10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

x QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended: March 31, 2014

OR

¨ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from   to  

Commission File Number: 001-11590

CHESAPEAKE UTILITIES CORPORATION

(Exact name of registrant as specified in its charter)

Delaware	51-0064146
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

909 Silver Lake Boulevard, Dover, Delaware 19904

(Address of principal executive offices, including Zip Code)

(302) 734-6799

(Registrant’s telephone number, including area code)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).    Yes  x    No  ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Large accelerated filer	¨	Accelerated filer	x
Non-accelerated filer	¨	Smaller reporting company	¨

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x

Common Stock, par value $0.4867 — 9,701,040 shares outstanding as of April 30, 2014.

Table of Contents

PART I—FINANCIAL INFORMATION		1
ITEM 1.	FINANCIAL STATEMENTS	1
ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	24
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	39
ITEM 4.	CONTROLS AND PROCEDURES	40
PART II—OTHER INFORMATION		41
ITEM 1.	LEGAL PROCEEDINGS	41
ITEM 1A.	RISK FACTORS	41
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	41
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	41
ITEM 5.	OTHER INFORMATION	41
ITEM 6.	EXHIBITS	42
SIGNATURES		43

GLOSSARY OF DEFINITIONS

401(k) SERP: Supplemental Executive Retirement Savings Plan

ASC: Accounting Standards Codification

ASU: Accounting Standards Update

Austin Cox: Austin Cox Home Services, Inc.

BravePoint: BravePoint^®, Inc., our advanced information services subsidiary, headquartered in Norcross, Georgia

Calpine: Calpine Energy Services, L.P.

CDD: Cooling degree-days, which is the measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is above 65 degrees Fahrenheit

Chesapeake: Chesapeake Utilities Corporation, its divisions and its subsidiaries, as appropriate in the context of the disclosure

Chesapeake Pension Plan: A defined benefit pension plan sponsored by Chesapeake

Chesapeake Postretirement Plan: An unfunded postretirement health care and life insurance plan sponsored by Chesapeake

Chesapeake SERP: An unfunded supplemental executive retirement pension plan sponsored by Chesapeake

Company: Chesapeake Utilities Corporation, its divisions and its subsidiaries, as appropriate in the context of the disclosure

CP: Certificate of Public Convenience and Necessity

Deferred Compensation Plan: A non-qualified, deferred compensation arrangement under which certain of our executives and members of the Board of Directors are able to defer payment of all or a part of certain specified types of compensation, including executive cash bonuses, executive performance shares, and directors’ retainers and fees

Delmarva Peninsula: A peninsula on the east coast of the United States of America occupied by Delaware and portions of Maryland and Virginia

DNREC: Delaware Department of Natural Resources and Environmental Control

DSCP: Directors Stock Compensation Plan

Dts/d: Dekatherms per day

Eastern Shore: Eastern Shore Natural Gas Company, a wholly-owned natural gas transmission subsidiary of Chesapeake

EGWIC: Eastern Gas & Water Investment Company, LLC, an affiliate of Eastern Shore Gas Company

EPA: United States Environmental Protection Agency

ESG: Eastern Shore Gas Company and its affiliates

FASB: Financial Accounting Standards Board

FERC: Federal Energy Regulatory Commission, an independent agency of the Federal government that regulates the interstate transmission of electricity, natural gas, and oil

FDEP: Florida Department of Environmental Protection

FDOT: Florida Department of Transportation

FGT: Florida Gas Transmission Company

Fort Meade: The natural gas system purchased by FPU from the City of Fort Meade, Florida

FPU: Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake

FPU Medical Plan: A separate unfunded postretirement medical plan for FPU sponsored by Chesapeake

FPU Pension Plan: A separate defined benefit pension plan for FPU sponsored by Chesapeake

GAAP: Accounting principles generally accepted in the United States of America

Glades: Glades Gas Co., Inc.

GRIP: Gas Reliability Infrastructure Program, which is a surcharge to natural gas customers designed to recover capital and other program-related costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying distribution mains and services in Florida

Gulf Power: Gulf Power Company

Gulfstream: Gulfstream Natural Gas System, LLC

HDD: Heating degree-days, which is a measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is below 65 degrees Fahrenheit

MDE: Maryland Department of Environment

MGP: Manufactured gas plant, which is a site where coal was previously used to manufacture gaseous fuel for industrial, commercial and residential use

NAM: Natural Attenuation Monitoring

Note Agreement: Note Purchase Agreement entered into by Chesapeake with Note Holders on September 5, 2013

Note Holders: PAR U Hartford Life & Annuity Comfort Trust, The Prudential Insurance Company of America, The Gibraltar Life Insurance Co., Ltd., The Penn Mutual Life Insurance Company, Thrivent Financial for Lutherans, United of Omaha Life Insurance Company, and Companion Life Insurance Company, which are collectively the lenders that entered into the Note Agreement with Chesapeake on September 5, 2013

Notes: Series A and B unsecured Senior Notes that have been or will be entered into with the Note Holders

OTC: Over-the-counter

Peninsula Pipeline: Peninsula Pipeline Company, Inc., our wholly-owned Florida intrastate pipeline subsidiary

PESCO: Peninsula Energy Services Company, Inc., our wholly-owned natural gas marketing subsidiary

PIP: Performance Incentive Plan

PSC: Public Service Commission, which is the state agency that regulates the rates and services provided by Chesapeake’s natural gas and electric distribution operations in Delaware, Maryland and Florida and Peninsula Pipeline in Florida

Sandpiper: Sandpiper Energy, Inc.

Sanford Group: FPU and other responsible parties involved with the Sanford environmental site

SEC: Securities and Exchange Commission

Series A Notes: Series A of the unsecured Senior Notes issued on December 16, 2013 pursuant to the Note Agreement

Series B Notes: Series B of the unsecured Senior Notes to be issued on May 15, 2014 pursuant to the Note Agreement

Sharp: Sharp Energy, Inc., our wholly-owned propane distribution subsidiary

SICP: 2013 Stock and Incentive Compensation Plan, which replaced DSCP and PIP effective May 2, 2013

TETLP: Texas Eastern Transmission, LP

Xeron: Xeron, Inc., our propane wholesale marketing subsidiary, based in Houston, Texas

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)

	Three Months Ended
	March 31,
	2014		2013
(in thousands, except shares and per share data)
Operating Revenues
Regulated energy	$	102,166	$	81,566
Unregulated energy	79,973		54,991
Other	4,198		4,172
Total Operating Revenues	186,337		140,729
Operating Expenses
Regulated energy cost of sales	54,307		41,615
Unregulated energy and other cost of sales	61,325		40,090
Operations	26,626		21,754
Maintenance	2,148		1,722
Depreciation and amortization	6,635		5,820
Other taxes	3,673		3,178
Total Operating Expenses	154,714		114,179
Operating Income	31,623		26,550
Other income, net of other expenses	6		289
Interest charges	2,155		2,072
Income Before Income Taxes	29,474		24,767
Income taxes	11,793		9,898
Net Income	$	17,681	$	14,869
Weighted Average Common Shares Outstanding:
Basic	9,658,431		9,601,529
Diluted	9,693,434		9,678,950
Earnings Per Share of Common Stock:
Basic	$	1.83	$	1.55
Diluted	$	1.82	$	1.54
Cash Dividends Declared Per Share of Common Stock	$	0.385	$	0.365

The accompanying notes are an integral part of these financial statements.

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended
	March 31,
	2014			2013
(in thousands)
Net Income	$	17,681		$	14,869
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of ($6) and ($6), respectively	(9		)	(9		)
Net gain, net of tax of $27 and $38, respectively	40			58
Total other comprehensive income	31			49
Comprehensive Income	$	17,712		$	14,918

The accompanying notes are an integral part of these financial statements.

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Assets	March 31, 2014			December 31, 2013
(in thousands, except shares)
Property, Plant and Equipment
Regulated energy	$	697,725		$	691,522
Unregulated energy	76,938			76,267
Other	21,129			21,002
Total property, plant and equipment	795,792			788,791
Less: Accumulated depreciation and amortization	(179,918		)	(174,148		)
Plus: Construction work in progress	27,228			16,603
Net property, plant and equipment	643,102			631,246
Current Assets
Cash and cash equivalents	4,791			3,356
Accounts receivable (less allowance for uncollectible accounts of $1,976 and $1,635, respectively)	80,313			75,293
Accrued revenue	12,536			13,910
Propane inventory, at average cost	6,088			10,456
Other inventory, at average cost	3,728			4,880
Storage gas prepayments	1,323			4,318
Prepaid expenses	4,890			6,910
Income taxes receivable	—			2,609
Mark-to-market energy assets	—			385
Regulatory assets	4,342			2,436
Deferred income taxes	1,723			1,696
Other current assets	198			160
Total current assets	119,932			126,409
Deferred Charges and Other Assets
Investments, at fair value	2,951			3,098
Regulatory assets	66,395			66,584
Goodwill	4,625			4,354
Other intangible assets, net	2,875			2,975
Receivables and other deferred charges	2,681			2,856
Total deferred charges and other assets	79,527			79,867
Total Assets	$	842,561		$	837,522

The accompanying notes are an integral part of these financial statements.

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Capitalization and Liabilities	March 31, 2014			December 31, 2013
(in thousands, except shares and per share data)
Capitalization
Stockholders’ equity
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)	$	4,715		$	4,691
Additional paid-in capital	152,862			152,341
Retained earnings	138,176			124,274
Accumulated other comprehensive loss	(2,502		)	(2,533		)
Deferred compensation obligation	1,138			1,124
Treasury stock	(1,138		)	(1,124		)
Total stockholders’ equity	293,251			278,773
Long-term debt, net of current maturities	117,195			117,592
Total capitalization	410,446			396,365
Current Liabilities
Current portion of long-term debt	10,955			11,353
Short-term borrowing	83,470			105,666
Accounts payable	58,183			53,482
Accrued compensation	4,937			8,394
Accrued interest	2,536			1,235
Dividends payable	3,730			3,710
Income taxes payable	8,955			—
Mark-to-market energy liabilities	—			127
Regulatory liabilities	7,071			4,157
Customer deposits and refunds	24,405			26,140
Other accrued liabilities	8,934			7,678
Total current liabilities	213,176			221,942
Deferred Credits and Other Liabilities
Deferred income taxes	142,414			142,597
Deferred investment tax credits	65			74
Regulatory liabilities	4,178			4,402
Accrued asset removal cost—Regulatory liability	40,007			39,510
Environmental liabilities	9,129			9,155
Other pension and benefit costs	20,662			21,000
Other liabilities	2,484			2,477
Total deferred credits and other liabilities	218,939			219,215
Other commitments and contingencies (Note 6)
Total Capitalization and Liabilities	$	842,561		$	837,522

The accompanying notes are an integral part of these financial statements.

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended
	March 31,
	2014			2013
(in thousands)
Operating Activities
Net income	$	17,681		$	14,869
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	6,635			5,820
Depreciation and accretion included in other costs	1,783			1,476
Deferred income taxes, net	(231		)	2,208
Gain on sale of assets	(8		)	(8		)
Unrealized (gain) loss on commodity contracts	68			(214		)
Unrealized gain on investments	(37		)	(283		)
Realized gain on sales of investments, net	—			(69		)
Employee benefits	162			209
Share-based compensation	638			381
Other, net	(1		)	(3		)
Changes in assets and liabilities:
Sale (purchase) of investments	184			(7		)
Accounts receivable and accrued revenue	(3,647		)	(8,657		)
Propane inventory, storage gas and other inventory	8,243			5,064
Regulatory assets	(2,788		)	852
Prepaid expenses and other current assets	2,185			1,469
Accounts payable and other accrued liabilities	4,821			1,510
Income taxes receivable and payable	11,565			8,899
Accrued interest	1,301			1,185
Customer deposits and refunds	(1,735		)	(2,520		)
Accrued compensation	(3,505		)	(2,753		)
Regulatory liabilities	2,925			5,711
Other assets and liabilities, net	(240		)	21
Net cash provided by operating activities	45,999			35,160
Investing Activities
Property, plant and equipment expenditures	(18,464		)	(16,409		)
Proceeds from sales of assets	29			34
Acquisitions	—			(2,437		)
Environmental expenditures	(26		)	(20		)
Net cash used in investing activities	(18,461		)	(18,832		)
Financing Activities
Common stock dividends	(3,369		)	(3,176		)
Purchase of stock for Dividend Reinvestment Plan	(341		)	(326		)
Change in cash overdrafts due to outstanding checks	(501		)	83
Net repayment under line of credit agreements	(21,696		)	(13,647		)
Repayment of long-term debt and capital lease obligation	(196		)	(15		)
Net cash used in financing activities	(26,103		)	(17,081		)
Net Increase (Decrease) in Cash and Cash Equivalents	1,435			(753		)
Cash and Cash Equivalents—Beginning of Period	3,356			3,361
Cash and Cash Equivalents—End of Period	$	4,791		$	2,608

The accompanying notes are an integral part of these financial statements.

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

	Common Stock
(in thousands, except shares and pershare data)	Number  of Shares(1)	Par Value		Additional  Paid-In Capital			Retained Earnings			Accumulated  Other Comprehensive Loss			Deferred Compensation		Treasury Stock			Total
Balance at December 31, 2012	9,597,499	$	4,671	$	150,750		$	106,239		$	(5,062	)	$	982	$	(982	)	$	256,598
Net Income	—	—		—			32,787			—			—		—			32,787
Other comprehensive income	—	—		—			—			2,529			—		—			2,529
Dividend declared ($1.520 per share)	—	—		(6		)	(14,752		)	—			—		—			(14,758		)
Conversion of debentures	17,383	8		287			—			—			—		—			295
Share-based compensation and tax benefit (2) (3)	23,348	12		1,310			—			—			—		—			1,322
Treasury stock activities	—	—		—			—			—			142		(142		)	—
Balance at December 31, 2013	9,638,230	4,691		152,341			124,274			(2,533		)	1,124		(1,124		)	278,773
Net Income	—	—		—			17,681			—			—		—			17,681
Other comprehensive income	—	—		—			—			31			—		—			31
Dividend declared ($0.385 per share)	—	—		(1		)	(3,779		)	—			—		—			(3,780		)
Conversion of debentures	31,542	15		520			—			—			—		—			535
Share-based compensation and tax benefit (2)(3)	17,906	9		2			—			—			—		—			11
Treasury stock activities	—	—		—			—			—			14		(14		)	—
Balance at March 31, 2014	9,687,678	$	4,715	$	152,862		$	138,176		$	(2,502	)	$	1,138	$	(1,138	)	$	293,251

⁽¹⁾  Includes 34,731 and 34,495 shares at March 31, 2014 and December 31, 2013, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.

⁽²⁾  Includes amounts for shares issued for Directors’ compensation.

⁽³⁾  The shares issued under the SICP are net of shares withheld for employee taxes. For the quarter ended March 31, 2014 and for the year ended December 31, 2013, we withheld 8,458 and 10,411 shares, respectively, for taxes.

The accompanying notes are an integral part of these financial statements.

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NOTESTO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. Summary of Accounting Policies

Basis of Presentation

References in this document to the “Company,” “Chesapeake,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure.

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2013. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures.

We have assessed and reported on subsequent events through the date of issuance of these condensed consolidated financial statements.

Reclassifications

We reclassified certain amounts in the condensed consolidated cash flows statement for the three months ended March 31, 2013 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

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.

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2. Calculation of Earnings Per Share

	Three Months Ended
	March 31,
	2014		2013
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	17,681	$	14,869
Weighted average shares outstanding	9,658,431		9,601,529
Basic Earnings Per Share	$	1.83	$	1.55
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	17,681	$	14,869
Effect of 8.25% Convertible debentures (1)	—		11
Adjusted numerator—Diluted	$	17,681	$	14,880
Reconciliation of Denominator:
Weighted shares outstanding—Basic	9,658,431		9,601,529
Effect of dilutive securities:
Share-based Compensation	35,003		23,132
8.25% Convertible debentures (1)	—		54,289
Adjusted denominator—Diluted	9,693,434		9,678,950
Diluted Earnings Per Share	$	1.82	$	1.54

⁽¹⁾As of March 1, 2014, we no longer have any outstanding convertible debentures. See Note 14, Long-term debt for additional information.

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3. Acquisitions

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 now subject to rate and service regulation by the Maryland PSC. We are evaluating the potential conversion of some of the underground propane distribution systems to natural gas distribution. Although 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, $344,000 in propane inventory, $2.5 million in accounts receivable and accrued revenue and $227,000 in other current liabilities, which included the effect of the purchase price adjustment in the third quarter of 2013. All but insignificant amounts of assets and liabilities are recorded in the Regulated Energy segment. No goodwill or intangible asset was recorded from this acquisition. The allocation of the purchase price and valuation of assets are preliminary, and we will complete the final purchase price allocation as soon as practicable, but no later than one year from the purchase of the assets.

The revenue and net income from this acquisition for the three months ended March 31, 2014 included in our condensed consolidated statement of income were $10.3 million and $1.7 million, 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 $670,000 in property, plant and equipment, $14,000 in inventory, $150,000 in goodwill and $42,000 in other current liabilities. Valuation of certain property, plant and equipment is preliminary and may be adjusted in the future based upon the final valuation, but no later than one year from the date of acquisition. All of the goodwill is expected to be deductible for income tax purposes. The revenue and net income from this acquisition that were included in our condensed consolidated statement of income for the three months ended March 31, 2014 were not material.

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. All of the goodwill is expected to be deductible for income tax purposes. These amounts reflected 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 for the same amount. The revenue and net income from this acquisition that were included in our condensed consolidated statement of income for the three months ended March 31, 2014 were not material.

4. Rates and Other Regulatory Activities

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake’s Florida natural gas distribution division and FPU’s natural gas and electric distribution operations continue to be subject to regulation by the Florida PSC as separate entities.

Delaware

There were no rates and other regulatory activities in Delaware during the first quarter of 2014.

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Maryland

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. Sandpiper recommended slightly lower depreciation rates to be applied prospectively and a reduction of $4.5 million in accumulated depreciation. At the administrative meeting on April 23, 2014, the Maryland PSC assigned this matter to an administrative judge for further review.

Florida

On April 28, 2014, FPU filed a base rate proceeding for its electric distribution operation. FPU is seeking interim rate relief of approximately $2.4 million and final rate relief of approximately $5.9 million. The interim rate relief requested is based on the twelve-month period ended September 30, 2013. We expect the interim rate relief to be determined in the second quarter of 2014. Any increase to our rates as a result of this interim rate relief will be subject to refund based on the outcome of the final rate relief, which we expect to occur during the fourth quarter of 2014.

