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: June 30, 2015

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 — 15,260,473 shares outstanding as of July 31, 2015.

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	28
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	50
ITEM 4.	CONTROLS AND PROCEDURES	51
PART II—OTHER INFORMATION		52
ITEM 1.	LEGAL PROCEEDINGS	52
ITEM 1A.	RISK FACTORS	52
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	52
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	52
ITEM 5.	OTHER INFORMATION	52
ITEM 6.	EXHIBITS	53
SIGNATURES		54

GLOSSARY OF DEFINITIONS

ASC: Accounting Standards Codification

ASU: Accounting Standards Update

Aspire Energy of Ohio: Aspire Energy of Ohio, LLC, a newly formed, wholly-owned subsidiary of Chesapeake into which Gatherco, Inc. merged on April 1, 2015.

BravePoint: BravePoint, Inc., our former advanced information services subsidiary, headquartered in Norcross, Georgia, which was sold on October 1, 2014

CDD: Cooling degree-day, 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

CHP: A combined heat and power plant being constructed by Eight Flags in Nassau County, Florida

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

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

Eight Flags: Eight Flags Energy, LLC, a subsidiary of Chesapeake OnSight Services, LLC

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

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

FRP: Fuel Retention Percentage

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

Gatherco: Gatherco, 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-day, 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

NYSE: New York Stock Exchange

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 were entered into with the Note Holders

OPT ≤ 90 Service: Off Peak ≤ 90 Firm Transportation Service, a new tariff associated with Eastern Shore's firm transportation service that will allow Eastern Shore the right not to schedule service for up to 90 days during the peak months of November through April each year

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

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

RAP: Remedial Action Plan, which is a plan that outlines the procedures taken or being considered in removing contaminants from a MGP formerly owned by Chesapeake or FPU

Sandpiper: Sandpiper Energy, Inc.

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

SEC: Securities and Exchange Commission

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

SICP: 2013 Stock and Incentive Compensation Plan

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					Six Months Ended
	June 30,					June 30,
	2015			2014		2015			2014
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	62,060		$	61,646	$	171,642		$	163,812
Unregulated Energy and other	30,622			38,851		91,121			123,022
Total Operating Revenues	92,682			100,497		262,763			286,834
Operating Expenses
Regulated Energy cost of sales	21,124			24,672		78,253			78,979
Unregulated Energy and other cost of sales	20,272			28,442		55,507			89,766
Operations	26,190			24,615		53,133			51,242
Maintenance	2,727			2,457		5,431			4,606
Gain from a settlement	(1,500		)	—		(1,500		)	—
Depreciation and amortization	7,543			6,736		14,518			13,371
Other taxes	3,156			3,118		6,743			6,791
Total Operating Expenses	79,512			90,040		212,085			244,755
Operating Income	13,170			10,457		50,678			42,079
Other income (loss), net of other expenses	(171		)	405		(38		)	413
Interest charges	2,485			2,303		4,933			4,459
Income Before Income Taxes	10,514			8,559		45,707			38,033
Income taxes	4,220			3,425		18,304			15,218
Net Income	$	6,294		$	5,134	$	27,403		$	22,815
Weighted Average Common Shares Outstanding:
Basic	15,235,860			14,556,242		14,922,094			14,522,133
Diluted	15,280,657			14,606,779		14,970,190			14,573,643
Earnings Per Share of Common Stock:
Basic	$	0.41		$	0.35	$	1.84		$	1.57
Diluted	$	0.41		$	0.35	$	1.83		$	1.57
Cash Dividends Declared Per Share of Common Stock	$	0.288		$	0.270	$	0.558		$	0.527

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						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
(in thousands)
Net Income	$	6,294		$	5,134		$	27,403		$	22,815
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(7), $(6), $(14) and $(12), respectively	(10		)	(9		)	(20		)	(18		)
Net gain, net of tax of $62, $27, $125 and $53, respectively	93			40			185			79
Cash Flow Hedges, net of tax:
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $4, ($1), $21 and ($1), respectively.	6			(1		)	32			(1		)
Total Other Comprehensive Income	89			30			197			60
Comprehensive Income	$	6,383		$	5,164		$	27,600		$	22,875

