded as a regulatory asset for our pension and postretirement benefits plans that are expected to be recognized as a component of net benefit cost in 2015 are set forth in the following table:


(in thousands)	Chesapeake				FPU				Chesapeake				Chesapeake				FPU				Total
	Pension				Pension				SERP				Postretirement				Medical
	Plan				Plan								Plan				Plan
Prior service cost (credit)	$	—			$	—			$	9			$	(77	)		$	—			$	(68	)

Net loss	$	364			$	454			$	99			$	70			$	6			$	993

Amortization of pre-merger regulatory asset	$	—			$	761			$	—			$	—			$	8			$	769


Assumptions
The assumptions used for the discount rate to calculate the benefit obligations of all the plans were based on the interest rates of high-quality bonds in 2014, reflecting the expected lives of the plans. In determining the average expected return on plan assets for each applicable plan, various factors, such as historical long-term return experience, investment policy and current and expected allocation, were considered. Since Chesapeake’s plans and FPU’s plans have different expected plan lives and investment policies, particularly in light of the lump-sum-payment option provided in the Chesapeake Pension Plan, different assumptions regarding discount rate and expected return on plan assets were selected for Chesapeake’s and FPU’s plans. Since both pension plans are frozen with respect to additional years of service and compensation, the rate of assumed compensation increases is not applicable. We adopted a new mortality table (RP 2014), which was developed by the Society of Actuaries and published during 2014.
The health care inflation rate for 2014 used to calculate the benefit obligation is 5.0 percent for medical and 6.0 percent for prescription drugs for the Chesapeake Postretirement Plan; and 5.5 percent for the FPU Medical Plan. A one–percentage point increase in the health care inflation rate from the assumed rate would increase the accumulated postretirement benefit obligation by approximately $380,000 as of December 31, 2014, and would increase the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2014 by approximately $14,000. A one-percentage point decrease in the health care inflation rate from the assumed rate would decrease the accumulated postretirement benefit obligation by approximately $302,000 as of December 31, 2014, and would decrease the aggregate of the service cost and interest cost components of the net periodic postretirement benefit cost for 2014 by approximately $11,000.
Estimated Future Benefit Payments
In 2015, we expect to contribute $475,000 and $1.6 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, and $151,000 to the Chesapeake SERP. We also expect to contribute $79,000 and $207,000 to the Chesapeake Postretirement Plan and FPU Medical Plan, respectively, in 2015. The schedule below shows the estimated future benefit payments for each of the plans previously described:


	Chesapeake				FPU				Chesapeake				Chesapeake				FPU
	Pension				Pension				SERP(2)				Postretirement				Medical
	Plan(1)				Plan(1)								Plan(2)				Plan(2)
(in thousands)
2015	$	642			$	2,957			$	151			$	79			$	207

2016	$	594			$	3,008			$	151			$	78			$	179

2017	$	715			$	3,022			$	150			$	75			$	151

2018	$	637			$	3,090			$	149			$	76			$	111

2019	$	706			$	3,178			$	148			$	76			$	116

Years 2020 through 2024	$	3,896			$	17,207			$	938			$	331			$	474


(1)	The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.

(2)	Benefit payments are expected to be paid out of our general funds.
Retirement Savings Plan
Effective January 1, 2012, we sponsor one 401(k) retirement savings plan and the 401(k) SERP, a non-qualified supplemental executive retirement savings plan.
Our 401(k) plan is offered to all eligible employees who have completed three months of service, except for employees represented by a collective bargaining agreement that does not specifically provide for participation in the plan, non-resident aliens with no U.S. source income and individuals classified as consultants, independent contractors or leased employees. Effective January 1, 2011, we match 100 percent of eligible participants’ pre-tax contributions to the Chesapeake 401(k) plan up to a maximum of six percent of eligible compensation. In addition, we may make a supplemental contribution to participants in the plan, without regard to whether or not they make pre-tax contributions. Beginning January 1, 2011, the employer matching contribution is made in cash and is invested based on a participant’s investment directions. Any supplemental employer contribution is generally made in Chesapeake stock. With respect to the employer match and supplemental employer contribution, employees are 100 percent vested after two years of service or upon reaching 55 years of age while still employed by Chesapeake. Employees with one year of service are 20 percent vested and will become 100 percent vested after two years of service. Employees who do not make an election to contribute or do not opt out of the Chesapeake 401(k) plan will be automatically enrolled at a deferral rate of three percent, and the automatic deferral rate will increase by one percent per year up to a maximum of six percent.
We also offer the 401(k) SERP to our executive officers over a specific income threshold. Participants receive a cash-only matching contribution percentage equivalent to their 401(k) match level. All contributions and matched funds can be invested among the mutual funds available for investment. All obligations arising under the 401(k) SERP are payable from our general assets, although we have established a Rabbi Trust for the 401(k) SERP. Assets held in the Rabbi Trust for the 401(k) SERP had a fair value of $3.7 million and $3.1 million at December 31, 2014 and 2013, respectively. (See Note 9, Investments, for further details). The assets of the Rabbi Trust are at all times subject to the claims of our general creditors.
Contributions to all of our 401(k) plans totaled $4.1 million, $3.7 million and $2.9 million for the years ended December 31, 2014, 2013 and 2012, respectively. As of December 31, 2014, there are 855,975 shares of our common stock reserved to fund future contributions to the 401(k) plan.
Deferred Compensation Plan
On December 7, 2006, the Board of Directors approved the Deferred Compensation Plan as amended, effective January 1, 2007. At December 31, 2014, the Deferred Compensation Plan consisted of shares of our common stock related to the deferral of executive performance shares, directors’ stock retainers and director cash retainers and fees.
Participants in the Deferred Compensation Plan are able to elect the payment of benefits to begin on a specified future date after the election is made in the form of a lump sum or annual installments. Deferrals of executive cash bonuses and directors’ cash retainers and fees are paid in cash. All deferrals of executive performance shares, which represent deferred stock units, and directors’ stock retainers are paid in shares of our common stock, except that cash is paid in lieu of fractional shares. We established a Rabbi Trust in connection with the Deferred Compensation Plan. The value of our stock held in the Rabbi Trust is classified within the stockholders’ equity section of the consolidated balance sheet and has been accounted for in a manner similar to treasury stock. The amounts recorded under the Deferred Compensation Plan totaled $1.3 million and $1.1 million at December 31, 2014 and 2013, respectively.

Effective January 1, 2014, our 401(k) SERP was amended, restated and renamed as the Chesapeake Utilities Corporation Non-Qualified Deferred Compensation Plan. In addition, the Deferred Compensation Plan was consolidated into this plan. As a result of these actions, the 401(k) SERP and the Deferred Compensation Plan are now administered as a single plan.

ShareBased_Compensation_Plans

Share-Based Compensation Plans	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Share-Based Compensation Plans	SHARE-BASED COMPENSATION PLANS
	Since May 2, 2013, our non-employee directors and key employees have been granted share-based awards through our SICP. Prior to May 2, 2013, they were awarded share-based awards through DSCP and 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 the shares awarded, using the estimated fair value of each share on the date it was granted and the number of shares to be issued at the end of the service period. We have 621,176 shares reserved for issuance under the SICP.
	The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the SICP for the years ended December 31, 2014, 2013 and 2012:


		For the Year Ended December 31,
		2014				2013			2012
	(in thousands)
	Awards to non-employee directors	$	540			$	478		$	443

	Awards to key employees	1,418				1,153			976

	Total compensation expense	1,958				1,631			1,419

	Less: tax benefit	(790		)		(657		)	(569		)
	Share-Based Compensation amounts included in net income	$	1,168			$	974		$	850

	Stock Options
	We did not have any stock options outstanding at December 31, 2014, or 2013, nor were any stock options issued during 2014, 2013 and 2012.
	Non-employee Directors
	Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the date of the grant. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2014, each of our non-employee directors received an annual retainer of 1,209 shares of common stock under the SICP as of December 31, 2014.
	A summary of stock activity for our non-employee directors for the years ended December 31, 2014, 2013 and 2012 is presented below.


		Number of			Weighted Average
		Shares			Grant Date Fair Value
	Outstanding — December 31, 2012	—			$	—

	Granted	14,141			$	34.99

	Vested	14,141			$	34.99

	Outstanding — December 31, 2013	—			$	—

	Granted (1)	13,827			$	41.6

	Vested (1)	13,827			$	41.6

	Outstanding — December 31, 2014	—			$	—

	(1) In November 2014, we added a new member to our Board of Directors. The number of shares granted to the director for his annual retainer was prorated.
	The weighted average grant date fair value of shares granted to our non-employee directors during 2014, 2013 and 2012 was $41.60, $34.99 and $27.37 per share, respectively. The intrinsic values of the shares granted to our non-employee directors are equal to the fair value of these awards on the date of grant. At December 31, 2014, there was $201,000 of unrecognized compensation expense related to these awards. This expense will be fully recognized by April 2015, which approximates the expected remaining service period of those directors.
	Key Employees
	Our Compensation Committee is authorized to grant key employees of the Company the right to receive awards of shares of our common stock, contingent upon the achievement of established performance goals. These awards are subject to certain post-vesting transfer restrictions.
	We currently have multi-year performance plans, which are based upon the successful achievement of long-term goals, growth and financial results, which comprised both market-based and performance-based conditions or targets. The fair value of each share of stock tied to a performance-based condition or target is equal to the market price of our common stock on the date of the grant. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each share of market-based award granted.
	The table below presents the summary of the stock activity for awards to key employees:


		Number of			Weighted Average
		Shares			Fair Value
	Outstanding — December 31, 2012	126,968			$	25.24

	Granted	35,237			$	29.9

	Vested	36,498			$	22.17

	Expired	4,565			$	26.08

	Outstanding — December 31, 2013	121,142			$	28.2

	Granted	41,442			$	39.99

	Vested	39,546			$	26.87

Outstanding — December 31, 2014	123,038			$	32.6

In 2014, 2013 and 2012, we withheld shares with value at least equivalent to the employees’ minimum statutory obligation for the applicable income and other employment taxes, and remitted the cash to the appropriate taxing authorities with the executives receiving the net shares. The total number of shares withheld of 12,687, 15,617 and 8,505 for 2014, 2013 and 2012, respectively, was based on the value of the shares on their vesting date, determined by the average of high and low of our stock price. Total payments for the employees’ tax obligations to the taxing authorities were approximately $503,000, $519,000, and $238,000, in 2014, 2013 and 2012, respectively. The tax benefit for 2014, 2013 and 2012 is $398,000, 202,000 and 172,000, respectively, and is included in additional paid-in capital in the consolidated statements of stockholders' equity.
The weighted average grant-date fair value of shares awards granted to key employees during 2014, 2013 and 2012 was $39.99, $29.90 and $26.41 per share, respectively. The intrinsic value of these awards was $6.1 million, $4.8 million and $3.8 million for 2014, 2013 and 2012, respectively. At December 31, 2014, there was of $1.2 million of unrecognized compensation cost related to these awards, which is expected to be recognized during 2015 and 2016.

Rates_and_Other_Regulatory_Act

Rates and Other Regulatory Activities	12 Months Ended
Rates and Other Regulatory Activities	Dec. 31, 2014
Text Block [Abstract]
Rates and Other Regulatory Activities	RATES AND OTHER REGULATORY ACTIVITIES
	Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake’s Florida natural gas distribution division and FPU’s natural gas and electric operations continue to be subject to regulation by the Florida PSC as separate entities.
	Delaware
	There were no significant rates and other regulatory activities in Delaware during 2014.
	Maryland
	Sandpiper depreciation study: On March 24, 2014, Sandpiper filed a depreciation study with the Maryland PSC regarding the assets purchased in the ESG acquisition. This depreciation study was filed in accordance with the order dated May 29, 2013, which allowed Sandpiper to recommend the proper depreciation rates and accumulated depreciation associated with the acquired assets. After a series of testimonies and discussions, Sandpiper, the Maryland Office of People's Counsel and the technical staff of the Maryland PSC reached a settlement agreement, which, among other things, establishes new depreciation rates and accumulated depreciation for the acquired assets. Under the terms of the settlement agreement, Sandpiper would adopt new depreciation rates, which are lower than the rates currently in place, and decrease accumulated depreciation included in its rate base by approximately $3.0 million for future rate making purposes. Sandpiper also agrees to file a new depreciation study within five years. The settlement agreement does not change Sandpiper's rates charged to its customers. On September 29, 2014, the Public Utility Law Judge approved the settlement and issued a proposed order, which became a final order of the Maryland PSC on October 30, 2014. The decrease in accumulated depreciation of the acquired assets is for regulatory rate-making purposes and does not change the value of those assets reflected on our consolidated balance sheets, which, pursuant to U.S. GAAP, were originally recorded based on the fair value of those assets on the date of the ESG acquisition.
	Cecil County expansion: On October 7, 2014, Chesapeake’s Maryland Division filed with the Maryland PSC for expansion of its service territory in Cecil County, Maryland to extend south of the Chesapeake and Delaware Canal in order to serve an industrial customer near Warwick, Maryland. On November 12, 2014, the Maryland PSC granted Chesapeake’s request, conditioned on no adverse comments being received within thirty days. On December 11, 2014, the conditional order approving the request became final.

	Florida
	Natural gas depreciation study: On January 13, 2014, FPU's natural gas distribution divisions and Chesapeake's Florida natural gas distribution division filed a consolidated natural gas depreciation study with the Florida PSC. We also filed for approval to establish a regulatory asset and related amortization to address the costs associated with the development of this study. The Florida PSC approved new depreciation rates at the Agenda Conference on November 25, 2014. New rates became effective retroactive to January 1, 2014. The new depreciation rates resulted in a reduction of approximately $1.0 million in annual depreciation expense. The Florida PSC also approved amortization of a regulatory asset related to the costs associated with the development of this depreciation study.

	Electric rate case: On April 28, 2014, FPU filed a base rate case for its electric distribution operation. FPU requested interim rate relief of approximately $2.4 million and final rate relief of approximately $5.9 million. The interim rate relief requested was based on the twelve-month period ended September 30, 2013. At the July 10, 2014 Agenda Conference, the Florida PSC approved interim rate relief of approximately $2.2 million. The interim rates were effective for meter readings on or after August 10, 2014. On August 29, 2014, FPU and the Florida Office of Public Counsel reached a settlement agreement, which provided, among other things, an increase in annual base rates of approximately $3.8 million and a rate of common equity return of 10.25 percent. On September 15, 2014, the Florida PSC approved the settlement agreement. New final rates were effective for all meter readings on or after November 1, 2014.
	PPA with Eight Flags: On September 26, 2014, FPU filed a PPA with the Florida PSC pursuant to which FPU proposes to purchase up to 20 megawatts of electricity from its affiliate, Eight Flags, to service its customers in the Northeast division. Eight Flags is pursuing the development and construction of a CHP plant in Nassau County, Florida. FPU expects the PPA to provide significant savings in fuel costs over its 20-year term, which FPU will pass on to its customers. The Florida PSC approved this agreement at the Agenda Conference on December 18, 2014
	Other Matters: We also had developments in the following regulatory matters in Florida:

	On November 15, 2013, Chesapeake's Florida natural gas distribution division petitioned the Florida PSC for an extension to its surcharge to recover an additional $381,000 in estimated remaining environmental cleanup costs that have not yet been recovered. The Florida PSC approved the extension of the surcharge and the additional amount for recovery at the Agenda Conference on January 7, 2014. This extension is effective for two years, beginning January 1, 2014.

	On September 30, 2014, FPU filed for approval with the Florida PSC two contracts with its Peninsula Pipeline affiliate for additional natural gas transportation services in Nassau and Palm Beach Counties, Florida. The Florida PSC approved these two contracts at the Agenda Conference on December 18, 2014.
	Eastern Shore
	The following are regulatory activities involving FERC orders applicable to Eastern Shore and the expansions of Eastern Shore’s transmission system:
	White Oak Mainline Expansion Project: On November 21, 2014, Eastern Shore submitted to the FERC an application for a CP seeking authorization to construct, own, operate and maintain the White Oak mainline expansion project. The project is designed to provide 45,000 Dts/d of firm transportation service to an industrial customer in Kent County, Delaware. Eastern Shore proposes to construct approximately 7.2 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and 3,550 horsepower of additional compression at Eastern Shore’s existing Delaware City Compressor Station in New Castle County, Delaware. The estimated cost of the project is $29.8 million.
	OPT ≤ 90 Service: On August 7, 2014, Eastern Shore submitted for filing and acceptance tariff records to establish a new OPT ≤ 90 Service. The OPT ≤ 90 Service is designed to allow a customer to contract to receive unrestricted firm service subject to Eastern Shore’s right to not schedule service for up to 90 days during the peak months of November through April of each year. In addition, during these peak months, the OPT ≤ 90 Service would have a scheduling priority below that of Firm Transportation Service but above the priority given to all secondary firm and interruptible services. On September 5, 2014, the FERC issued an order accepting Eastern Shore’s tariff changes to be made effective September 7, 2014. On October 1, 2014, the FERC accepted and approved Eastern Shore’s compliance filing, and no further action is required.
	TETLP Expansion Project: On January 31, 2014, Eastern Shore submitted to the FERC a request for prior notice authorization regarding a project that included certain improvements at Eastern Shore’s existing interconnection with TETLP near Honey Brook, Pennsylvania. This project allows Eastern Shore to increase its capacity to receive natural gas from TETLP by 57,000 Dts/d to a total capacity of 107,000 Dts/d; however, this project does not result in an increase in Eastern Shore’s overall system capacity. On April 8, 2014, the FERC approved Eastern Shore’s prior notice application, and Eastern Shore made this additional receipt point capacity available to an existing industrial customer.
	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 consisted 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 was designed to provide 55,200 Dts/d of delivery lateral firm transportation service to an industrial customer facility that was under construction. The total cost of the project was approximately $11.5 million, $2.5 million of which was received from a state grant. The FERC issued a CP for this project, and a notice to allow construction to proceed. Eastern Shore completed construction activities for this project and service commenced on October 1, 2014.

	Other matters: On May 30, 2014, Eastern Shore submitted to the FERC a combined filing of its FRP and Cash-Out Refund for a twelve-month period from April 2013 to March 2014. In this filing, Eastern Shore proposed an FRP rate of 0.62 percent. During the period, Eastern Shore experienced an under-recovery of $494,000 in its Deferred Gas Required for Operations costs and an over-recovery of $160,000 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.

Environmental_Commitments_and_

Environmental Commitments and Contingencies	12 Months Ended
Environmental Commitments and Contingencies	Dec. 31, 2014
Text Block [Abstract]
Environmental Commitments and Contingencies	ENVIRONMENTAL COMMITMENTS AND CONTINGENCIES
	We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remediate at current and former operating sites the effect on the environment of the disposal or release of specified substances.
	We have participated in the investigation, assessment or remediation, and have exposures at six former MGP sites. Those sites are located in Salisbury, Maryland, and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. In January 2015, DNREC issued a report on a former MGP site located in Seaford, Delaware regarding groundwater contamination. We have also been in discussions with the MDE regarding another former MGP site located in Cambridge, Maryland.
	As of December 31, 2014, we had approximately $10.1 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, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to all of its MGP sites, approximately $9.7 million of which has been recovered as of December 31, 2014, leaving approximately $4.3 million in regulatory assets for future recovery of environmental costs from FPU’s customers.
	In addition to the FPU MGP sites, we had $382,000 in environmental liabilities at December 31, 2014, related to Chesapeake’s MGP sites in Salisbury, Maryland and Winter Haven, Florida, representing our estimate of future costs associated with these sites. As of December 31, 2014, we had approximately $313,000 in regulatory and other assets for future recovery through Chesapeake’s rates.
	We did not have any environmental liability related to the former MGP sites in Seaford, Delaware and Cambridge, Maryland at December 31, 2014.
	Environmental liabilities for all of our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs associated with the two former MGP sites under discussion, for which we do not currently have approval for regulatory recovery, 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 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 at this site. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of December 31, 2014, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements.
	In December 2014, the EPA issued a Preliminary Close Out Report, documenting the completion of all physical remedial construction activities at the Sanford site. Groundwater monitoring and statutory Five-Year Reviews to ensure performance of the approved remedy will continue on this site. The total cost of the final remedy is estimated to be over $20.0 million, which includes long-term monitoring and the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU 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 December 31, 2014, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be $24,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million to implement the final remedy for this site, as provided in the Third Participation Agreement, or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of December 31, 2014.
	Key West, Florida
	FPU formerly owned and operated a MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In 2010, after 17 years of regulatory inactivity, FDEP observed that some soil and groundwater standards were exceeded and requested implementation of additional soil and groundwater fieldwork. The scope of work is limited to the installation of two additional monitoring wells and periodic monitoring of the new and existing wells. The two new monitoring wells were installed in November 2011, and groundwater monitoring began in December 2011. The first semi-annual report from the monitoring program was issued in May 2012. The data from the June 2012 and September 2012 monitoring events were submitted to the FDEP on October 4, 2012. FDEP responded on October 9, 2012 that, based on the data, NAM appears to be an appropriate remedy for the site.
	In October 2012, FDEP issued a Remedial Action Plan approval order, which specified that a limited semi-annual monitoring program be conducted. The most recent groundwater-monitoring event was conducted on September 15, 2014. Natural Attenuation Default Criteria were met at all locations sampled. The next semi-annual sampling event is scheduled for March of 2015.
	Although the duration of the FDEP-required limited NAM cannot be determined with certainty, it is anticipated that total costs to complete the remedial action will not exceed $50,000. The annual cost to conduct the limited NAM program is not expected to exceed $8,000.
	Pensacola, Florida
	FPU formerly owned and operated a MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the FDOT. In October 2009, FDEP informed Gulf Power that it would approve a conditional No Further Action determination for the site with the requirement for institutional and engineering controls. A Memorandum of Understanding was executed on June 16, 2014 between FDOT and FDEP to implement site closure with approved institutional and engineering controls for the site. It is anticipated that FPU’s share of remaining legal and cleanup costs will not exceed $5,000.
	Winter Haven, Florida
	The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a consent order entered into with FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. Groundwater monitoring results have shown a continuing reduction in contaminant concentrations from the sparging system, which has been in operation since 2002. On September 12, 2014, FDEP issued a letter approving shut-down of the sparging operations on the northern portion of the site, contingent upon continued semi-annual monitoring.
	Groundwater monitoring results on the southern portion of this site indicate that Natural Attenuation Default Criteria continue to be exceeded. Plans to modify the monitoring network on the southern portion of the site in order to collect additional data to support the development of a remedial plan were specified in a letter to FDEP, dated October 17, 2014. The well installation and abandonment program was implemented in October 2014, and documentation will be reported in the next Semi-Annual RAP Implementation Status Report, which will be submitted in January of 2015. Although specific remedial actions have not yet been identified, we estimate that future remediation costs for the subsurface soils and groundwater at the site should not exceed $443,000, which includes an estimate of $100,000 to implement additional actions, such as institutional controls, at the site. We continue to believe that the entire amount will be recoverable from customers through rates.
	FDEP previously indicated that we could also be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, and our recent meeting with FDEP, we believe that corrective measures for lake sediments are not warranted and will not be required by FDEP. We therefore have not recorded a liability for sediment remediation.
	Salisbury, Maryland
	We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized ground-water 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.
	In a letter dated December 5, 2013, the DNREC notified us that it will be conducting a facility evaluation of a former MGP site in Seaford, Delaware. In a report issued during January 2015, DNREC provided the evaluation of this site, which found contaminants impacting the groundwater. Shallow groundwater was also impacted by low levels of metals above the DNREC screening levels. Based on these findings, further tests and investigations are required to delineate the extent of soil and groundwater impact associated with site. Subsequent to this report, we estimated the cost of potential remedial actions based on the findings of the report to be $273,000 to $465,000.