On January 13, 2014, FPU's natural gas 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. Depending on the results of this proceeding, we may be required to change depreciation expense on our Florida natural gas distribution operations. The PSC agenda date for the depreciation study has not yet been set.

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. This extension would be effective for two years beginning January 1, 2014. The Florida PSC approved the extension of the surcharge and the additional amount for recovery at the Agenda conference on January 7, 2014.

Eastern Shore

The following are regulatory activities involving FERC orders applicable to Eastern Shore and the expansions of Eastern Shore’s transmission system:

TETLP Expansion Project: On January 31, 2014, Eastern Shore submitted to the FERC a request for prior notice authorizationregarding a projectwhich includedcertain improvements at Eastern Shore’s existinginterconnection with TETLP near Honey Brook, Pennsylvania. This project will allow Eastern Shore toincrease its capacity to receive natural gas from TETLP by 57,000 Dts/d to a total capacity of 107,000 Dts/d but this requested improvement does not result in an increase in Eastern Shore’s overall pipeline 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 consists of installing approximately 5.5 miles of 16-inch diameter pipeline, metering facilities and miscellaneous appurtenances extending from Eastern Shore's mainline system near its North Dover City Gate Station to the Garrison Oak Technical Park, all located in Dover, Delaware. This project is designed to provide 55,200 Dts/d of delivery lateral firm transportation service to an industrial customer facility currently under construction. The total cost of the project is estimated to be approximately $11.2 million.

On August 9, 2013, the FERC issued a notice of intent to prepare an environmental assessment for the project. The comment period concluded on September 9, 2013, with no comments being filed in the docket. The environmental assessment was issued on October 4, 2013, and FERC staff recommended a finding of no significant impact. Eastern Shore filed the implementation plan and acceptance of conditions, stating that it will comply with all environmental conditions as set forth in the order. On November 27, 2013, the FERC issued a CP for this project. On January 17, 2014, the FERC issued its notice to allow construction to proceed, and Eastern Shore began construction activities for this project on January 22, 2014, for a planned in-service date of January 1, 2015.

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5. 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 and assessment of, and have remediation 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. We have also been in discussions with the MDE regarding a seventh former MGP site located in Cambridge, Maryland.

As of March 31, 2014, we had approximately $10.2 million in environmental liabilities related to all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites, representing our estimate of the future costs associated with those sites. FPU has approval to recover up to $14.0 million of its environmental costs related to all of its MGP sites from insurance and from customers through rates, approximately $9.3 million of which has been recovered as of March 31, 2014. We had approximately $4.7 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

In addition to the FPU MGP sites, we had $474,000 in environmental liabilities at March 31, 2014, related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of March 31, 2014, we had approximately $598,000 in regulatory and other assets for future recovery through Chesapeake’s rates. Environmental liabilities for all of our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants.

We continue to expect that all costs related to environmental remediation and related activities will be recoverable from customers through rates.

The following discussion provides details on MGP sites:

West Palm Beach, Florida

Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at, and in the immediate vicinity of, a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated a MGP. FPU is currently implementing a remedial plan approved by the FDEP for the east parcel of the West Palm Beach site, which includes installation of monitoring test wells, sparging of air into the groundwater system and extraction of vapors from the subsurface. It is anticipated that similar remedial actions ultimately will be implemented for other portions of the site. Estimated costs of remediation for the West Palm Beach site range from approximately $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.

Sanford, Florida

FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of March 31, 2014, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements.

The total cost of the final remedy is now estimated to be over $20.0 million, which includes long-term monitoring and the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.

As of March 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 as provided in the Third Participation Agreement to implement the final remedy for this site or will pursue a claim against FPU for a sum in excess

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of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of March 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 via e-mail on October 9, 2012 that based on the data, NAM appears to be an appropriate remedy for the site. The FDEP issued a Remedial Action Plan approval order, dated October 12, 2012, which specified that a limited semi-annual monitoring program is to be conducted. The annual cost to conduct the limited NAM program is not expected to exceed $8,000. Although the duration of the FDEP-required limited NAM cannot be determined with certainty, it is anticipated that total costs to complete the remedial action will not exceed $50,000.

Pensacola, Florida

FPU formerly owned and operated a MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the FDOT. In October 2009, FDEP informed Gulf Power that FDEP would approve a conditional No Further Action determination for the site, which must include a requirement for institutional and engineering controls. On December 13, 2011, Gulf Power, the City of Pensacola, FDOT and FPU submitted to FDEP a draft covenant for institutional and engineering controls for the site. Upon FDEP’s approval and the subsequent recording of the institutional and engineering controls, no further work is expected to be required of the parties. Assuming FDEP approves the draft institutional and engineering controls, it is anticipated that FPU’s share of remaining legal and cleanup costs will not exceed $5,000.

Winter Haven, Florida

The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a consent order entered into with FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. Recent groundwater sampling results show a continuing reduction in contaminant concentrations from the treatment system, which has been in operation since 2002. Currently, we predict that remedial action objectives could be met in approximately two to three years for the area being treated by the remediation system. On August 7, 2012, FDEP issued a letter discussing the need to evaluate further remedial options, which could incorporate risk-management options, including natural attenuation and the use of institutional and engineering controls. Modifications to the existing consent order and the remedial action plan modification could be required to incorporate risk-management options into the remedy for the site. A response letter was submitted to FDEP on May 7, 2013. FDEP issued an additional comment letter, dated September 16, 2013, containing various requests and questions, which we responded to on October 10, 2013.

An exploratory drilling program was conducted in November of 2013, and the most recent groundwater monitoring report was submitted on January 27, 2014. The results of the drilling program suggest that some additional remedial activities might be necessary in the southwest corner of the Winter Haven site, and, we are currently negotiating with FDEP the scope of such activities.

If modifications to the existing consent order and remedial action plan are required, we estimate that future remediation costs for the subsurface soils and groundwater at the site could be as much as $443,000, which includes an estimate of $100,000 to implement additional actions, such as institutional controls, at the site. If we are required to incur this cost, we continue to believe that the entire amount will be recoverable from customers through 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, we object to FDEP’s suggestion that the sediments have been adversely impacted by the former operations of the MGP. Our early estimates indicate that some of the corrective measures previously discussed by FDEP could cost as much as $1.0 million. We believe that corrective measures for the sediments are not warranted and intend to oppose any requirement that we undertake corrective measures in the offshore sediments. We have not recorded a liability for sediment remediation, as the final resolution of this matter cannot be predicted at this time.

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Salisbury, Maryland

We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized groundwater contamination. In February 2002, the MDE granted permission to permanently decommission the systems used for remediation and to discontinue all on-site and off-site well monitoring, except for one well, which is being maintained for periodic product monitoring and recovery. We anticipate that the remaining costs of the one remaining monitoring well will not exceed $5,000 annually. We cannot predict at this time when the MDE will grant permission to permanently decommission the one remaining monitoring well.

Other

We are in discussions with the MDE regarding a former MGP site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.

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. The facility evaluation has not been conducted and the outcome of this evaluation cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.

6. 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 gas, electricity and propane from various suppliers. The contracts have various expiration dates. For our Delaware and Maryland natural gas distribution divisions, we have a contract with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage capacity, which expires on March 31, 2015.

In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term. Sandpiper's initial annual commitment is estimated at approximately 7.4 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.

Chesapeake’s Florida natural gas distribution division has firm transportation service contracts with FGT and Gulfstream. 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 for the service.

In May 2013, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2014. PESCO is currently obtaining and reviewing proposals from suppliers and anticipates executing new agreements before the existing agreements expire.

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) a fixed charge coverage ratio greater than 1.5 times. If either ratio is not met by FPU, it has 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken or proposed to be taken to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could result in FPU having to provide an irrevocable letter of credit. As of March 31, 2014, FPU was in compliance with all of the requirements of its fuel supply contracts.

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 initial annual commitment is estimated at approximately 7.4 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one against those specified in the other.

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Corporate Guarantees

The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our obligations, including the obligations of our subsidiaries. The maximum authorized liability under such guarantees and letters of credit is $45.0 million.

We have issued corporate guarantees to certain vendors of our subsidiaries, the largest portion of which are for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at March 31, 2014 was $31.6 million, with the guarantees expiring on various dates through February 2015.

Chesapeake guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under the guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 14, Long-Term Debt, to the condensed consolidated financial statements for further details).

In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million, which expires on September 12, 2014, related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for $1.1 million, which expires on December 2, 2014, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company in 2010, we renewed and decreased the letter of credit for $304,000 to our former primary insurance company, which will expire on June 1, 2014. There have been no draws on these letters of credit as of March 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 our Delaware and Maryland divisions.

Tax-related Contingencies

We are subject to various audits and reviews by the federal, state, local and other regulatory authorities regarding income taxes and taxes other than income. As of March 31, 2014, we maintained a liability of $300,000 related to unrecognized income tax benefits and $968,000 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.

7. 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 PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.

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

• Other. The “Other” segment consists primarily of our advanced information services subsidiary, as well as our unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.

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The following table presents financial information about our reportable segments:

	Three Months Ended
	March 31,
	2014			2013
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	101,874		$	81,304
Unregulated Energy	79,874			54,991
Other	4,589			4,434
Total operating revenues, unaffiliated customers	$	186,337		$	140,729
Intersegment Revenues (1)
Regulated Energy	$	292		$	263
Unregulated Energy	99			—
Other	253			243
Total intersegment revenues	$	644		$	506
Operating Income
Regulated Energy	$	21,091		$	17,306
Unregulated Energy	10,858			9,369
Other and eliminations	(326		)	(125		)
Total operating income	31,623			26,550
Other income, net of other expenses	6			289
Interest	2,155			2,072
Income before Income Taxes	29,474			24,767
Income taxes	11,793			9,898
Net Income	$	17,681		$	14,869

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

(in thousands)	March 31, 2014		December 31, 2013
Identifiable Assets
Regulated energy	$	715,062	$	708,950
Unregulated energy	103,658		100,585
Other	23,841		27,987
Total identifiable assets	$	842,561	$	837,522

Our operations are almost entirely domestic. BravePoint has infrequent transactions in foreign countries which are denominated and paid primarily in U.S. dollars. These transactions are immaterial to the consolidated revenues.

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8. Accumulated Other Comprehensive Income (Loss)

The following table presents the changes in the balance of accumulated other comprehensive income (loss) for the three months ended March 31, 2014 and 2013. Defined benefit pension and postretirement plan items are the only component of our accumulated comprehensive income (loss). All amounts in the following table are presented net of tax.

	Three Months Ended
	March 31,
	2014			2013
(in thousands)
Beginning balance	$	(2,533	)	$	(5,062	)
Other comprehensive loss before reclassifications	—			(6		)
Amounts reclassified from accumulated other comprehensive loss	31			55
Net current-period other comprehensive income	31			49
Ending balance	$	(2,502	)	$	(5,013	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three months ended March 31, 2014 and 2013:

	Three Months Ended
	March 31,
	2014			2013
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	14		$	14
Net loss (1)	(66		)	(106		)
Total before income taxes	(52		)	(92		)
Income tax benefit	21			37
Net of tax	$	(31	)	$	(55	)

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

Amortization of defined benefit pension and postretirement plan items are included in operations expense in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.

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9. Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three months ended March 31, 2014 and 2013 are set forth in the following tables:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake Pension SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended March 31,	2014			2013			2014			2013			2014		2013		2014			2013			2014		2013
(in thousands)
Interest cost	$	107		$	102		$	647		$	594		$	23	$	21	$	13		$	12		$	17	$	16
Expected return on plan assets	(133		)	(126		)	(773		)	(719		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			5		5		(19		)	(19		)	—		—
Amortization of net loss	37			57			—			81			12		16		17			18			—		—
Net periodic cost (benefit)	11			33			(126		)	(44		)	40		42		11			11			17		16
Amortization of pre-merger regulatory asset	—			—			190			190			—		—		—			—			2		2
Total periodic cost	$	11		$	33		$	64		$	146		$	40	$	42	$	11		$	11		$	19	$	18

We expect to record pension and postretirement benefit costs of approximately $578,000 for 2014. Included in these costs is $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations of the changes in funded status that occurred but were not recognized as part of net periodic benefit costs prior to the merger. This was deferred as a regulatory asset by FPU prior to the merger to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was $4.2 million and $4.4 million at March 31, 2014 and December 31, 2013, respectively. The amortization included in pension expense is being offset by a net periodic benefit of $191,000, which will reduce our total expected benefit costs to $578,000.

FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs related to its regulated operations after the merger pursuant to a Florida PSC order. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake’s operations is recorded to accumulated other comprehensive income/loss. The following table presents the amounts included in the regulatory asset and accumulated other comprehensive income/loss that were recognized as components of net periodic benefit cost during the three months ended March 31, 2014:

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

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

During the three months ended March 31, 2014, we contributed $91,000 and $211,000, to the Chesapeake and FPU pension plans, respectively. We expect to contribute a total of $520,000 and $1.7 million to the Chesapeake and FPU pension plans, respectively, during 2014, which represent the minimum contribution payments required in 2014.

The Chesapeake Pension SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake Pension SERP for the three months

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ended March 31, 2014, were $22,000. We expect to pay total cash benefits of approximately $88,000 under the Chesapeake Pension SERP in 2014. Cash benefits paid for the Chesapeake Postretirement Plan, primarily for medical claims for the three months ended March 31, 2014, were $23,000. We have estimated that approximately $95,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2014. Cash benefits paid for the FPU Medical Plan, primarily for medical claims for the three months ended March 31, 2014, were $55,000. We estimate that approximately $245,000 will be paid for such benefits under the FPU Medical Plan in 2014.

10. Investments

The investment balances at March 31, 2014 and December 31, 2013, consist of the Rabbi Trusts associated with the 401(k) SERP and deferred compensation plans. We classify these investments as trading securities and report them at their fair value. For the three months ended March 31, 2014 and 2013, we recorded a net unrealized gain of $37,000 and $283,000, respectively, in other income in the condensed consolidated statements of income related to these investments. We also have recorded an associated liability, which is included in other pension and benefit costs in the condensed consolidated balance sheets. This liability is adjusted each month for the gains and losses incurred by the Rabbi Trusts.

11. Share-Based Compensation

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

The table below presents the amounts included in net income related to share-based compensation expense for the three months ended March 31, 2014 and 2013:

	Three Months Ended
	March 31,
	2014		2013
(in thousands)
Awards to non-employee directors	$	124	$	111
Awards to key employees	514		270
Total compensation expense	638		381
Less: tax benefit	257		153
Share-Based Compensation amounts included in net income	$	381	$	228

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. At March 31, 2014, there was $41,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors’ remaining service periods ending April 30, 2014.

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Key Employees

The table below presents the summary of the stock activity for the awards to key employees for the three months ended March 31, 2014:

	Number of Shares	Weighted Average Fair Value
Outstanding—December 31, 2013	80,761	$	42.30
Granted	27,628	$	58.35
Vested	26,364	$	40.30
Outstanding—March 31, 2014	82,025	$	48.35

In January and March 2014, the Board of Directors granted awards of 27,628 shares to key employees under the SICP. The award of 23,200 shares granted in January 2014 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2016. The award of 4,428 shares granted in March 2014 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2015. These awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprise both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the date each award is granted. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

At March 31, 2014, the aggregate intrinsic value of the SICP awards was $5.2 million.

12. Derivative Instruments

We use derivative and non-derivative contracts to engage in trading activities and manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory in order to mitigate the impact of wholesale price fluctuations. As of March 31, 2014, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

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 these options as fair value hedges, and there is no ineffective portion of these 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 expected to be purchased at market-based prices to supply the demands of our propane price cap program customers. The program caps the retail price that we can charge to those customers during the upcoming heating season at a pre-determined level. The call option is exercised if the propane prices rise above the strike price of $0.975 per gallon in January through March of 2014. We 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.

Xeron engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under this method, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statement of income for the period of change. As of March 31, 2014, we did not have outstanding trading contracts.

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

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payable, which are presented on a gross basis in the accompanying condensed consolidated balance sheets. At March 31, 2014, Xeron had a right to offset $5.3 million and $3.8 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 condensed consolidated balance sheet as of March 31, 2014 and December 31, 2013, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2014		December 31, 2013
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	—	$	196
Call Option (1)	Mark-to-market energy assets	—		169
Derivatives designated as fair value hedges
Put Options (2)	Mark-to-market energy assets	—		20
Total asset derivatives		$	—	$	385

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

⁽¹⁾  We purchased a call option for the propane price cap program in May 2013. The call option was fully exercised during 2014. There was no outstanding call option at March 31, 2014.

⁽²⁾  We purchased put options for the propane price cap program in June 2013. The put options expired in March 2014.

The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows:

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended March 31,
(in thousands)	(Loss) on Derivatives	2014			2013
Derivatives not designated as hedging instruments:
Unrealized gain (loss) on forward contracts	Revenue	$	(68	)	214
Call Option	Cost of sales	137			—
Derivatives designated as fair value hedges:
Put/Call Options	Cost of sales	(20		)	(28		)
Total		$	49		$	186

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The effects of trading activities on the condensed consolidated statements of income are the following:

	Location in the	For the Three Months Ended March 31,
(in thousands)	Statements of Income	2014			2013
Realized gain on forward contracts	Revenue	$	1,246		$	74
Unrealized gain (loss) on forward contracts	Revenue	(68		)	214
Total		$	1,178		$	288

13. 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).

We did not have mark-to-market energy assets or liabilities at March 31, 2014. The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at March 31, 2014 and December 31, 2013:

			Fair Value Measurements Using:
March 31, 2014	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—guaranteed income fund	$	365	$	—	$	—	$	365
Investments—other	$	2,586	$	2,586	$	—	$	—

			Fair Value Measurements Using:
December 31, 2013 (in thousands)	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Investments—guaranteed income fund	$	458	$	—	$	—	$	458
Investments—other	$	2,640	$	2,640	$	—	$	—
Mark-to-market energy assets, incl. put/call options	$	385	$	—	$	385	$	—
Liabilities:
Mark-to-market energy liabilities	$	127	$	—	$	127	$	—

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

	Three Months Ended   March 31,
	2014			2013
(in thousands)
Beginning Balance	$	458		$	—
Transfers in due to change in trustee	—			425
Purchases and adjustments	(94		)	(13		)
Transfers	—			(16		)
Investment income	1			2
Ending Balance	$	365		$	398

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

The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of March 31, 2014 and December 31, 2013:

Level 1 Fair Value Measurements:

Investments- equity securities—The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.

Investments- other—The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares.

Level 2 Fair Value Measurements:

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

Propane put/call options—The fair value of the propane put/call options are determined using market transactions for similar assets and liabilities in either the listed or OTC markets.

Level 3 Fair Value Measurements:

Investments- guaranteed income fund—The fair values of these investments are recorded at the contract value, which approximates their fair value.

At March 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 March 31, 2014, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of $121.2 million. This compares to a fair value of $137.9 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At December 31, 2013, long-term debt, including the current maturities but excludes a capital lease obligation, 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.

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14. Long-Term Debt

Our outstanding long-term debt is shown below:

	March 31,			December 31,
(in thousands)	2014			2013
FPU secured first mortgage bonds (A) :
9.08% bond, due June 1, 2022	$	7,967		$	7,967
Uncollateralized senior notes:
7.83% note, due January 1, 2015	2,000			2,000
6.64% note, due October 31, 2017	10,909			10,909
5.50% note, due October 12, 2020	14,000			14,000
5.93% note, due October 31, 2023	30,000			30,000
5.68% note, due June 30, 2026	29,000			29,000
6.43% note, due May 2, 2028	7,000			7,000
3.73% note, due December 16, 2028	20,000			20,000
Convertible debentures:
8.25% due March 1, 2014	—			646
Promissory notes	360			445
Capital lease obligation	6,914			6,978
Total long-term debt	128,150			128,945
Less: current maturities	(10,955		)	(11,353		)
Total long-term debt, net of current maturities	$	117,195		$	117,592

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

Uncollateralized Senior Notes

In September 2013, we entered into a Note Agreement to issue $70.0 million in aggregate of unsecured Senior Notes to the Note Holders. In December 2013, we issued Series A Notes of unsecured Senior Notes, with an aggregate principal amount of $20.0 million, at a rate of 3.73 percent. Series B of the unsecured Senior Notes, with an aggregate principal amount of $50.0 million, will be issued on May 15, 2014, at a rate of 3.88 percent. The proceeds received from the issuances of the Notes will be used to reduce our short-term borrowings under our lines of credit and to fund capital expenditures.

Convertible Debentures

During the first two months of 2014, Convertible Debentures totaling $537,000 were converted to stock and $109,000 were redeemed for cash. As of March 1, 2014, we no longer have any outstanding Convertible Debentures.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K for the year ended December 31, 2013, including the audited consolidated financial statements and notes thereto.

Safe Harbor for Forward-Looking Statements

We make statements in this Quarterly Report on Form 10-Q that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. One can typically identify forward-looking statements by the use of forward-looking words, such as “project,” “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “continue,” “potential,” “forecast” or other similar words, or future or conditional verbs such as “may,” “will,” “should,” “would” or “could.” These statements represent our intentions, plans, expectations, assumptions and beliefs about future financial performance, business strategy, projected plans and objectives of the Company. These statements are subject to many risks, uncertainties and other important factors that could cause actual results to differ materially from those expressed in the forward-looking statements. Such factors include, but are not limited to:

• state and federal legislative and regulatory initiatives (including deregulation) that affect cost and investment recovery, have an impact on rate structures, and affect the speed at and degree to which competition enters the electric and natural gas industries;

• the outcomes of regulatory, tax, environmental and legal matters, including whether pending matters are resolved within current estimates and whether the costs associated with such matters are adequately covered by insurance or recovered in rates;

• the loss of customers due to a government-mandated sale of our utility distribution facilities;

• industrial, commercial and residential growth or contraction in our markets or service territories;

• the weather and other natural phenomena, including the economic, operational and other effects of hurricanes, ice storms and other damaging weather events;

• the timing and extent of changes in commodity prices and interest rates;

• general economic conditions, including any potential effects arising from terrorist attacks and any consequential hostilities or other hostilities or other external factors over which we have no control;

• changes in environmental and other laws and regulations to which we are subject and changes in environmental conditions of property that we now or may in the future own or operate;

• the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;

• the impact to the asset values and resulting higher costs and funding obligations of the Company's pension and other postretirement benefit plans as a result of potential downturns in the financial markets, lower discount rates or impacts associated with the Patient Protection and Affordable Care Act;

• the creditworthiness of counterparties with which we are engaged in transactions;

• the extent of success in connecting natural gas and electric supplies to transmission systems and in expanding natural gas and electric markets;

• the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;

• conditions of the capital markets and equity markets during the periods covered by the forward-looking statements;

• the ability to successfully execute, manage and integrate merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture;

• the ability to establish and maintain new key supply sources;

• the effect of spot, forward and future market prices on our distribution, wholesale marketing and energy trading businesses;

• the effect of competition on our businesses;

• the ability to construct facilities at or below estimated costs;

• risks related to cyber-attack or failure of information technology systems; and

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• changes in technology affecting our advanced information services business.

Introduction

We are a diversified energy company engaged, directly or through our operating divisions and subsidiaries, in regulated energy businesses, unregulated energy businesses, and other unregulated businesses, including advanced information services.

Our strategy is focused on growing earnings from a stable utility foundation and investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. The key elements of this strategy include:

• executing a capital investment program in pursuit of organic growth opportunities that generate returns equal to or greater than our cost of capital;

• expanding the regulated energy distribution and transmission businesses into new geographic areas and providing new services in our current service territories;

• expanding the propane distribution business in existing and new markets through leveraging our community gas system services and our bulk delivery capabilities;

• expanding both our regulated energy and unregulated energy businesses through strategic acquisitions;

• utilizing our expertise across our various businesses to improve overall performance;

• pursuing and entering new unregulated energy markets and business lines that will complement our existing strategy and operating units;

• enhancing marketing channels to attract new customers;

• providing reliable and responsive customer service to existing customers so they become our best promoters;

• engaging our customers through a distinctive service excellence initiative;

• developing and retaining a high-performing team that advances our goals;

• empowering and engaging our employees at all levels to live our brand and vision;

• demonstrating community leadership and engaging our local communities and governments in a cooperative and mutually beneficial way;

• maintaining a capital structure that enables us to access capital as needed;

• maintaining a consistent and competitive dividend for shareholders; and

• creating and maintaining a diversified customer base, energy portfolio and utility foundation.

Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is normally highest due to colder temperatures.

The following discussions and those elsewhere in the document on operating income and segment results include the use of the term “gross margin.” Gross margin is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased cost of natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. We believe that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by us under our allowed rates for regulated energy operations and under our competitive pricing structure for non-regulated segments. Our management uses gross margin in measuring our business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.

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Results of Operations For Three Months Ended March 31, 2014

Overview and Highlights

Our net income for the three months ended March 31, 2014 was $17.7 million, or $1.82 per share (diluted). This represents an increase of $2.8 million, or $0.28 per share (diluted), compared to net income of $14.9 million, or $1.54 per share (diluted), as reported for the same quarter in 2013.

	Three Months Ended
	March 31,						Increase
	2014			2013			(decrease)
(in thousands except per share)
Business Segment:
Regulated Energy	$	21,091		$	17,306		$	3,785
Unregulated Energy	10,858			9,369			1,489
Other	(326		)	(125		)	(201		)
Operating Income	31,623			26,550			5,073
Other Income	6			289			(283		)
Interest Charges	2,155			2,072			83
Income Taxes	11,793			9,898			1,895
Net Income	$	17,681		$	14,869		$	2,812
Earnings Per Share of Common Stock
Basic	$	1.83		$	1.55		$	0.28
Diluted	$	1.82		$	1.54		$	0.28

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Key variances included:

(in thousands, except per share)	Pre-tax Income			Net Income			Earnings Per Share
First Quarter of 2013 Reported Results	$	24,767		$	14,869		$	1.54
Adjusting for unusual items:
Weather impact (due primarily to colder temperatures in 2014)	2,711			1,628			0.17
	2,711			1,628			0.17
Increased (Decreased) Gross Margins:
Major Projects (See Major Projects Highlights table)
Contribution from Sandpiper	4,289			2,575			0.27
Service expansions	1,423			855			0.08
Increased wholesale propane sales	1,032			620			0.06
Propane wholesale marketing	889			534			0.06
GRIP	724			435			0.04
Lower retail propane margins	(516		)	(310		)	(0.03		)
Contribution from other acquisitions	502			302			0.03
	8,343			5,011			0.51
Increased Other Operating Expenses:
Expenses from acquisitions	(2,117		)	(1,271		)	(0.14		)
Higher payroll costs	(1,161		)	(697		)	(0.07		)
Increased accruals for incentive compensation	(980		)	(589		)	(0.06		)
Higher depreciation, asset removal and property tax costs due to new capital investments	(726		)	(436		)	(0.04		)
Higher benefits costs	(674		)	(405		)	(0.04		)
	(5,658		)	(3,398		)	(0.35		)
Net Other Changes	(689		)	(429		)	(0.05		)
First Quarter of 2014 Reported Results	$	29,474		$	17,681		$	1.82

Summary of Key Factors

The following information highlights certain key factors contributing to our results for the quarter ended March 31, 2014.

Major Projects

Acquisition

In May 2013, we completed the purchase of the operating assets of ESG. Approximately 11,000 residential and commercial underground propane distribution system customers acquired in this transaction are now being served by Sandpiper under the tariff approved by the Maryland PSC. We are evaluating the potential conversion of some of these systems to natural gas. This acquisition is expected to be accretive to earnings per share in the first full year of operations. We generated $4.3 million in additional gross margin from Sandpiper and incurred $1.4 million in other operating expenses for the three months ended March 31, 2014.

Service Expansions

During 2013, Eastern Shore, our interstate natural gas transmission subsidiary, commenced new transmission services to local distribution utilities and industrial customers in Delaware and Maryland. These new services generated additional gross margin of $1.2 million in the first quarter of 2014 over the same quarter in 2013.

In August 2013, Peninsula Pipeline, our intrastate natural gas transmission subsidiary, commenced a new firm transportation service in Florida with an unaffiliated utility. This new service generated $210,000 in gross margin for the three months ended March 31, 2014.

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The following Major Project Highlights table summarizes our major projects initiated in 2011, 2012 and 2013 (dollars in thousands):

	Gross Margin
	Q1 2014		2014 (1)
Acquisition:
ESG acquisition being served by Sandpiper in Worcester County, Maryland (2)	$	4,289	$	9,817
Service Expansions
Natural Gas Distribution:
Long-term
Sussex County, Delaware (3)	$	204	$	694
Natural Gas Transmission:
Short-term
New Castle County, Delaware (4) (5)	$	—	$	1,862
Total Short-term	$	—	$	1,862
Long-term
Sussex County, Delaware (6)	$	431	$	1,725
New Castle County, Delaware (6) (7)	741		2,964
Nassau County, Florida (6)	327		1,300
Worcester County, Maryland (6)	137		547
Cecil County, Maryland (6)	287		1,147
Indian River County, Florida	210		840
Kent County, Delaware	665		2,660
Total Long-term	$	2,798	$	11,183
Total Service Expansions	$	3,002	$	13,739
Total Major Projects	$	7,291	$	23,556
Less: 2013 Margin	$	1,579	$	13,176
Incremental Margin in 2014 over 2013	$	5,712	$	10,380

⁽¹⁾ The figures provided represent the estimated annual gross margin.

⁽²⁾ During the quarter ended March 31, 2014, we incurred $1.4 million in other operating expenses related to Sandpiper's operation. We expect to incur $6.3 million in other operating expenses for the entire 2014.

⁽³⁾ These services generated $201,000 in gross margin in the first quarter of 2013.

⁽⁴⁾ Expected gross margin in 2014 includes $1.9 million from a new short-term contract for 50,000 Dts/d for one year, which began in April 2014.

⁽⁵⁾ During the first quarter of 2013 we provided short-term service and generated $40,000 in gross margin. The short-term service was displaced by the new long-term service in November 2013.

⁽⁶⁾ Gross margin generated by these services in the first quarter of 2013 was $345,000 for Sussex County, Delaware; $343,000 for New Castle County, Delaware; $332,000 for Nassau County, Florida; $98,000 for Worcester County Maryland and $220,000 for Cecil County, Maryland.

⁽⁷⁾ Gross margin generated from this service expansion replaces the 10,000 Dts/d contract, which expired in November 2012. This expired contract had annualized gross margin of $1.1 million.

Future System Expansions and New Services

In June 2013, Eastern Shore filed an application with the FERC, seeking approval to construct a pipeline lateral to an industrial customer facility under construction in Kent County, Delaware. Upon completion of construction of the required facilities, this new service is expected to generate annual gross margin of approximately $1.2 million to $1.8 million. The new facilities include approximately 5.5 miles of lateral pipeline and metering facilities and extend from Eastern Shore's mainline to the new industrial customer facility. The construction of this lateral will not increase the overall capacity of Eastern Shore's mainline system. Service is projected to commence in January 2015.

Eastern Shore also executed a one-year contract with another industrial customer to provide an additional 50,000 Dts/d of service from April 2014 to April 2015. This short-term contract is expected to generate $1.9 million and $767,000 of gross margin in 2014 and 2015, respectively.

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GRIP

The Florida PSC approved the GRIP, which is designed to recover capital and other program-related-costs, inclusive of a return on investment, to replace older pipes in our Florida service territories. We received approval to invest $75 million to replace qualifying distribution mains and services (any material other than coated steel or plastic). Since the beginning of 2013, $21.4 million has been invested, $4.6 million of which is in 2014. These investments generated additional gross margin of $724,000 for the three months ended March 31, 2014 over the same quarter in 2013.

Investing in Growth

We continue to expand our resources and capabilities to support growth. Our Delmarva natural gas distribution operation is in the early stages of natural gas distribution expansions in Sussex County, Delaware, and Worcester and Cecil Counties, Maryland. These expansions will require not only the construction or conversion of distribution facilities, but also the conversion of residential customers’ appliances or equipment. We have begun the process of reorganizing our Delmarva natural gas distribution operation and expect to increase staffing to support future expansions. Eastern Shore expects to increase its staffing to support recent and future expansions of its facilities and services. Finally, to increase our overall capabilities to support sustained future growth, resources have been added in our corporate shared services departments. For the three months ended March 31, 2014, payroll expenses for our Regulated Energy segment increased by $616,000, compared to the same quarter in 2013, as a result of the increased resources. We expect to make additional investments in human resources, as needed, to further develop our capability to capitalize on future growth opportunities.

Weather and Consumption

Temperatures on the Delmarva Peninsula and in Florida during the first three months of 2014 were significantly colder than the first quarter of 2013. The following tables highlight the HDD and CDD information for the quarter ended March 31, 2014 and 2013 and the gross margin variance resulting from the weather fluctuation in those periods.

HDD and CDD Information

	Three Months Ended
	March 31,
	2014		2013		Variance
Delmarva
Actual HDD	2,717		2,407		310
10-Year Average HDD ("Normal")	2,361		2,377		(16	)
Variance from Normal	356		30
Florida
Actual HDD	557		468		89
10-Year Average HDD ("Normal")	529		541		(12	)
Variance from Normal	28		(73	)
Florida
Actual CDD	42		81		(39	)
10-Year Average CDD ("Normal")	74		75		(1	)
Variance from Normal	(32	)	6

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Gross Margin Variance attributed to Weather

(in thousands)	2014 vs. 2013		2014 vs. Normal
Delmarva
Regulated Energy	$	511	$	617
Unregulated Energy	1,827		1,096
Florida
Regulated Energy	325		(207		)
Unregulated Energy	48		81
Total	$	2,711	$	1,587

Propane Prices

Our retail propane margins began to revert to more normal levels during the first quarter of 2014 as a significant increase in wholesale prices in late 2013 and early 2014 increased our average propane inventory cost. The decline in retail propane margins reduced gross margin by $516,000 during the first quarter of 2014, compared to the same quarter in 2013.

The increase in wholesale propane sales generated additional gross margin of $1.0 million due primarily to the wholesale propane supply agreements entered into in May 2013 with an affiliate of ESG.

Xeron, which benefits from price volatility in the propane wholesale market by entering into trading transactions, generated an increase in gross margin of $889,000 during the first quarter of 2014. Higher propane wholesale price volatility during the current quarter resulted in higher profits on executed trades.

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Regulated Energy

	Three Months Ended
	March 31,				Increase
	2014		2013		(decrease)
(in thousands)
Revenue	$	102,166	$	81,566	$	20,600
Cost of sales	54,307		41,615		12,692
Gross margin	47,859		39,951		7,908
Operations & maintenance	18,402		15,468		2,934
Depreciation & amortization	5,527		4,809		718
Other taxes	2,839		2,368		471
Other operating expenses	26,768		22,645		4,123
Operating Income	$	21,091	$	17,306	$	3,785

Operating income for the Regulated Energy segment for the quarter ended March 31, 2014 was $21.1 million, an increase of $3.8 million, or 22 percent. An increase in gross margin of $7.9 million was partially offset by an increase in other operating expenses of $4.1 million.

Gross Margin

Items contributing to the quarter-over-quarter increase of $7.9 million, or 20 percent, in gross margin are listed in the following table:

(in thousands)
Gross margin for the three months ended March 31, 2013	$	39,951
Factors contributing to the gross margin increase for the three months ended March 31, 2014:
Contributions from acquisitions	4,351
Service expansions	1,423
Increased customer consumption - weather and other	726
Additional revenue for GRIP in Florida	724
Other natural gas growth	496
Other	188
Gross margin for the three months ended March 31, 2014	$	47,859

Contributions from Acquisitions

In late May 2013, upon completion of the purchase of the ESG operating assets, Sandpiper began providing services to approximately 11,000 propane underground distribution system customers in Worcester County, Maryland under a tariff approved by the Maryland PSC. Sandpiper generated $4.3 million of gross margin in the first quarter of 2014. Also, the acquisition of operating assets of Fort Meade, Florida in December 2013 generated $62,000 of additional gross margin during the first quarter of 2014.

Service Expansions

Increased gross margin from service expansions was due primarily to the following:

• $400,000 from expansions completed in 2013 that facilitated new natural gas transmission and distribution services in Sussex County, Delaware; Worcester and Cecil Counties, Maryland; and Nassau and Indian River Counties, Florida.

• $1.1 million from long-term transmission services commenced in November 2013, when Eastern Shore began providing long-term transmission services to industrial customers, located in New Castle and Kent Counties, Delaware. These long-term transmission services, which displaced short-term services that Eastern Shore provided to these customers from May through October 2013, are expected to generate $4.3 million of annual gross margin. They also displace annualized gross margin of $1.1 million from an older contract, which expired in November 2012.

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Increased Customer Consumption—Weather and Other

Higher customer consumption due to colder temperatures on the Delmarva Peninsula and in Florida during the first quarter of 2014 generated increased gross margin of approximately $511,000 and $325,000, respectively.