Other_Commitments_and_Continge

Other Commitments and Contingencies	12 Months Ended
Other Commitments and Contingencies	Dec. 31, 2014
Text Block [Abstract]
Other Commitments and Contingencies	OTHER COMMITMENTS AND CONTINGENCIES
	Natural Gas, Electric and Propane Supply
	Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. For our Delaware and Maryland natural gas distribution divisions, we 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, we entered into a new contract with a different company to perform similar asset management functions. The new contract expires on March 31, 2017.
	In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six -year term, with approximately five years remaining under this contract. Sandpiper's current annual commitment is estimated at approximately 6.5 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.
	Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a six-year term. Sharp's current annual commitment is estimated at approximately 6.5 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement.
	Chesapeake’s Florida natural gas distribution division has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including PESCO. Under the terms of these capacity release agreements, Chesapeake is contingently liable to FGT and Gulfstream, should any party that acquired the capacity through release fail to pay the capacity charge.
	In May 2014, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2015.
	FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) 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 nine 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 providing an irrevocable letter of credit. As of December 31, 2014, FPU was in compliance with all of the requirements of its fuel supply contracts.
	The total purchase obligations for natural gas, electric and propane supplies are $78.6 million for 2015, $98.7 million for 2016-2017, $87.1 million for 2018-2019 and $121.0 million thereafter.
	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 $50.0 million.
	We have issued corporate guarantees to certain vendors of our subsidiaries, the largest of which are for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event that PESCO or Xeron defaults. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at December 31, 2014 was $31.6 million, with the guarantees expiring on various dates through December 30, 2015.
	Chesapeake guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under the guarantee is the outstanding principal and accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 12, Long-Term Debt, for further details).
	In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million, which expires on September 12, 2015, related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for $1.1 million, which expires on October 31, 2015, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company in 2010, we renewed and decreased the letter of credit to $40,000 to our former primary insurance company, which will expire on June 1, 2015. There have been no draws on these letters of credit as of December 31, 2014. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.
	We provided a letter of credit for $2.3 million to TETLP related to the precedent agreement and firm transportation service agreement between TETLP and our Delaware and Maryland divisions.
	On July 25, 2014, we provided a letter to the Florida PSC guaranteeing potential refunds from interim rates to be charged by our Florida electric operation (see Note 18, Rates and Other Regulatory Activities, for further details on the Florida electric rate case). This guarantee expired in October 2014 upon approval of the permanent rate increase by the Florida PSC and its determination that no refunds from interim rates were required.
	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 December 31, 2014, we maintained a liability of $100,000 related to unrecognized income tax benefits and $724,000 related to contingencies for taxes other than income. As of December 31, 2013, we maintained a liability of $300,000 related to unrecognized income tax benefits and $1.0 million related to contingencies for taxes other than income.

	Other
	We are involved in certain other legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on our consolidated financial position, results of operations or cash flows.

Quarterly_Financial_Data

Quarterly Financial Data	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Quarterly Financial Data (Unaudited)	QUARTERLY FINANCIAL DATA (UNAUDITED)
	In our opinion, the quarterly financial information shown below includes all adjustments necessary for a fair presentation of the operations for such periods. Due to the seasonal nature of our business, there are substantial variations in operations reported on a quarterly basis.


		For the Quarters Ended
		March 31		June 30		September 30		December 31
	(in thousands except per share amounts)
	2014 (1)
	Operating Revenues	$	186,337	$	100,497	$	91,619	$	120,380

	Operating Income	$	31,623	$	10,457	$	7,792	$	12,408

	Net Income	$	17,681	$	5,134	$	3,180	$	10,097

	Earnings per share:
	Basic	$	1.22	$	0.35	$	0.22	$	0.69

	Diluted	$	1.21	$	0.35	$	0.22	$	0.69

	2013 (1)
	Operating Revenues	$	140,729	$	94,146	$	86,545	$	122,887

	Operating Income	$	26,550	$	9,152	$	8,720	$	18,312

	Net Income	$	14,869	$	4,356	$	3,879	$	9,683

	Earnings per share:
	Basic	$	1.03	$	0.3	$	0.27	$	0.67

	Diluted	$	1.03	$	0.3	$	0.27	$	0.67


	-1	The sum of the four quarters does not equal the total year due to rounding.

Summary_of_Significant_Account1

Summary of Significant Accounting Policies (Policies)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Use of Estimates	Use of Estimates
	The preparation of financial statements in conformity with GAAP requires management to make estimates in measuring assets and liabilities and related revenues and expenses. These estimates involve judgments with respect to, among other things, various future economic factors that are difficult to predict and are beyond our control; therefore, actual results could differ from these estimates.
Property, Plant and Equipment	Property, Plant and Equipment
	Property, plant and equipment are stated at original cost less accumulated depreciation or fair value, if impaired. Costs include direct labor, materials and third-party construction contractor costs, AFUDC, and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged against income as incurred, and the costs of major renewals and betterments are capitalized. Upon retirement or disposition of property owned by the unregulated businesses, the gain or loss, net of salvage value, is charged to income. Upon retirement or disposition of property within the regulated businesses, the gain or loss, net of salvage value, is charged to accumulated depreciation. A summary of property, plant and equipment by classification as of December 31, 2014 and 2013 is provided in the following table:


		As of December 31,
	(in thousands)	2014			2013
	Property, plant and equipment
	Regulated Energy
	Natural gas distribution – Delmarva	$	193,071		$	179,724

	Natural gas distribution – Florida	234,344			199,289

	Natural gas transmission – Delmarva	243,560			226,244

	Natural gas transmission – Florida	18,240			15,919

	Electric distribution – Florida	77,640			70,346

	Unregulated Energy
	Propane distribution—Delmarva	60,877			54,865

	Propane distribution – Florida	23,142			20,829

	Other unregulated energy	754			573

	Other	18,497			21,002

	Total property, plant and equipment	870,125			788,791

	Less: Accumulated depreciation and amortization	(193,369		)	(174,148		)
	Plus: Construction work in progress	13,006			16,603

	Net property, plant and equipment	$	689,762		$	631,246

	Contributions or Advances in Aid of Construction
	Customer contributions or advances in aid of construction reduce property, plant and equipment unless the amounts are refundable to customers. Contributions or advances may be refundable to customers after a number of years based on the amount of revenues generated from the customers or the duration of the service provided to the customers. Refundable contributions or advances are recorded initially as liabilities. The amounts that are determined to be non-refundable reduce property, plant and equipment at the time of such determination. During the years ended December 31, 2014 and 2013, there were $813,000 and $785,000, respectively, of non-refunded contributions or advances reducing property, plant and equipment.
	Allowed Funds Used During Construction
	Some of the additions to our regulated property, plant and equipment include AFUDC, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects. AFUDC is capitalized in rate base for rate making purposes when the completed projects are placed in service. During the years ended December 31, 2014, 2013, and 2012, we recorded $58,000, $131,000, and $111,000, respectively, of AFUDC, all of which were related to short-term debt and reflected as a reduction of interest charges.
	Asset Used in Leases
	Property, plant and equipment for the Florida natural gas transmission operation includes $1.4 million of assets, consisting primarily of mains, measuring equipment and regulation station equipment used by Peninsula Pipeline to provide natural gas transmission service pursuant to a contract with a third party. This contract is accounted for as an operating lease due to the exclusive use of the assets by the customer. The service under this contract commenced in January 2009 and generates $264,000 in annual revenue for a term of 20 years. Accumulated depreciation for these assets totaled $435,000 and $363,000 at December 31, 2014 and 2013, respectively.
	Capital Lease Asset
	Property, plant and equipment for our Delmarva natural gas distribution operation includes a capital lease asset of $6.1 million and $7.0 million, net of amortization, at December 31, 2014 and 2013, respectively, related to Sandpiper's capacity, supply and operating agreement. See Note 20, Other Commitments and Contingencies for additional information. At December 31, 2014 and 2013, accumulated amortization for the capital lease asset was $996,000 and $147,000, respectively. For the years ended December 31, 2014 and 2013, we recorded $848,000 and $147,000, respectively in amortization of the capital lease asset which was included in our fuel cost recovery mechanisms.
	Jointly-owned pipeline
	Property, plant and equipment for the Florida natural gas transmission operation also includes $6.7 million of assets, which consists of the 16-mile pipeline from the Duval/Nassau County line to Amelia Island in Nassau County, Florida, jointly owned by Peninsula Pipeline and Peoples Gas. The amount included in property, plant and equipment represents Peninsula Pipeline’s 45-percent ownership of this pipeline. This 16-mile pipeline was placed in service in December 2012. Accumulated depreciation for this pipeline totaled $584,000 and $361,000, at December 31, 2014 and 2013, respectively.
	Impairment of long-lived assets
	We periodically evaluate whether events or circumstances have occurred which indicate that other long-lived assets may not be fully recoverable. When such events or circumstances are present, we record an impairment loss equal to the excess of the assets' carrying value over its fair value if any.
	At December 31, 2014, we recorded a $6.5 million pre-tax, non-cash impairment loss related to uncertainty around the implementation of a customer billing system. We recorded $6.4 million of this impairment loss in the Regulated Energy segment, with the remaining $19,000 included in the Unregulated Energy segment. This impairment represents all of the capitalized costs associated with this project. Prior to December 31, 2014, these costs were included in construction work in progress. We are engaged in negotiations with the system vendor regarding the implementation, and are considering several options to recover these costs, including regulatory proceedings. The outcome cannot be predicted at this time. We will record a gain contingency if and when any recovery from the vendor is realizable or establish a regulatory asset if future recovery through rates is probable, respectively
Depreciation and Accretion Included in Operations Expenses	Depreciation and Accretion Included in Operations Expenses
	We compute depreciation expense for our regulated operations by applying composite, annual rates, as approved by the regulators. The following table shows the average depreciation rates used during the years ended December 31, 2014, 2013 and 2012:


		2014		2013	2012
	Natural gas distribution – Delmarva	2.50%		2.50%	2.50%
	Natural gas distribution – Florida	2.90%		3.40%	3.30%
	Natural gas transmission – Delmarva	2.70%		2.70%	2.70%
	Natural gas transmission – Florida	4.00%		4.80%	4.40%
	Electric distribution – Florida	3.80%		3.60%	3.80%
	During 2014, the Florida PSC approved new depreciation rates for our Florida natural gas distribution operations (see Note 18, Rates and Other Regulatory Activities, for additional information), which lowered their depreciation rates effective January 1, 2014.
	For our unregulated operations, we compute depreciation expense on a straight line basis over the following estimated useful lives of the assets:


	Asset Description	Useful Life
	Propane distribution mains	10-37 years
	Propane bulk plants and tanks	10-40 years
	Propane equipment	5-33 years
	Meters and meter installations	5-33 years
	Measuring and regulating station equipment	5-37 years
	Office furniture and equipment	3-10 years
	Transportation equipment	4-20 years
	Structures and improvements	5-45 years
	Other	Various

	We report certain depreciation and accretion in operations expense, rather than depreciation and amortization expense, in the accompanying consolidated statements of income in accordance with industry practice and regulatory requirements. Depreciation and accretion included in operations expense consists of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, 2014, 2013 and 2012, we reported $6.6 million, $6.1 million and $5.5 million, respectively, of depreciation and accretion in operations expenses.
Regulated Operations	Regulated Operations
	We account for our regulated operations in accordance with ASC Topic 980, Regulated Operations, which includes accounting principles for companies whose rates are determined by independent third-party regulators. When setting rates, regulators often make decisions, the economics of which require companies to defer costs or revenues in different periods than may be appropriate for unregulated enterprises. When this situation occurs, a regulated company defers the associated costs as regulatory assets on the balance sheet and records them as expense on the income statement as it collects revenues. Further, regulators can also impose liabilities upon a regulated company for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future as regulatory liabilities. If we were required to terminate the application of these regulatory provisions to our regulated operations, all such deferred amounts would be recognized in the statement of income at that time, which could have a material impact on our financial position, results of operations and cash flows.
	At December 31, 2014 and 2013, the regulated utility operations had recorded the following regulatory assets and liabilities included in our consolidated balance sheets. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.


		As of December 31,
		2014			2013
	(in thousands)
	Regulatory Assets
	Under-recovered purchased fuel and conservation cost recovery (1)	$	6,865		$	1,651

	Under-recovered GRIP revenue (1)	1,491			—

	Deferred post retirement benefits (2)	19,762			8,578

	Deferred transaction and transition costs (3)	—			471

	Deferred conversion and development costs (1)	3,745			1,320

	Environmental regulatory assets and expenditures (4)	4,452			5,170

	Acquisition adjustment (5)	45,607			47,478

	Loss on reacquired debt (6)	1,372			1,486

	Other	3,809			2,866

	Total Regulatory Assets	$	87,103		$	69,020

	Regulatory Liabilities
	Self insurance (7)	$	1,003		$	1,000

	Over-recovered purchased fuel and conservation cost recovery (1)	2,936			2,869

	Over-recovered GRIP revenue (1)	—			518

	Storm reserve (7)	2,982			2,875

	Accrued asset removal cost (8)	39,583			39,510

	Deferred gains (9)	—			783

	Other	183			514

	Total Regulatory Liabilities	$	46,687		$	48,069


	(1)	We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets.

	(2)	The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. See Note 16, Employee Benefit Plans, for additional information.

	(3)	The Florida PSC approved the inclusion of the FPU merger-related costs in our rate base and the recovery of those costs in rates through October 2014. The balance at December 31, 2013 includes the gross-up of this regulatory asset for income tax because a portion of the merger-related costs is not tax-deductible.

	(4)	All of our environmental expenditures incurred to date and current estimate of future environmental expenditures have been approved by various PSCs for recovery. See Note 19, Environmental Commitments and Contingencies, for additional information on our environmental contingencies.

	(5)	We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. Included in these amounts are $1.3 million of the premium paid by FPU, $34.2 million of the premium paid by Chesapeake in 2009, including the gross up of the amount for income tax, because it is not tax deductible, and $746,000 of the premium paid by FPU in 2010.

	(6)	Gains and losses resulting from the reacquisition of long-term debt are amortized over future periods as adjustments to interest expense in accordance with established regulatory practice.

	(7)	We have self-insurance and storm reserves that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.

	(8)	In accordance with regulatory treatment, our depreciation rates are comprised of two components – historical cost and the estimated cost of removal, net of estimated salvage, of certain regulated properties. We collect these costs in base rates through depreciation expense with a corresponding credit to accumulated depreciation. Because the accumulated estimated removal costs meet the requirements of authoritative guidance related to regulated operations, we have accounted for them as a regulatory liability and have reclassified them from accumulated depreciation to accumulated removal costs in our consolidated balance sheets.

	(9)	Pursuant to the Florida PSC order, we were required to defer and amortize, until 2014, certain gains identified during the FPU merger integration.
We monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we were to determine that recovery of these assets is no longer probable, we would write off the assets against earnings. We believe that provisions of ASC Topic 980, Regulated Operations, continue to apply to our regulated operations and that the recovery of our regulatory assets is probable.
Operating Revenues	Operating Revenues
	Revenues for our natural gas and electric distribution operations are based on rates approved by the PSC in each state in which they operate. Eastern Shore’s revenues are based on rates approved by the FERC. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have authorized our regulated operations to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to negotiated rates.
	For regulated deliveries of natural gas and electricity, we read meters and bill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. We estimate the amount of the unbilled revenue by jurisdiction and customer class. A similar computation is made to accrue unbilled revenues for propane customers with meters and natural gas marketing customers, whose billing cycles do not coincide with our accounting periods.
	The propane wholesale marketing operation records trading activity for open contracts on a net mark-to-market basis in our consolidated statements of income. For propane bulk delivery customers without meters we record revenue in the period the products are delivered and/or services are rendered.

	All of our natural gas and electric distribution operations, except for two utilities that do not sell natural gas to end-use customers as a result of deregulation, have fuel cost recovery mechanisms. These mechanisms provide a method of adjusting the billing rates to reflect changes in the cost of purchased fuel. The difference between the current cost of fuel purchased and the cost of fuel recovered in billed rates is deferred and accounted for as either unrecovered fuel cost or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year. Chesapeake’s Florida natural gas distribution division and FPU's Indiantown division provide unbundled delivery service to their customers, whereby the customers are permitted to purchase their gas requirements directly from competitive natural gas marketers.
	We charge flexible rates to our natural gas distribution industrial interruptible customers to compete with prices of alternative fuels, which these customers are able to use. Neither we nor our interruptible customers are contractually obligated to deliver or receive natural gas on a firm service basis.
	We report revenue taxes, such as gross receipts taxes, franchise taxes, and sales taxes, on a net basis.
Cost of Sales	Cost of Sales
	Cost of sales includes the direct costs attributable to the products sold or services provided to our customers. These costs include primarily the variable cost of natural gas, electricity and propane commodities, pipeline capacity costs needed to transport and store natural gas, transmission costs for electricity, transportation costs to transport propane purchases to our storage facilities and, for the period prior to the sale of BravePoint, the direct cost of labor for our advanced information services subsidiary. Depreciation expense is not included in our cost of sales.
Operations and Maintenance Expenses	Operations and Maintenance Expenses
	Operations and maintenance expenses include operations and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, customer service, professional fees and other outside services, insurance expense, minor amounts of depreciation, accretion of cost of removal for future retirements of utility assets, and other administrative expenses.
Cash and Cash Equivalents	Cash and Cash Equivalents
	Our policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates fair value. Investments with an original maturity of three months or less when purchased are considered cash equivalents.
Accounts Receivable and Allowance for Doubtful Accounts	Accounts Receivable and Allowance for Doubtful Accounts
	Accounts receivable consist primarily of amounts due for distribution sales of natural gas, electricity and propane and transportation services to customers. An allowance for doubtful accounts is recorded against amounts due to reduce the receivables balance to the amount we reasonably expect to collect based upon our collections experiences and our assessment of customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such estimates include, but are not limited to, customer credit issues, the level of natural gas, electricity and propane prices and general economic conditions. Accounts are written off when they are deemed to be uncollectible.
Inventories	Inventories
	We use the average cost method to value propane, materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to market values. At December 31, 2014, we reduced our propane inventory value by $681,000 to reflect the lower-of-cost-or-market adjustment.
Goodwill and Other Intangible Assets	Goodwill and Other Intangible Assets
	Goodwill is not amortized but is tested for impairment at least annually. In addition, goodwill of a reporting unit is tested for impairment between annual tests if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives. Please refer to Note 10, Goodwill and Other Intangible Assets, for additional discussion of this subject.
	The annual goodwill impairment test as of December 31, 2014 resulted in a $237,000 goodwill impairment loss associated with the Austin Cox acquisition. We also recorded a $175,000 impairment loss on an intangible asset related to a non-compete agreement associated with the same acquisition.
Other Deferred Charges	Other Deferred Charges
	Other deferred charges include discount, premium and issuance costs associated with long-term debt. Debt issuance costs are deferred and then are amortized to interest expense over the original lives of the respective debt issuances.
Pension and Other Postretirement Plans	Pension and Other Postretirement Plans
	Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates, including the fair value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. We review annually the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities with the assistance of third-party actuarial firms. The assumed discount rates, expected returns on plan assets and the mortality assumption are the factors that generally have the most significant impact on our pension costs and liabilities. The assumed discount rates, health care cost trend rates and rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.
	The discount rates are utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net pension and postretirement costs. When estimating our discount rates, we consider high quality corporate bond rates, such as Moody’s Aa bond index and the Citigroup yield curve, changes in those rates from the prior year and other pertinent factors, including the expected life of each of our plans and their respective payment options.
	The expected long-term rates of return on assets are utilized in calculating the expected returns on the plan assets component of our annual pension plan costs. We estimate the expected returns on plan assets of each of our plans by evaluating expected bond returns, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rates of return on assets.
	We estimate the health care cost trend rates used in determining our postretirement net expense based upon actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual reviews of participant census information as of the measurement date.
	The mortality assumption used for our pension and postretirement plans is based on the actuarial table that is most reflective of the expected mortality of the plan participants and reviewed periodically.
	Actual changes in the fair value of plan assets and the differences between the actual and expected return on plan assets could have a material effect on the amount of pension and postretirement benefit costs that we ultimately recognize. A 0.25 percent decrease in the discount rate could increase our annual pension and postretirement costs by approximately $18,000, and a 0.25 percent increase could decrease our annual pension and postretirement costs by approximately $22,000. A 0.25 percent change in the rate of return could change our annual pension cost by approximately $134,000 and would not have an impact on the postretirement and supplemental executive retirement plans because these plans are not funded.
Income Taxes and Investment Tax Credit Adjustments	Income Taxes, Investment Tax Credit Adjustments and Tax-related contingency
	Deferred tax assets and liabilities are recorded for the income tax effect of temporary differences between the financial statement basis and tax basis of assets and liabilities and are measured using the enacted income tax rates in effect in the years in which the differences are expected to reverse. Deferred tax assets are recorded net of any valuation allowance when it is more likely than not that such income tax benefits will be realized. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.
	We account for uncertainty in income taxes in the financial statements only if it is more likely than not that an uncertain tax position is sustainable based on technical merits. Recognizable tax positions are then measured to determine the amount of benefit recognized in the financial statements. We recognize penalties and interest related to unrecognized tax benefits as a component of other income.
	We account for contingencies associated with taxes other than income when the likelihood of a loss is both probable and estimable. In assessing the likelihood of a loss, we do not consider the existence of current inquiries, or the likelihood of future inquiries, by tax authorities as a factor. Our assessment is based solely on our application of the appropriate statutes and the likelihood of a loss assuming the proper inquiries are made by tax authorities.
Financial Instruments	Financial Instruments
	Xeron engages in trading activities using forward and futures contracts, which have been accounted for using the mark-to-market method of accounting. Under mark-to-market accounting, our trading contracts are recorded at fair value as mark-to-market energy assets and liabilities. The changes in fair value of the contracts are recognized as gains or losses in revenues on the consolidated statements of income in the period of change.