Additional Revenue for GRIP in Florida

In August 2012, the Florida PSC approved the GRIP for FPU and Chesapeake's Florida division. This program provides additional revenue designed to recover capital and other program-related costs, inclusive of an appropriate rate of return on investment, associated with accelerating the replacement of qualifying distribution mains and services. During the first quarter of 2014, FPU and Chesapeake's Florida division recorded $724,000 in additional gross margin as a result of the increased GRIP capital expenditures.

Other Natural Gas Growth

Increased gross margin from other natural growth was due primarily to the following:

• $462,000 from Florida customer growth due primarily to new services to commercial and industrial customers.

• $280,000 from three-percent residential customer growth, as well as growth in commercial and industrial customers, in our Delmarva natural gas distribution operation.

• These increases were partially offset by reduced interruptible service, which lowered lower gross margin by $293,000.

Other Operating Expenses

Other operating expenses for the Regulated Energy segment increased by $4.1 million, or 18 percent, in the first quarter of 2014, compared to the same quarter in 2013. The increase in other operating expenses was due primarily to: (a) $1.4 million in other operating expenses associated with Sandpiper's operations; (b) $744,000 in higher depreciation expense, amortization, asset removal and property tax costs associated with capital investments to support growth and maintain system integrity; (c) $643,000 in increased accruals for incentive bonuses as a result of strong financial performance; (d) $616,000 in higher payroll costs to support recent growth and expand our capabilities for future growth; and (e) $478,000 in higher benefits costs.

Unregulated Energy

	Three Months Ended
	March 31,				Increase
	2014		2013		(decrease)
(in thousands)
Revenue	$	79,973	$	54,991	$	24,982
Cost of sales	59,159		37,807		21,352
Gross margin	20,814		17,184		3,630
Operations & maintenance	8,424		6,387		2,037
Depreciation & amortization	980		900		80
Other taxes	552		528		24
Other operating expenses	9,956		7,815		2,141
Operating Income	$	10,858	$	9,369	$	1,489

Operating income for the Unregulated Energy segment for the first quarter of 2014 was $10.9 million, an increase of $1.5 million, or 16 percent. An increase in gross margin of $3.6 million was partially offset by an increase in other operating expenses of $2.1 million.

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Gross Margin

Items contributing to the quarter-over-quarter increase of $3.6 million, or 21 percent, in gross margin are as follows:

(in thousands)
Gross margin for the three months ended March 31, 2013	$	17,184
Factors contributing to the gross margin increase for the three months ended March 31, 2014:
Increased customer consumption—weather and other	1,860
Increased wholesale propane sales	1,032
Increased margins from propane wholesale marketing	889
Decrease in retail propane margins	(516		)
Contributions from acquisitions	440
Other	(75		)
Gross margin for the three months ended March 31, 2014	$	20,814

Increased Customer Consumption—Weather and Other

Increased gross margin from higher customer consumption of $1.9 million is due primarily to colder temperatures on Delmarva Peninsula during the first quarter of 2014.

Increased Wholesale Propane Sales

An increase in wholesale propane sales generated additional gross margin of $1.0 million due primarily to higher wholesale sales as a result of the supply agreement entered into in May 2013 with an affiliate of ESG.

Increased Margins from Propane Wholesale Marketing

Xeron generated additional gross margin of $889,000 during the first quarter of 2014 as a result of: (a) trades executed with higher margins due primarily to higher price volatility in the wholesale propane market, and (b) a 20-percent increase in trading activity.

Decrease in Retail Propane Margins

Lower retail propane margins for our Delmarva propane distribution operation decreased gross margin by $841,000, partially offset by $325,000 in higher retail propane margins in Florida. Retail propane margins began to return to more normal levels on the Delmarva Peninsula during the first quarter of 2014 as a significant increase in wholesale prices in late 2013 and early 2014 increased our average propane inventory costs. In contrast, retail propane margins on the Delmarva Peninsula were unusually strong in the first quarter of 2013 as a 27-percent decline in propane costs from lower propane wholesale prices in late 2012 and early 2013 significantly outpaced a slight decline in retail prices. The propane retail price per gallon is subject to various market conditions, including competition with other propane suppliers and the availability and price of alternative energy sources, and may fluctuate based on changes in demand, supply and other energy commodity prices.

Contributions from Acquisitions

The acquisitions of the operating assets of Glades in February 2013 and Austin Cox in June 2013 generated $146,000 and $294,000, respectively, of additional gross margin during the first quarter of 2014.

Other Operating Expenses

Other operating expenses for the Unregulated Energy segment increased by $2.1 million, or 27 percent, in the first quarter of 2014, compared to the same quarter in 2013. The increase in other operating expenses was due primarily to: (a) $632,000 in additional expenses incurred by the 2013 acquisitions; (b) $392,000 in higher payroll expense due to increased seasonal overtime and resources; and (c) $389,000 in increased accruals for incentive bonuses as a result of strong financial results.

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Other

	Three Months Ended
	March 31,						Increase
	2014			2013			(decrease)
(in thousands)
Revenue	$	4,198		$	4,171		$	27
Cost of sales	2,166			2,282			(116		)
Gross margin	2,032			1,889			143
Operations & maintenance	1,948			1,621			327
Depreciation & amortization	128			111			17
Other taxes	282			282			—
Other operating expenses	2,358			2,014			344
Operating Loss—Other	$	(326	)	$	(125	)	$	(201	)

The “Other” segment reported an operating loss of $326,000 in the first quarter of 2014 compared to $125,000 in the first quarter of 2013. The increase in operating loss was attributable to a $344,000 increase in operating expenses partially offset by a $143,000 increase in gross margin.

Interest Charges

Interest charges for the three months ended March 31, 2014 increased by approximately $83,000, or four percent, compared to the same quarter in 2013. The increase in interest charges is attributable primarily to an increase of $121,000 in short-term interest expense due to higher borrowings in the first quarter of 2014. This increase was partially offset by decreases of $39,000 in other long-term interest expense due to scheduled repayments.

Income Taxes

Income tax expense was $11.8 million in the first quarter of 2014, compared to $9.9 million in the same quarter in 2013. The increase in income tax expense was due to higher taxable income. Our effective income tax rate was 40.0 percent for the first quarters of 2014 and 2013.

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FINANCIAL POSITION, LIQUIDITYAND CAPITAL RESOURCES

Our capital requirements reflect the capital-intensive and seasonal nature of our business and are principally attributable to investment in new plant and equipment, retirement of outstanding debt and seasonal variability in working capital. We rely on cash generated from operations, short-term borrowings, and other sources to meet normal working capital requirements and to finance capital expenditures.

Our energy businesses are weather-sensitive and seasonal. We normally generate a large portion of our annual net income and subsequent increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas, electricity, and propane delivered to customers during the peak heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely depleted in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.

Capital expenditures, which are our investments in new or acquired plant and equipment, are our largest capital requirements. We budgeted $110.9 million for capital expenditures during 2014. The following table shows the 2014 capital expenditure budget by segment:

(dollars in thousands)
Regulated Energy:
Natural gas distribution	$	53,444
Natural gas transmission	26,857
Electric distribution	4,697
Total Regulated Energy	84,998
Unregulated Energy:
Propane distribution	5,846
Other unregulated energy	9,823
Total Unregulated Energy	15,669
Other
Advanced information services	846
Other	9,400
Total Other	10,246
Total 2014 projected capital expenditures	$	110,913

We expect to fund the 2014 capital expenditures program from short-term borrowings, cash provided by operating activities, and other sources. In addition, as further discussed in the Capital Structure section below, we will be issuing $50.0 million of our long-term uncollateralized senior notes in May 2014.

The capital expenditures program is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, customer growth in existing areas, regulation, new growth or acquisition opportunities and availability of capital. Historically, actual capital expenditures have typically lagged behind the budgeted amounts.

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Capital Structure

We are committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access capital markets when required. This commitment, along with adequate and timely rate relief for our regulated operations, is intended to ensure our ability to attract capital from outside sources at a reasonable cost. We believe that the achievement of these objectives will provide benefits to our customers, creditors and investors. The following presents our capitalization, excluding and including short-term borrowings, as of March 31, 2014 and December 31, 2013:

	March 31, 2014				December 31, 2013
(in thousands)
Long-term debt, net of current maturities	$	117,195	29	%	$	117,592	30	%
Stockholders’ equity	293,251		71	%	278,773		70	%
Total capitalization, excluding short-term debt	$	410,446	100	%	$	396,365	100	%
	March 31, 2014				December 31, 2013
(in thousands)
Short-term debt	$	83,470	17	%	$	105,666	21	%
Long-term debt, including current maturities	128,150		25	%	128,945		25	%
Stockholders’ equity	293,251		58	%	278,773		54	%
Total capitalization, including short - term debt	$	504,871	100	%	$	513,384	100	%

In September 2013, we entered into an agreement with the Note Holders to issue $70.0 million of uncollateralized senior notes.

We issued $20.0 million of these notes in December 2013. We will be issuing the remaining $50.0 million of the senior notes in May 2014. The proceeds from this issuance will be used to reduce our short-term borrowings and fund capital expenditures.

Included in the long-term debt balances at March 31, 2014 and December 31, 2013 was a capital lease obligation associated with Sandpiper's capacity, supply and operating agreement ($5.8 million and $6.1 million, respectively, net of current maturities and $6.9 million and $7.0 million, respectively, including current maturities). At the closing of the ESG acquisition in May 2013, Sandpiper entered into this agreement, which has a six-year term. The capacity portion of this agreement is accounted for as a capital lease.

Short-term Borrowings

Our outstanding short-term borrowings at March 31, 2014 and December 31, 2013 were $83.5 million and $105.7 million, respectively, at weighted average interest rates of 1.21 percent and 1.25 percent, respectively.

As of March 31, 2014, we had five unsecured short-term credit facilities with two financial institutions for a total of $165.0 million. Two of these unsecured bank lines, totaling $85.0 million, are available under committed lines of credit. Advances offered under the uncommitted lines of credit, totaling $40.0 million, are subject to the discretion of the banks. None of these unsecured bank lines of credit requires compensating balances. The remaining $40.0 million of our short-term credit facilities is structured in the form of a revolving credit note.

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Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the three months ended March 31, 2014 and 2013:

	Three Months Ended
	March 31,
	2014			2013
(in thousands)
Net cash provided by (used in):
Operating activities	$	45,999		$	35,160
Investing activities	(18,461		)	(18,832		)
Financing activities	(26,103		)	(17,081		)
Net increase (decrease) in cash and cash equivalents	1,435			(753		)
Cash and cash equivalents—beginning of period	3,356			3,361
Cash and cash equivalents—end of period	$	4,791		$	2,608

Cash Flows Provided By Operating Activities

Changes in our cash flows from operating activities are attributable primarily to changes in net income, non-cash adjustments for depreciation and deferred income taxes and working capital. Changes in working capital are determined by a variety of factors, including weather, the prices of natural gas, electricity and propane, the timing of customer collections, payments for purchases of natural gas, electricity and propane, and deferred fuel cost recoveries.

We normally generate a large portion of our annual net income and subsequent increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas and propane delivered by our natural gas and propane distribution operations to customers during the peak heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.

During the three months ended March 31, 2014 and 2013, net cash provided by operating activities was $46.0 million and $35.2 million, respectively, resulting in an increase in cash flows of $10.8 million. Significant operating activities generating the cash flow change were as follows:

• The changes in net accounts receivable and payable increased the cash flows by $8.3 million, due primarily to the timing of the collections and payments associated with trading contracts entered into by our propane wholesale and marketing subsidiary;

• The changes in net regulatory assets and liabilities decreased the cash flows by $6.4 million, due primarily to a change in fuel costs collected through fuel cost recovery;

• Net cash flows from changes in propane and natural gas inventories increased by approximately $3.2 million as a result of the higher use of propane and natural gas usage, which decreases the levels of our inventory;

• Net income, adjusted for reconciling activities, increased cash flows by $2.3 million, due primarily to higher earnings and increased non-cash items, such as depreciation and amortization expenses included in our earnings.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $18.5 million and $18.8 million during the three months ended March 31, 2014 and 2013, respectively, resulting in an increase in cash flows of $371,000. Significant investing activities generating the cash flow change were as follows:

• Net cash of $2.4 million was used in connection with the Glades acquisition during the first quarter of 2013; there was not a corresponding transaction during the same period of 2014;

• Cash paid for capital expenditures increased by $2.1 million to $18.5 million for the first three months of 2014, compared to $16.4 million for the same period in 2013.

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Cash Flows Used by Financing Activities

Net cash used in financing activities totaled $26.1 million and $17.1 million in the first three months of 2014 and 2013, respectively, resulting in a decrease of $9.0 million in cash flows. Significant financing activities generating the cash flow change were as follows:

• During the first three months of 2014 and 2013, we had net repayments of $21.7 million and $13.6 million, respectively, under our line of credit agreements, resulting in a net cash decrease of $8.1 million. Changes in cash overdrafts decreased by $584,000, resulting in a period-over-period net cash decrease.

Off-Balance Sheet Arrangements

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily our propane wholesale marketing subsidiary and natural gas marketing subsidiary. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. None of these subsidiaries has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at March 31, 2014 was $31.6 million, with the guarantees expiring on various dates through February, 2015.

In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million, which was renewed through September 12, 2014, related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for $1.1 million, which expires on December 2, 2014, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company in 2010, we renewed and decreased the letter of credit for $304,000 to our former primary insurance company, which will expire on June 1, 2014. There have been no draws on these letters of credit as of March 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 firm transportation service agreement between our Delaware and Maryland divisions and TETLP.

Contractual Obligations

There has not been any material change in the contractual obligations presented in our 2013 Annual Report on Form 10-K, except for commodity purchase obligations and forward contracts entered into in the ordinary course of our business. The following table summarizes the commodity and forward contract obligations at March 31, 2014.

	Payments Due by Period
Purchase Obligations	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
(in thousands)
Commodities (1)	$	13,049	$	267	$	4	$	—	$	13,320
Propane	6,546		17,200		5,219		—		28,965
Total Purchase Obligations	$	19,595	$	17,467	$	5,223	$	—	$	42,285

⁽¹⁾  In addition to the obligations noted above, the natural gas, electric and propane distribution operations have agreements with commodity suppliers that have provisions with no minimum purchase requirements. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts allow the suppliers to reduce the amounts available in the winter season if we do not purchase specified amounts during the summer season. Under these contracts, the commodity prices will fluctuate as market prices fluctuate.

Rates and Regulatory Matters

Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by the respective state PSC; Eastern Shore is subject to regulation by the FERC and Peninsula Pipeline is subject to regulation by the Florida PSC. At March 31, 2014, we were involved in rate filings and/or regulatory matters in each of the jurisdictions in which we operate. Each of these rate filings and/or regulatory matters is fully described in Note 4, Rates and Other Regulatory Activities, to the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

On April 28, 2014, FPU filed a base rate proceeding for its electric distribution operation. FPU is seeking interim rate relief of approximately $2.4 million and final rate relief of approximately $5.9 million. The interim rate relief requested is based on the twelve-month period ended September 30, 2013. We expect the interim rate relief to be determined in the second quarter of 2014.

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Any increase to our rates as a result of this interim rate relief will be subject to refund based on the outcome of the final rate relief, which we expect to occur during the fourth quarter of 2014.

Recent Authoritative Pronouncements on Financial Reporting and Accounting

Recent accounting developments applicable to us and their impact on our financial position, results of operations and cash flows are described in Note 1,Summary of Accounting Policies, to the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk represents the potential loss arising from adverse changes in market rates and prices. Long-term debt is subject to potential losses based on changes in interest rates. Our long-term debt consists of fixed-rate senior notes and secured debt. All of our long-term debt, excluding a capital lease obligation, is fixed-rate debt and was not entered into for trading purposes. The carrying value of our long-term debt, including current maturities but excluding a capital lease obligation, was $121.2 million at March 31, 2014, as compared to a fair value of $137.9 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 with adjustments for duration, optionality, credit risk, and risk profile. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowing, based in part on the fluctuation in interest rates.

Our propane distribution business is exposed to market risk as a result of propane storage activities and entering into fixed price contracts for supply. We can store up to approximately 6.1 million gallons of propane (including leased storage and rail cars) during the winter season to meet our customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline. To mitigate the impact of price fluctuations, we have adopted a Risk Management Policy that allows the propane distribution operation to enter into fair value hedges or other economic hedges of our inventory.

Our propane wholesale marketing operation is a party to natural gas liquids (primarily propane) forward contracts, with various third parties, which require that the propane wholesale marketing operation purchase or sell natural gas liquids at a fixed price at fixed future dates. At expiration, the contracts are typically settled financially without taking physical delivery of propane. The propane wholesale marketing operation also enters into futures contracts that are traded on the IntercontinentalExchange. In certain cases, the futures contracts are settled by the payment or receipt of a net amount equal to the difference between the current market price of the futures contract and the original contract price; however, they may also be settled by physical receipt or delivery of propane.

The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing business is subject to commodity price risk on its open positions to the extent that market prices for natural gas liquids deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts is monitored daily for compliance with our Risk Management Policy, which includes volumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed daily by our oversight officials. In addition, the Risk Management Committee reviews periodic reports on markets and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. We did not have any outstanding forward and futures contracts at March 31, 2014.

Our natural gas distribution, electric distribution and natural gas marketing operations have entered into agreements with various 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.

At March 31, 2014, we did not have any outstanding forward or futures contracts. At December 31, 2013, we marked these forward and other contracts to market, using market transactions in either the listed or OTC markets, which resulted in the following assets and liabilities:

(in thousands)	March 31, 2014		December 31, 2013
Mark-to-market energy assets, including call options	$	—	$	385
Mark-to-market energy liabilities	$	—	$	127

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of the Company, with the participation of other Company officials, have evaluated our “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e), promulgated under the Securities Exchange Act of 1934, as amended) as of March 31, 2014. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2014.

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2014, there was no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

As disclosed in Note 6, Other Commitments and Contingencies, of the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we are involved in certain legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental or regulatory agencies concerning rates and other regulatory actions. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on our condensed consolidated financial position, results of operations or cash flows.

Item 1A. Risk Factors

Our business, operations, and financial condition are subject to various risks and uncertainties. The risk factors described in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K, for the year ended December 31, 2013, should be carefully considered, together with the other information contained or incorporated by reference in this Quarterly Report on Form 10-Q and in our other filings with the SEC in connection with evaluating the Company, our business and the forward-looking statements contained in this Report. Additional risks and uncertainties not known to us at present, or that we currently deem immaterial also may affect the Company. The occurrence of any of these known or unknown risks could have a material adverse impact on our business, financial condition, and results of operations.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

	Total Number of Shares	Average Price Paid		Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Number of Shares That May Yet Be Purchased Under the Plans
Period	Purchased	per Share		or Programs (2)	or Programs (2)
January1, 2014 through January 31, 2014 (1)	236	$	59.01	—	—
February 1, 2014 through February 28, 2014	—	$	—	—	—
March 1, 2014 through March 31, 2014	—	$	—	—	—
Total	236	$	59.01	—	—

⁽¹⁾  Chesapeake purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain Directors and Senior Executives under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Item 8 under the heading “Notes to the Consolidated Financial Statements—Note 16, Employee Benefit Plans” in our latest Annual Report on Form 10-K for the year ended December 31, 2013. During the quarter ended March 31, 2014, 236 shares were purchased through the reinvestment of dividends on deferred stock units.

⁽²⁾  Except for the purposes described in Footnote ⁽¹⁾, Chesapeake has no publicly announced plans or programs to repurchase its shares.

Item 3. Defaults upon Senior Securities

None.

Item 5. Other Information

None.

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Item 6. Exhibits

31.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated May 6, 2014.
31.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated May 6, 2014.
32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 6, 2014.
32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 6, 2014.
101.INS*	XBRL Instance Document.
101.SCH*	XBRL Taxonomy Extension Schema Document.
101.CAL*	XBRL Taxonomy Extension Calculation Linkbase Document.
101.DEF*	XBRL Taxonomy Extension Definition Linkbase Document.
101.LAB*	XBRL Taxonomy Extension Label Linkbase Document.
101.PRE*	XBRL Taxonomy Extension Presentation Linkbase Document.

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

CHESAPEAKE UTILITIES CORPORATION

/S/ BETH W. COOPER

Beth W. Cooper

Senior Vice President and Chief Financial Officer

Date: May 6, 2014

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EX-31.1

EXHIBIT 31.1

CERTIFICATE PURSUANT TO RULE 13A-14(A)

UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Michael P. McMasters, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2014 of Chesapeake Utilities Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–15(e) and 15d–15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2014

/S/ MICHAEL P. MCMASTERS

Michael P. McMasters

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATE PURSUANT TO RULE 13A-14(A)

UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Beth W. Cooper, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2014 of Chesapeake Utilities Corporation;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a–15(e) and 15d–15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a–15(f) and 15d–15(f)) for the registrant and have:

a) designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: May 6, 2014

/S/ BETH W. COOPER

Beth W. Cooper

Senior Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

Certificate of Chief Executive Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, Michael P. McMasters, President and Chief Executive Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Quarterly Report on Form 10-Q of Chesapeake Utilities Corporation (“Chesapeake”) for the period ended March 31, 2014, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/S/ MICHAEL P. MCMASTERS

Michael P. McMasters

May 6, 2014

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Chesapeake Utilities Corporation and will be retained by Chesapeake Utilities Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

EX-32.2

EXHIBIT 32.2

Certificate of Chief Financial Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, Beth W. Cooper, Senior Vice President and Chief Financial Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Quarterly Report on Form 10-Q of Chesapeake Utilities Corporation (“Chesapeake”) for the period ended March 31, 2014, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/S/ BETH W. COOPER

Beth W. Cooper

May 6, 2014

A signed original of this written statement required by Section 906 of the Sarbanes-Oxley Act of 2002, or other document authenticating, acknowledging, or otherwise adopting the signature that appears in typed form within the electronic version of this written statement required by Section 906, has been provided to Chesapeake Utilities Corporation and will be retained by Chesapeake Utilities Corporation and furnished to the Securities and Exchange Commission or its staff upon request.

XML

Other Commitments and Contingencies - Additional Information (Detail) (USD $)	0 Months Ended	3 Months Ended
	May 31, 2013 gal	Mar. 31, 2014	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	7,400,000
Total liabilities to tangible net worth minimum times		3.75
Fixed charge coverage ratio minimum times		1.5
Time to cure ratio		30 days
Funds from operations interest coverage ratio minimum times		2
Total debt to capital maximum		0.65
Document Period End Date		Mar. 31, 2014
Maximum authorized liability under such guarantees and letters of credit		$ 45,000,000
Aggregate guaranteed amount		31,600,000
Draws on letters of credit		0
Liability for Uncertain Tax Positions, Noncurrent		300,000	300,000
Unrecognized Tax Benefits		968,000	1,030,000
September 12, 2013 [Member]
Other Contingencies And Commitments [Line Items]
Amount of letter of credit to our current primary insurance company		1,000,000
December 2, 2013 [Member]
Other Contingencies And Commitments [Line Items]
Amount of letter of credit to our current primary insurance company		1,094,000
June 1, 2014 [Member]
Other Contingencies And Commitments [Line Items]
Amount of letter of credit to our current primary insurance company		304,000
TETLP Letter of Credit [Member] | Texas Eastern Transmission, LP [Member]
Other Contingencies And Commitments [Line Items]
Amount of letter of credit to our current primary insurance company		$ 2,300,000

XML

Derivative Instruments - Effects of Trading Activities on Condensed Consolidated Statements of Income (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Trading Activity, Gains and Losses, Net [Line Items]
Unrealized gain (loss) on forward contracts Revenue	$ 49	$ 186
Total	1,178	288
Revenue [Member] | Forward Contracts [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Unrealized gain (loss) on forward contracts Revenue	(68)	214
Revenue [Member] | Forward Contracts [Member] | Options [Member]
Trading Activity, Gains and Losses, Net [Line Items]
Gain (Loss) on Sale of Derivatives	$ 1,246	$ 74

XML

Share-Based Compensation - Share-Based Compensation Amounts Included in Net Income (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 638	$ 381
Less: tax benefit	(257)	(153)
Share-Based Compensation amounts included in net income	381	228
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	124	111
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 514	$ 270

XML

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013	Dec. 31, 2013 Quoted Prices in Active Markets (Level 1) [Member] Mark-to-market energy liabilities [Member]	Dec. 31, 2013 Quoted Prices in Active Markets (Level 1) [Member] Investments in equity securities [Member]	Dec. 31, 2013 Quoted Prices in Active Markets (Level 1) [Member] Investments - other [Member]	Dec. 31, 2013 Quoted Prices in Active Markets (Level 1) [Member] Mark To Market Energy Assets Including Put Option [Member]	Dec. 31, 2013 Significant Other Observable Inputs (Level 2) [Member] Mark-to-market energy liabilities [Member]	Dec. 31, 2013 Significant Other Observable Inputs (Level 2) [Member] Investments in equity securities [Member]	Dec. 31, 2013 Significant Other Observable Inputs (Level 2) [Member] Investments - other [Member]	Dec. 31, 2013 Significant Other Observable Inputs (Level 2) [Member] Mark To Market Energy Assets Including Put Option [Member]	Dec. 31, 2013 Significant Unobservable Inputs (Level 3) [Member] Mark-to-market energy liabilities [Member]	Dec. 31, 2013 Significant Unobservable Inputs (Level 3) [Member] Investments in equity securities [Member]	Dec. 31, 2013 Significant Unobservable Inputs (Level 3) [Member] Investments - other [Member]	Dec. 31, 2013 Recurring [Member] Mark-to-market energy liabilities [Member]	Dec. 31, 2013 Recurring [Member] Investments in equity securities [Member]	Dec. 31, 2013 Recurring [Member] Investments - other [Member]	Dec. 31, 2013 Recurring [Member] Mark To Market Energy Assets Including Put Option [Member]	Jun. 30, 2013 Recurring [Member] Estimate of Fair Value, Fair Value Disclosure [Member] Investments in guaranteed income fund [Member]	Jun. 30, 2013 Recurring [Member] Estimate of Fair Value, Fair Value Disclosure [Member] Investments - other [Member]	Jun. 30, 2013 Recurring [Member] Quoted Prices in Active Markets (Level 1) [Member] Investments in guaranteed income fund [Member]	Jun. 30, 2013 Recurring [Member] Quoted Prices in Active Markets (Level 1) [Member] Investments - other [Member]	Jun. 30, 2013 Recurring [Member] Significant Other Observable Inputs (Level 2) [Member] Investments in guaranteed income fund [Member]	Jun. 30, 2013 Recurring [Member] Significant Other Observable Inputs (Level 2) [Member] Investments - other [Member]	Jun. 30, 2013 Recurring [Member] Significant Unobservable Inputs (Level 3) [Member] Investments in guaranteed income fund [Member]	Jun. 30, 2013 Recurring [Member] Significant Unobservable Inputs (Level 3) [Member] Investments - other [Member]
Assets:
Investments	$ 2,951	$ 3,098		$ 0	$ 2,640			$ 0	$ 0			$ 458	$ 0		$ 458	$ 2,640		$ 365	$ 2,586	$ 0	$ 2,586	$ 0	$ 0	$ 365	$ 0
Mark-to-market energy assets						0				385	0						385
Liabilities:
Mark-to-market energy liabilities			$ 0				$ 127							$ 127

XML

Investments - Schedule of Investment (Detail) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Investment [Line Items]
Investments, at fair value	$ 2,951	$ 3,098

XML

Calculation of Earnings Per Share - Calculation of Basic and Diluted Earnings Per Share (Detail) (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended		12 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Calculation of Basic Earnings Per Share:
Net Income	$ 17,681	$ 14,869	$ 32,787
Weighted shares outstanding - Basic (in shares)	9,658,431	9,601,529
Basic Earnings Per Share (in usd per share)	$ 1.83	$ 1.55
Reconciliation of Numerator:
Net Income	17,681	14,869	32,787
Effect of 8.25% Convertible debentures	0	11
Adjusted numerator-Diluted	$ 17,681	$ 14,880
Reconciliation of Denominator:
Weighted shares outstanding - Basic (in shares)	9,658,431	9,601,529
Effect of dilutive securities:
Share-based Compensation (in shares)	35,003	23,132
8.25% Convertible debentures (in shares)	0	54,289
Adjusted denominator-Diluted (in shares)	9,693,434	9,678,950
Diluted Earnings Per Share (in usd per share)	$ 1.82	$ 1.54

XML

Fair Value of Financial Instruments - Additional Information (Detail) (USD $)	Mar. 31, 2014	Dec. 31, 2013
Fair Value Disclosures [Abstract]
Long-term debt including current maturities	$ 121,200,000	$ 122,000,000
Fair value of long-term debt	137,900,000	136,800,000
Total Long-term debt	$ 128,150,000	$ 128,945,000

XML

Calculation of Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Calculation of Basic and Diluted Earnings Per Share

	Three Months Ended
	March 31,
	2014		2013
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	17,681	$	14,869
Weighted average shares outstanding	9,658,431		9,601,529
Basic Earnings Per Share	$	1.83	$	1.55
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	17,681	$	14,869
Effect of 8.25% Convertible debentures (1)	—		11
Adjusted numerator—Diluted	$	17,681	$	14,880
Reconciliation of Denominator:
Weighted shares outstanding—Basic	9,658,431		9,601,529
Effect of dilutive securities:
Share-based Compensation	35,003		23,132
8.25% Convertible debentures (1)	—		54,289
Adjusted denominator—Diluted	9,693,434		9,678,950
Diluted Earnings Per Share	$	1.82	$	1.54

XML

Share-Based Compensation - Summary of Stock Activity under PIP (Detail) (Award to key employees [Member], USD $)	3 Months Ended
	Mar. 31, 2014
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Shares, Outstanding - December 31, 2013	80,761
Number of Shares, Granted	27,628
Number of Shares, Vested	26,364
Number of Shares, Outstanding - March 31, 2014	82,025.000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Fair Value, Outstanding - December 31, 2013	$ 42.30
Weighted Average Fair Value, Granted	$ 58.35
Weighted Average Fair Value, Vested	$ 40.30
Weighted Average Fair Value, Outstanding - March 31, 2014	$ 48.35

XML

Accumulated Other Comprehensive Income (Loss) - Reclassifications of Accumulated Other Comprehensive Loss (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Amortization of pension and postretirement items:
Tax benefit	$ 11,793		$ 9,898
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Amortization of pension and postretirement items:
Prior service cost	14	[1]	14	[1]
Net loss	66	[1]	106	[1]
Total before tax	(52)		(92)
Tax benefit	(21)		(37)
Net of tax	$ (31)		$ (55)

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

XML

Environmental Commitments and Contingencies - Additional Information (Detail) (USD $)	3 Months Ended
	Mar. 31, 2014 site	Mar. 31, 2013	Dec. 31, 2013
Environmental Commitments And Contingencies [Line Items]
Company's exposure in number of former Manufactured Gas Plant Sites	6
Environmental liabilities	$ 9,129,000		$ 9,155,000
Amount paid for funding requirements	26,000	20,000
West Palm Beach Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	4,500,000
Estimated costs of remediation range, maximum	15,400,000
Sanford Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, maximum	13,000,000
Cost of remedy for settlements of claims	20,000,000
Environmental remediation expense	24,000
FPU [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	10,200,000
Approval of recovery of environmental costs	14,000,000
Environmental costs recovered	9,300,000
FPU [Member] | Sanford Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, maximum	650,000
Environmental remediation expense percent	5.00%
Amount paid for funding requirements	650,000
FPU [Member] | Manufactured Gas Plant [Member]
Environmental Commitments And Contingencies [Line Items]
Regulatory assets for future recovery of environmental costs	4,700,000
Chesapeake [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	474,000
Regulatory assets for future recovery of environmental costs	$ 598,000

XML

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Derivatives, Fair Value [Line Items]
Document Period End Date	Mar. 31, 2014
Derivatives designated as fair value hedges, Asset derivatives	$ 0	$ 385
Derivatives not designated as hedging instruments, Liability derivatives	0	127
Mark-to-market energy assets [Member] | Forward Contracts [Member]
Derivatives, Fair Value [Line Items]
Derivatives asset not designated as hedging instruments, Forward contracts, Asset Derivatives	0	196
Mark-to-market energy assets [Member] | Call options [Member]
Derivatives, Fair Value [Line Items]
Derivatives asset not designated as hedging instruments, Call Option, Derivatives assets		169
Mark-to-market energy assets [Member] | Put Option [Member] | Derivatives designated as fair value hedges [Member]
Derivatives, Fair Value [Line Items]
Derivatives designated as fair value hedges, Asset derivatives	0	20
Mark-to-market energy liabilities [Member] | Forward Contracts [Member]
Derivatives, Fair Value [Line Items]
Derivatives not designated as hedging instruments, Liability derivatives	$ 0	$ 127

XML

Investments - Additional Information (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Investments, Debt and Equity Securities [Abstract]
Unrealized gain, net of other expenses	$ 37	$ 283

XML

Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
Deferred compensation plan held Rabbi Trust (in shares)	34,731	34,495
Shares issued under the performance incentive plan withheld for employee taxes (in shares)	8,458	10,411
Cash Dividends Declared Per Share of Common Stock (in usd per share)	$ 0.385	$ 1.52

XML

Employee Benefit Plans - Employee Benefit Plans (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Document Period End Date	Mar. 31, 2014
Amortization of prior service cost	$ (14)
Amortization of net loss	66
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	107	102
Expected return on plan assets	(133)	(126)
Amortization of prior service cost	0	0
Amortization of net loss	37	57
Net periodic cost (benefit)	11	33
Total periodic cost	11	33
FPU Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	647	594
Expected return on plan assets	(773)	(719)
Amortization of net loss	0	81
Net periodic cost (benefit)	(126)	(44)
Amortization of pre-merger regulatory asset	190	190
Total periodic cost	64	146
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	23	21
Amortization of prior service cost	5	5
Amortization of net loss	12	16
Net periodic cost (benefit)	40	42
Total periodic cost	40	42
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	13	12
Amortization of prior service cost	(19)	(19)
Amortization of net loss	17	18
Net periodic cost (benefit)	11	11
Total periodic cost	11	11
FPU Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	17	16
Amortization of net loss	0	0
Net periodic cost (benefit)	17	16
Amortization of pre-merger regulatory asset	2	2
Total periodic cost	$ 19	$ 18

XML

Share-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2014

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

Share-Based Compensation Amounts Included in Net Income

The table below presents the amounts included in net income related to share-based compensation expense for the three months ended March 31, 2014 and 2013:

	Three Months Ended
	March 31,
	2014		2013
(in thousands)
Awards to non-employee directors	$	124	$	111
Awards to key employees	514		270
Total compensation expense	638		381
Less: tax benefit	257		153
Share-Based Compensation amounts included in net income	$	381	$	228

Summary of Stock Activity under SICP

The table below presents the summary of the stock activity for the awards to key employees for the three months ended March 31, 2014:

	Number of Shares	Weighted Average Fair Value
Outstanding—December 31, 2013	80,761	$	42.30
Granted	27,628	$	58.35
Vested	26,364	$	40.30
Outstanding—March 31, 2014	82,025	$	48.35

XML

Employee Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three months ended March 31, 2014 and 2013 are set forth in the following tables:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake Pension SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended March 31,	2014			2013			2014			2013			2014		2013		2014			2013			2014		2013
(in thousands)
Interest cost	$	107		$	102		$	647		$	594		$	23	$	21	$	13		$	12		$	17	$	16
Expected return on plan assets	(133		)	(126		)	(773		)	(719		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			5		5		(19		)	(19		)	—		—
Amortization of net loss	37			57			—			81			12		16		17			18			—		—
Net periodic cost (benefit)	11			33			(126		)	(44		)	40		42		11			11			17		16
Amortization of pre-merger regulatory asset	—			—			190			190			—		—		—			—			2		2
Total periodic cost	$	11		$	33		$	64		$	146		$	40	$	42	$	11		$	11		$	19	$	18

Amounts Included in Regulatory Asset and Accumulated Other Comprehensive Income/Loss Recognized as Net Periodic Benefit Cost

The following table presents the amounts included in the regulatory asset and accumulated other comprehensive income/loss that were recognized as components of net periodic benefit cost during the three months ended March 31, 2014:

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

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

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Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 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	(94)	(13)
Transfers	0	(16)
Investment Income	1	2
Ending Balance	$ 365	$ 398

XML

Employee Benefit Plans - Additional Information (Detail) (USD $)	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013
Defined Benefit Plan Disclosure [Line Items]
Document Period End Date	Mar. 31, 2014
Expected pension and postretirement benefit costs	$ 578,000
Expected amortization of pre merger regulatory asset	769,000
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Unamortized balance of regulatory asset	4,200,000		4,400,000
Defined Benefit Plan, Net Periodic Benefit Cost	11,000	33,000
Contribution to pension plan	91,000
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	520,000
Consolidated [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	191,000
FPU Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	(126,000)	(44,000)
Contribution to pension plan	211,000
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	1,677,000
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	40,000	42,000
Contribution to pension plan	22,000
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	88,000
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	11,000	11,000
Contribution to pension plan	23,000
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	95,000
FPU Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	17,000	16,000
Contribution to pension plan	55,000
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	$ 245,000

XML

Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Outstanding Trading Contracts

As of March 31, 2014, we did not have outstanding trading contracts.

Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet

Fair values of the derivative contracts recorded in the condensed consolidated balance sheet as of March 31, 2014 and December 31, 2013, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2014		December 31, 2013
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	—	$	196
Call Option (1)	Mark-to-market energy assets	—		169
Derivatives designated as fair value hedges
Put Options (2)	Mark-to-market energy assets	—		20
Total asset derivatives		$	—	$	385

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

⁽¹⁾  We purchased a call option for the propane price cap program in May 2013. The call option was fully exercised during 2014. There was no outstanding call option at March 31, 2014.

⁽²⁾ 

Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements

The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows:

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended March 31,
(in thousands)	(Loss) on Derivatives	2014			2013
Derivatives not designated as hedging instruments:
Unrealized gain (loss) on forward contracts	Revenue	$	(68	)	214
Call Option	Cost of sales	137			—
Derivatives designated as fair value hedges:
Put/Call Options	Cost of sales	(20		)	(28		)
Total		$	49		$	186

Effects of Trading Activities on Condensed Consolidated Statements of Income

The effects of trading activities on the condensed consolidated statements of income are the following:

	Location in the	For the Three Months Ended March 31,
(in thousands)	Statements of Income	2014			2013
Realized gain on forward contracts	Revenue	$	1,246		$	74
Unrealized gain (loss) on forward contracts	Revenue	(68		)	214
Total		$	1,178		$	288

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Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Financial Assets and Liabilities Measured at Fair Value on Recurring Basis

The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at March 31, 2014 and December 31, 2013:

			Fair Value Measurements Using:
March 31, 2014	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—guaranteed income fund	$	365	$	—	$	—	$	365
Investments—other	$	2,586	$	2,586	$	—	$	—

			Fair Value Measurements Using:
December 31, 2013 (in thousands)	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Investments—guaranteed income fund	$	458	$	—	$	—	$	458
Investments—other	$	2,640	$	2,640	$	—	$	—
Mark-to-market energy assets, incl. put/call options	$	385	$	—	$	385	$	—
Liabilities:
Mark-to-market energy liabilities	$	127	$	—	$	127	$	—

Summary of Changes in Fair Value of Investments

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

	Three Months Ended   March 31,
	2014			2013
(in thousands)
Beginning Balance	$	458		$	—
Transfers in due to change in trustee	—			425
Purchases and adjustments	(94		)	(13		)
Transfers	—			(16		)
Investment income	1			2
Ending Balance	$	365		$	398

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Condensed Consolidated Statements of Stockholders' Equity (USD $) In Thousands, except Share data, unless otherwise specified		Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Deferred Compensation [Member]	Treasury Stock [Member]
Beginning Balances at Dec. 31, 2012		$ 256,598	$ 4,671	$ 150,750	$ 106,239	$ (5,062)	$ 982	$ (982)
Beginning Balances, shares at Dec. 31, 2012	[1]		9,597,499
Common Stock, Dividends, Per Share, Declared		$ 1.52
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		32,787			32,787
Other comprehensive loss/income		2,529				2,529
Dividends		(14,758)			(14,752)
Conversion of debentures		295	8	287
Conversion of debentures, shares	[1]		17,383
Share-based compensation	[2],[3]	1,322	12	1,310
Share-based compensation, shares	[1],[2],[3]		23,348
Stock Issued During Period, Shares, Dividend Reinvestment Plan			0
Stock Issued During Period, Value, Dividend Reinvestment Plan			0	(6)
Treasury Stock Activity During Period, Shares			0
Treasury Stock Activity And Deferred Compensation Plan Activity During Period Value		0	0	0			142	(142)
Ending Balances at Dec. 31, 2013		278,773	4,691	152,341	124,274	(2,533)	1,124	(1,124)
Ending Balances, shares at Dec. 31, 2013	[1]		9,638,230
Common Stock, Dividends, Per Share, Declared		$ 0.385
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		17,681			17,681
Other comprehensive loss/income		31				31
Dividends		(3,780)			(3,779)
Conversion of debentures		535	15	520
Conversion of debentures, shares	[1]		31,542
Share-based compensation	[2],[3]	11	9	2
Share-based compensation, shares	[1],[2],[3]		17,906
Stock Issued During Period, Shares, Dividend Reinvestment Plan	[1]		0
Stock Issued During Period, Value, Dividend Reinvestment Plan			0	(1)
Treasury Stock Activity During Period, Shares			0
Treasury Stock Activity And Deferred Compensation Plan Activity During Period Value		0					14	(14)
Ending Balances at Mar. 31, 2014		$ 293,251	$ 4,715	$ 152,862	$ 138,176	$ (2,502)	$ 1,138	$ (1,138)
Ending Balances, shares at Mar. 31, 2014	[1]		9,687,678

[1] Includes 34,731 and 34,495 shares at March 31, 2014 and December 31, 2013, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.

[2] Includes amounts for shares issued for Directors’ compensation.

[3] The shares issued under the SICP are net of shares withheld for employee taxes. For the quarter ended March 31, 2014 and for the year ended December 31, 2013, we withheld 8,458 and 10,411 shares, respectively, for taxes.

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Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below:

	March 31,			December 31,
(in thousands)	2014			2013
FPU secured first mortgage bonds (A) :
9.08% bond, due June 1, 2022	$	7,967		$	7,967
Uncollateralized senior notes:
7.83% note, due January 1, 2015	2,000			2,000
6.64% note, due October 31, 2017	10,909			10,909
5.50% note, due October 12, 2020	14,000			14,000
5.93% note, due October 31, 2023	30,000			30,000
5.68% note, due June 30, 2026	29,000			29,000
6.43% note, due May 2, 2028	7,000			7,000
3.73% note, due December 16, 2028	20,000			20,000
Convertible debentures:
8.25% due March 1, 2014	—			646
Promissory notes	360			445
Capital lease obligation	6,914			6,978
Total long-term debt	128,150			128,945
Less: current maturities	(10,955		)	(11,353		)
Total long-term debt, net of current maturities	$	117,195		$	117,592

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

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Segment Information - Schedule of Segment Reporting Information by Segment (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended				12 Months Ended
	Mar. 31, 2014		Mar. 31, 2013		Dec. 31, 2013
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	$ 186,337		$ 140,729
Intersegment Revenues
Total operating revenues, unaffiliated customers	186,337		140,729
Operating Income
Total operating income	31,623		26,550
Other income, net of other expenses	6		289
Interest	2,155		2,072
Income Before Income Taxes	29,474		24,767
Income taxes	11,793		9,898
Net Income	17,681		14,869		32,787
Identifiable Assets
Total identifiable assets	842,561				837,522
Regulated Energy [Member]
Operating Income
Total operating income	21,091		17,306
Identifiable Assets
Total identifiable assets	715,062				708,950
Unregulated Energy [Member]
Operating Income
Total operating income	10,858		9,369
Identifiable Assets
Total identifiable assets	103,658				100,585
Other [Member]
Identifiable Assets
Total identifiable assets	23,841				27,987
Other and eliminations [Member]
Operating Income
Total operating income	(326)		(125)
Operating Revenues, Unaffiliated Customers [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	186,337		140,729
Intersegment Revenues
Total operating revenues, unaffiliated customers	186,337		140,729
Operating Revenues, Unaffiliated Customers [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	101,874		81,304
Intersegment Revenues
Total operating revenues, unaffiliated customers	101,874		81,304
Operating Revenues, Unaffiliated Customers [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	79,874		54,991
Intersegment Revenues
Total operating revenues, unaffiliated customers	79,874		54,991
Operating Revenues, Unaffiliated Customers [Member] | Other [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	4,589		4,434
Intersegment Revenues
Total operating revenues, unaffiliated customers	4,589		4,434
Intersegment Revenues [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	644	[1]	506	[1]
Intersegment Revenues
Total operating revenues, unaffiliated customers	644	[1]	506	[1]
Intersegment Revenues [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	292	[1]	263	[1]
Intersegment Revenues
Total operating revenues, unaffiliated customers	292	[1]	263	[1]
Intersegment Revenues [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	99	[1]	0	[1]
Intersegment Revenues
Total operating revenues, unaffiliated customers	99	[1]	0	[1]
Intersegment Revenues [Member] | Other [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	253	[1]	243	[1]
Intersegment Revenues
Total operating revenues, unaffiliated customers	$ 253	[1]	$ 243	[1]

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

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Derivative Instruments - Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	$ 49	$ 186
Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on Sale of Derivatives	209
Derivatives not designated as hedging instruments [Member] | Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives		0
Gain (Loss) on Sale of Derivatives	137
Derivatives designated as fair value hedges [Member] | Put/Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	(20)	(28)
Revenue [Member] | Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	(68)	214
Revenue [Member] | Derivatives not designated as hedging instruments [Member] | Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	$ (68)	$ 214

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Condensed Consolidated Statements of Income (USD $) In Thousands, except Share data, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating Revenues
Regulated energy	$ 102,166	$ 81,566
Unregulated energy	79,973	54,991
Other	4,198	4,172
Total Operating Revenues	186,337	140,729
Operating Expenses
Regulated energy cost of sales	54,307	41,615
Unregulated energy and other cost of sales	61,325	40,090
Operations	26,626	21,754
Maintenance	2,148	1,722
Depreciation and amortization	6,635	5,820
Other taxes	3,673	3,178
Total Operating Expenses	154,714	114,179
Operating Income	31,623	26,550
Other income, net of other expenses	6	289
Interest charges	2,155	2,072
Income Before Income Taxes	29,474	24,767
Income taxes	11,793	9,898
Net Income	$ 17,681	$ 14,869
Weighted Average Common Shares Outstanding:
Basic (in shares)	9,658,431	9,601,529
Diluted (in shares)	9,693,434	9,678,950
Earnings Per Share of Common Stock:
Basic (in usd per share)	$ 1.83	$ 1.55
Diluted (in usd per share)	$ 1.82	$ 1.54
Cash Dividends Declared Per Share of Common Stock (in usd per share)	$ 0.385	$ 0.365

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Employee Benefit Plans - Amounts Included in Regulatory Asset and Accumulated Other Comprehensive Income/Loss Recognized as Net Periodic Benefit Cost (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014		Mar. 31, 2013
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	$ (14)
Net loss	66
Recognized from accumulated other comprehensive loss	52	[1]
Recognized from regulatory asset	0
Total recognized in net periodic benefit cost	52
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	0		0
Net loss	37		57
Recognized from accumulated other comprehensive loss	37	[1]
Total recognized in net periodic benefit cost	37
FPU Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Net loss	0		81
Recognized from accumulated other comprehensive loss	0	[1]
Recognized from regulatory asset	0
Total recognized in net periodic benefit cost	0
Chesapeake Pension SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	5		5
Net loss	12		16
Recognized from accumulated other comprehensive loss	17	[1]
Total recognized in net periodic benefit cost	17
Chesapeake Postretirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	(19)		(19)
Net loss	17		18
Recognized from accumulated other comprehensive loss	(2)	[1]
Total recognized in net periodic benefit cost	$ (2)

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

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Condensed Consolidated Balance Sheets (Parenthetical) (USD $) In Thousands, except Share data, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 1,976	$ 1,635
Common stock, par value (in usd per share)	$ 0.4867	$ 0.4867
Common stock, shares authorized	25,000,000	25,000,000

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Long-Term Debt - Outstanding Long-Term Debt (Parenthetical) (Detail)	3 Months Ended
	Mar. 31, 2014	Dec. 31, 2013
9.08% bond, due June 1, 2022 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	9.08%
Debt instrument, maturity date	Jun. 01, 2022
7.83% note, due January 1, 2015 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	7.80%
Debt instrument, maturity date	Jan. 01, 2015
6.64% note, due October 31, 2017 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.64%
Debt instrument, maturity date	Oct. 31, 2017
5.50% note, due October 12, 2020 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.50%
Debt instrument, maturity date	Oct. 12, 2020
5.93% note, due October 31, 2023 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.93%
Debt instrument, maturity date	Oct. 31, 2023
5.68% note, due June 30, 2026 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.68%
Debt instrument, maturity date	Jun. 30, 2026
8.25% due March 1, 2014 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	8.25%
Debt instrument, maturity date	Mar. 01, 2014
Uncollateralized Senior Notes Due On May Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.43%
Debt instrument, maturity date	May 02, 2028
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.73%	3.73%
Debt instrument, maturity date	Dec. 16, 2028

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Acquisitions - Additional Information (Detail) (USD $)	3 Months Ended		12 Months Ended	0 Months Ended	3 Months Ended		0 Months Ended		3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	May 31, 2013 Eastern Shore Gas Company [Member] Customer	Mar. 31, 2014 Eastern Shore Gas Company [Member]	Sep. 30, 2013 Eastern Shore Gas Company [Member]	Dec. 02, 2013 Fort Meade [Member]	Feb. 05, 2013 Propane Acquisition [Member] customer	Mar. 31, 2014 Propane Acquisition [Member]
Business Acquisition [Line Items]
Inventory Purchase Accounting Adjustment									$ 271,031
Purchase Price Adjustment						543,000
Number of residential and commercial customers receiving propane gas distribution service				11,000				3,000
Minimum number of customers to whom gas distribution systems and bulk delivery service provided				500
Purchase price allocated to property, plant and equipment				12,600,000			670,000	1,600,000
Purchase price allocated to propane and other inventory				344,000			14,000	231,000
Receivables				2,500,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Net				227,000
Revenues	186,337,000	140,729,000			10,300,000
Net Income (Loss) Attributable to Parent	17,681,000	14,869,000	32,787,000		1,700,000
Purchase price allocated to intangible assets related to customer list								300,000
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life								12 years
Payments to Acquire Businesses, Gross	0	2,437,000		16,500,000			792,000	2,900,000
Sales Tax						726,000
Goodwill	4,625,000		4,354,000				150,000	724,000
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Current Liabilities, Other							42,000
Goodwill, Purchase Accounting Adjustments									$ 271,000

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Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2014

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments

Fair Value of Financial Instruments

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are the following:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;

Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and

Level 3: Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity).

We did not have mark-to-market energy assets or liabilities at March 31, 2014. The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy used at March 31, 2014 and December 31, 2013:

			Fair Value Measurements Using:
March 31, 2014	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—guaranteed income fund	$	365	$	—	$	—	$	365
Investments—other	$	2,586	$	2,586	$	—	$	—

			Fair Value Measurements Using:
December 31, 2013 (in thousands)	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
Assets:
Investments—guaranteed income fund	$	458	$	—	$	—	$	458
Investments—other	$	2,640	$	2,640	$	—	$	—
Mark-to-market energy assets, incl. put/call options	$	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 three months ended March 31, 2014 and 2013:

	Three Months Ended   March 31,
	2014			2013
(in thousands)
Beginning Balance	$	458		$	—
Transfers in due to change in trustee	—			425
Purchases and adjustments	(94		)	(13		)
Transfers	—			(16		)
Investment income	1			2
Ending Balance	$	365		$	398

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

The following valuation techniques were used to measure fair value assets in the table above on a recurring basis as of March 31, 2014 and December 31, 2013:

Level 1 Fair Value Measurements:

Investments- equity securities—The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.

Investments- other—The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares.

Level 2 Fair Value Measurements:

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

Propane put/call options—The fair value of the propane put/call options are determined using market transactions for similar assets and liabilities in either the listed or OTC markets.

Level 3 Fair Value Measurements:

Investments- guaranteed income fund—The fair values of these investments are recorded at the contract value, which approximates their fair value.

At March 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 March 31, 2014, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of $121.2 million. This compares to a fair value of $137.9 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At December 31, 2013, long-term debt, including the current maturities but excludes a capital lease obligation, 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.

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Rates and Other Regulatory Activities - Additional Information (Detail) (USD $)	3 Months Ended			0 Months Ended	6 Months Ended
	Mar. 31, 2014	Mar. 31, 2014 Florida [Member]	Mar. 31, 2014 TETLP Expansion Project [Member] Eastern Shore [Member]	Jun. 13, 2013 White Oak Lateral Project Filing [Member] Eastern Shore [Member] mi in	Jun. 30, 2013 White Oak Lateral Project Filing [Member] Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Reduction in accumulated depreciation	$ 4,500,000
Public Utilities, Interim Rate Increase (Decrease), Amount		2,400,000
Public Utilities, Requested Rate Increase (Decrease), Amount		5,900,000
Estimated Environmental Cleanup Costs To Be Recovered		381,000
Increase in Pipeline Capacity			57,000
Estimated capital cost					$ 11,200,000
White Oak lateral capacity of firm transportation service				55,200
White Oak lateral length of pipeline to be installed				5.5
Lateral diamater of pipeline to be installed				16
New plant capacity volume			107,000	55,200

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Summary of Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

References in this document to the “Company,” “Chesapeake,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure.

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2013. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures.

We have assessed and reported on subsequent events through the date of issuance of these condensed consolidated financial statements.

Reclassifications

Reclassifications

We reclassified certain amounts in the condensed consolidated cash flows statement for the three months ended March 31, 2013 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

New Accounting Pronouncements, Policy [Policy Text Block]

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

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.

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Condensed Consolidated Statements of Cash Flows (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Operating Activities
Net Income	$ 17,681	$ 14,869
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	6,635	5,820
Depreciation and accretion included in other costs	1,783	1,476
Deferred income taxes, net	(231)	2,208
(Gain) loss on sale of assets	(8)	(8)
Unrealized (gain) loss on commodity contracts	68	(214)
Unrealized gain on investments	(37)	(283)
Realized gain on sales of investments, net	0	(69)
Employee benefits	162	209
Share-based compensation	638	381
Other, net	(1)	(3)
Changes in assets and liabilities:
Purchase of investments	184	(7)
Accounts receivable and accrued revenue	(3,647)	(8,657)
Propane inventory, storage gas and other inventory	8,243	5,064
Regulatory assets	(2,788)	852
Prepaid expenses and other current assets	2,185	1,469
Accounts payable and other accrued liabilities	4,821	1,510
Income taxes receivable	11,565	8,899
Accrued interest	1,301	1,185
Customer deposits and refunds	(1,735)	(2,520)
Accrued compensation	(3,505)	(2,753)
Regulatory liabilities	2,925	5,711
Other assets and liabilities, net	(240)	21
Net cash provided by operating activities	45,999	35,160
Investing Activities
Property, plant and equipment expenditures	(18,464)	(16,409)
Proceeds from sales of assets	29	34
Payments to Acquire Businesses, Gross	0	(2,437)
Environmental expenditures	(26)	(20)
Net cash used in investing activities	(18,461)	(18,832)
Financing Activities
Common stock dividends	(3,369)	(3,176)
Purchase of stock for Dividend Reinvestment Plan	(341)	(326)
Change in cash overdrafts due to outstanding checks	(501)	83
Net borrowing (repayment) under line of credit agreements	(21,696)	(13,647)
Repayment of long-term debt	(196)	(15)
Net cash used in financing activities	(26,103)	(17,081)
Net Decrease in Cash and Cash Equivalents	1,435	(753)
Cash and Cash Equivalents-Beginning of Period	3,356	3,361
Cash and Cash Equivalents-End of Period	$ 4,791	$ 2,608

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Condensed Consolidated Statements of Comprehensive Income (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Net Income	$ 17,681	$ 14,869
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of ($6) and ($6), respectively	9	9
Net gain, net of tax of $27 and $38, respectively	40	58
Total other comprehensive income	31	49
Comprehensive Income	$ 17,712	$ 14,918

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Accumulated Other Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss)

The following table presents the changes in the balance of accumulated other comprehensive income (loss) for the three months ended March 31, 2014 and 2013. Defined benefit pension and postretirement plan items are the only component of our accumulated comprehensive income (loss). All amounts in the following table are presented net of tax.