	Our natural gas, electric and propane distribution operations and natural gas marketing operations enter 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 enter into derivative transactions, such as swaps, put options and call options in order to mitigate the impact of wholesale price fluctuations on its inventory valuation and future purchase commitments. These transactions may be designated as fair value hedges or cash flow hedges, if they meet all of the accounting requirements pursuant to ASC Topic 815, Derivatives and Hedging and we elect to designate the instruments as hedges. If designated as a fair value hedge, the value of the hedging instrument, such as a swap or put option, is recorded at fair value with the effective portion of the gain or loss of the hedging instrument effectively reducing or increasing the value of propane inventory. If designated as a cash flow hedge, the value of the hedging instrument, such as a swap or call option, is recorded at fair value with the effective portion of the gain or loss of the hedging instrument being recorded in comprehensive income. The ineffective portion of the gain or loss of a hedge is recorded in earnings. If the instrument is not designated as a fair value or cash flow hedge or does not meet the accounting requirements of a hedge, it is recorded at fair value with the gain or loss being recorded in earnings.
Recently Adopted Accounting Standards	FASB Statements and Other Authoritative Pronouncements
	Recent Accounting Standards Yet to be Adopted
	Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. ASU 2014-09 is effective for reporting periods (interim and annual) beginning after December 15, 2016. We are currently assessing the impact this standard will have on our financial position and results of operations.
	Recently Adopted Accounting Standards
	Presentation of Financial Statements (ASC 205) and Property Plant and Equipment (ASC 360) - In April 2014, the FASB issued ASU 2014-08, Reporting Discontinued Operations and Disclosures of Disposals of Components of an Entity. The new standard limits discontinued operations reporting to disposals of components of an entity that represent strategic shifts that have or will have a major effect on an entity's operations and financial results, and requires additional disclosures related to discontinued operations. Upon adoption of the new standard, fewer disposals are expected to be presented as discontinued operations. We early adopted the provisions of this standard in the third quarter of 2014 and applied them to the sale of BravePoint (see Note 4, Acquisitions and Disposition, for additional details on the sale). As a result, BravePoint is not presented as a discontinued operation in the accompanying consolidated statements of income.
	Income Taxes (ASC 740) - In July 2013, the FASB issued 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. ASU 2013-11 became effective for us on January 1, 2014. The adoption of ASU 2013-11 had no material impact on our financial position and results of operations.

Summary_of_Significant_Account2

Summary of Significant Accounting Policies (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Summary of Property, Plant and Equipment by Classification	A summary of property, plant and equipment by classification as of December 31, 2014 and 2013 is provided in the following table:


		As of December 31,
	(in thousands)	2014			2013
	Property, plant and equipment
	Regulated Energy
	Natural gas distribution – Delmarva	$	193,071		$	179,724

	Natural gas distribution – Florida	234,344			199,289

	Natural gas transmission – Delmarva	243,560			226,244

	Natural gas transmission – Florida	18,240			15,919

	Electric distribution – Florida	77,640			70,346

	Unregulated Energy
	Propane distribution—Delmarva	60,877			54,865

	Propane distribution – Florida	23,142			20,829

	Other unregulated energy	754			573

	Other	18,497			21,002

	Total property, plant and equipment	870,125			788,791

	Less: Accumulated depreciation and amortization	(193,369		)	(174,148		)
	Plus: Construction work in progress	13,006			16,603

	Net property, plant and equipment	$	689,762		$	631,246

Average Depreciation Rates	We compute depreciation expense for our regulated operations by applying composite, annual rates, as approved by the regulators. The following table shows the average depreciation rates used during the years ended December 31, 2014, 2013 and 2012:


		2014		2013	2012
	Natural gas distribution – Delmarva	2.50%		2.50%	2.50%
	Natural gas distribution – Florida	2.90%		3.40%	3.30%
	Natural gas transmission – Delmarva	2.70%		2.70%	2.70%
	Natural gas transmission – Florida	4.00%		4.80%	4.40%
	Electric distribution – Florida	3.80%		3.60%	3.80%
	During 2014, the Florida PSC approved new depreciation rates for our Florida natural gas distribution operations (see Note 18, Rates and Other Regulatory Activities, for additional information), which lowered their depreciation rates effective January 1, 2014.
Estimated Useful Lives of Assets	For our unregulated operations, we compute depreciation expense on a straight line basis over the following estimated useful lives of the assets:


	Asset Description	Useful Life
	Propane distribution mains	10-37 years
	Propane bulk plants and tanks	10-40 years
	Propane equipment	5-33 years
	Meters and meter installations	5-33 years
	Measuring and regulating station equipment	5-37 years
	Office furniture and equipment	3-10 years
	Transportation equipment	4-20 years
	Structures and improvements	5-45 years
	Other	Various
Schedule of Regulatory Assets	These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.


		As of December 31,
		2014			2013
	(in thousands)
	Regulatory Assets
	Under-recovered purchased fuel and conservation cost recovery (1)	$	6,865		$	1,651

	Under-recovered GRIP revenue (1)	1,491			—

	Deferred post retirement benefits (2)	19,762			8,578

	Deferred transaction and transition costs (3)	—			471

	Deferred conversion and development costs (1)	3,745			1,320

	Environmental regulatory assets and expenditures (4)	4,452			5,170

	Acquisition adjustment (5)	45,607			47,478

	Loss on reacquired debt (6)	1,372			1,486

	Other	3,809			2,866

	Total Regulatory Assets	$	87,103		$	69,020

	Regulatory Liabilities
	Self insurance (7)	$	1,003		$	1,000

	Over-recovered purchased fuel and conservation cost recovery (1)	2,936			2,869

	Over-recovered GRIP revenue (1)	—			518

	Storm reserve (7)	2,982			2,875

	Accrued asset removal cost (8)	39,583			39,510

	Deferred gains (9)	—			783

	Other	183			514

	Total Regulatory Liabilities	$	46,687		$	48,069


	(1)	We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets.

	(2)	The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. See Note 16, Employee Benefit Plans, for additional information.

	(3)	The Florida PSC approved the inclusion of the FPU merger-related costs in our rate base and the recovery of those costs in rates through October 2014. The balance at December 31, 2013 includes the gross-up of this regulatory asset for income tax because a portion of the merger-related costs is not tax-deductible.

	(4)	All of our environmental expenditures incurred to date and current estimate of future environmental expenditures have been approved by various PSCs for recovery. See Note 19, Environmental Commitments and Contingencies, for additional information on our environmental contingencies.

	(5)	We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. Included in these amounts are $1.3 million of the premium paid by FPU, $34.2 million of the premium paid by Chesapeake in 2009, including the gross up of the amount for income tax, because it is not tax deductible, and $746,000 of the premium paid by FPU in 2010.

	(6)	Gains and losses resulting from the reacquisition of long-term debt are amortized over future periods as adjustments to interest expense in accordance with established regulatory practice.

	(7)	We have self-insurance and storm reserves that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.

	(8)	In accordance with regulatory treatment, our depreciation rates are comprised of two components – historical cost and the estimated cost of removal, net of estimated salvage, of certain regulated properties. We collect these costs in base rates through depreciation expense with a corresponding credit to accumulated depreciation. Because the accumulated estimated removal costs meet the requirements of authoritative guidance related to regulated operations, we have accounted for them as a regulatory liability and have reclassified them from accumulated depreciation to accumulated removal costs in our consolidated balance sheets.

	(9)	Pursuant to the Florida PSC order, we were required to defer and amortize, until 2014, certain gains identified during the FPU merger integration.
Schedule of Regulatory Liabilities

		As of December 31,
		2014			2013
	(in thousands)
	Regulatory Assets
	Under-recovered purchased fuel and conservation cost recovery (1)	$	6,865		$	1,651

	Under-recovered GRIP revenue (1)	1,491			—

	Deferred post retirement benefits (2)	19,762			8,578

	Deferred transaction and transition costs (3)	—			471

	Deferred conversion and development costs (1)	3,745			1,320

	Environmental regulatory assets and expenditures (4)	4,452			5,170

	Acquisition adjustment (5)	45,607			47,478

	Loss on reacquired debt (6)	1,372			1,486

	Other	3,809			2,866

	Total Regulatory Assets	$	87,103		$	69,020

	Regulatory Liabilities
	Self insurance (7)	$	1,003		$	1,000

	Over-recovered purchased fuel and conservation cost recovery (1)	2,936			2,869

	Over-recovered GRIP revenue (1)	—			518

	Storm reserve (7)	2,982			2,875

	Accrued asset removal cost (8)	39,583			39,510

	Deferred gains (9)	—			783

	Other	183			514

	Total Regulatory Liabilities	$	46,687		$	48,069


	(1)	We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets.

	(2)	The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. See Note 16, Employee Benefit Plans, for additional information.

	(3)	The Florida PSC approved the inclusion of the FPU merger-related costs in our rate base and the recovery of those costs in rates through October 2014. The balance at December 31, 2013 includes the gross-up of this regulatory asset for income tax because a portion of the merger-related costs is not tax-deductible.

	(4)	All of our environmental expenditures incurred to date and current estimate of future environmental expenditures have been approved by various PSCs for recovery. See Note 19, Environmental Commitments and Contingencies, for additional information on our environmental contingencies.

	(5)	We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. Included in these amounts are $1.3 million of the premium paid by FPU, $34.2 million of the premium paid by Chesapeake in 2009, including the gross up of the amount for income tax, because it is not tax deductible, and $746,000 of the premium paid by FPU in 2010.

	(6)	Gains and losses resulting from the reacquisition of long-term debt are amortized over future periods as adjustments to interest expense in accordance with established regulatory practice.

	(7)	We have self-insurance and storm reserves that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.

	(8)	In accordance with regulatory treatment, our depreciation rates are comprised of two components – historical cost and the estimated cost of removal, net of estimated salvage, of certain regulated properties. We collect these costs in base rates through depreciation expense with a corresponding credit to accumulated depreciation. Because the accumulated estimated removal costs meet the requirements of authoritative guidance related to regulated operations, we have accounted for them as a regulatory liability and have reclassified them from accumulated depreciation to accumulated removal costs in our consolidated balance sheets.

Earnings_Per_Share_Tables

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Calculations of Basic and Diluted Earnings Per Share	The calculations of both basic and diluted earnings per share are presented in the following table.


		For the Year Ended December 31,
		2014		2013		2012
	(in thousands, except shares and per share data)
	Calculation of Basic Earnings Per Share:
	Net Income	$	36,092	$	32,787	$	28,863

	Weighted average shares outstanding	14,551,308		14,430,962		14,379,216

	Basic Earnings Per Share	$	2.48	$	2.27	$	2.01

	Calculation of Diluted Earnings Per Share:
	Reconciliation of Numerator:
	Net Income	$	36,092	$	32,787	$	28,863

	Effect of 8.25% Convertible debentures	—		43		53

	Adjusted numerator — Diluted	$	36,092	$	32,830	$	28,916

	Reconciliation of Denominator:
	Weighted shares outstanding — Basic	14,551,308		14,430,962		14,379,216

	Effect of dilutive securities:
	Share-based Compensation	53,636		37,866		35,249

	8.25% Convertible debentures (1)	—		74,618		92,796

	Adjusted denominator — Diluted	14,604,944		14,543,446		14,507,261

	Diluted Earnings Per Share	$	2.47	$	2.26	$	1.99

	(1) As of March 1, 2014, we no longer have any outstanding convertible debentures. See Note 12, Long-term debt for additional information.

Segment_Information_Segment_In

Segment Information Segment Information (Tables)	12 Months Ended
	Dec. 31, 2014
Segment Reporting [Abstract]
Schedule of Segment Reporting Information, by Segment [Table Text Block]	The following table presents information about our reportable segments.


		For the Year Ended December 31,
		2014			2013		2012
	(in thousands)
	Operating Revenues, Unaffiliated Customers
	Regulated Energy	$	299,345		$	263,573	$	245,042

	Unregulated Energy	184,557			161,760		130,020

	Other	14,932			18,973		17,440

	Total operating revenues, unaffiliated customers	$	498,834		$	444,306	$	392,502

	Intersegment Revenues (1)
	Regulated Energy	$	1,097		$	1,064	$	1,166

	Unregulated Energy	404			4,963		3,029

	Other	979			1,017		917

	Total intersegment revenues	$	2,480		$	7,044	$	5,112

	Operating Income
	Regulated Energy	$	50,451		$	50,084	$	46,999

	Unregulated Energy	11,723			12,353		8,355

	Other	105			297		1,281

	Operating Income	62,279			62,734		56,635

	Gain from sale of businesses	7,139			—		—

	Other income	101			372		271

	Interest charges	9,482			8,234		8,747

	Income Before Income taxes	60,037			54,872		48,159

	Income taxes	23,945			22,085		19,296

	Net Income	$	36,092		$	32,787	$	28,863

	Depreciation and Amortization
	Regulated Energy	$	21,915		$	19,822	$	18,653

	Unregulated Energy	3,994			3,686		3,420

	Other and eliminations	407			457		437

	Total depreciation and amortization	$	26,316		$	23,965	$	22,510

	Capital Expenditures
	Regulated Energy	$	84,959		$	95,944	$	69,056

	Unregulated Energy	9,648			4,829		3,969

	Other	3,450			7,266		5,185

	Total capital expenditures	$	98,057		$	108,039	$	78,210



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


	As of December 31,
	2014			2013
Identifiable Assets
Regulated Energy	$	796,021		$	708,950

Unregulated Energy	84,732			100,585

Other	23,716			27,987

Total identifiable assets	$	904,469		$	837,522

Supplemental_Cash_Flow_Disclos1

Supplemental Cash Flow Disclosures (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Cash Paid for Interest and Income Taxes	Cash paid for interest and income taxes during the years ended December 31, 2014, 2013 and 2012 were as follows:


		For the Year Ended December 31,
		2014		2013		2012
	(in thousands)
	Cash paid for interest	$	8,870	$	7,837	$	8,086

	Cash paid for income taxes	$	17,833	$	10,243	$	3,809

Non-Cash Investing and Financing Activities	Non-cash investing and financing activities during the years ended December 31, 2014, 2013, and 2012 were as follows:


		For the Year Ended December 31,
		2014		2013		2012
	(in thousands)
	Capital property and equipment acquired on account, but not paid as of December 31	$	459	$	341	$	7,065

	Retirement Savings Plan	$	602	$	—	$	—

	Conversion of Debentures	$	535	$	295	$	186

	Performance Incentive Plan	$	958	$	355	$	427

	Director Stock Compensation Plan	$	575	$	495	$	443

	Capital Lease Obligation	$	6,130	$	7,126	$	—

Derivative_Instruments_Tables

Derivative Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Outstanding Trading Contracts	As of December 31, 2014 and December 31, 2013, we had the following outstanding trading contracts, which we accounted for as derivatives:



		Quantity in		Estimated Market		Weighted Average
	At December 31, 2014	Gallons		Prices		Contract Prices
	Forward Contracts
	Sale	4,200,000		$0.5400 - $0.7900		$	0.6714

	Purchase	4,201,000		$0.4700 - $1.3176		$	0.6416


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



	At December 31, 2013	Quantity in		Estimated Market		Weighted Average Contract Prices
		Gallons		Prices
	Forward Contracts
	Sale	1,892,000		$0.9900 - $1.4750		$	1.2786

	Purchase	1,991,000		$0.9411 - $1.4600		$	1.2444

Fair Values of Derivative Contracts Recorded in Consolidated Balance Sheets	Fair values of the derivative contracts recorded in the consolidated balance sheets as of December 31, 2014 and 2013, are as follows:


		Asset Derivatives
			Fair Value As Of
	(in thousands)	Balance Sheet Location	December 31, 2014				December 31, 2013
	Derivatives not designated as hedging instruments
	Forward contracts	Mark-to-market energy assets	$	407			$	196

	Call option	Mark-to-market energy assets	—				169

	Derivatives designated as fair value hedges
	Put options	Mark-to-market energy assets	622				20

	Derivatives designated as cash flow hedges
	Call options	Mark-to-market energy assets	26				—

	Total asset derivatives		$	1,055			$	385





		Liability Derivatives
			Fair Value As Of
	(in thousands)	Balance Sheet Location	December 31, 2014				December 31, 2013
	Derivatives not designated as hedging instruments
	Forward contracts	Mark-to-market energy liabilities	$	283			$	127

	Propane swap agreements	Mark-to-market energy liabilities	735				—

	Total liability derivatives		$	1,018			$	127


Effects of Gains and Losses from Derivative Instruments	The effects of gains and losses from derivative instruments are as follows:



		Amount of Gain (Loss) on Derivatives:
		Location of Gain	For the Year Ended December 31,
	(in thousands)	(Loss) on Derivatives	2014				2013			2012
	Derivatives not designated as hedging instruments:
	Realized gain on forward contracts and options (1)	Revenue	$	1,423			$	1,127		$	2,695

	Unrealized gain (loss) on forward contracts (1)	Revenue	57				217			(339		)

	Call Options	Cost of Sales	—				97			—

	Propane swap agreements	Cost of Sales	(735		)		—			—

	Derivatives designated as fair value hedges:
	Put/Call Option	Cost of Sales	235				(28		)	27

	Put/Call Option (2)	Propane Inventory	517				(100		)	(40		)

	Derivatives designated as cash flow hedges
	Propane swap agreements	Cost of Sales	(341		)		—			—

	Call Options	Cost of Sales	(17		)		—			—

	Call Options	Other Comprehensive Income (Loss)	(55		)		—			—

	Total		$	1,084			$	1,313		$	2,343


	-1	All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our consolidated statements of income.

	-2	As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero and the unrealized gains and losses of this call option effectively changed the value of propane inventory.

Fair_Value_of_Financial_Instru1

Fair Value of Financial Instruments (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Financial Assets and Liabilities Measured at Fair Value on Recurring Basis	The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2014:



					Fair Value Measurements Using:
	(in thousands)	Fair Value			Quoted Prices in			Significant Other		Significant
					Active Markets			Observable		Unobservable
					(Level 1)			Inputs		Inputs
								(Level 2)		(Level 3)
	Assets:
	Investments—guaranteed income fund	$	287		$	—		$	—	$	287

	Investments—other	$	3,391		$	3,391		$	—	$	—

	Mark-to-market energy assets, incl. put/call options	$	1,055		$	—		$	1,055	$	—

	Liabilities:
	Mark-to-market energy liabilities, incl. swap agreements	$	1,018		$	—		$	1,018	$	—



	The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of December 31, 2013:



					Fair Value Measurements Using:
	(in thousands)	Fair Value			Quoted Prices in Active Markets (Level 1)			Significant Other		Significant
								Observable		Unobservable
								Inputs		Inputs
								(Level 2)		(Level 3)
	Assets:
	Investments—guaranteed income fund	$	458		$	—		$	—	$	458

	Investments—other	$	2,640		$	2,640		$	—	$	—

	Mark-to-market energy assets, including put option	$	385		$	—		$	385	$	—

	Liabilities:
	Mark-to-market energy liabilities	$	127		$	—		$	127	$	—


Schedule of Changes in Fair Value of Plan Assets	The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2014 and 2013:


		For the Year Ended December 31,
		2014			2013
	(in thousands)
	Beginning Balance	$	458		$	—

	Transfers in due to change in trustee	—			425

	Purchases and adjustments	76			41

	Transfers	(253		)	(16		)
	Investment income	6			8

	Ending Balance	$	287		$	458

Goodwill_and_Other_Intangible_1

Goodwill and Other Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Schedule of Carrying Value of Goodwill	The carrying value of goodwill as of December 31, 2014 and 2013 was as follows:


		As of December 31,
	(in thousands)	2014		2013
	Regulated Energy segment	$	3,354	$	2,790

	Unregulated Energy segment	1,598		1,564

	Total	$	4,952	$	4,354

Schedule of Carrying Value and Accumulated Amortization of Intangible Assets	The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2014 and 2013 are as follows:


		As of December 31,
		2014				2013
	(in thousands)	Gross		Accumulated		Gross		Accumulated
		Carrying		Amortization		Carrying		Amortization
		Amount				Amount
	Customer lists	$	3,993	$	1,719	$	3,993	$	1,389

	Non-Compete agreements	103		72		353		87

	Other	270		171		270		165

	Total	$	4,366	$	1,962	$	4,616	$	1,641

Income_Taxes_Tables

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Schedule of Income Tax Expense	The following tables provide: (a) the components of income tax expense in 2014, 2013, and 2012; (b) the reconciliation between the statutory federal income tax rate and the effective income tax rate for 2014, 2013, and 2012; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2014 and 2013.