	Three Months Ended
	March 31,
	2014			2013
(in thousands)
Beginning balance	$	(2,533	)	$	(5,062	)
Other comprehensive loss before reclassifications	—			(6		)
Amounts reclassified from accumulated other comprehensive loss	31			55
Net current-period other comprehensive income	31			49
Ending balance	$	(2,502	)	$	(5,013	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three months ended March 31, 2014 and 2013:

	Three Months Ended
	March 31,
	2014			2013
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	14		$	14
Net loss (1)	(66		)	(106		)
Total before income taxes	(52		)	(92		)
Income tax benefit	21			37
Net of tax	$	(31	)	$	(55	)

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

Amortization of defined benefit pension and postretirement plan items are included in operations expense in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.

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Document and Entity Information	3 Months Ended
	Mar. 31, 2014	Apr. 30, 2014
Entity Information [Line Items]
Entity Registrant Name	CHESAPEAKE UTILITIES CORP
Trading Symbol	CPK
Entity Central Index Key	0000019745
Current Fiscal Year End Date	--12-31
Entity Filer Category	Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2014
Document Fiscal Year Focus	2014
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		9,701,040

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Employee Benefit Plans

3 Months Ended

Mar. 31, 2014

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three months ended March 31, 2014 and 2013 are set forth in the following tables:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake Pension SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended March 31,	2014			2013			2014			2013			2014		2013		2014			2013			2014		2013
(in thousands)
Interest cost	$	107		$	102		$	647		$	594		$	23	$	21	$	13		$	12		$	17	$	16
Expected return on plan assets	(133		)	(126		)	(773		)	(719		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			5		5		(19		)	(19		)	—		—
Amortization of net loss	37			57			—			81			12		16		17			18			—		—
Net periodic cost (benefit)	11			33			(126		)	(44		)	40		42		11			11			17		16
Amortization of pre-merger regulatory asset	—			—			190			190			—		—		—			—			2		2
Total periodic cost	$	11		$	33		$	64		$	146		$	40	$	42	$	11		$	11		$	19	$	18

We expect to record pension and postretirement benefit costs of approximately $578,000 for 2014. Included in these costs is $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations of the changes in funded status that occurred but were not recognized as part of net periodic benefit costs prior to the merger. This was deferred as a regulatory asset by FPU prior to the merger to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was $4.2 million and $4.4 million at March 31, 2014 and December 31, 2013, respectively. The amortization included in pension expense is being offset by a net periodic benefit of $191,000, which will reduce our total expected benefit costs to $578,000.

FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs related to its regulated operations after the merger pursuant to a Florida PSC order. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake’s operations is recorded to accumulated other comprehensive income/loss. The following table presents the amounts included in the regulatory asset and accumulated other comprehensive income/loss that were recognized as components of net periodic benefit cost during the three months ended March 31, 2014:

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

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

During the three months ended March 31, 2014, we contributed $91,000 and $211,000, to the Chesapeake and FPU pension plans, respectively. We expect to contribute a total of $520,000 and $1.7 million to the Chesapeake and FPU pension plans, respectively, during 2014, which represent the minimum contribution payments required in 2014.

The Chesapeake Pension SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake Pension SERP for the three months ended March 31, 2014, were $22,000. We expect to pay total cash benefits of approximately $88,000 under the Chesapeake Pension SERP in 2014. Cash benefits paid for the Chesapeake Postretirement Plan, primarily for medical claims for the three months ended March 31, 2014, were $23,000. We have estimated that approximately $95,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2014. Cash benefits paid for the FPU Medical Plan, primarily for medical claims for the three months ended March 31, 2014, were $55,000. We estimate that approximately $245,000 will be paid for such benefits under the FPU Medical Plan in 2014.

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Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Tax expense recognized on the amortization of prior service cost	$ (6)	$ (6)
Tax expense recognized on the net gain (loss)	$ 27	$ 38

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Acquisitions

3 Months Ended

Mar. 31, 2014

Business Combinations [Abstract]

Acquisitions

Acquisitions

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 now subject to rate and service regulation by the Maryland PSC. We are evaluating the potential conversion of some of the underground propane distribution systems to natural gas distribution. Although 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, $344,000 in propane inventory, $2.5 million in accounts receivable and accrued revenue and $227,000 in other current liabilities, which included the effect of the purchase price adjustment in the third quarter of 2013. All but insignificant amounts of assets and liabilities are recorded in the Regulated Energy segment. No goodwill or intangible asset was recorded from this acquisition. The allocation of the purchase price and valuation of assets are preliminary, and we will complete the final purchase price allocation as soon as practicable, but no later than one year from the purchase of the assets.

The revenue and net income from this acquisition for the three months ended March 31, 2014 included in our condensed consolidated statement of income were $10.3 million and $1.7 million, 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 $670,000 in property, plant and equipment, $14,000 in inventory, $150,000 in goodwill and $42,000 in other current liabilities. Valuation of certain property, plant and equipment is preliminary and may be adjusted in the future based upon the final valuation, but no later than one year from the date of acquisition. All of the goodwill is expected to be deductible for income tax purposes. The revenue and net income from this acquisition that were included in our condensed consolidated statement of income for the three months ended March 31, 2014 were not material.

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. All of the goodwill is expected to be deductible for income tax purposes. These amounts reflected 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 for the same amount. The revenue and net income from this acquisition that were included in our condensed consolidated statement of income for the three months ended March 31, 2014 were not material.

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Calculation of Earnings Per Share

3 Months Ended

Mar. 31, 2014

Earnings Per Share [Abstract]

Calculation of Earnings Per Share

Calculation of Earnings Per Share

	Three Months Ended
	March 31,
	2014		2013
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	17,681	$	14,869
Weighted average shares outstanding	9,658,431		9,601,529
Basic Earnings Per Share	$	1.83	$	1.55
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	17,681	$	14,869
Effect of 8.25% Convertible debentures (1)	—		11
Adjusted numerator—Diluted	$	17,681	$	14,880
Reconciliation of Denominator:
Weighted shares outstanding—Basic	9,658,431		9,601,529
Effect of dilutive securities:
Share-based Compensation	35,003		23,132
8.25% Convertible debentures (1)	—		54,289
Adjusted denominator—Diluted	9,693,434		9,678,950
Diluted Earnings Per Share	$	1.82	$	1.54

⁽¹⁾As of March 1, 2014, we no longer have any outstanding convertible debentures. See Note 14, Long-term debt for additional information.

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Long-Term Debt

3 Months Ended

Mar. 31, 2014

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Our outstanding long-term debt is shown below:

	March 31,			December 31,
(in thousands)	2014			2013
FPU secured first mortgage bonds (A) :
9.08% bond, due June 1, 2022	$	7,967		$	7,967
Uncollateralized senior notes:
7.83% note, due January 1, 2015	2,000			2,000
6.64% note, due October 31, 2017	10,909			10,909
5.50% note, due October 12, 2020	14,000			14,000
5.93% note, due October 31, 2023	30,000			30,000
5.68% note, due June 30, 2026	29,000			29,000
6.43% note, due May 2, 2028	7,000			7,000
3.73% note, due December 16, 2028	20,000			20,000
Convertible debentures:
8.25% due March 1, 2014	—			646
Promissory notes	360			445
Capital lease obligation	6,914			6,978
Total long-term debt	128,150			128,945
Less: current maturities	(10,955		)	(11,353		)
Total long-term debt, net of current maturities	$	117,195		$	117,592

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

Uncollateralized Senior Notes

In September 2013, we entered into a Note Agreement to issue $70.0 million in aggregate of unsecured Senior Notes to the Note Holders. In December 2013, we issued Series A Notes of unsecured Senior Notes, with an aggregate principal amount of $20.0 million, at a rate of 3.73 percent. Series B of the unsecured Senior Notes, with an aggregate principal amount of $50.0 million, will be issued on May 15, 2014, at a rate of 3.88 percent. The proceeds received from the issuances of the Notes will be used to reduce our short-term borrowings under our lines of credit and to fund capital expenditures.

Convertible Debentures

During the first two months of 2014, Convertible Debentures totaling $537,000 were converted to stock and $109,000 were redeemed for cash. As of March 1, 2014, we no longer have any outstanding Convertible Debentures.

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Investments

3 Months Ended

Mar. 31, 2014

Investments, Debt and Equity Securities [Abstract]

Investments

Investments

The investment balances at March 31, 2014 and December 31, 2013, consist of the Rabbi Trusts associated with the 401(k) SERP and deferred compensation plans. We classify these investments as trading securities and report them at their fair value. For the three months ended March 31, 2014 and 2013, we recorded a net unrealized gain of $37,000 and $283,000, respectively, in other income in the condensed consolidated statements of income related to these investments. We also have recorded an associated liability, which is included in other pension and benefit costs in the condensed consolidated balance sheets. This liability is adjusted each month for the gains and losses incurred by the Rabbi Trusts.

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Other Commitments and Contingencies

3 Months Ended

Mar. 31, 2014

Commitments and Contingencies Disclosure [Abstract]

Other Commitments and Contingencies

Other Commitments and Contingencies

Natural Gas, Electric and Propane Supply

Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase gas, electricity and propane from various suppliers. The contracts have various expiration dates. For our Delaware and Maryland natural gas distribution divisions, we have a contract with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage capacity, which expires on March 31, 2015.

In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term. Sandpiper's initial annual commitment is estimated at approximately 7.4 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.

Chesapeake’s Florida natural gas distribution division has firm transportation service contracts with FGT and Gulfstream. 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 for the service.

In May 2013, PESCO renewed contracts to purchase natural gas from various suppliers. These contracts expire in May 2014. PESCO is currently obtaining and reviewing proposals from suppliers and anticipates executing new agreements before the existing agreements expire.

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) a fixed charge coverage ratio greater than 1.5 times. If either ratio is not met by FPU, it has 30 days to cure the default or provide an irrevocable letter of credit if the default is not cured. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken or proposed to be taken to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could result in FPU having to provide an irrevocable letter of credit. As of March 31, 2014, FPU was in compliance with all of the requirements of its fuel supply contracts.

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 initial annual commitment is estimated at approximately 7.4 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one against those specified in the other.

Corporate Guarantees

The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our obligations, including the obligations of our subsidiaries. The maximum authorized liability under such guarantees and letters of credit is $45.0 million.

We have issued corporate guarantees to certain vendors of our subsidiaries, the largest portion of which are for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at March 31, 2014 was $31.6 million, with the guarantees expiring on various dates through February 2015.

Chesapeake guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under the guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 14, Long-Term Debt, to the condensed consolidated financial statements for further details).

In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million, which expires on September 12, 2014, related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for $1.1 million, which expires on December 2, 2014, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company in 2010, we renewed and decreased the letter of credit for $304,000 to our former primary insurance company, which will expire on June 1, 2014. There have been no draws on these letters of credit as of March 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 our Delaware and Maryland divisions.

Tax-related Contingencies

We are subject to various audits and reviews by the federal, state, local and other regulatory authorities regarding income taxes and taxes other than income. As of March 31, 2014, we maintained a liability of $300,000 related to unrecognized income tax benefits and $968,000 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.

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Long-Term Debt - Additional Information (Detail) (USD $)	3 Months Ended									3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013	Dec. 31, 2013	Mar. 31, 2014 5.68% note, due June 30, 2026 [Member]	Dec. 31, 2013 5.68% note, due June 30, 2026 [Member]	Mar. 31, 2014 Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member]	Sep. 05, 2013 Aggregate Unsecured Senior Notes [Member]	Mar. 31, 2014 Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]	Dec. 31, 2013 Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]	Mar. 31, 2014 Convertible Debt Securities [Member]
Debt Instrument [Line Items]
Long term debt maximum borrowing capacity						$ 50,000,000.0	$ 70,000,000
Total long-term debt	121,200,000		122,000,000	29,000,000	29,000,000			20,000,000	20,000,000
Long-term debt, interest percentage				5.68%		3.88%		3.73%	3.73%
Repayments of Long-term Debt	196,000	15,000
Debt Conversion, Converted Instrument, Amount										537,000
Repayments of Convertible Debt										$ 109,000

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Rates and Other Regulatory Activities

3 Months Ended

Mar. 31, 2014

Regulated Operations [Abstract]

Rates and Other Regulatory Activities

Rates and Other Regulatory Activities

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake’s Florida natural gas distribution division and FPU’s natural gas and electric distribution operations continue to be subject to regulation by the Florida PSC as separate entities.

Delaware

There were no rates and other regulatory activities in Delaware during the first quarter of 2014.

Maryland

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. Sandpiper recommended slightly lower depreciation rates to be applied prospectively and a reduction of $4.5 million in accumulated depreciation. At the administrative meeting on April 23, 2014, the Maryland PSC assigned this matter to an administrative judge for further review.

Florida

On April 28, 2014, FPU filed a base rate proceeding for its electric distribution operation. FPU is seeking interim rate relief of approximately $2.4 million and final rate relief of approximately $5.9 million. The interim rate relief requested is based on the twelve-month period ended September 30, 2013. We expect the interim rate relief to be determined in the second quarter of 2014. Any increase to our rates as a result of this interim rate relief will be subject to refund based on the outcome of the final rate relief, which we expect to occur during the fourth quarter of 2014.

On January 13, 2014, FPU's natural gas 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. Depending on the results of this proceeding, we may be required to change depreciation expense on our Florida natural gas distribution operations. The PSC agenda date for the depreciation study has not yet been set.

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. This extension would be effective for two years beginning January 1, 2014. The Florida PSC approved the extension of the surcharge and the additional amount for recovery at the Agenda conference on January 7, 2014.

Eastern Shore

The following are regulatory activities involving FERC orders applicable to Eastern Shore and the expansions of Eastern Shore’s transmission system:

TETLP Expansion Project: On January 31, 2014, Eastern Shore submitted to the FERC a request for prior notice authorizationregarding a projectwhich includedcertain improvements at Eastern Shore’s existinginterconnection with TETLP near Honey Brook, Pennsylvania. This project will allow Eastern Shore toincrease its capacity to receive natural gas from TETLP by 57,000 Dts/d to a total capacity of 107,000 Dts/d but this requested improvement does not result in an increase in Eastern Shore’s overall pipeline 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 consists of installing approximately 5.5 miles of 16-inch diameter pipeline, metering facilities and miscellaneous appurtenances extending from Eastern Shore's mainline system near its North Dover City Gate Station to the Garrison Oak Technical Park, all located in Dover, Delaware. This project is designed to provide 55,200 Dts/d of delivery lateral firm transportation service to an industrial customer facility currently under construction. The total cost of the project is estimated to be approximately $11.2 million.

On August 9, 2013, the FERC issued a notice of intent to prepare an environmental assessment for the project. The comment period concluded on September 9, 2013, with no comments being filed in the docket. The environmental assessment was issued on October 4, 2013, and FERC staff recommended a finding of no significant impact. Eastern Shore filed the implementation plan and acceptance of conditions, stating that it will comply with all environmental conditions as set forth in the order. On November 27, 2013, the FERC issued a CP for this project. On January 17, 2014, the FERC issued its notice to allow construction to proceed, and Eastern Shore began construction activities for this project on January 22, 2014, for a planned in-service date of January 1, 2015.

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Environmental Commitments and Contingencies

3 Months Ended

Mar. 31, 2014

Environmental Remediation Obligations [Abstract]

Environmental Commitments and Contingencies

Environmental Commitments and Contingencies

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remediate at current and former operating sites the effect on the environment of the disposal or release of specified substances.

We have participated in the investigation and assessment of, and have remediation 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. We have also been in discussions with the MDE regarding a seventh former MGP site located in Cambridge, Maryland.

As of March 31, 2014, we had approximately $10.2 million in environmental liabilities related to all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites, representing our estimate of the future costs associated with those sites. FPU has approval to recover up to $14.0 million of its environmental costs related to all of its MGP sites from insurance and from customers through rates, approximately $9.3 million of which has been recovered as of March 31, 2014. We had approximately $4.7 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

In addition to the FPU MGP sites, we had $474,000 in environmental liabilities at March 31, 2014, related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of March 31, 2014, we had approximately $598,000 in regulatory and other assets for future recovery through Chesapeake’s rates. Environmental liabilities for all of our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants.

We continue to expect that all costs related to environmental remediation and related activities will be recoverable from customers through rates.

The following discussion provides details on MGP sites:

West Palm Beach, Florida

Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at, and in the immediate vicinity of, a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated a MGP. FPU is currently implementing a remedial plan approved by the FDEP for the east parcel of the West Palm Beach site, which includes installation of monitoring test wells, sparging of air into the groundwater system and extraction of vapors from the subsurface. It is anticipated that similar remedial actions ultimately will be implemented for other portions of the site. Estimated costs of remediation for the West Palm Beach site range from approximately $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.

Sanford, Florida

FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of March 31, 2014, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements.

The total cost of the final remedy is now estimated to be over $20.0 million, which includes long-term monitoring and the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.

As of March 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 as provided in the Third Participation Agreement to implement the final remedy for this site or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of March 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 via e-mail on October 9, 2012 that based on the data, NAM appears to be an appropriate remedy for the site. The FDEP issued a Remedial Action Plan approval order, dated October 12, 2012, which specified that a limited semi-annual monitoring program is to be conducted. The annual cost to conduct the limited NAM program is not expected to exceed $8,000. Although the duration of the FDEP-required limited NAM cannot be determined with certainty, it is anticipated that total costs to complete the remedial action will not exceed $50,000.