		For the Year Ended December 31,
		2014			2013			2012
	(in thousands)
	Current Income Tax Expense
	Federal	$	434		$	4,882		$	3,483

	State	1,311			2,382			1,990

	Investment tax credit adjustments, net	(35		)	(39		)	(58		)
	Total current income tax expense	1,710			7,225			5,415

	Deferred Income Tax Expense (1)
	Property, plant and equipment	20,382			16,758			13,688

	Deferred gas costs	1,614			(209		)	515

	Pensions and other employee benefits	537			(335		)	553

	FPU merger related premium cost and deferred gain	(802		)	(686		)	(509		)
	Net operating loss carryforwards	(112		)	62			740

	Other	616			(730		)	(1,106		)

	Total deferred income tax expense	22,235			14,860			13,881

	Total Income Tax Expense	$	23,945		$	22,085		$	19,296

Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates

		For the Year Ended December 31,
		2014			2013			2012
	(in thousands)
	Reconciliation of Effective Income Tax Rates
	Continuing Operations
	Federal income tax expense (1)	$	21,121		$	19,205		$	16,745

	State income taxes, net of federal benefit	2,946			3,105			2,571

	ESOP dividend deduction	(267		)	(256		)	(235		)
	Other	145			31			215

	Total Income Tax Expense	$	23,945		$	22,085		$	19,296

	Effective Income Tax Rate	39.88		%	40.25		%	40.07		%

	(1)	Federal income taxes were recorded at 35% for each year represented.
Schedule of Accumulated Deferred Income Tax Assets and Liabilities

		As of December 31,
		2014			2013
	(in thousands)
	Deferred Income Taxes
	Deferred income tax liabilities:
	Property, plant and equipment	$	152,877		$	134,414

	Acquisition adjustment	16,140			16,790

	Loss on reacquired debt	529			573

	Deferred gas costs	2,222			607

	Other	4,507			2,850

	Total deferred income tax liabilities	176,275			155,234

	Deferred income tax assets:
	Pension and other employee benefits	6,532			5,390

	Environmental costs	2,313			2,083

	Net operating loss carryforwards	1,186			1,444

	Self insurance	275			403

	Storm reserve liability	1,150			1,109

	Other	3,755			3,904

	Total deferred income tax assets	15,211			14,333

	Deferred Income Taxes Per Consolidated Balance Sheets	$	161,064		$	140,901

LongTerm_Debt_Tables

Long-Term Debt (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Outstanding Long-Term Debt	Our outstanding long-term debt is shown below:


		As of December 31,
		2014			2013
	(in thousands)
	FPU secured first mortgage bonds:
	9.08% bond, due June 1, 2022	7,969			7,967

	Uncollateralized senior notes:
	7.83% note, due January 1, 2015	—			2,000

	6.64% note, due October 31, 2017	8,182			10,909

	5.50% note, due October 12, 2020	12,000			14,000

	5.93% note, due October 31, 2023	27,000			30,000

	5.68% note, due June 30, 2026	29,000			29,000

	6.43% note, due May 2, 2028	7,000			7,000

	3.73% note, due December 16, 2028	20,000			20,000

	3.88% note, due May 15, 2029	50,000			—

	Convertible debentures:
	8.25% due March 1, 2014	—			646

	Promissory notes	314			445

	Capital lease obligation	6,130			6,978

	Total long-term debt	167,595			128,945

	Less: current maturities	(9,109		)	(11,353		)
	Total long-term debt, net of current maturities	$	158,486		$	117,592

	Annual maturities and principal repayments of consolidated long-term debt, excluding the capital lease obligation, are as follows: $9,109 for 2015; $9,151 for 2016; $12,099 for 2017; $9,421 for 2018; $11,245 for 2019 and $116,600 thereafter. See Note 14, Lease obligations for future payments related to the capital lease obligation.

ShortTerm_Borrowing_ShortTerm_

Short-Term Borrowing Short-Term Borrowing (Tables)	12 Months Ended
	Dec. 31, 2014
Debt Disclosure [Abstract]
Schedule of Short-term Debt

						Outstanding borrowings at
	(in thousands)	Total Facility		Interest Rate	Expiration Date	31-Dec-14		31-Dec-13		Available at December 31, 2014
	Bank Credit Facility
	Committed revolving credit facility A	$	55,000	LIBOR plus 1.25 percent	June 26, 2015	$	20,000	$	35,000	$	35,000

	Committed revolving credit facility B	30,000		LIBOR plus 1.25 percent (1)	October 31, 2015	16,040		17,554		13,960

	Committed revolving credit facility C	35,000		LIBOR plus 0.85 percent	December 22, 2015	—		—		35,000

	Short-term revolving credit Note D	50,000		LIBOR plus 0.80 percent (3)	October 31, 2015	50,000		40,000		—

	Uncommitted revolving credit facility E	20,000		Rate offered by the bank	June 26, 2015	—		—		20,000

	Uncommitted revolving credit facility F (2)	20,000		Rate offered by the bank	October 31, 2015	—		10,000		20,000

	Total short term credit facilities	$	210,000			$	86,040	$	102,554	$	123,960

	Book overdrafts(4)					2,191		3,112

	Total short-term borrowing					$	88,231	$	105,666

	(1) This facility bears interest at LIBOR for the applicable period plus 1.25 percent, if requested three days prior to the advance date. If requested and
	advanced on the same day, this facility bears interest at a base rate plus 1.25 percent.
	(2) We have issued $4.4 million in letters of credit under this credit facility as of December 31, 2014. There have been no draws on these letters of credit,
	and we do not anticipate that they will be drawn upon by the counter-parties. We expect that the letters of credit will be renewed to the
	extent necessary in the future.
	(3) At our discretion, the borrowings under this facility can bear interest at the lender's base rate plus 0.80 percent.
	(4) If presented, these book overdrafts would be funded through the bank revolving credit facilities.

Accumulated_Other_Comprehensiv1

Accumulated Other Comprehensive Income (Loss) (Tables)	12 Months Ended
	Dec. 31, 2014
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	The following table presents the changes in the balance of accumulated other comprehensive loss for the years ended December 31, 2014 and 2013. All amounts in the following table are presented net of tax.



			Defined Benefit Pension and Postretirement Plan Items				Commodity Contracts Cash Flow Hedges			Total
	(in thousands)
	As of December 31, 2013		$	(2,533	)		$	—		$	(2,533	)

	Other comprehensive loss before reclassifications		(3,242		)		(482		)	(3,724		)
	Amounts reclassified from accumulated other comprehensive loss		132				449			581

	Net current-period other comprehensive loss		(3,110		)		(33		)	(3,143		)
	As of December 31, 2014		$	(5,643	)		$	(33	)	$	(5,676	)



			Defined Benefit Pension and Postretirement Plan Items				Commodity Contracts Cash Flow Hedges			Total
	(in thousands)
	As of December 31, 2012		$	(5,062	)		$	—		$	(5,062	)

	Other comprehensive income before reclassifications		2,251				—			2,251

	Amounts reclassified from accumulated other comprehensive loss		278				—			278

	Net current-period other comprehensive income		2,529				—			2,529

	As of December 31, 2013		$	(2,533	)		$	—		$	(2,533	)

Reclassification out of Accumulated Other Comprehensive Income	The following table presents amounts reclassified out of accumulated other comprehensive loss for the years ended December 31, 2014 and 2013.


	For the Year Ended December 31,	2014				2013
	(in thousands)
	Amortization of defined benefit pension and postretirement plan items:
	Prior service cost (1)	$	58			$	60

	Net gain (1)	(279		)		(523		)
	Total before income taxes	(221		)		(463		)
	Income tax benefit	89				185

	Net of tax	$	(132	)		$	(278	)

	Gains and losses on commodity contracts cash flow hedges
	Propane swap agreements (2)	$	(735	)		$	—

	Call options (2)	(17		)		—

	Total before income taxes	(752		)		—

	Income tax benefit	303				—

	Net of tax	$	(449	)		$	—


	Total reclassifications for the period	$	(581	)		$	(278	)


	-1	These amounts are included in the computation of net periodic benefits. See Note 16, Employee Benefit Plans, for additional details.

	(2)	These amounts are included in the effects of gains and losses from derivative instruments. See Note 7, Derivative Instruments, for additional details.

Employee_Benefit_Plans_Tables

Employee Benefit Plans (Tables)	12 Months Ended
	Dec. 31, 2014
Schedule of Assets by Investment Type	The following schedule summarizes the assets of the Chesapeake Pension Plan and the FPU Pension Plan, by investment type, at December 31, 2014, 2013 and 2012:


		Chesapeake									FPU
		Pension Plan									Pension Plan
	At December 31,	2014			2013			2012			2014			2013			2012
	Asset Category
	Equity securities	51.42	%		54.4	%		52.07	%		52.62	%		55.02	%		52.81	%
	Debt securities	37.31	%		36.54	%		38	%		37.69	%		36.54	%		38.04	%
	Other	11.27	%		9.06	%		9.93	%		9.69	%		8.44	%		9.15	%
	Total	100	%		100	%		100	%		100	%		100	%		100	%
Schedule of Asset Allocation Strategy	The following allocation range of asset classes is intended to produce a rate of return sufficient to meet the Plans’ goals and objectives:


	Asset Allocation Strategy
	Asset Class	Minimum			Maximum
		Allocation			Allocation
		Percentage			Percentage
	Domestic Equities (Large Cap, Mid Cap and Small Cap)	14	%		32	%
	Foreign Equities (Developed and Emerging Markets)	13	%		25	%
	Fixed Income (Inflation Bond and Taxable Fixed)	26	%		40	%
	Alternative Strategies (Long/Short Equity and Hedge Fund of Funds)	6	%		14	%
	Diversifying Assets (High Yield Fixed Income, Commodities, and Real Estate)	7	%		19	%
	Cash	0	%		5	%
Summary of Pension Plan Assets	At December 31, 2013, the assets of the Chesapeake Pension Plan and the FPU Pension Plan were comprised of the following investments:



		Fair Value Measurement Hierarchy
	Asset Category	Level 1				Level 2				Level 3				Total
	(in thousands)
	Equity securities
	U.S. Large Cap (1)	$	3,964			$	4,118			$	—			$	8,082

	U.S. Mid Cap (1)	—				3,412				—				3,412

	U.S. Small Cap (1)	—				1,736				—				1,736

	International (2)	10,687				—				—				10,687

	Alternative Strategies (3)	5,235				—				—				5,235

		19,886				9,266				—				29,152

	Debt securities
	Inflation Protected (4)	2,462				—				—				2,462

	Fixed income (5)	—				14,305				—				14,305

	High Yield (5)	—				2,629				—				2,629

		2,462				16,934				—				19,396

	Other
	Commodities (6)	1,939				—				—				1,939

	Real Estate (7)	1,991				—				—				1,991

	Guaranteed deposit (8)	—				—				602				602

		3,930				—				602				4,532

	Total Pension Plan Assets	$	26,278			$	26,200			$	602			$	53,080



	At December 31, 2014, the assets of the Chesapeake Pension Plan and the FPU Pension Plan were comprised of the following investments:


		Fair Value Measurement Hierarchy
	Asset Category	Level 1				Level 2				Level 3				Total
	(in thousands)
	Equity securities
	U.S. Large Cap (1)	$	4,069			$	4,028			$	—			$	8,097

	U.S. Mid Cap (1)	1,733				1,714				—				3,447

	U.S. Small Cap (1)	873				821				—				1,694

	International (2)	9,621				—				—				9,621

	Alternative Strategies (3)	5,531				—				—				5,531

		21,827				6,563				—				28,390

	Debt securities
	Fixed income (4)	17,717				—				—				17,717

High Yield (4)	2,658				—				—				2,658

	20,375				—				—				20,375

Other
Commodities (5)	1,819				—				—				1,819

Real Estate (6)	2,427				—				—				2,427

Guaranteed deposit (7)	—				—				1,144				1,144

	4,246				—				1,144				5,390

Total Pension Plan Assets	$	46,448			$	6,563			$	1,144			$	54,155


(1)	Includes funds that invest primarily in United States common stocks.

(2)	Includes funds that invest primarily in foreign equities and emerging markets equities.

(3)	Includes funds that actively invest in both equity and debt securities, funds that sell short securities and funds that provide long-term capital appreciation. The funds may invest in debt securities below investment grade.

(4)	Includes funds that invest in investment grade and fixed income securities.

(5)	Includes funds that invest primarily in commodity-linked derivative instruments and fixed income securities.

(6)	Includes funds that invest primarily in real estate.

(7)	Includes investment in a group annuity product issued by an insurance company.
Schedule of Level Three Defined Benefit Plan Assets Roll Forward	The following table sets forth the summary of the changes in the fair value of Level 3 investments for the years ended December 31, 2014 and 2013:


		For the Year Ended December 31,
		2014				2013
	(in thousands)
	Balance, beginning of year	$	602			$	710

	Purchases	1,811				618

	Transfers in	2,390				3,175

	Disbursements	(3,704		)		(3,966		)
	Investment income	45				65

	Balance, end of year	$	1,144			$	602

Schedule of Amounts Not Yet Reflected in Net Periodic Benefit Cost and Included in Accumulated Other Comprehensive Income Loss or Regulatory Assets	The following table presents the amounts not yet reflected in net periodic benefit cost and included in accumulated other comprehensive income/loss or as a regulatory asset as of December 31, 2014:


	(in thousands)	Chesapeake				FPU				Chesapeake				Chesapeake				FPU			Total
		Pension				Pension				SERP				Postretirement				Medical
		Plan				Plan								Plan				Plan
	Prior service cost (credit)	$	—			$	—			$	9			$	(832	)		$	—		$	(823	)

	Net loss	4,410				19,679				1,050				924				233			26,296

	Total	$	4,410			$	19,679			$	1,059			$	92			$	233		$	25,473

	Accumulated other comprehensive loss pre-tax(1)	$	4,410			$	3,739			$	1,059			$	92			$	44		$	9,344

	Post-merger regulatory asset	—				15,940				—				—				189			16,129

	Subtotal	4,410				19,679				1,059				92				233			25,473

	Pre-merger regulatory asset	—				3,587				—				—				46			3,633

	Total unrecognized cost	$	4,410			$	23,266			$	1,059			$	92			$	279		$	29,106


	(1)	The total amount of accumulated other comprehensive loss recorded on our consolidated balance sheet as of December 31, 2014 is net of income tax benefits of $3.7 million.
Amounts in Accumulated Other Comprehensive Income/Loss and Regulatory Asset	The amounts in accumulated other comprehensive income/loss and recorded as a regulatory asset for our pension and postretirement benefits plans that are expected to be recognized as a component of net benefit cost in 2015 are set forth in the following table:


	(in thousands)	Chesapeake				FPU				Chesapeake				Chesapeake				FPU			Total
		Pension				Pension				SERP				Postretirement				Medical
		Plan				Plan								Plan				Plan
	Prior service cost (credit)	$	—			$	—			$	9			$	(77	)		$	—		$	(68	)

	Net loss	$	364			$	454			$	99			$	70			$	6		$	993

	Amortization of pre-merger regulatory asset	$	—			$	761			$	—			$	—			$	8		$	769

Schedule of Estimated Future Benefit Payments	The schedule below shows the estimated future benefit payments for each of the plans previously described:


		Chesapeake				FPU				Chesapeake				Chesapeake				FPU
		Pension				Pension				SERP(2)				Postretirement				Medical
		Plan(1)				Plan(1)								Plan(2)				Plan(2)
	(in thousands)
	2015	$	642			$	2,957			$	151			$	79			$	207

	2016	$	594			$	3,008			$	151			$	78			$	179

	2017	$	715			$	3,022			$	150			$	75			$	151

	2018	$	637			$	3,090			$	149			$	76			$	111

	2019	$	706			$	3,178			$	148			$	76			$	116

	Years 2020 through 2024	$	3,896			$	17,207			$	938			$	331			$	474


	(1)	The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.

	(2)	Benefit payments are expected to be paid out of our general funds.
Pension benefit
Component of Net Periodic Pension Cost (Benefit)

		Chesapeake												FPU
		Pension Plan												Pension Plan
	For the Years Ended December 31,	2014				2013				2012				2014				2013			2012
	(in thousands)
	Components of net periodic pension cost:
	Interest cost	$	425			$	405			$	458			$	2,613			$	2,367		$	2,577

	Expected return on assets	(516		)		(486		)		(418		)		(3,089		)		(2,866		)	(2,627		)
	Amortization of prior service cost	—				(1		)		(5		)		—				—			—

	Amortization of actuarial loss	176				322				255				8				330			196

	Net periodic pension cost	85				240				290				(468		)		(169		)	146

	Amortization of pre-merger regulatory asset	—				—				—				761				761			761

	Total periodic cost	$	85			$	240			$	290			$	293			$	592		$	907

	Assumptions:
	Discount rate	4.25		%		3.5		%		4.25		%		4.75		%		3.75		%	4.5		%
	Expected return on plan assets	6		%		6		%		6		%		7		%		7		%	7		%
Schedule of Funded Status of Benefit Obligation and Plan Assets	The following schedule sets forth the funded status at December 31, 2014 and 2013 and the net periodic cost for the years ended December 31, 2014, 2013 and 2012 for the Chesapeake and FPU Pension Plans:



		Chesapeake								FPU
		Pension Plan								Pension Plan
	At December 31,	2014				2013				2014				2013
	(in thousands)
	Change in benefit obligation:
	Benefit obligation — beginning of year	$	10,268			$	11,933			$	55,876			$	64,512

	Interest cost	425				405				2,613				2,367

	Actuarial loss (gain)	1,891				(1,092		)		12,785				(8,007		)

	Benefits paid	(603		)		(978		)		(3,101		)		(2,996		)
	Benefit obligation — end of year	11,981				10,268				68,173				55,876

	Change in plan assets:
	Fair value of plan assets — beginning of year	8,743				8,430				44,337				41,954

	Actual return on plan assets	305				967				1,485				4,747

	Employer contributions	633				324				2,356				632

	Benefits paid	(603		)		(978		)		(3,101		)		(2,996		)
	Fair value of plan assets — end of year	9,078				8,743				45,077				44,337

	Reconciliation:
	Funded status	(2,903		)		(1,525		)		(23,096		)		(11,539		)
	Accrued pension cost	$	(2,903	)		$	(1,525	)		$	(23,096	)		$	(11,539	)
	Assumptions:

	Discount rate	3.5		%		4.25		%		3.75		%		4.75		%
	Expected return on plan assets	6		%		6		%		7		%		7		%
Rabbi trust (associated with Supplemental Executive Retirement Savings Plan)
Component of Net Periodic Pension Cost (Benefit)

	For the Years Ended December 31,	2014				2013				2012
	(in thousands)
	Components of net periodic pension cost:
	Interest cost	$	92			$	81			$	90

	Amortization of prior service cost	19				19				19

	Amortization of actuarial loss	47				64				46

	Net periodic pension cost	$	158			$	164			$	155

	Assumptions:
	Discount rate	4.25		%		3.5		%		4.25		%
Schedule of Funded Status of Benefit Obligation and Plan Assets	The following sets forth the funded status at December 31, 2014 and 2013 and the net periodic cost for the years ended December 31, 2014, 2013 and 2012 for the Chesapeake SERP:


	At December 31,	2014				2013
	(in thousands)
	Change in benefit obligation:
	Benefit obligation — beginning of year	$	2,210			$	2,352

	Interest cost	92				81

	Actuarial loss (gain)	437				(134		)

	Benefits paid	(89		)		(89		)
	Benefit obligation — end of year	2,650				2,210

	Change in plan assets:
	Fair value of plan assets — beginning of year	—				—

	Employer contributions	89				89

	Benefits paid	(89		)		(89		)
	Fair value of plan assets — end of year	—				—

	Reconciliation:
	Funded status	(2,650		)		(2,210		)
	Accrued pension cost	$	(2,650	)		$	(2,210	)
	Assumptions:
	Discount rate	3.5		%		4.25		%
Other Postretirement Benefit Plans
Component of Net Periodic Pension Cost (Benefit)	Net periodic postretirement benefit costs for 2014, 2013, and 2012 include the following components:


		Chesapeake												FPU
		Postretirement Plan												Medical Plan
	For the Years Ended December 31,	2014				2013				2012				2014				2013			2012
	(in thousands)
	Components of net periodic postretirement cost:
	Service cost	$	—			$	—			$	—			$	—			$	—		$	1

	Interest cost	39				47				55				69				63			79

	Amortization of:
	Actuarial loss	55				74				73				—				—			—

	Prior service cost	(77		)		(77		)		(77		)		—				—			—

	Net periodic cost	17				44				51				69				63			80

	Curtailment gain	—				—				—				—				—			(892		)

	Amortization of pre-merger regulatory asset	—				—				—				8				8			8

	Net periodic cost	$	17			$	44			$	51			$	77			$	71		$	(804	)

	Assumptions
	Discount rate	4.25		%		3.5		%		4.25		%		4.75		%		3.75		%	4.5		%
Schedule of Funded Status of Benefit Obligation and Plan Assets	The following sets forth the funded status at December 31, 2014 and 2013 and the net periodic cost for the years ended December 31, 2014, 2013, and 2012:


		Chesapeake								FPU
		Postretirement Plan								Medical Plan
	At December 31,	2014				2013				2014				2013
	(in thousands)
	Change in benefit obligation:
	Benefit obligation — beginning of year	$	1,262			$	1,415			$	1,519			$	1,774

	Interest cost	39				47				69				63

	Plan participants contributions	106				92				97				104

	Actuarial loss (gain)	6				(108		)		375				(165		)

	Benefits paid	(175		)		(184		)		(348		)		(257		)
	Benefit obligation — end of year	1,238				1,262				1,712				1,519

	Change in plan assets:
	Fair value of plan assets — beginning of year	—				—				—				—

	Employer contributions(1)	69				92				251				153

	Plan participants contributions	106				92				97				104

	Benefits paid	(175		)		(184		)		(348		)		(257		)
	Fair value of plan assets — end of year	—				—				—				—

	Reconciliation:
	Funded status	(1,238		)		(1,262		)		(1,712		)		(1,519		)
	Accrued postretirement cost	$	(1,238	)		$	(1,262	)		$	(1,712	)		$	(1,519	)
	Assumptions:
	Discount rate	3.5		%		4.25		%		3.75		%		4.75		%

	(1)	Chesapeake’s Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period.

ShareBased_Compensation_Plans_

Share-Based Compensation Plans (Tables)	12 Months Ended
	Dec. 31, 2014
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 SICP for the years ended December 31, 2014, 2013 and 2012:


		For the Year Ended December 31,
		2014				2013			2012
	(in thousands)
	Awards to non-employee directors	$	540			$	478		$	443

	Awards to key employees	1,418				1,153			976

	Total compensation expense	1,958				1,631			1,419

	Less: tax benefit	(790		)		(657		)	(569		)
	Share-Based Compensation amounts included in net income	$	1,168			$	974		$	850

Directors Stock Compensation Plan
Summary of Stock Activity under DSCP	A summary of stock activity for our non-employee directors for the years ended December 31, 2014, 2013 and 2012 is presented below.


		Number of			Weighted Average
		Shares			Grant Date Fair Value
	Outstanding — December 31, 2012	—			$	—

	Granted	14,141			$	34.99

	Vested	14,141			$	34.99

	Outstanding — December 31, 2013	—			$	—

	Granted (1)	13,827			$	41.6

	Vested (1)	13,827			$	41.6

	Outstanding — December 31, 2014	—			$	—

Performance Incentive Plan
Summary of Stock Activity under DSCP	The table below presents the summary of the stock activity for awards to key employees:


		Number of			Weighted Average
		Shares			Fair Value
	Outstanding — December 31, 2012	126,968			$	25.24

	Granted	35,237			$	29.9

	Vested	36,498			$	22.17

	Expired	4,565			$	26.08

	Outstanding — December 31, 2013	121,142			$	28.2

	Granted	41,442			$	39.99

	Vested	39,546			$	26.87

	Outstanding — December 31, 2014	123,038			$	32.6

Quarterly_Financial_Data_Table

Quarterly Financial Data (Tables)	12 Months Ended
	Dec. 31, 2014
Text Block [Abstract]
Schedule of Quarterly Financial Information	Due to the seasonal nature of our business, there are substantial variations in operations reported on a quarterly basis.


		For the Quarters Ended
		March 31		June 30		September 30		December 31
	(in thousands except per share amounts)
	2014 (1)
	Operating Revenues	$	186,337	$	100,497	$	91,619	$	120,380

	Operating Income	$	31,623	$	10,457	$	7,792	$	12,408

	Net Income	$	17,681	$	5,134	$	3,180	$	10,097

	Earnings per share:
	Basic	$	1.22	$	0.35	$	0.22	$	0.69

	Diluted	$	1.21	$	0.35	$	0.22	$	0.69

	2013 (1)
	Operating Revenues	$	140,729	$	94,146	$	86,545	$	122,887

	Operating Income	$	26,550	$	9,152	$	8,720	$	18,312

	Net Income	$	14,869	$	4,356	$	3,879	$	9,683

	Earnings per share:
	Basic	$	1.03	$	0.3	$	0.27	$	0.67

	Diluted	$	1.03	$	0.3	$	0.27	$	0.67


	-1	The sum of the four quarters does not equal the total year due to rounding.

Organization_and_Basis_of_Pres1

Organization and Basis of Presentation Organization and Basis of Presentation (Details) (USD $)	12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Organization and basis of presentation [Line Items]
Stock Split in Form of Stock Dividend Adjustment to Retained Earnings	$9
Common Stock, Par or Stated Value Per Share	$0.49	$0.49
Common Stock [Member]
Organization and basis of presentation [Line Items]
Stock Split in Form of Stock Dividend Adjustment to Retained Earnings	($2,365)

Summary_of_Significant_Account3

Summary of Significant Accounting Policies - Summary of Property, Plant and Equipment by Classification (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Property, plant and equipment
Total property, plant and equipment	$870,125	$788,791
Less: Accumulated depreciation and amortization	-193,369	-174,148
Plus: Construction work in progress	13,006	16,603
Net property, plant and equipment	689,762	631,246
Natural gas distribution \| Delmarva
Property, plant and equipment
Total property, plant and equipment	193,071	179,724
Natural gas distribution \| Florida
Property, plant and equipment
Total property, plant and equipment	234,344	199,289
Natural gas transmission \| Delmarva
Property, plant and equipment
Total property, plant and equipment	243,560	226,244
Natural gas transmission \| Florida
Property, plant and equipment
Total property, plant and equipment	18,240	15,919
Electric distribution \| Florida
Property, plant and equipment
Total property, plant and equipment	77,640	70,346
Propane distribution \| Delmarva
Property, plant and equipment
Total property, plant and equipment	60,877	54,865
Propane distribution \| Florida
Property, plant and equipment
Total property, plant and equipment	23,142	20,829
Other unregulated energy
Property, plant and equipment
Total property, plant and equipment	754	573
Other
Property, plant and equipment
Total property, plant and equipment	$18,497	$21,002

Summary_of_Significant_Account4

Summary of Significant Accounting Policies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011	Dec. 31, 2009
Summary Of Accounting Policies [Line Items]
Maturity Period To Be Considered Cash Equivalents	3
Inventory Write-down	$681,000
Non-refundable contributions for construction received	813,000	785,000
Allowed funds used during construction	58,000	131,000	111,000
Property, plant and equipment in service assets under operating lease contract	1,400,000
Annual revenue from operating lease	264,000
Operating lease term	20 years
Accumulated depreciation, plant in service assets under operating lease	435,000	363,000
Capital Leased Assets, Gross	6,100,000	7,000,000
Ground Leases, Accumulated Amortization	996,000	147,000
Amortization of Leased Asset	848,000	147,000
Net property, plant and equipment	689,762,000	631,246,000
Accumulated depreciation	193,369,000	174,148,000
Depreciation and accretion reported in operations expenses	6,600,000	6,100,000	5,500,000
Deferred revenue refund payment, period	1 year
Asset Impairment Charges	6,881,000	0	0
Pensions and other employee benefits
Summary Of Accounting Policies [Line Items]
Percentage of change in discount rate	0.25%
Percentage of change in rate of return	0.25%
Estimated increase in annual pension and postretirement costs	18,000
Estimated decrease in annual pension and postretirement costs	-22,000
Estimated change in annual post retirement and supplemental executive retirement plans	134,000
Natural Gas Operations
Summary Of Accounting Policies [Line Items]
Net property, plant and equipment	6,700,000
Length of pipeline	16
Ownership interest	4500.00%
Accumulated depreciation	584,000	361,000
Parent
Summary Of Accounting Policies [Line Items]
Premium paid for acquisition				746,000	34,200,000
Regulated Energy
Summary Of Accounting Policies [Line Items]
Asset Impairment Charges	6,400,000
Unregulated Energy
Summary Of Accounting Policies [Line Items]
Asset Impairment Charges	19,000
Chesapeake [Member]
Summary Of Accounting Policies [Line Items]
Asset Impairment Charges	6,468,000
Noncompete Agreements [Member]
Summary Of Accounting Policies [Line Items]
Impairment of Intangible Assets (Excluding Goodwill)	$175,000

Summary_of_Significant_Account5

Summary of Significant Accounting Policies - Average Depreciation Rates (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Natural gas distribution \| Delmarva
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.50%	2.50%	2.50%
Natural gas distribution \| Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.90%	3.40%	3.30%
Natural gas transmission \| Delmarva
Property, Plant and Equipment [Line Items]
Average depreciation rates	2.70%	2.70%	2.70%
Natural gas transmission \| Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	4.00%	4.80%	4.40%
Electric distribution \| Florida
Property, Plant and Equipment [Line Items]
Average depreciation rates	3.80%	3.60%	3.80%

Summary_of_Significant_Account6

Summary of Significant Accounting Policies - Estimated Useful Lives of Assets (Detail)	12 Months Ended
	Dec. 31, 2014
Minimum \| Propane Distribution Mains [Member]
Useful Life of Assets	10 years
Minimum \| Propane Bulk Plants And Tanks [Member]
Useful Life of Assets	10 years
Minimum \| Liquefied Petroleum Gas Equipment [Member]
Useful Life of Assets	5 years
Minimum \| Meters And Meter Installations [Member]
Useful Life of Assets	5 years
Minimum \| Measuring And Regulating Station Equipment [Member]
Useful Life of Assets	5 years
Minimum \| Office Furniture And Equipment [Member]
Useful Life of Assets	3 years
Minimum \| Transportation Equipment [Member]
Useful Life of Assets	4 years
Minimum \| Structures And Improvements [Member]
Useful Life of Assets	5 years
Maximum \| Propane Distribution Mains [Member]
Useful Life of Assets	37 years
Maximum \| Propane Bulk Plants And Tanks [Member]
Useful Life of Assets	40 years
Maximum \| Liquefied Petroleum Gas Equipment [Member]
Useful Life of Assets	33 years
Maximum \| Meters And Meter Installations [Member]
Useful Life of Assets	33 years
Maximum \| Measuring And Regulating Station Equipment [Member]
Useful Life of Assets	37 years
Maximum \| Office Furniture And Equipment [Member]
Useful Life of Assets	10 years
Maximum \| Transportation Equipment [Member]
Useful Life of Assets	20 years
Maximum \| Structures And Improvements [Member]
Useful Life of Assets	45 years

Summary_of_Significant_Account7

Summary of Significant Accounting Policies - Schedule of Regulatory Assets and Liabilities (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Regulatory Assets
Total Regulatory Assets	$87,103		$69,020
Regulatory Liabilities
Total Regulatory Liabilities	46,687		48,069
Underrecovered purchased fuel costs
Regulatory Assets
Total Regulatory Assets	6,865		1,651
Under-recovered GRIP Revenue [Member]
Regulatory Assets
Total Regulatory Assets	1,491		0
Deferred post retirement benefits
Regulatory Assets
Total Regulatory Assets	19,762	[1]	8,578	[1]
Deferred transaction and transition costs
Regulatory Assets
Total Regulatory Assets	0		471
Deferred conversion and development costs
Regulatory Assets
Total Regulatory Assets	3,745		1,320
Environmental regulatory assets and expenditures
Regulatory Assets
Total Regulatory Assets	4,452	[1]	5,170	[1]
Acquisition adjustment
Regulatory Assets
Total Regulatory Assets	45,607	[2]	47,478	[2]
Loss on reacquired debt
Regulatory Assets
Total Regulatory Assets	1,372		1,486
Other
Regulatory Assets
Total Regulatory Assets	3,809		2,866
Self insurance
Regulatory Liabilities
Total Regulatory Liabilities	1,003	[3]	1,000	[3]
Overrecovered purchased fuel costs
Regulatory Liabilities
Total Regulatory Liabilities	2,936		2,869
Over-recovered GRIP Revenue [Member]
Regulatory Liabilities
Total Regulatory Liabilities			518
Storm reserve
Regulatory Liabilities
Total Regulatory Liabilities	2,982	[3]	2,875	[3]
Accrued asset removal cost
Regulatory Liabilities
Total Regulatory Liabilities	39,583	[4]	39,510	[4]
Deferred gains
Regulatory Liabilities
Total Regulatory Liabilities	0	[5]	783	[5]
Other
Regulatory Liabilities
Total Regulatory Liabilities	$183		$514

[1]	All of our environmental expenditures incurred to date and current estimate of future environmental expenditures have been approved by various PSCs for recovery. See Note 19, Environmental Commitments and Contingencies, for additional information on our environmental contingencies.
[2]	We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. Included in these amounts are $1.3 million of the premium paid by FPU, $34.2 million of the premium paid by Chesapeake in 2009, including the gross up of the amount for income tax, because it is not tax deductible, and $746,000 of the premium paid by FPU in 2010.
[3]	Pursuant to the Florida PSC order, we were required to defer and amortize, until 2014, certain gains identified during the FPU merger integration.
[4]	In accordance with regulatory treatment, our depreciation rates are comprised of two components â€“ historical cost and the estimated cost of removal, net of estimated salvage, of certain regulated properties. We collect these costs in base rates through depreciation expense with a corresponding credit to accumulated depreciation. Because the accumulated estimated removal costs meet the requirements of authoritative guidance related to regulated operations, we have accounted for them as a regulatory liability and have reclassified them from accumulated depreciation to accumulated removal costs in our consolidated balance sheets.
[5]	We have self-insurance and storm reserves that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.

Summary_of_Significant_Account8

Summary of Significant Accounting Policies - Schedule of Regulatory Assets and Liabilities (Phantoms) (Detail) (FPU, USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
FPU
Schedule Of Regulatory Assets And Liabilities [Line Items]
Premium paid by FPU for acquisition	$1.30

Earnings_Per_Share_Calculation

Earnings Per Share - Calculations of Basic and Diluted Earnings Per Share (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Calculation of Basic Earnings Per Share:
Net Income	$10,097	$3,180	$5,134	$17,681	$9,683	$3,879	$4,356	$14,869	$36,092	$32,787	$28,863
Weighted shares outstanding - Basic (in shares)									14,551,308	14,430,962	14,379,216
Basic Earnings Per Share (in usd per share)	$0.69	$0.22	$0.35	$1.22	$0.67	$0.27	$0.30	$1.03	$2.48	$2.27	$2.01
Reconciliation of Numerator:
Net Income	10,097	3,180	5,134	17,681	9,683	3,879	4,356	14,869	36,092	32,787	28,863
Effect of 8.25% Convertible debentures									0	43	53
Adjusted numerator â€” Diluted									$36,092	$32,830	$28,916
Reconciliation of Denominator:
Weighted shares outstanding - Basic (in shares)									14,551,308	14,430,962	14,379,216
Effect of dilutive securities:
Share-based Compensation									53,636	37,866	35,249
8.25% Convertible debentures									0	74,618	92,796
Adjusted denominator â€” Diluted									14,604,944	14,543,446	14,507,261
Diluted Earnings Per Share (in usd per share)	$0.69	$0.22	$0.35	$1.21	$0.67	$0.27	$0.30	$1.03	$2.47	$2.26	$1.99

Earnings_Per_Share_Calculation1

Earnings Per Share - Calculations of Basic and Diluted Earnings Per Share (Phantoms) (Detail)	Dec. 31, 2013	Dec. 31, 2012
Calculation Of Numerator And Denominator In Earnings Per Share [Line Items]
Interest rate, Convertible debentures	8.25%	8.25%

Acquisitions_Additional_Inform

Acquisitions - Additional Information (Detail) (USD $)	3 Months Ended								12 Months Ended			0 Months Ended				6 Months Ended
Share data in Millions, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	31-May-13	Dec. 02, 2013	Jun. 07, 2013	Feb. 05, 2013	Jun. 30, 2015	Aug. 30, 2010	Jan. 30, 2015
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	customer	Dec. 02, 2013	Jun. 07, 2013	customer	Jun. 30, 2015	Aug. 30, 2010	mi
Cash paid for acquisition									$0	$20,201,000	$124,000
Regulatory Assets	87,103,000				69,020,000				87,103,000	69,020,000
Revenues	120,380,000	91,619,000	100,497,000	186,337,000	122,887,000	86,545,000	94,146,000	140,729,000	498,834,000	444,306,000	392,502,000
Net Income	10,097,000	3,180,000	5,134,000	17,681,000	9,683,000	3,879,000	4,356,000	14,869,000	36,092,000	32,787,000	28,863,000
Goodwill	4,952,000				4,354,000				4,952,000	4,354,000
Asset Impairment Charges									6,881,000	0	0
Eastern Shore Gas Company
Cash paid for acquisition												16,500,000
Purchase Price Adjustment		543,000
Business Acquisition, Cost of Acquired Entity, Transaction Costs, Sales Tax		-726,000
Number of residential and commercial customers receiving propane gas distribution service												11,000
Minimum number of customers to whom gas distribution systems and bulk delivery service provided												500
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment												12,600,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory												384,000
Business Combination, Acquired Receivables, Fair Value												2,500,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Financial Liabilities												-227,000
Revenues									24,300,000	9,800,000
Net Income									2,500,000	309,000
Fort Meade
Cash paid for acquisition													792,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment													92,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory													14,000
Regulatory Assets													14,000
Goodwill													714,000				714,000
Goodwill, Purchase Accounting Adjustments									564,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other													42,000
Public Utilities, Property, Plant and Equipment, Amount of Acquisition Adjustments	578,000								578,000
Austin Cox
Cash paid for acquisition														600,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment														105,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory														30,000
Goodwill														237,000
Asset Impairment Charges									412,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles														250,000
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life														5 years
Propane Acquisitions
Cash paid for acquisition															2,900,000
Number of residential and commercial customers receiving propane gas distribution service															3,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Property, Plant, and Equipment															1,600,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Inventory															231,000
Goodwill, Purchase Accounting Adjustments									271,000
Business Combination, Provisional Information, Initial Accounting Incomplete, Adjustment, Inventory									271,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Finite-Lived Intangibles															300,000
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life															12 years
Glades
Goodwill	724,000								724,000
BravePoint Group [Member]
Revenues									15,100,000	19,100,000	17,500,000
Net Income									-232,000	-155,000	454,000
Gatherco [Member]
Cash paid for acquisition																27,600,000
Business Combination Recognized Identifiable Assets Acquired And Liabilities To Be Assumed Long Term Debt																		1,700,000
Number Of Gathering Stations																		16
Number of Pipeline Miles																		2,000
Number of Producers Served																		300
Number of Customers Served																		6,000
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned																		$29,900,000
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares																0.6

Acquisitions_Dispositions_Addi

Acquisitions Dispositions - Additional Information (Details) (USD $)	3 Months Ended								12 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Revenues	$120,380,000	$91,619,000	$100,497,000	$186,337,000	$122,887,000	$86,545,000	$94,146,000	$140,729,000	$498,834,000	$444,306,000	$392,502,000
Net Income (Loss) Attributable to Parent	10,097,000	3,180,000	5,134,000	17,681,000	9,683,000	3,879,000	4,356,000	14,869,000	36,092,000	32,787,000	28,863,000
BravePoint Group [Member]
Income Statement, Balance Sheet and Additional Disclosures by Disposal Groups, Including Discontinued Operations [Line Items]
Proceeds from Divestiture of Businesses, Net of Cash Divested									12,000,000
Disposal Group, Not Discontinued Operation, Gain (Loss) on Disposal									6,700,000
DisposalGroupNotDiscontinuedOperationGainLossOnDisposalNetOfTax									4,000,000
Revenues									15,100,000	19,100,000	17,500,000
Net Income (Loss) Attributable to Parent									($232,000)	($155,000)	$454,000

Segment_Information_Schedule_o

Segment Information - Schedule of Segment Reporting Information by Segment (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Operating Revenues, Unaffiliated Customers
Total intersegment revenues	$120,380	$91,619	$100,497	$186,337	$122,887	$86,545	$94,146	$140,729	$498,834	$444,306	$392,502
Intersegment Revenues (1)
Total intersegment revenues	120,380	91,619	100,497	186,337	122,887	86,545	94,146	140,729	498,834	444,306	392,502
Operating Income
Operating Income	12,408	7,792	10,457	31,623	18,312	8,720	9,152	26,550	62,279	62,734	56,635
Gain (Loss) on Disposition of Business									7,139
Other income									101	372	271
Interest charges									9,482	8,234	8,747
Income Before Income taxes									60,037	54,872	48,159
Income taxes									23,945	22,085	19,296
Net Income	10,097	3,180	5,134	17,681	9,683	3,879	4,356	14,869	36,092	32,787	28,863
Depreciation and Amortization
Total depreciation and amortization									26,316	23,965	22,510
Capital Expenditures
Total capital expenditures									98,057	108,039	78,210
Identifiable Assets
Total identifiable assets	904,469				837,522				904,469	837,522
Regulated Energy
Operating Income
Operating Income									50,451	50,084	46,999
Depreciation and Amortization
Total depreciation and amortization									21,915	19,822	18,653
Capital Expenditures
Total capital expenditures									84,959	95,944	69,056
Identifiable Assets
Total identifiable assets	796,021				708,950				796,021	708,950
Unregulated Energy
Operating Income
Operating Income									11,723	12,353	8,355
Depreciation and Amortization
Total depreciation and amortization									3,994	3,686	3,420
Capital Expenditures
Total capital expenditures									9,648	4,829	3,969
Identifiable Assets
Total identifiable assets	84,732				100,585				84,732	100,585
Other
Operating Income
Operating Income									105	297	1,281
Capital Expenditures
Total capital expenditures									3,450	7,266	5,185
Identifiable Assets
Total identifiable assets	23,716				27,987				23,716	27,987
Other and eliminations
Depreciation and Amortization
Total depreciation and amortization									407	457	437
Operating Segments
Operating Revenues, Unaffiliated Customers
Total intersegment revenues									498,834	444,306	392,502
Intersegment Revenues (1)
Total intersegment revenues									498,834	444,306	392,502
Operating Segments \| Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues									299,345	263,573	245,042
Intersegment Revenues (1)
Total intersegment revenues									299,345	263,573	245,042
Operating Segments \| Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues									184,557	161,760	130,020
Intersegment Revenues (1)
Total intersegment revenues									184,557	161,760	130,020
Operating Segments \| Other
Operating Revenues, Unaffiliated Customers
Total intersegment revenues									14,932	18,973	17,440
Intersegment Revenues (1)
Total intersegment revenues									14,932	18,973	17,440
Intersegment Eliminations
Operating Revenues, Unaffiliated Customers
Total intersegment revenues									2,480	7,044	5,112
Intersegment Revenues (1)
Total intersegment revenues									2,480	7,044	5,112
Intersegment Eliminations \| Regulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues									1,097	1,064	1,166
Intersegment Revenues (1)
Total intersegment revenues									1,097	1,064	1,166
Intersegment Eliminations \| Unregulated Energy
Operating Revenues, Unaffiliated Customers
Total intersegment revenues									404	4,963	3,029
Intersegment Revenues (1)
Total intersegment revenues									404	4,963	3,029
Intersegment Eliminations \| Other
Operating Revenues, Unaffiliated Customers
Total intersegment revenues									979	1,017	917
Intersegment Revenues (1)
Total intersegment revenues									$979	$1,017	$917

Supplemental_Cash_Flow_Disclos2

Supplemental Cash Flow Disclosures - Cash Paid for Interest and Income Taxes (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Supplemental Cash Flow Disclosures Cash Paid For Interest And Income Taxes [Abstract]
Cash paid for interest	$8,870	$7,837	$8,086
Cash paid for income taxes	$17,833	$10,243	$3,809

Supplemental_Cash_Flow_Disclos3

Supplemental Cash Flow Disclosures - Non-Cash Investing and Financing Activities (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Supplemental Cash Flow Disclosures Noncash Investing And Financing Activities [Abstract]
Capital property and equipment acquired on account, but not paid as of December 31	$459	$341	$7,065
Retirement Savings Plan	602	0	0
Conversion of Debentures	535	295	186
Performance Incentive Plan	958	355	427
Director Stock Compensation Plan	575	495	443
Capital Lease Obligation	$6,130	$7,126	$0

Derivative_Instruments_Outstan

Derivative Instruments - Outstanding Trading Contracts (Detail) (Forward Contracts)	Dec. 31, 2014	Dec. 31, 2013
	gal	gal
Revenue
Derivative [Line Items]
Quantity in Gallons	4,200,000	1,892,000
Weighted Average Contract Prices	0.6714	1.2786
Purchase
Derivative [Line Items]
Quantity in Gallons	4,201,000	1,991,000
Weighted Average Contract Prices	0.6416	1.2444
Minimum \| Revenue
Derivative [Line Items]
Estimated Market Prices	0.54	0.99
Minimum \| Purchase
Derivative [Line Items]
Estimated Market Prices	0.47	0.9411
Maximum \| Revenue
Derivative [Line Items]
Estimated Market Prices	0.79	1.475
Maximum \| Purchase
Derivative [Line Items]
Estimated Market Prices	1.3176	1.46