Pensacola, Florida

FPU formerly owned and operated a MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the FDOT. In October 2009, FDEP informed Gulf Power that FDEP would approve a conditional No Further Action determination for the site, which must include a requirement for institutional and engineering controls. On December 13, 2011, Gulf Power, the City of Pensacola, FDOT and FPU submitted to FDEP a draft covenant for institutional and engineering controls for the site. Upon FDEP’s approval and the subsequent recording of the institutional and engineering controls, no further work is expected to be required of the parties. Assuming FDEP approves the draft institutional and engineering controls, it is anticipated that FPU’s share of remaining legal and cleanup costs will not exceed $5,000.

Winter Haven, Florida

The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a consent order entered into with FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. Recent groundwater sampling results show a continuing reduction in contaminant concentrations from the treatment system, which has been in operation since 2002. Currently, we predict that remedial action objectives could be met in approximately two to three years for the area being treated by the remediation system. On August 7, 2012, FDEP issued a letter discussing the need to evaluate further remedial options, which could incorporate risk-management options, including natural attenuation and the use of institutional and engineering controls. Modifications to the existing consent order and the remedial action plan modification could be required to incorporate risk-management options into the remedy for the site. A response letter was submitted to FDEP on May 7, 2013. FDEP issued an additional comment letter, dated September 16, 2013, containing various requests and questions, which we responded to on October 10, 2013.

An exploratory drilling program was conducted in November of 2013, and the most recent groundwater monitoring report was submitted on January 27, 2014. The results of the drilling program suggest that some additional remedial activities might be necessary in the southwest corner of the Winter Haven site, and, we are currently negotiating with FDEP the scope of such activities.

If modifications to the existing consent order and remedial action plan are required, we estimate that future remediation costs for the subsurface soils and groundwater at the site could be as much as $443,000, which includes an estimate of $100,000 to implement additional actions, such as institutional controls, at the site. If we are required to incur this cost, we continue to believe that the entire amount will be recoverable from customers through 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, we object to FDEP’s suggestion that the sediments have been adversely impacted by the former operations of the MGP. Our early estimates indicate that some of the corrective measures previously discussed by FDEP could cost as much as $1.0 million. We believe that corrective measures for the sediments are not warranted and intend to oppose any requirement that we undertake corrective measures in the offshore sediments. We have not recorded a liability for sediment remediation, as the final resolution of this matter cannot be predicted at this time.

Salisbury, Maryland

We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized groundwater contamination. In February 2002, the MDE granted permission to permanently decommission the systems used for remediation and to discontinue all on-site and off-site well monitoring, except for one well, which is being maintained for periodic product monitoring and recovery. We anticipate that the remaining costs of the one remaining monitoring well will not exceed $5,000 annually. We cannot predict at this time when the MDE will grant permission to permanently decommission the one remaining monitoring well.

Other

We are in discussions with the MDE regarding a former MGP site located in Cambridge, Maryland. The outcome of this matter cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.

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. The facility evaluation has not been conducted and the outcome of this evaluation cannot be determined at this time; therefore, we have not recorded an environmental liability for this location.

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Segment Information

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Segment Information

Segment Information

We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance. The segments are evaluated based on their pre-tax operating income. Our operations 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 PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.

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

• Other. The “Other” segment consists primarily of our advanced information services subsidiary, as well as our unregulated subsidiaries that own real estate leased to Chesapeake and certain corporate costs not allocated to other operations.

The following table presents financial information about our reportable segments:

	Three Months Ended
	March 31,
	2014			2013
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	101,874		$	81,304
Unregulated Energy	79,874			54,991
Other	4,589			4,434
Total operating revenues, unaffiliated customers	$	186,337		$	140,729
Intersegment Revenues (1)
Regulated Energy	$	292		$	263
Unregulated Energy	99			—
Other	253			243
Total intersegment revenues	$	644		$	506
Operating Income
Regulated Energy	$	21,091		$	17,306
Unregulated Energy	10,858			9,369
Other and eliminations	(326		)	(125		)
Total operating income	31,623			26,550
Other income, net of other expenses	6			289
Interest	2,155			2,072
Income before Income Taxes	29,474			24,767
Income taxes	11,793			9,898
Net Income	$	17,681		$	14,869

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

(in thousands)	March 31, 2014		December 31, 2013
Identifiable Assets
Regulated energy	$	715,062	$	708,950
Unregulated energy	103,658		100,585
Other	23,841		27,987
Total identifiable assets	$	842,561	$	837,522

Our operations are almost entirely domestic. BravePoint has infrequent transactions in foreign countries which are denominated and paid primarily in U.S. dollars. These transactions are immaterial to the consolidated revenues.

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Calculation of Earnings Per Share - Calculation of Basic and Diluted Earnings Per Share (Parenthetical) (Detail) (8.25% Convertible debentures [Member])	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
8.25% Convertible debentures [Member]
Calculation Of Numerator And Denominator In Earnings Per Share [Line Items]
Debt Instrument, Interest Rate During Period	0.00%	8.25%

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Derivative Instruments - Additional Information (Detail) (USD $)	3 Months Ended			1 Months Ended		3 Months Ended	6 Months Ended
	Mar. 31, 2014 Counterparty	Dec. 31, 2013 Counterparty	May 31, 2013	Jun. 30, 2013 Call options [Member] gal	May 31, 2013 Call options [Member] gal	Mar. 31, 2014 Call options [Member]	Jun. 30, 2013 Put Option [Member]	Jun. 30, 2013 Put Option [Member] Minimum [Member]	Jun. 30, 2013 Put Option [Member] Maximum [Member]	Dec. 31, 2013 Mark To Market Energy Assets [Member] Call options [Member]	Mar. 31, 2014 Designated as Hedging Instrument [Member] Mark To Market Energy Assets [Member] Put Option [Member]	Dec. 31, 2013 Designated as Hedging Instrument [Member] Mark To Market Energy Assets [Member] Put Option [Member]
Derivative [Line Items]
Document Period End Date	Mar. 31, 2014
Purchase quantity for propane price cap				1,300,000	630,000
Strike price of put option			0.9750					0.8300	0.8600
Payment to purchase put option							$ 120,000
Derivative asset, fair value, net	0	385,000									0	20,000
Payment to purchase call options					72,000
Fair value of call options										169,000
Number of counterparties under master netting agreements	2	2
Rights to offset accounts receivable	5,300,000	2,800,000
Rights to offset accounts payable	3,800,000	3,155,000
Gain (Loss) on Sale of Derivatives						$ 209,000

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Derivative Instruments

3 Months Ended

Mar. 31, 2014

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Derivative Instruments

We use derivative and non-derivative contracts to engage in trading activities and manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory in order to mitigate the impact of wholesale price fluctuations. As of March 31, 2014, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

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 these options as fair value hedges, and there is no ineffective portion of these 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 expected to be purchased at market-based prices to supply the demands of our propane price cap program customers. The program caps the retail price that we can charge to those customers during the upcoming heating season at a pre-determined level. The call option is exercised if the propane prices rise above the strike price of $0.975 per gallon in January through March of 2014. We 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.

Xeron engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under this method, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statement of income for the period of change. As of March 31, 2014, we did not have outstanding trading contracts.

Xeron has entered into master netting agreements with two counterparties to mitigate exposure to counterparty credit risk. The master netting agreements enable Xeron to net these two counterparties' outstanding accounts receivable and payable, which are presented on a gross basis in the accompanying condensed consolidated balance sheets. At March 31, 2014, Xeron had a right to offset $5.3 million and $3.8 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 condensed consolidated balance sheet as of March 31, 2014 and December 31, 2013, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2014		December 31, 2013
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	—	$	196
Call Option (1)	Mark-to-market energy assets	—		169
Derivatives designated as fair value hedges
Put Options (2)	Mark-to-market energy assets	—		20
Total asset derivatives		$	—	$	385

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

⁽¹⁾  We purchased a call option for the propane price cap program in May 2013. The call option was fully exercised during 2014. There was no outstanding call option at March 31, 2014.

⁽²⁾  We purchased put options for the propane price cap program in June 2013. The put options expired in March 2014.

The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows:

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended March 31,
(in thousands)	(Loss) on Derivatives	2014			2013
Derivatives not designated as hedging instruments:
Unrealized gain (loss) on forward contracts	Revenue	$	(68	)	214
Call Option	Cost of sales	137			—
Derivatives designated as fair value hedges:
Put/Call Options	Cost of sales	(20		)	(28		)
Total		$	49		$	186

The effects of trading activities on the condensed consolidated statements of income are the following:

	Location in the	For the Three Months Ended March 31,
(in thousands)	Statements of Income	2014			2013
Realized gain on forward contracts	Revenue	$	1,246		$	74
Unrealized gain (loss) on forward contracts	Revenue	(68		)	214
Total		$	1,178		$	288

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2014

Segment Reporting [Abstract]

Schedule of Segment Reporting Information by Segment

The following table presents financial information about our reportable segments:

	Three Months Ended
	March 31,
	2014			2013
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy	$	101,874		$	81,304
Unregulated Energy	79,874			54,991
Other	4,589			4,434
Total operating revenues, unaffiliated customers	$	186,337		$	140,729
Intersegment Revenues (1)
Regulated Energy	$	292		$	263
Unregulated Energy	99			—
Other	253			243
Total intersegment revenues	$	644		$	506
Operating Income
Regulated Energy	$	21,091		$	17,306
Unregulated Energy	10,858			9,369
Other and eliminations	(326		)	(125		)
Total operating income	31,623			26,550
Other income, net of other expenses	6			289
Interest	2,155			2,072
Income before Income Taxes	29,474			24,767
Income taxes	11,793			9,898
Net Income	$	17,681		$	14,869

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

(in thousands)	March 31, 2014		December 31, 2013
Identifiable Assets
Regulated energy	$	715,062	$	708,950
Unregulated energy	103,658		100,585
Other	23,841		27,987
Total identifiable assets	$	842,561	$	837,522

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Share-Based Compensation - Additional Information (Detail) (USD $)	3 Months Ended
	Mar. 31, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Document Period End Date	Mar. 31, 2014
Unrecognized compensation expense related to the awards to non-employee directors	$ 41,000
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Amortization of expense equally over a service period	1 year
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards, shares	27,628
Intrinsic value of the SICP awards	$ 5,200,000
2014-2016 service period [Member] | Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards, shares	23,200
Vesting period	3 years
2013-2015 service period [Member] | Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards, shares	4,428
Vesting period	3 years

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Accumulated Other Comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Detail) (USD $) In Thousands, unless otherwise specified	3 Months Ended
	Mar. 31, 2014	Mar. 31, 2013
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	$ (2,533)	$ (5,062)
Other comprehensive loss before reclassifications	0	(6)
Amounts reclassified from accumulated other comprehensive loss	31	55
Net current-period other comprehensive income (loss)	31	49
Ending balance	$ (2,502)	$ (5,013)

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Condensed Consolidated Balance Sheets (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014	Dec. 31, 2013
Property, Plant and Equipment
Regulated energy	$ 697,725	$ 691,522
Unregulated energy	76,938	76,267
Other	21,129	21,002
Total property, plant and equipment	795,792	788,791
Less: Accumulated depreciation and amortization	(179,918)	(174,148)
Plus: Construction work in progress	27,228	16,603
Net property, plant and equipment	643,102	631,246
Current Assets
Cash and cash equivalents	4,791	3,356
Accounts receivable (less allowance for uncollectible accounts of $1,976 and $1,635, respectively)	80,313	75,293
Accrued revenue	12,536	13,910
Propane inventory, at average cost	6,088	10,456
Other inventory, at average cost	3,728	4,880
Storage gas prepayments	1,323	4,318
Prepaid expenses	4,890	6,910
Income taxes receivable	0	2,609
Mark-to-market energy assets	0	385
Regulatory assets	4,342	2,436
Deferred income taxes	1,723	1,696
Other current assets	198	160
Total current assets	119,932	126,409
Deferred Charges and Other Assets
Investments, at fair value	2,951	3,098
Regulatory assets	66,395	66,584
Goodwill	4,625	4,354
Other intangible assets, net	2,875	2,975
Receivables and other deferred charges	2,681	2,856
Total deferred charges and other assets	79,527	79,867
Total Assets	842,561	837,522
Stockholders' equity
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)	4,715	4,691
Additional paid-in capital	152,862	152,341
Retained earnings	138,176	124,274
Accumulated other comprehensive loss	(2,502)	(2,533)
Deferred compensation obligation	1,138	1,124
Treasury stock	(1,138)	(1,124)
Total stockholders' equity	293,251	278,773
Long-term debt, net of current maturities	117,195	117,592
Total capitalization	410,446	396,365
Current Liabilities
Current portion of long-term debt	10,955	11,353
Short-term borrowing	83,470	105,666
Accounts payable	58,183	53,482
Accrued compensation	4,937	8,394
Accrued interest	2,536	1,235
Dividends payable	3,730	3,710
Income Taxes Payable	8,955	0
Mark-to-market energy liabilities	0	127
Regulatory liabilities	7,071	4,157
Customer deposits and refunds	24,405	26,140
Other accrued liabilities	8,934	7,678
Total current liabilities	213,176	221,942
Deferred Credits and Other Liabilities
Deferred income taxes	142,414	142,597
Deferred investment tax credits	65	74
Regulatory liabilities	4,178	4,402
Accrued asset removal cost-Regulatory liability	40,007	39,510
Environmental liabilities	9,129	9,155
Other pension and benefit costs	20,662	21,000
Other liabilities	2,484	2,477
Total deferred credits and other liabilities	218,939	219,215
Other commitments and contingencies (Note 6)
Total Capitalization and Liabilities	$ 842,561	$ 837,522

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Summary of Accounting Policies Summary of Accounting Policies (Notes)

3 Months Ended

Mar. 31, 2014

Accounting Policies [Abstract]

Significant Accounting Policies [Text Block]

Summary of Accounting Policies

Basis of Presentation

References in this document to the “Company,” “Chesapeake,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure.

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2013. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures.

We have assessed and reported on subsequent events through the date of issuance of these condensed consolidated financial statements.

Reclassifications

We reclassified certain amounts in the condensed consolidated cash flows statement for the three months ended March 31, 2013 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

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.

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Long-Term Debt - Outstanding Long-Term Debt (Detail) (USD $) In Thousands, unless otherwise specified	Mar. 31, 2014		Dec. 31, 2013
Debt Instrument [Line Items]
Total long-term debt	$ 121,200		$ 122,000
Capital Lease Obligations	6,914		6,978
Total Long-term debt	128,150		128,945
Less: current maturities	(10,955)		(11,353)
Total long-term debt, net of current maturities	117,195		117,592
9.08% bond, due June 1, 2022 [Member]
Debt Instrument [Line Items]
Total long-term debt	7,967	[1]	7,967	[1]
7.83% note, due January 1, 2015 [Member]
Debt Instrument [Line Items]
Total long-term debt	2,000		2,000
6.64% note, due October 31, 2017 [Member]
Debt Instrument [Line Items]
Total long-term debt	10,909		10,909
5.50% note, due October 12, 2020 [Member]
Debt Instrument [Line Items]
Total long-term debt	14,000		14,000
5.93% note, due October 31, 2023 [Member]
Debt Instrument [Line Items]
Total long-term debt	30,000		30,000
5.68% note, due June 30, 2026 [Member]
Debt Instrument [Line Items]
Total long-term debt	29,000		29,000
Uncollateralized Senior Notes Due On May Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Total long-term debt	7,000		7,000
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Total long-term debt	20,000		20,000
8.25% due March 1, 2014 [Member]
Debt Instrument [Line Items]
Total long-term debt	0		646
Promissory note [Member]
Debt Instrument [Line Items]
Total long-term debt	$ 360		$ 445

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

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Accumulated Other Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2014

Equity [Abstract]

Changes in Accumulated Other Comprehensive Loss

The following table presents the changes in the balance of accumulated other comprehensive income (loss) for the three months ended March 31, 2014 and 2013. Defined benefit pension and postretirement plan items are the only component of our accumulated comprehensive income (loss). All amounts in the following table are presented net of tax.

	Three Months Ended
	March 31,
	2014			2013
(in thousands)
Beginning balance	$	(2,533	)	$	(5,062	)
Other comprehensive loss before reclassifications	—			(6		)
Amounts reclassified from accumulated other comprehensive loss	31			55
Net current-period other comprehensive income	31			49
Ending balance	$	(2,502	)	$	(5,013	)

Reclassifications out of Accumulated Other Comprehensive Income (Loss)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three months ended March 31, 2014 and 2013:

	Three Months Ended
	March 31,
	2014			2013
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	14		$	14
Net loss (1)	(66		)	(106		)
Total before income taxes	(52		)	(92		)
Income tax benefit	21			37
Net of tax	$	(31	)	$	(55	)

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

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Environmental Commitments and Contingencies - Additional Information 1 (Detail) (USD $)	3 Months Ended	12 Months Ended
	Mar. 31, 2014	Dec. 31, 2010
Key West Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Period of regulatory inactivity		17 years
Costs to resolve liability	$ 50,000
Key West Florida [Member] | Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Costs to resolve liability	8,000
Pensacola Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Costs to resolve liability	5,000
Winter Haven Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental remediation expense	443,000
Additional remediation costs	100,000
Corrective measures cost	1,000,000
Winter Haven Florida [Member] | Minimum [Member]
Environmental Commitments And Contingencies [Line Items]
Remedial action time period	2 years
Winter Haven Florida [Member] | Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Remedial action time period	3 years
Salisbury Maryland [Member]
Environmental Commitments And Contingencies [Line Items]
Monitoring well remaining maximum cost	$ 5,000

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Share-Based Compensation

3 Months Ended

Mar. 31, 2014

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

Share-Based Compensation

Share-Based Compensation

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

The table below presents the amounts included in net income related to share-based compensation expense for the three months ended March 31, 2014 and 2013:

	Three Months Ended
	March 31,
	2014		2013
(in thousands)
Awards to non-employee directors	$	124	$	111
Awards to key employees	514		270
Total compensation expense	638		381
Less: tax benefit	257		153
Share-Based Compensation amounts included in net income	$	381	$	228

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. At March 31, 2014, there was $41,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors’ remaining service periods ending April 30, 2014.

Key Employees

The table below presents the summary of the stock activity for the awards to key employees for the three months ended March 31, 2014:

	Number of Shares	Weighted Average Fair Value
Outstanding—December 31, 2013	80,761	$	42.30
Granted	27,628	$	58.35
Vested	26,364	$	40.30
Outstanding—March 31, 2014	82,025	$	48.35

In January and March 2014, the Board of Directors granted awards of 27,628 shares to key employees under the SICP. The award of 23,200 shares granted in January 2014 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2016. The award of 4,428 shares granted in March 2014 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2015. These awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprise both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the date each award is granted. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

At March 31, 2014, the aggregate intrinsic value of the SICP awards was $5.2 million.