Derivative_Instruments_Additio

Derivative Instruments - Additional Information (Detail) (USD $)	12 Months Ended	1 Months Ended
	Dec. 31, 2014	Jun. 30, 2013	31-May-13	31-May-12	Dec. 31, 2013	Jun. 30, 2014	Dec. 31, 2012
	Counterparty	Jun. 30, 2013	gal	gal	Counterparty	Jun. 30, 2014	Dec. 31, 2012
Derivative [Line Items]
Other Comprehensive Income Loss Adjustments AOCI Swap Agreements	($735,000)
Energy Marketing Contract Liabilities, Current	1,018,000				127,000
Number Of Counterparties With Master Repurchase Agreements	2				2
Accounts Receivable Subject To Master Netting Arrangement	1,600,000				2,800,000
Accounts Payable Subject To Master Netting Arrangement	1,200,000				3,200,000
Strike price of put option			0.975
Mark-to-market energy assets	1,055,000				385,000
Put Option
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	630,000
Payment to purchase call options	128,000
Amount paid to purchase put option		120,000
Put Option \| Minimum
Derivative [Line Items]
Strike price of put option						0.83
Put Option \| Maximum
Derivative [Line Items]
Strike price of put option						0.86
Call options
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	1,260,000	1,300,000	630,000
Purchase quantity for propane price cap				1,300,000
Payment to purchase call options	98,000		72,000	139,000
Fair value of call options							28,000
Derivative, Gain on Derivative	209,000
Call options \| Minimum
Derivative [Line Items]
Strike price of put option							0.905
Call options \| Maximum
Derivative [Line Items]
Strike price of put option							0.99
Propane Swap Agreement
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume	630,000
Mark To Market Energy Assets
Derivative [Line Items]
Mark-to-market energy assets					0
Mark To Market Energy Assets \| Forward Contracts
Derivative [Line Items]
Mark-to-market energy assets	407,000				196,000
Mark To Market Energy Assets \| CALL OPTION 2 [Member]
Derivative [Line Items]
Mark-to-market energy assets	0				169,000
Mark To Market Energy Assets \| Put Option
Derivative [Line Items]
Mark-to-market energy assets	622,000				20,000
Mark To Market Energy Assets \| Call options
Derivative [Line Items]
Mark-to-market energy assets	26,000
Mark-to-market energy liabilities \| Forward Contracts
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	283,000				127,000
Mark-to-market energy liabilities \| Propane Swap Agreement
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$735,000				$0
Put Option Strike Price 1 [Member] \| Put Option
Derivative [Line Items]
Strike price of put option	1.035
Put Option Strike Price 2 [Member] \| Put Option
Derivative [Line Items]
Strike price of put option	0.9975
Put Option Strike Price 3 [Member] \| Put Option
Derivative [Line Items]
Strike price of put option	0.9475
Strike Price 1 [Member] \| Call options
Derivative [Line Items]
Strike price of put option	1.0875
Strike Price 2 [Member] \| Call options
Derivative [Line Items]
Strike price of put option	1.065
Strike Price 1 [Member] \| Propane Swap Agreement
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements	1.135
Strike Price 2 [Member] \| Propane Swap Agreement
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements	1.0975
Strike Price 3 [Member] \| Propane Swap Agreement
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements	1.0475

Derivative_Instruments_Fair_Va

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Consolidated Balance Sheets (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$1,018	$127
Mark-to-market energy liabilities \| Forward Contracts
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	283	127
Mark-to-market energy liabilities \| Propane Swap Agreement
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$735	$0

Derivative_Instruments_Effects

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	$1,084	$1,313	$2,343
Call options
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain on Derivative	209
Revenue \| Derivatives not designated as hedging instruments \| Forward Contracts
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain on Derivative	1,423	1,127	2,695
Gain (Loss) on derivatives	57	217	-339
Cost of Sales \| Derivatives designated as fair value hedges \| Put/Call Option
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	235	-28	27
Cost of Sales \| Derivatives designated as fair value hedges \| Call options
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	-17	0	0
Cost of Sales \| Derivatives designated as fair value hedges \| Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	-341	0	0
Cost of Sales \| Derivatives not designated as hedging instruments \| Call options
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain on Derivative	0	97	0
Cost of Sales \| Derivatives not designated as hedging instruments \| Propane Swap Agreement
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain on Derivative		0	0
Derivative, Gain (Loss) on Derivative, Net	-735
Propane Inventory \| Derivatives designated as fair value hedges \| Put/Call Option
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	517	-100	-40
Other Comprehensive Income (Loss) [Member] \| Derivatives designated as fair value hedges \| Call options
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	($55)	$0	$0

Fair_Value_of_Financial_Instru2

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Assets:
Investments	$3,678,000	$3,098,000
Quoted Prices in Active Markets (Level 1) \| Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	0	0
Significant Other Observable Inputs (Level 2) \| Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	1,018,000	127,000
Significant Unobservable Inputs (Level 3) \| Mark-to-market energy liabilities
Assets:
Mark-to-market energy assets, including put option	0	0
Guaranteed Income Fund [Member] \| Quoted Prices in Active Markets (Level 1)
Assets:
Investments	0
Guaranteed Income Fund [Member] \| Significant Other Observable Inputs (Level 2)
Assets:
Investments	0
Guaranteed Income Fund [Member] \| Significant Unobservable Inputs (Level 3)
Assets:
Investments	287,000	458,000
Investments - other \| Quoted Prices in Active Markets (Level 1)
Assets:
Investments	3,391,000	2,640,000
Investments - other \| Significant Other Observable Inputs (Level 2)
Assets:
Investments	0
Investments - other \| Significant Unobservable Inputs (Level 3)
Assets:
Investments	0
Mark-to-market energy assets, including put option \| Quoted Prices in Active Markets (Level 1)
Assets:
Mark-to-market energy assets, including put option	0	0
Mark-to-market energy assets, including put option \| Significant Other Observable Inputs (Level 2)
Assets:
Mark-to-market energy assets, including put option	1,055,000	385,000
Fair Value \| Mark-to-market energy liabilities
Liabilities:
Mark-to-market energy liabilities	1,018,000	127,000
Fair Value \| Guaranteed Income Fund [Member]
Assets:
Investments	287,000	458,000
Fair Value \| Investments - other
Assets:
Investments	3,391,000	2,640,000
Fair Value \| Mark-to-market energy assets, including put option
Assets:
Mark-to-market energy assets, including put option	$1,055,000	$385,000

Fair_Value_of_Financial_Instru3

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Phantom) (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Investments	$3,678	$3,098

Fair_Value_of_Financial_Instru4

Fair Value of Financial Instruments - Additional Information (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Disclosure Fair Value Of Financial Instruments Additional Information [Abstract]
Investments, Fair Value Disclosure	$3,678,000	$3,098,000
Long-term debt including current maturities	161,500,000	122,000,000
Fair value of long-term debt	180,700,000	136,800,000
Guaranteed Income Fund [Member] \| Fair Value, Inputs, Level 3 [Member]
Disclosure Fair Value Of Financial Instruments Additional Information [Abstract]
Investments, Fair Value Disclosure	$287,000	$458,000

Fair_Value_of_Financial_Instru5

Fair Value of Financial Instruments Fair Value of Financial Instruments - Summary of Changes in Fair Value of Instruments (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$458	$0
Transfers in due to change in trustee	0	425
Purchases and adjustments	76	41
Transfers	-253	-16
Investment income	6	8
Ending Balance	$287	$458

Investments_Schedule_of_Invest

Investments - Schedule of Investment (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Investment [Line Items]
Investments, at fair value	$3,678	$3,098

Investments_Additional_Informa

Investments - Additional Information (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2011
Schedule of Trading Securities and Other Trading Assets [Line Items]
Unrealized gain, net of other expenses	$237	$489	$451
Investments in equity securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Trading Securities, Realized Gain		702
Trading Securities, Unrealized Holding Gain		$438	$135	$304

Goodwill_and_Other_Intangible_2

Goodwill and Other Intangible Assets - Schedule of Carrying Value of Goodwill (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
Goodwill [Line Items]
Goodwill	$4,952,000	$4,354,000
Regulated Energy
Goodwill [Line Items]
Goodwill	3,354,000	2,790,000
Unregulated Energy
Goodwill [Line Items]
Goodwill	$1,598,000	$1,564,000

Goodwill_and_Other_Intangible_3

Goodwill and Other Intangible Assets - Additional Information (Detail) (USD $)	12 Months Ended			3 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Mar. 31, 2014	Oct. 31, 2009	Aug. 30, 2010	Dec. 02, 2013	Jun. 07, 2013
Goodwill [Line Items]
Goodwill	$4,952,000	$4,354,000
Amortization of intangible assets	396,000	373,000	329,000
Amortization of intangible assets, 2014	350,000
Amortization of intangible assets, 2015	325,000
Amortization of intangible assets, 2016	323,000
Amortization of intangible assets, 2017	323,000
Amortization of intangible assets, 2018	323,000
Regulated Energy
Goodwill [Line Items]
Goodwill	3,354,000	2,790,000
Unregulated Energy
Goodwill [Line Items]
Goodwill	1,598,000	1,564,000
Goodwill, Impairment Loss				237,000
FPU \| Regulated Energy
Goodwill [Line Items]
Goodwill					2,500,000
Indiantown Gas Company \| Regulated Energy
Goodwill [Line Items]
Goodwill	746,000					170,000
Regulatory assets	576,000
Fort Meade
Goodwill [Line Items]
Goodwill						714,000	714,000
Crescent Propane Inc \| Unregulated Energy
Goodwill [Line Items]
Goodwill			200,000
Sharp Energy Inc \| Unregulated Energy
Goodwill [Line Items]
Goodwill	674,000
Glades
Goodwill [Line Items]
Goodwill	724,000
Glades \| Unregulated Energy
Goodwill [Line Items]
Goodwill	724,000
Austin Cox
Goodwill [Line Items]
Goodwill								237,000
Virginia LP Gas, Inc. \| Maximum
Goodwill [Line Items]
Amortized period of acquired intangible assets	40 years
Customer list \| Minimum
Goodwill [Line Items]
Amortized period of acquired intangible assets	7 years
Customer list \| Maximum
Goodwill [Line Items]
Amortized period of acquired intangible assets	12 years
Non-Compete Agreements
Goodwill [Line Items]
Amortized period of acquired intangible assets	7 years
Impairment of Intangible Assets (Excluding Goodwill)	$175,000

Goodwill_and_Other_Intangible_4

Goodwill and Other Intangible Assets - Schedule of Carrying Value and Accumulated Amortization of Intangible Assets (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$4,366	$4,616
Accumulated Amortization	1,962	1,641
Customer list
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	3,993	3,993
Accumulated Amortization	1,719	1,389
Non-Compete Agreements
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	103	353
Accumulated Amortization	72	87
Other
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	270	270
Accumulated Amortization	$171	$165

Income_Taxes_Additional_Inform

Income Taxes - Additional Information (Detail) (USD $)	12 Months Ended
Income Taxes - Additional Information (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Income Taxes Additional Information [Abstract]
Total liability associated with unrecognized tax benefit	$100,000	$300,000
State net operating losses for state income tax	29,100,000
Deferred tax asset related to net operating loss carry-forwards	1,186,000	1,444,000
Deferred state income taxes	$2,600,000	$2,100,000	$1,900,000

Income_Taxes_Schedule_of_Incom

Income Taxes - Schedule of Income Tax Expense (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Current Income Tax Expense
Federal	$434	$4,882	$3,483
State	1,311	2,382	1,990
Investment tax credit adjustments, net	-35	-39	-58
Total current income tax expense	1,710	7,225	5,415
Deferred Income Tax Expense (1)
Total deferred income tax expense	22,235	14,860	13,881
Total Income Tax Expense	23,945	22,085	19,296
Property, plant and equipment
Deferred Income Tax Expense (1)
Total deferred income tax expense	20,382	16,758	13,688
Deferred gas costs
Deferred Income Tax Expense (1)
Total deferred income tax expense	1,614	-209	515
Pensions and other employee benefits
Deferred Income Tax Expense (1)
Total deferred income tax expense	537	-335	553
FPU merger related premium cost and deferred gain
Deferred Income Tax Expense (1)
Total deferred income tax expense	-802	-686	-509
Net operating loss carryforwards
Deferred Income Tax Expense (1)
Total deferred income tax expense	-112	62	740
Other
Deferred Income Tax Expense (1)
Total deferred income tax expense	$616	($730)	($1,106)

Income_Taxes_Summary_of_Reconc

Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Reconciliation of Effective Income Tax Rates Continuing Operations
Federal income tax expense (2)	$21,121	$19,205	$16,745
State income taxes, net of federal benefit	2,946	3,105	2,571
ESOP dividend deduction	-267	-256	-235
Other	145	31	215
Total Income Tax Expense	$23,945	$22,085	$19,296
Effective Income Tax Rate	39.88%	40.25%	40.07%

Income_Taxes_Schedule_of_Accum

Income Taxes - Schedule of Accumulated Deferred Income Tax Assets and Liabilities (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Deferred income tax liabilities:
Property, plant and equipment	$152,877	$134,414
Acquisition adjustment	16,140	16,790
Loss on reacquired debt	529	573
Deferred gas costs	2,222	607
Other	4,507	2,850
Total deferred income tax liabilities	176,275	155,234
Deferred income tax assets:
Pension and other employee benefits	6,532	5,390
Environmental costs	2,313	2,083
Net operating loss carryforwards	1,186	1,444
Self insurance	275	403
Storm reserve liability	1,150	1,109
Other	3,755	3,904
Total deferred income tax assets	15,211	14,333
Deferred Income Taxes Per Consolidated Balance Sheets	$161,064	$140,901

Income_Taxes_Schedule_of_Incom1

Income Taxes - Schedule of Income Tax Expense (Phantoms) (Detail) (USD $)	12 Months Ended
In Millions, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Income Taxes Schedule Of Income Tax Expense [Abstract]
Deferred state income taxes	$2.60	$2.10	$1.90

Income_Taxes_Summary_of_Reconc1

Income Taxes - Summary of Reconciliation of Statutory Federal Tax and Effective Income Tax Rates (Phantoms) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Income Taxes Summary Of Reconciliation Of Statutory Federal Tax And Effective Income Tax Rates [Abstract]
Federal income taxes rate recorded	35.00%	35.00%	35.00%

LongTerm_Debt_Outstanding_Long

Long-Term Debt - Outstanding Long-Term Debt (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument [Line Items]
Long-term Debt	$161,500	$122,000
Capital lease obligation	6,130	6,978
Long-term Debt and Capital Lease Obligations	167,595	128,945
Less: current maturities	-9,109	-11,353
Total long-term debt, net of current maturities	158,486	117,592
9.08% bond, due June 1, 2022
Debt Instrument [Line Items]
Long-term Debt	7,969	7,967
7.83% note, due January 1, 2015
Debt Instrument [Line Items]
Long-term Debt	0	2,000
6.64% note, due October 31, 2017
Debt Instrument [Line Items]
Long-term Debt	8,182	10,909
5.50% note, due October 12, 2020
Debt Instrument [Line Items]
Long-term Debt	12,000	14,000
5.93% note, due October 31, 2023
Debt Instrument [Line Items]
Long-term Debt	27,000	30,000
5.68% note, due June 30, 2026
Debt Instrument [Line Items]
Long-term Debt	29,000	29,000
6.43% note, due May 2, 2028
Debt Instrument [Line Items]
Long-term Debt	7,000	7,000
3.73% note, due December 16, 2028
Debt Instrument [Line Items]
Long-term Debt	20,000	20,000
3.88% note, due May 15, 2029
Debt Instrument [Line Items]
Long-term Debt	50,000	0
8.25% due March 1, 2014
Debt Instrument [Line Items]
Long-term Debt	0	646
Promissory note
Debt Instrument [Line Items]
Long-term Debt	$314	$445

LongTerm_Debt_Outstanding_Long1

Long-Term Debt - Outstanding Long-Term Debt (Phantoms) (Detail)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
9.08% bond, due June 1, 2022
Debt Instrument [Line Items]
Long-term debt, interest percentage	9.08%
Debt Instrument, Maturity Date	1-Jun-22
7.83% note, due January 1, 2015
Debt Instrument [Line Items]
Long-term debt, interest percentage	7.83%
Debt Instrument, Maturity Date	1-Jan-15
6.64% note, due October 31, 2017
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.64%
Debt Instrument, Maturity Date	31-Oct-17
5.50% note, due October 12, 2020
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.50%
Debt Instrument, Maturity Date	12-Oct-20
5.93% note, due October 31, 2023
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.93%
Debt Instrument, Maturity Date	31-Oct-23
5.68% note, due June 30, 2026
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.68%
Debt Instrument, Maturity Date	30-Jun-26
8.25% due March 1, 2014
Debt Instrument [Line Items]
Long-term debt, interest percentage	8.25%
Debt Instrument, Maturity Date	1-Mar-14
6.43% note, due May 2, 2028
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.43%
Debt Instrument, Maturity Date	2-May-28
3.73% note, due December 16, 2028
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.73%	3.73%
Debt Instrument, Maturity Date	16-Dec-28
3.88% note, due May 15, 2029
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.88%
Debt Instrument, Maturity Date	15-May-29

LongTerm_Debt_Additional_Infor

Long-Term Debt - Additional Information (Detail) (USD $)	12 Months Ended	2 Months Ended
Long-Term Debt - Additional Information (Detail) (USD $)	Dec. 31, 2014	Feb. 28, 2014	Dec. 31, 2013	Jun. 30, 2011	Jun. 30, 2010	Sep. 05, 2013
Debt Instrument [Line Items]
Long-term debt maturities repayment of principal in next twelve months	$9,109,000
Long-term debt maturities repayment of principal in year two	9,151,000
Long-term debt maturities repayment of principal in year three	12,099,000
Long-term debt maturities repayment of principal in year four	9,421,000
Long-term debt maturities repayment of principal in year five	11,245,000
Long-term debt maturities repayment of principal in year five thereafter	116,600,000
Long Term Debt Commitment					36,000,000
Long-term Debt	161,500,000		122,000,000
Debt Instrument, Number of Series				2
Long-term Debt and Capital Lease Obligations	167,595,000		128,945,000
Percentage of equity of total capitalization	40.00%
Fixed charge coverage ratio	1.2
Debt Instrument, Restrictive Covenants, Required Net Book Value of Regulated Business Assets Percentage of Consolidated Total Assets	50.00%
Maximum limit on payment of dividends	10
Cumulative consolidated net income base	243,800,000
Cumulative net income with restrictions	80,900,000
Cumulative net income free of restrictions	162,900,000
Restricted net assets of consolidated subsidiaries	49,400,000
Percentage of restricted net assets	16.00%
Uncollateralized Senior Note Due On Two Thousand Twenty Six [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.68%
Long-term Debt	29,000,000		29,000,000
Debt Instrument, Maturity Date	30-Jun-26
First Mortgage Bond Due On Two Thousand Twenty Two [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	9.08%
Long-term Debt	7,969,000		7,967,000
Debt Instrument, Maturity Date	1-Jun-22
Maximum limit on payment of dividends	2500000
Cumulative consolidated net income base	104,100,000
Cumulative net income with restrictions	37,600,000
Cumulative net income free of restrictions	66,500,000
Aggregate Unsecured Senior Notes [Member]
Debt Instrument [Line Items]
Long Term Debt Commitment						70,000,000
Uncollateralized Senior Notes Due On May Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.43%
Long-term Debt	7,000,000		7,000,000
Debt Instrument, Maturity Date	2-May-28
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.73%		3.73%
Long-term Debt	20,000,000		20,000,000
Debt Instrument, Maturity Date	16-Dec-28
Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.88%
Long-term Debt	50,000,000		0
Debt Instrument, Maturity Date	15-May-29
Convertible Debt Securities [Member]
Debt Instrument [Line Items]
Conversion price of debt instrument	$17.01
Carrying amount of convertible debt instrument	296,000
Total debentures redeemed for cash		109,000
Debt Conversion, Converted Instrument, Amount		$537,000

ShortTerm_Borrowing_Additional

Short-Term Borrowing - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013
Short-term Debt [Line Items]
Number Of Financial Institutions With Bank Credit Facilities	3
Letters of Credit Outstanding, Amount	$4,400,000
Short-term Debt, Weighted Average Interest Rate	1.15%	1.26%
Line of Credit Facility, Commitment Fee Amount	87,000	56,000
Short-term borrowings	88,231,000	105,666,000
Line of Credit Facility, Maximum Borrowing Capacity	210,000,000
Ratio of Indebtedness to Net Capital	0.65
Fixed Charge Coverage Ratio Minimum	1.2
Fixed Charge Coverage Ratio Maximum	1
Number Of Unsecured Bank Credit Facilities	6
Committed Line of Credit Facility Two [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	Base rate plus 1.25 percent
Line of Credit Facility, Maximum Borrowing Capacity	30,000,000
Committed Line of Credit Facility Three [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	LIBOR rate, plus 0.85 percent
Line of Credit Facility, Maximum Borrowing Capacity	35,000,000
Short-term Revolving Line of Credit Facility [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	Lender's base rate plus 80 basis points
Line of Credit Facility, Maximum Borrowing Capacity	50,000,000
Line of Credit Facility, Increase (Decrease), Net	10,000,000
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	200,000,000
Committed Line of Credit Facility One [Member]
Short-term Debt [Line Items]
Debt Instrument, Description of Variable Rate Basis	LIBOR rate, plus 1.25 percent
Line of Credit Facility, Maximum Borrowing Capacity	$55,000,000
Base Rate [Member] \| Committed Line of Credit Facility Two [Member]
Short-term Debt [Line Items]
Debt Instrument, Basis Spread on Variable Rate	125.00%
Base Rate [Member] \| Short-term Revolving Line of Credit Facility [Member]
Short-term Debt [Line Items]
Debt Instrument, Basis Spread on Variable Rate	80.00%

ShortTerm_Borrowing_ShortTerm_1

Short-Term Borrowing Short-Term Borrowing - Schedule of Short-Term Debt (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	$210,000
Long-term Line of Credit	86,040	102,554
Short-term borrowing	88,231	105,666
Line of Credit Facility, Remaining Borrowing Capacity	123,960
Bank Overdrafts	2,191	3,112
Committed Line of Credit Facility One [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	55,000
Line of Credit Facility, Expiration Date	26-Jun-15
Long-term Line of Credit	20,000	35,000
Line of Credit Facility, Remaining Borrowing Capacity	35,000
Committed Line of Credit Facility Two [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	30,000
Line of Credit Facility, Expiration Date	31-Oct-15
Long-term Line of Credit	16,040	17,554
Line of Credit Facility, Remaining Borrowing Capacity	13,960
Committed Line of Credit Facility Three [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	35,000
Line of Credit Facility, Expiration Date	22-Dec-15
Long-term Line of Credit	0	0
Line of Credit Facility, Remaining Borrowing Capacity	35,000
Short-term Revolving Line of Credit Facility [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	50,000
Line of Credit Facility, Expiration Date	31-Oct-15
Long-term Line of Credit	50,000	40,000
Line of Credit Facility, Remaining Borrowing Capacity	0
Uncommitted Line Of Credit Facility One [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	20,000
Line of Credit Facility, Expiration Date	26-Jun-15
Long-term Line of Credit	0	0
Line of Credit Facility, Remaining Borrowing Capacity	20,000
Uncommitted Line Of Credit Facility Two [Member]
Short-term Debt [Line Items]
Line of Credit Facility, Maximum Borrowing Capacity	20,000
Line of Credit Facility, Expiration Date	31-Oct-15
Long-term Line of Credit	0	10,000
Line of Credit Facility, Remaining Borrowing Capacity	$20,000

Lease_Obligations_Additional_I

Lease Obligations - Additional Information (Detail) (USD $)	12 Months Ended
Lease Obligations - Additional Information (Detail) (USD $)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Lease Obligations Additional Information [Abstract]
Rent expense related to operating leases	$1,800,000	$1,600,000	$1,400,000
Operating Leases, Future Minimum Payments Due, Next Twelve Months	1,100,000
Operating Leases, Future Minimum Payments, Due in Two Years	942,000
Operating Leases, Future Minimum Payments, Due in Three Years	338,000
Operating Leases, Future Minimum Payments, Due in Four Years	293,000
Operating Leases, Future Minimum Payments, Due in Five Years	228,000
Future minimum payments under current lease agreements, thereafter	2,300,000
Future minimum payments under current lease agreements, total	5,200,000
Payments to Acquire Capital Leases	1,100,000
Capital Leases, Future Minimum Payments Due, Next Twelve Months	1,500,000
Capital Leases, Future Minimum Payments Due in Five Years	625,000
Capital Leases, Future Minimum Payments Due	$6,600,000

Lease_Obligations_Lease_Obliga

Lease Obligations Lease Obligations - Additional Details (Phantom) (Details) (USD $)	Dec. 31, 2014
Leases [Abstract]
Capital Leases, Future Minimum Payments Due in Two Years	$1,500,000
Capital Leases, Future Minimum Payments Due in Three Years	1,500,000
Capital Leases, Future Minimum Payments, Receivable in Four Years	$1,500,000

Accumulated_Other_Comprehensiv2

Accumulated Other Comprehensive Income (Loss) Accumulated Other comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Details) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	($2,533)	($5,062)
Other Comprehensive Income (Loss), before Reclassifications, before Tax	-3,724	2,251
Amounts reclassified from accumulated other comprehensive loss	581	278
Net current-period other comprehensive loss	-3,143	2,529
Accumulated other comprehensive loss at end of period	-5,676	-2,533
UnrealizedGainsLossesFromDefinedBenefitPensionAndPostretirementPlanItems [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	-2,533	-5,062
Other Comprehensive Income (Loss), before Reclassifications, before Tax	-3,242	2,251
Amounts reclassified from accumulated other comprehensive loss	132	278
Net current-period other comprehensive loss	-3,110	2,529
Accumulated other comprehensive loss at end of period	-5,643	-2,533
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Accumulated other comprehensive loss at beginning of period	0	0
Other Comprehensive Income (Loss), before Reclassifications, before Tax	-482	0
Amounts reclassified from accumulated other comprehensive loss	449	0
Net current-period other comprehensive loss	-33	0
Accumulated other comprehensive loss at end of period	($33)	$0

Accumulated_Other_Comprehensiv3

Accumulated Other Comprehensive Income (Loss) Accumulated Other Comprehensive Income (loss) - Reclassifications of Accumulated Other Comprehensive Loss (Details) (USD $)	12 Months Ended
	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Amortization of defined benefit pension and postretirement plan items:
Income tax benefit	($23,945,000)		($22,085,000)		($19,296,000)
Other Comprehensive Income Loss Adjustments AOCI Swap Agreements	-735,000
Reclassification out of Accumulated Other Comprehensive Income [Member]
Amortization of defined benefit pension and postretirement plan items:
Net of tax	-581,000		-278,000
Reclassification out of Accumulated Other Comprehensive Income [Member] \| Accumulated Defined Benefit Plans Adjustment [Member]
Amortization of defined benefit pension and postretirement plan items:
Prior service cost	58,000	[1]	60,000	[1]
Net gain	-279,000	[1]	-523,000	[1]
Total before income taxes	-221,000		-463,000
Income tax benefit	89,000		185,000
Net of tax	-132,000		-278,000
Reclassification out of Accumulated Other Comprehensive Income [Member] \| Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of defined benefit pension and postretirement plan items:
Total before income taxes	-752,000		0
Income tax benefit	303,000		0
Net of tax	-449,000		0
Other Comprehensive Income Loss Adjustments AOCI Swap Agreements	-735,000	[2]	0	[2]
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	($17,000)	[2]	$0	[2]

[1]	These amounts are included in the computation of net periodic benefits. See Note 16, Employee Benefit Plans, for additional details.
[2]	These amounts are included in the effects of gains and losses from derivative instruments. See Note 7, Derivative Instruments, for additional details.

Employee_Benefit_Plans_Schedul

Employee Benefit Plans - Schedule of Amounts Not Yet Reflected in Net Periodic Benefit Cost and Included in Accumulated Other Comprehensive Income Loss or Regulatory Assets (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	($823)
Net loss	26,296
Total	25,473
Accumulated other comprehensive loss pre-tax	9,344
Post-merger regulatory asset	16,129
Subtotal	25,473
Pre-merger regulatory asset	3,633
Total unrecognized cost	29,106
Chesapeake Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	0
Net loss	4,410
Total	4,410
Accumulated other comprehensive loss pre-tax	4,410
Post-merger regulatory asset	0
Subtotal	4,410
Pre-merger regulatory asset	0
Total unrecognized cost	4,410
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	0
Net loss	19,679
Total	19,679
Accumulated other comprehensive loss pre-tax	3,739
Post-merger regulatory asset	15,940
Subtotal	19,679
Pre-merger regulatory asset	3,587	4,300
Total unrecognized cost	23,266
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	9
Net loss	1,050
Total	1,059
Accumulated other comprehensive loss pre-tax	1,059
Post-merger regulatory asset	0
Subtotal	1,059
Pre-merger regulatory asset	0
Total unrecognized cost	1,059
Chesapeake Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	-832
Net loss	924
Total	92
Accumulated other comprehensive loss pre-tax	92
Post-merger regulatory asset	0
Subtotal	92
Pre-merger regulatory asset	0
Total unrecognized cost	92
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	0
Net loss	233
Total	233
Accumulated other comprehensive loss pre-tax	44
Post-merger regulatory asset	189
Subtotal	233
Pre-merger regulatory asset	46	54
Total unrecognized cost	$279

Employee_Benefit_Plans_Schedul1

Employee Benefit Plans - Schedule of Amounts Not Yet Reflected in Net Periodic Benefit Cost and Included in Accumulated Other Comprehensive Income Loss or Regulatory Assets (Phantoms) (Detail) (USD $)	Dec. 31, 2014
In Millions, unless otherwise specified	Dec. 31, 2014
Disclosure Employee Benefit Plans Schedule Of Amounts Not Yet Reflected In Net Periodic Benefit Cost And Included In Accumulated Other Comprehensive Income Loss Or Regulatory Assets [Abstract]
Income tax benefits	$3.70

Employee_Benefit_Plans_Additio

Employee Benefit Plans - Additional Information (Detail) (USD $)	1 Months Ended	12 Months Ended
	Jan. 31, 2011	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	Jan. 31, 2011	plan	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Number of Plans		3
Income tax benefits		$3,700,000
Pre-merger regulatory asset		3,633,000
Total unrecognized cost		29,106,000
Escrow deposit percent	125.00%
Expected Amortization Of Pre Merger Regulatory Asset		0
One-percentage point increase in health care inflation rate, accumulated postretirement benefit obligation		380,000
One-percentage point increase in health care inflation rate, service cost and interest cost components		14,000
One-percentage point decrease in health care inflation rate, accumulated postretirement benefit obligation		302,000
One-percentage point decrease in health care inflation rate, service cost and interest cost components		11,000
Percentage of eligible participants contribution to the plan		100.00%
Maximum percentage of eligible compensation		6.00%
Employer matching contribution vested, percentage		100.00%
Employer matching contribution vested, period		2 years
Employee contribution age		55 years
Deferral rate		3.00%
Deferral rate increase, minimum		1.00%
Deferral rate increase, maximum		6.00%
Assets Held-in-trust		3,700,000	3,100,000
Employer contributions to pension plan		4,100,000	3,700,000	2,900,000
Shares reserved to fund future contributions		855,975
Deferred Compensation Plan		1,300,000	1,100,000
Minimum
Defined Benefit Plan Disclosure [Line Items]
Employer matching contribution vested, percentage		20.00%
Employer matching contribution vested, period		1 year
Maximum
Defined Benefit Plan Disclosure [Line Items]
Employer matching contribution vested, percentage		100.00%
Employer matching contribution vested, period		2 years
Chesapeake Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Pre-merger regulatory asset		0
Total unrecognized cost		4,410,000
Unfunded accumulated benefit obligation		-2,903,000	-1,525,000
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year		475,000
Expected contribution		642,000
Chesapeake Pension Plan \| Maximum
Defined Benefit Plan Disclosure [Line Items]
Maximum percent of benefit obligation required	110.00%
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Pre-merger regulatory asset		0
Total unrecognized cost		1,059,000
Unfunded accumulated benefit obligation		-2,650,000	-2,210,000
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year		151,000
Expected contribution		151,000
Medical
Defined Benefit Plan Disclosure [Line Items]
Health care inflation rate		5.00%
Chesapeake Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Pre-merger regulatory asset		0
Total unrecognized cost		92,000
Unfunded accumulated benefit obligation		-1,238,000	-1,262,000
Expected Amortization Of Pre Merger Regulatory Asset			0	0
Health care inflation rate		6.00%
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year		79,000
Expected contribution		79,000
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Pre-merger regulatory asset		46,000	54,000
Total unrecognized cost		279,000
Curtailment gain		892,000
Unfunded accumulated benefit obligation		-1,712,000	-1,519,000
Health care inflation rate		5.50%
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year		207,000
Expected contribution		207,000
FPU Medical Plan \| Unregulated operations
Defined Benefit Plan Disclosure [Line Items]
Curtailment gain, unregulated operations		170,000
FPU Medical Plan \| Regulated liability
Defined Benefit Plan Disclosure [Line Items]
Curtailment gain, regulatory liability		722,000
Amortization of Curtailment Gain Regulatory Liability		212,000	510,000
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Pre-merger regulatory asset		3,587,000	4,300,000
Total unrecognized cost		23,266,000
Unfunded accumulated benefit obligation		-23,096,000	-11,539,000
Defined Benefit Plans, Estimated Future Employer Contributions in Next Fiscal Year		1,600,000
Expected contribution		$2,957,000

Employee_Benefit_Plans_Amounts

Employee Benefit Plans - Amounts in Accumulated Other Comprehensive Income/Loss and Regulatory Asset (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Defined Benefit Plan Disclosure [Line Items]
Accumulated Other Comprehensive Income Loss Tax Effect	$3,700,000
Prior service cost (credit)	-68,000
Net loss	993,000
Amortization of pre-merger regulatory asset	769,000
Chesapeake Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	0
Net loss	364,000
Amortization of pre-merger regulatory asset	0	0	0
FPU Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	0
Net loss	454,000
Amortization of pre-merger regulatory asset	761,000	761,000	761,000
Chesapeake SERP
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	9,000
Net loss	99,000
Amortization of pre-merger regulatory asset	0
Chesapeake Postretirement Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	-77,000
Net loss	70,000
Amortization of pre-merger regulatory asset	0
FPU Medical Plan
Defined Benefit Plan Disclosure [Line Items]
Prior service cost (credit)	0
Net loss	6,000
Amortization of pre-merger regulatory asset	$8,000	$8,000	$8,000

Employee_Benefit_Plans_Schedul2

Employee Benefit Plans - Schedule of Assets by Investment Type (Detail)	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Chesapeake Pension Plan
Asset Category
Percentage of assets by investment type	100.00%	100.00%	100.00%
Chesapeake Pension Plan \| Investments in equity securities
Asset Category
Percentage of assets by investment type	51.42%	54.40%	52.07%
Chesapeake Pension Plan \| Debt securities
Asset Category
Percentage of assets by investment type	37.31%	36.54%	38.00%
Chesapeake Pension Plan \| Other
Asset Category
Percentage of assets by investment type	11.27%	9.06%	9.93%
FPU Pension Plan
Asset Category
Percentage of assets by investment type	100.00%	100.00%	100.00%
FPU Pension Plan \| Investments in equity securities
Asset Category
Percentage of assets by investment type	52.62%	55.02%	52.81%
FPU Pension Plan \| Debt securities
Asset Category
Percentage of assets by investment type	37.69%	36.54%	38.04%
FPU Pension Plan \| Other
Asset Category
Percentage of assets by investment type	9.69%	8.44%	9.15%

Employee_Benefit_Plans_Schedul3

Employee Benefit Plans - Schedule of Asset Allocation Strategy (Detail)	12 Months Ended
	Dec. 31, 2014
Domestic Equities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Asset Allocation Strategy, Minimum Allocation Percentage	14.00%
Asset Allocation Strategy, Maximum Allocation Percentage	32.00%
Foreign Equities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Asset Allocation Strategy, Minimum Allocation Percentage	13.00%
Asset Allocation Strategy, Maximum Allocation Percentage	25.00%
Fixed Income
Schedule of Trading Securities and Other Trading Assets [Line Items]
Asset Allocation Strategy, Minimum Allocation Percentage	26.00%
Asset Allocation Strategy, Maximum Allocation Percentage	40.00%
Alternative Strategies
Schedule of Trading Securities and Other Trading Assets [Line Items]
Asset Allocation Strategy, Minimum Allocation Percentage	6.00%
Asset Allocation Strategy, Maximum Allocation Percentage	14.00%
Diversifying Assets
Schedule of Trading Securities and Other Trading Assets [Line Items]
Asset Allocation Strategy, Minimum Allocation Percentage	7.00%
Asset Allocation Strategy, Maximum Allocation Percentage	19.00%
Cash
Schedule of Trading Securities and Other Trading Assets [Line Items]
Asset Allocation Strategy, Minimum Allocation Percentage	0.00%
Asset Allocation Strategy, Maximum Allocation Percentage	5.00%

Employee_Benefit_Plans_Summary

Employee Benefit Plans - Summary of Pension Plan Assets (Detail) (USD $)	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	$54,155		$53,080
Investments in equity securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	28,390		29,152
Investments in equity securities \| Us Large Cap Equity Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	8,097	[1]	8,082	[1]
Investments in equity securities \| Us Mid Cap Equity Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	3,447	[1]	3,412	[1]
Investments in equity securities \| United States Equity Small Cap
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	1,694	[1]	1,736	[1]
Investments in equity securities \| International All Cap Equity
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	9,621	[2]	10,687	[2]
Investments in equity securities \| Alternative Strategies
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	5,531	[3]	5,235	[3]
Debt securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	20,375		19,396
Debt securities \| Us Treasury Inflation Protected Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets			2,462
Debt securities \| Fixed Income
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	17,717	[4]	14,305	[4]
Debt securities \| High Yield Asset Backed Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	2,658	[4]	2,629	[4]
Other
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	5,390		4,532
Other \| Commodities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	1,819	[5]	1,939	[5]
Other \| Real Estate
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	2,427	[6]	1,991	[6]
Other \| Guaranteed deposit
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	1,144	[7]	602	[7]
Quoted Prices in Active Markets (Level 1)
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	46,448		26,278
Quoted Prices in Active Markets (Level 1) \| Investments in equity securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	21,827		19,886
Quoted Prices in Active Markets (Level 1) \| Investments in equity securities \| Us Large Cap Equity Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	4,069	[1]	3,964	[1]
Quoted Prices in Active Markets (Level 1) \| Investments in equity securities \| Us Mid Cap Equity Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	1,733	[1]	0	[1]
Quoted Prices in Active Markets (Level 1) \| Investments in equity securities \| United States Equity Small Cap
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	873	[1]	0	[1]
Quoted Prices in Active Markets (Level 1) \| Investments in equity securities \| International All Cap Equity
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	9,621	[2]	10,687	[2]
Quoted Prices in Active Markets (Level 1) \| Investments in equity securities \| Alternative Strategies
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	5,531	[3]	5,235	[3]
Quoted Prices in Active Markets (Level 1) \| Debt securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	20,375		2,462
Quoted Prices in Active Markets (Level 1) \| Debt securities \| Us Treasury Inflation Protected Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets			2,462
Quoted Prices in Active Markets (Level 1) \| Debt securities \| Fixed Income
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	17,717	[4]	0	[4]
Quoted Prices in Active Markets (Level 1) \| Debt securities \| High Yield Asset Backed Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	2,658	[4]	0	[4]
Quoted Prices in Active Markets (Level 1) \| Other
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	4,246		3,930
Quoted Prices in Active Markets (Level 1) \| Other \| Commodities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	1,819	[5]	1,939	[5]
Quoted Prices in Active Markets (Level 1) \| Other \| Real Estate
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	2,427	[6]	1,991	[6]
Quoted Prices in Active Markets (Level 1) \| Other \| Guaranteed deposit
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[7]	0	[7]
Significant Other Observable Inputs (Level 2)
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	6,563		26,200
Significant Other Observable Inputs (Level 2) \| Investments in equity securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	6,563		9,266
Significant Other Observable Inputs (Level 2) \| Investments in equity securities \| Us Large Cap Equity Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	4,028	[1]	4,118	[1]
Significant Other Observable Inputs (Level 2) \| Investments in equity securities \| Us Mid Cap Equity Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	1,714	[1]	3,412	[1]
Significant Other Observable Inputs (Level 2) \| Investments in equity securities \| United States Equity Small Cap
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	821	[1]	1,736	[1]
Significant Other Observable Inputs (Level 2) \| Investments in equity securities \| International All Cap Equity
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[2]	0	[2]
Significant Other Observable Inputs (Level 2) \| Investments in equity securities \| Alternative Strategies
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[3]	0	[3]
Significant Other Observable Inputs (Level 2) \| Debt securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0		16,934
Significant Other Observable Inputs (Level 2) \| Debt securities \| Us Treasury Inflation Protected Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets			0
Significant Other Observable Inputs (Level 2) \| Debt securities \| Fixed Income
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[4]	14,305	[4]
Significant Other Observable Inputs (Level 2) \| Debt securities \| High Yield Asset Backed Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[4]	2,629	[4]
Significant Other Observable Inputs (Level 2) \| Other
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0		0
Significant Other Observable Inputs (Level 2) \| Other \| Commodities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[5]	0	[5]
Significant Other Observable Inputs (Level 2) \| Other \| Real Estate
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[6]	0	[6]
Significant Other Observable Inputs (Level 2) \| Other \| Guaranteed deposit
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[7]	0	[7]
Significant Unobservable Inputs (Level 3)
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	1,144		602		710
Significant Unobservable Inputs (Level 3) \| Investments in equity securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0		0
Significant Unobservable Inputs (Level 3) \| Investments in equity securities \| Us Large Cap Equity Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[1]	0	[1]
Significant Unobservable Inputs (Level 3) \| Investments in equity securities \| Us Mid Cap Equity Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[1]	0	[1]
Significant Unobservable Inputs (Level 3) \| Investments in equity securities \| United States Equity Small Cap
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[1]	0	[1]
Significant Unobservable Inputs (Level 3) \| Investments in equity securities \| International All Cap Equity
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[2]	0	[2]
Significant Unobservable Inputs (Level 3) \| Investments in equity securities \| Alternative Strategies
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[3]	0	[3]
Significant Unobservable Inputs (Level 3) \| Debt securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0		0
Significant Unobservable Inputs (Level 3) \| Debt securities \| Us Treasury Inflation Protected Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets			0
Significant Unobservable Inputs (Level 3) \| Debt securities \| Fixed Income
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[4]	0	[4]
Significant Unobservable Inputs (Level 3) \| Debt securities \| High Yield Asset Backed Securities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[4]	0	[4]
Significant Unobservable Inputs (Level 3) \| Other
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	1,144		602
Significant Unobservable Inputs (Level 3) \| Other \| Commodities
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[5]	0	[5]
Significant Unobservable Inputs (Level 3) \| Other \| Real Estate
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	0	[6]	0	[6]
Significant Unobservable Inputs (Level 3) \| Other \| Guaranteed deposit
Schedule of Trading Securities and Other Trading Assets [Line Items]
Total Pension Plan Assets	$1,144	[7]	$602	[7]

[1]	Includes funds that invest primarily in United States common stocks.
[2]	Includes funds that invest primarily in foreign equities and emerging markets equities.
[3]	Includes funds that actively invest in both equity and debt securities, funds that sell short securities and funds that provide long-term capital appreciation. The funds may invest in debt securities below investment grade.
[4]	Includes funds that invest in investment grade and fixed income securities.
[5]	Includes funds that invest primarily in commodity-linked derivative instruments and fixed income securities.
[6]	Includes funds that invest primarily in real estate.
[7]	Includes investment in a group annuity product issued by an insurance company.

Employee_Benefit_Plans_Summary1

Employee Benefit Plans - Summary of Changes in Fair Value of Level 3 Investments (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	$54,155		$53,080
Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	46,448		26,278
Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	6,563		26,200
Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, beginning of year	602		710
Purchases	1,811		618
Transfers in	2,390		3,175
Disbursements	-3,704		-3,966
Investment Income	45		65
Balance, end of year	1,144		602
Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	28,390		29,152
Investments in equity securities \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	21,827		19,886
Investments in equity securities \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	6,563		9,266
Investments in equity securities \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0		0
Debt securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	20,375		19,396
Debt securities \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	20,375		2,462
Debt securities \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0		16,934
Debt securities \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0		0
Other than Securities Investment
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	5,390		4,532
Other than Securities Investment \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	4,246		3,930
Other than Securities Investment \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0		0
Other than Securities Investment \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	1,144		602
Us Large Cap Equity Securities \| Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	8,097	[1]	8,082	[1]
Us Large Cap Equity Securities \| Investments in equity securities \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	4,069	[1]	3,964	[1]
Us Large Cap Equity Securities \| Investments in equity securities \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	4,028	[1]	4,118	[1]
Us Large Cap Equity Securities \| Investments in equity securities \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[1]	0	[1]
Us Mid Cap Equity Securities \| Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	3,447	[1]	3,412	[1]
Us Mid Cap Equity Securities \| Investments in equity securities \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	1,733	[1]	0	[1]
Us Mid Cap Equity Securities \| Investments in equity securities \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	1,714	[1]	3,412	[1]
Us Mid Cap Equity Securities \| Investments in equity securities \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[1]	0	[1]
United States Equity Small Cap \| Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	1,694	[1]	1,736	[1]
United States Equity Small Cap \| Investments in equity securities \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	873	[1]	0	[1]
United States Equity Small Cap \| Investments in equity securities \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	821	[1]	1,736	[1]
United States Equity Small Cap \| Investments in equity securities \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[1]	0	[1]
International All Cap Equity \| Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	9,621	[2]	10,687	[2]
International All Cap Equity \| Investments in equity securities \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	9,621	[2]	10,687	[2]
International All Cap Equity \| Investments in equity securities \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[2]	0	[2]
International All Cap Equity \| Investments in equity securities \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[2]	0	[2]
Alternative Strategies \| Investments in equity securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	5,531	[3]	5,235	[3]
Alternative Strategies \| Investments in equity securities \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	5,531	[3]	5,235	[3]
Alternative Strategies \| Investments in equity securities \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[3]	0	[3]
Alternative Strategies \| Investments in equity securities \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[3]	0	[3]
Us Treasury Inflation Protected Securities \| Debt securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year			2,462
Us Treasury Inflation Protected Securities \| Debt securities \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year			2,462
Us Treasury Inflation Protected Securities \| Debt securities \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year			0
Us Treasury Inflation Protected Securities \| Debt securities \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year			0
Fixed Income \| Debt securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	17,717	[4]	14,305	[4]
Fixed Income \| Debt securities \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	17,717	[4]	0	[4]
Fixed Income \| Debt securities \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[4]	14,305	[4]
Fixed Income \| Debt securities \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[4]	0	[4]
High Yield Asset Backed Securities \| Debt securities
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	2,658	[4]	2,629	[4]
High Yield Asset Backed Securities \| Debt securities \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	2,658	[4]	0	[4]
High Yield Asset Backed Securities \| Debt securities \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[4]	2,629	[4]
High Yield Asset Backed Securities \| Debt securities \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[4]	0	[4]
Commodities \| Other than Securities Investment
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	1,819	[5]	1,939	[5]
Commodities \| Other than Securities Investment \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	1,819	[5]	1,939	[5]
Commodities \| Other than Securities Investment \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[5]	0	[5]
Commodities \| Other than Securities Investment \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[5]	0	[5]
Real Estate \| Other than Securities Investment
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	2,427	[6]	1,991	[6]
Real Estate \| Other than Securities Investment \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	2,427	[6]	1,991	[6]
Real Estate \| Other than Securities Investment \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[6]	0	[6]
Real Estate \| Other than Securities Investment \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[6]	0	[6]
Guaranteed deposit \| Other than Securities Investment
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	1,144	[7]	602	[7]
Guaranteed deposit \| Other than Securities Investment \| Quoted Prices in Active Markets (Level 1)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[7]	0	[7]
Guaranteed deposit \| Other than Securities Investment \| Significant Other Observable Inputs (Level 2)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	0	[7]	0	[7]
Guaranteed deposit \| Other than Securities Investment \| Significant Unobservable Inputs (Level 3)
Defined Benefit Plan, Change in Fair Value of Plan Assets [Roll Forward]
Balance, end of year	$1,144	[7]	$602	[7]

[1]	Includes funds that invest primarily in United States common stocks.
[2]	Includes funds that invest primarily in foreign equities and emerging markets equities.
[3]	Includes funds that actively invest in both equity and debt securities, funds that sell short securities and funds that provide long-term capital appreciation. The funds may invest in debt securities below investment grade.
[4]	Includes funds that invest in investment grade and fixed income securities.
[5]	Includes funds that invest primarily in commodity-linked derivative instruments and fixed income securities.
[6]	Includes funds that invest primarily in real estate.
[7]	Includes investment in a group annuity product issued by an insurance company.

Employee_Benefit_Plans_Schedul4

Employee Benefit Plans - Schedule of Funded Status of Benefit Obligation and Plan Assets (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014		Dec. 31, 2013		Dec. 31, 2012
Change in plan assets:
Balance, end of year	$54,155		$53,080
Chesapeake Pension Plan
Change in benefit obligation:
Benefit obligation - beginning of year	10,268		11,933
Interest cost	425		405		458
Actuarial loss	1,891		-1,092
Benefits paid	-603		-978
Benefit obligation - end of year	11,981		10,268		11,933
Change in plan assets:
Balance, beginning of year	8,743		8,430
Actual return on plan assets	305		967
Employer contributions	633		324
Benefits paid	-603		-978
Balance, end of year	9,078		8,743		8,430
Reconciliation:
Funded status	-2,903		-1,525
Accrued pension cost	-2,903		-1,525
Assumptions:
Discount rate	4.25%		3.50%		4.25%
Discount rate	3.50%		4.25%
Expected return on plan assets	6.00%		6.00%		6.00%
FPU Pension Plan
Change in benefit obligation:
Benefit obligation - beginning of year	55,876		64,512
Interest cost	2,613		2,367		2,577
Actuarial loss	12,785		-8,007
Benefits paid	-3,101		-2,996
Benefit obligation - end of year	68,173		55,876		64,512
Change in plan assets:
Balance, beginning of year	44,337		41,954
Actual return on plan assets	1,485		4,747
Employer contributions	2,356		632
Benefits paid	-3,101		-2,996
Balance, end of year	45,077		44,337		41,954
Reconciliation:
Funded status	-23,096		-11,539
Accrued pension cost	-23,096		-11,539
Assumptions:
Discount rate	4.75%		3.75%		4.50%
Discount rate	3.75%		4.75%
Expected return on plan assets	7.00%		7.00%		7.00%
Chesapeake SERP
Change in benefit obligation:
Benefit obligation - beginning of year	2,210		2,352
Interest cost	92		81		90
Actuarial loss	437		-134
Benefits paid	-89		-89
Benefit obligation - end of year	2,650		2,210		2,352
Change in plan assets:
Employer contributions	89		89
Benefits paid	-89		-89
Reconciliation:
Funded status	-2,650		-2,210
Accrued pension cost	-2,650		-2,210
Assumptions:
Discount rate	4.25%		3.50%		4.25%
Discount rate	3.50%		4.25%
Chesapeake Postretirement Plan
Change in benefit obligation:
Benefit obligation - beginning of year	1,262		1,415
Service cost	0		0		0
Interest cost	39		47		55
Plan participants contributions	106		92
Actuarial loss	6		-108
Benefits paid	-175		-184
Benefit obligation - end of year	1,238		1,262		1,415
Change in plan assets:
Balance, beginning of year	0		0
Employer contributions	69	[1]	92	[1]
Plan participants contributions	106		92
Benefits paid	-175		-184
Balance, end of year	0		0		0
Reconciliation:
Funded status	-1,238		-1,262
Accrued pension cost	-1,238		-1,262
Assumptions:
Discount rate	4.25%		3.50%		4.25%
Discount rate	3.50%		4.25%
FPU Medical Plan
Change in benefit obligation:
Benefit obligation - beginning of year	1,519		1,774
Service cost	0		0		1
Interest cost	69		63		79
Plan participants contributions	97		104
Actuarial loss	375		-165
Benefits paid	-348		-257
Benefit obligation - end of year	1,712		1,519		1,774
Change in plan assets:
Balance, beginning of year	0		0
Employer contributions	251	[1]	153	[1]
Plan participants contributions	97		104
Benefits paid	-348		-257
Balance, end of year	0		0		0
Reconciliation:
Funded status	-1,712		-1,519
Accrued pension cost	($1,712)		($1,519)
Assumptions:
Discount rate	4.75%		3.75%		4.50%
Discount rate	3.75%		4.75%

[1]	Chesapeakeâ€™s Postretirement Plan does not receive a Medicare Part-D subsidy. The FPU Medical Plan did not receive a significant subsidy for the post-merger period.

Employee_Benefit_Plans_Compone

Employee Benefit Plans - Component of Net Periodic Pension Cost (Benefit) (Detail) (USD $)	12 Months Ended
In Thousands, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Components of net periodic cost:
Curtailment gain	$0
Expected Amortization Of Pre Merger Regulatory Asset	0
Amortization of pre-merger regulatory asset	769
Chesapeake Pension Plan
Components of net periodic cost:
Interest cost	425	405	458
Expected return on assets	-516	-486	-418
Amortization of prior service cost	0	-1	-5
Actuarial (gain) loss	176	322	255
Net periodic pension cost	85	240	290
Amortization of pre-merger regulatory asset	0	0	0
Net periodic postretirement cost	85	240	290
Assumptions
Discount rate	4.25%	3.50%	4.25%
Expected return on plan assets	6.00%	6.00%	6.00%
FPU Pension Plan
Components of net periodic cost:
Interest cost	2,613	2,367	2,577
Expected return on assets	-3,089	-2,866	-2,627
Amortization of prior service cost	0	0	0
Actuarial (gain) loss	8	330	196
Net periodic pension cost	-468	-169	146
Amortization of pre-merger regulatory asset	761	761	761
Net periodic postretirement cost	293	592	907
Assumptions
Discount rate	4.75%	3.75%	4.50%
Expected return on plan assets	7.00%	7.00%	7.00%
Chesapeake SERP
Components of net periodic cost:
Interest cost	92	81	90
Amortization of prior service cost	19	19	19
Actuarial (gain) loss	47	64	46
Amortization of pre-merger regulatory asset	0
Net periodic postretirement cost	158	164	155
Assumptions
Discount rate	4.25%	3.50%	4.25%
Chesapeake Postretirement Plan
Components of net periodic cost:
Service cost	0	0	0
Interest cost	39	47	55
Amortization of prior service cost	-77	-77	-77
Actuarial (gain) loss	55	74	73
Net periodic pension cost	17	44	51
Curtailment gain		0	0
Expected Amortization Of Pre Merger Regulatory Asset		0	0
Amortization of pre-merger regulatory asset	0
Net periodic postretirement cost	17	44	51
Assumptions
Discount rate	4.25%	3.50%	4.25%
FPU Medical Plan
Components of net periodic cost:
Service cost	0	0	1
Interest cost	69	63	79
Amortization of prior service cost	0	0	0
Actuarial (gain) loss	0	0	0
Net periodic pension cost	69	63	80
Curtailment gain	0	0	-892
Amortization of pre-merger regulatory asset	8	8	8
Net periodic postretirement cost	$77	$71	($804)
Assumptions
Discount rate	4.75%	3.75%	4.50%

Employee_Benefit_Plans_Schedul5

Employee Benefit Plans - Schedule of Estimated Future Benefit Payments (Detail) (USD $)	Dec. 31, 2014
In Thousands, unless otherwise specified	Dec. 31, 2014
Chesapeake Pension Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2014	$642
2015	594
2016	715
2017	637
2018	706
Years 2019 through 2023	3,896
FPU Pension Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2014	2,957
2015	3,008
2016	3,022
2017	3,090
2018	3,178
Years 2019 through 2023	17,207
Chesapeake SERP
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2014	151
2015	151
2016	150
2017	149
2018	148
Years 2019 through 2023	938
Chesapeake Postretirement Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2014	79
2015	78
2016	75
2017	76
2018	76
Years 2019 through 2023	331
FPU Medical Plan
Defined Benefit Plan, Expected Future Benefit Payments, Maturity [Line Items]
2014	207
2015	179
2016	151
2017	111
2018	116
Years 2019 through 2023	$474

ShareBased_Compensation_Plans_1

Share-Based Compensation Plans - Share-Based Compensation Amounts Included in Net Income (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$1,958,000	$1,631,000	$1,419,000
Less: tax benefit	-790,000	-657,000	-569,000
Share-Based Compensation amounts included in net income	1,168,000	974,000	850,000
Directors Stock Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant-date fair value of awards granted	$41.60	$34.99	$27.37
Unrecognized compensation expense related to the DSCP awards	201,000
Total compensation expense	540,000	478,000	443,000
Performance Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares withheld	12,687	15,617	8,505
Payments of employees' tax obligations to taxing authorities	503,000	519,000	238,000
Weighted average grant-date fair value of awards granted	$39.99	$29.90	$26.41
Intrinsic value of PIP awards	6,100,000	4,800,000	3,800,000
Total compensation expense	$1,418,000		$976,000

ShareBased_Compensation_Additi

Share-Based Compensation - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance	855,975
Granted awards, shares	1,209
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$1,200,000
Stock and Incentive Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares reserved for issuance	621,176
Directors Stock Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Amortization of expense equally over a service period	1 year
Weighted average grant-date fair value of awards granted	$41.60	$34.99	$27.37
Unrecognized compensation expense related to the DSCP awards	201,000
Granted awards, shares	13,827	14,141
Performance Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Weighted average grant-date fair value of awards granted	$39.99	$29.90	$26.41
Granted awards, shares	41,442	35,236.50
Number of shares withheld	12,687	15,617	8,505
Payments of employees' tax obligations to taxing authorities	503,000	519,000	238,000
Additional Paid-In Capital [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Adjustments to Additional Paid in Capital, Income Tax Benefit from Share-based Compensation	$398,000	$202,000	$172,000

ShareBased_Compensation_Plans_2

Share-Based Compensation Plans - Summary of Stock Activity under DSCP (Detail) (USD $)	12 Months Ended
In Thousands, except Share data, unless otherwise specified	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted	1,209
Directors Stock Compensation Plan
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Outstanding Beginning Balance	0	0
Number of Shares, Granted	13,827	14,141
Number of Shares, Vested	13,827	14,141
Number of Shares, Outstanding Ending Balance	0	0	0
Weighted Average Grant Date Fair Value, Outstanding Beginning Balance	$0	$0
Weighted Average Grant Date Fair Value, Granted	$41.60	$34.99	$27.37
Weighted Average Grant Date Fair Value, Vested	$41.60	$34.99
Weighted Average Grant Date Fair Value, Outstanding Ending Balance	$0	$0	$0
Unrecognized compensation expense related to the DSCP awards	$201
Performance Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Outstanding Beginning Balance	121,142	126,968
Number of Shares, Granted	41,442	35,236
Number of Shares, Vested	39,546	36,498
Number of Shares, Outstanding Ending Balance	123,038	121,142	126,968
Number of shares withheld	12,687	15,617	8,505
Payments of employees' tax obligations to taxing authorities	$503	$519	$238
Weighted Average Grant Date Fair Value, Outstanding Beginning Balance	$28.20	$25.24
Weighted Average Grant Date Fair Value, Granted	$39.99	$29.90	$26.41
Weighted Average Grant Date Fair Value, Vested	$26.87	$22.17
Weighted Average Grant Date Fair Value, Outstanding Ending Balance	$32.60	$28.20	$25.24

ShareBased_Compensation_Plans_3

Share-Based Compensation Plans - Summary of Stock Activity under PIP (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Granted	1,209
Performance Incentive Plan
Share-based Compensation Arrangement by Share-based Payment Award, Options, Outstanding [Roll Forward]
Number of Shares, Outstanding Beginning Balance	121,142	126,967.50
Number of Shares, Granted	41,442	35,236.50
Number of Shares, Vested	39,546	36,498
Number of Shares, Expired		4,564.50
Number of Shares, Outstanding Ending Balance	123,038	121,142	126,967.50
Weighted Average Grant Date Fair Value, Outstanding Beginning Balance	$28.20	$25.24
Weighted Average Grant Date Fair Value, Granted	$39.99	$29.90	$26.41
Weighted Average Grant Date Fair Value, Vested	$26.87	$22.17
Weighted Average Grant Date Fair Value, Expired		$26.08
Weighted Average Grant Date Fair Value, Outstanding Ending Balance	$32.60	$28.20	$25.24

Rates_and_Other_Regulatory_Act1

Rates and Other Regulatory Activities - Additional Information (Detail) (USD $)	12 Months Ended	9 Months Ended
	Dec. 31, 2014	Sep. 30, 2014	Dec. 31, 2013
Investment In Affiliates [Line Items]
Regulatory Assets	$87,103,000		$69,020,000
MARYLAND
Investment In Affiliates [Line Items]
Reduction in accumulated depreciation	3,000,000
PeriodWithinWhichToPerformDepreciationStudy	5 years
Florida
Investment In Affiliates [Line Items]
Reduction In Annual Depreciation Expense	1,000,000
Public Utilities Interim Rate Increase Decrease Request Amount		2,400,000
Public Utilities, Requested Rate Increase (Decrease), Amount		5,900,000
Public Utilities, Interim Rate Increase (Decrease), Amount		2,200,000
Public Utilities, Approved Rate Increase (Decrease), Amount		3,800,000
Public Utilities, Approved Return on Equity, Percentage		10.25%
Total Number Of Electricity Units Proposed To Be Purchased Under Contract	20
Term of the Power Purchase Agreement	20 years
Estimated Environmental Cleanup Costs To Be Recovered		381,000
Eastern Shore Gas Company
Investment In Affiliates [Line Items]
NumberOfDaysDuringPeakPeriodSubjectToRightNotToScheduleService		90 days
Proposed Fuel Retention Percentage Rate	0.62%
Deferred Gas Required For Operations Underrecovery Regulatory Balance	494,000
Deferred Cash Out Costs Overrecovery Regulatory Balance	160,000
Eastern Shore Gas Company \| White Oak Lateral Mainline Expansion [Member]
Investment In Affiliates [Line Items]
Number of Pipeline Miles	7.2
Estimated capital costs of project	29,800,000
Lateral Diameter Of Pipeline To Be Installed	16
Horsepower of additional compression	3,550
Volume The Expansion Project Is Expected to Provide	45,000
Eastern Shore Gas Company \| TETLP Expansion Project [Member]
Investment In Affiliates [Line Items]
Total Capacity After Pipeline Improvements	57,000
Additional firm transportation service capacity	107,000
Eastern Shore Gas Company \| White Oak Lateral Project Filing [Member]
Investment In Affiliates [Line Items]
Additional firm transportation service capacity	55,200
Estimated capital costs of project	11,500,000
Amount Received From A State Grant	$2,500,000
Lateral Length Of Pipeline To Be Installed	5.5
Lateral Diameter Of Pipeline To Be Installed	16

Environmental_Commitments_and_1

Environmental Commitments and Contingencies - Additional Information (Detail) (USD $)	12 Months Ended
	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
	site	Dec. 31, 2013	Dec. 31, 2012
Environmental Commitments And Contingencies [Line Items]
Company's exposure in number of former Manufactured Gas Plant Sites	6
Environmental liabilities	$8,923,000	$9,155,000
Amount paid for funding requirements	233,000	-41,000	607,000
West Palm Beach Florida
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
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, maximum	13,000,000
Cost of remedy for settlements of claims	20,000,000
Loss Contingency, Pending Claims, Number	2
Environmental Remediation Expense	24,000
Costs to resolve liability	650,000
Key West Florida
Environmental Commitments And Contingencies [Line Items]
Costs to resolve liability	50,000
Period of regulatory inactivity	17 years
Key West Florida \| Maximum
Environmental Commitments And Contingencies [Line Items]
Costs to resolve liability	8,000
Pensacola Florida \| Maximum
Environmental Commitments And Contingencies [Line Items]
Costs to resolve liability	5,000
Salisbury Maryland
Environmental Commitments And Contingencies [Line Items]
Monitoring well remaining maximum cost	5,000
Winter Haven Florida
Environmental Commitments And Contingencies [Line Items]
Environmental Remediation Expense	443,000
Additional remediation costs	100,000
Seaford [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	300,000
Estimated costs of remediation range, maximum	500,000
FPU
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	10,100,000
Approval of recovery of environmental costs	14,000,000
Environmental costs recovered	9,700,000
FPU \| Manufactured Gas Plant
Environmental Commitments And Contingencies [Line Items]
Regulatory assets for future recovery of environmental costs	4,300,000
FPU \| Sanford Florida
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
Chesapeake
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	382,000
Regulatory assets for future recovery of environmental costs	$313,000

Other_Commitments_and_Continge1

Other Commitments and Contingencies - Additional Information (Detail) (USD $)	1 Months Ended	12 Months Ended
	31-May-13	Dec. 31, 2014	Dec. 31, 2013
	31-May-13	gal	Dec. 31, 2013
Other Contingencies And Commitments [Line Items]
Number Of Years To Purchase Propane Under Contract	6 years
Annual Estimate Of Volume Of Propane To Be Purchased		6,500,000
Total liabilities to tangible net worth minimum times		3.75
Fixed charge coverage ratio minimum times		1.5
Time to cure ratio		30 days
Funds from operations interest coverage ratio minimum times		2
Total debt to capital maximum		65
Total purchase obligations for 2013		$78,600,000
Total purchase obligations for 2014 - 2015		98,700,000
Total purchase obligations for 2016 - 2017		87,100,000
Total purchase obligations thereafter		121,000,000
Maximum authorized liability under such guarantees and letters of credit		50,000,000
Aggregate guaranteed amount		31,600,000
Amount of letter of credit to our current primary insurance company		40,000
Unrecognized Tax Benefits		100,000	300,000
Guarantees expiring date		12/30/15
Accruals related to additional sales taxes and gross receipts taxes		700,000	1,000,000
TETLP
Other Contingencies And Commitments [Line Items]
Amount of letter of credit to our current primary insurance company		2,300,000
Letter of credit two
Other Contingencies And Commitments [Line Items]
Amount of letter of credit to our current primary insurance company		1,100,000
Issued letter of credit expiry date		31-Oct-15
Letter of credit one
Other Contingencies And Commitments [Line Items]
Amount of letter of credit to our current primary insurance company		$1,000,000
Issued letter of credit expiry date		12-Sep-15

Quarterly_Financial_Data_Sched

Quarterly Financial Data - Schedule of Quarterly Financial Information (Detail) (USD $)	3 Months Ended								12 Months Ended
In Thousands, except Per Share data, unless otherwise specified	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2013	Sep. 30, 2013	Jun. 30, 2013	Mar. 31, 2013	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Disclosure Quarterly Financial Data Schedule Of Quarterly Financial Information [Abstract]
Revenues	$120,380	$91,619	$100,497	$186,337	$122,887	$86,545	$94,146	$140,729	$498,834	$444,306	$392,502
Operating Income	12,408	7,792	10,457	31,623	18,312	8,720	9,152	26,550	62,279	62,734	56,635
Net Income	$10,097	$3,180	$5,134	$17,681	$9,683	$3,879	$4,356	$14,869	$36,092	$32,787	$28,863
Earnings per share:
Basic (in usd per share)	$0.69	$0.22	$0.35	$1.22	$0.67	$0.27	$0.30	$1.03	$2.48	$2.27	$2.01
Diluted (in usd per share)	$0.69	$0.22	$0.35	$1.21	$0.67	$0.27	$0.30	$1.03	$2.47	$2.26	$1.99

Schedule_II_Valuation_and_Qual

Schedule II - Valuation and Qualifying Accounts (Detail) (USD $)	3 Months Ended	12 Months Ended
In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2012	Dec. 31, 2014
Movement in Valuation Allowances and Reserves [Roll Forward]
Balance at Beginning of Year	$1,635	$826	$1,090	$1,120
Additions, Charged to Income	1,073	1,796	826
Additions, Other Accounts	85	249	354
Deductions	-1,673	-1,236	-1,444
Balance at End of Year		$1,635	$826	$1,120