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	June 30, 2015			December 31, 2014
(in thousands, except shares)
Property, Plant and Equipment
Regulated Energy	$	795,331		$	766,855
Unregulated Energy	139,174			84,773
Other businesses and eliminations	19,051			18,497
Total property, plant and equipment	953,556			870,125
Less: Accumulated depreciation and amortization	(205,030		)	(193,369		)
Plus: Construction work in progress	41,923			13,006
Net property, plant and equipment	790,449			689,762
Current Assets
Cash and cash equivalents	2,104			4,574
Accounts receivable (less allowance for uncollectible accounts of $1,146 and $1,120, respectively)	42,270			53,300
Accrued revenue	8,091			13,617
Propane inventory, at average cost	4,151			7,250
Other inventory, at average cost	4,305			3,699
Regulatory assets	7,587			8,967
Storage gas prepayments	2,498			4,258
Income taxes receivable	2,518			18,806
Deferred income taxes	128			—
Prepaid expenses	4,223			6,652
Mark-to-market energy assets	358			1,055
Other current assets	285			195
Total current assets	78,518			122,373
Deferred Charges and Other Assets
Goodwill	16,048			4,952
Other intangible assets, net	2,415			2,404
Investments, at fair value	3,665			3,678
Regulatory assets	77,657			78,136
Receivables and other deferred charges	1,884			3,164
Total deferred charges and other assets	101,669			92,334
Total Assets	$	970,636		$	904,469

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	June 30, 2015			December 31, 2014
(in thousands, except shares and per share data)
Capitalization
Stockholders’ equity
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)	$	7,419		$	7,100
Additional paid-in capital	187,903			156,581
Retained earnings	161,333			142,317
Accumulated other comprehensive loss	(5,479		)	(5,676		)
Deferred compensation obligation	1,843			1,258
Treasury stock	(1,843		)	(1,258		)
Total stockholders’ equity	351,176			300,322
Long-term debt, net of current maturities	156,247			158,486
Total capitalization	507,423			458,808
Current Liabilities
Current portion of long-term debt	9,127			9,109
Short-term borrowing	94,713			88,231
Accounts payable	38,173			44,610
Customer deposits and refunds	21,449			25,197
Accrued interest	1,256			1,352
Dividends payable	4,382			3,939
Deferred income taxes	—			832
Accrued compensation	6,500			10,076
Regulatory liabilities	15,205			3,268
Mark-to-market energy liabilities	47			1,018
Other accrued liabilities	8,756			6,603
Total current liabilities	199,608			194,235
Deferred Credits and Other Liabilities
Deferred income taxes	173,821			160,232
Regulatory liabilities	43,307			43,419
Environmental liabilities	9,043			8,923
Other pension and benefit costs	33,614			35,027
Deferred investment tax credits and other liabilities	3,820			3,825
Total deferred credits and other liabilities	263,605			251,426
Other commitments and contingencies (Note 6)
Total Capitalization and Liabilities	$	970,636		$	904,469

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)

	Six Months Ended
	June 30,
	2015			2014
(in thousands)
Operating Activities
Net income	$	27,403		$	22,815
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization	14,518			13,371
Depreciation and accretion included in other costs	3,486			3,447
Deferred income taxes, net	(1,366		)	166
Realized gain on commodity contracts/sale of assets/investments	(686		)	(420		)
Unrealized gain on investments/commodity contracts	(187		)	(90		)
Employee benefits and compensation	601			319
Share-based compensation	947			1,065
Other, net	8			(1		)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	20,194			36,713
Propane inventory, storage gas and other inventory	4,405			6,074
Regulatory assets/liabilities, net	12,728			(3,147		)
Prepaid expenses and other current assets	3,261			3,183
Accounts payable and other accrued liabilities	(8,990		)	(22,491		)
Income taxes receivable/payable	19,300			3,305
Customer deposits and refunds	(3,748		)	(2,658		)
Accrued compensation	(3,788		)	(2,975		)
Other assets and liabilities, net	(315		)	(113		)
Net cash provided by operating activities	87,771			58,563
Investing Activities
Property, plant and equipment expenditures	(64,719		)	(42,882		)
Proceeds from sales of assets	49			459
Acquisitions, net of cash acquired	(20,930		)	—
Environmental expenditures	(73		)	(79		)
Net cash used in investing activities	(85,673		)	(42,502		)
Financing Activities
Common stock dividends	(7,532		)	(7,120		)
Issuance (purchase) of stock for Dividend Reinvestment Plan	417			(26		)
Change in cash overdrafts due to outstanding checks	2,367			(806		)
Net borrowing (repayment) under line of credit agreements	4,114			(56,990		)
Proceeds from issuance of long-term debt	—			49,975
Repayment of long-term debt and capital lease obligation	(3,934		)	(1,921		)
Net cash used in financing activities	(4,568		)	(16,888		)
Net Decrease in Cash and Cash Equivalents	(2,470		)	(827		)
Cash and Cash Equivalents—Beginning of Period	4,574			3,356
Cash and Cash Equivalents—End of Period	$	2,104		$	2,529

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, 2013	14,457,345	$	4,691	$	152,341	$	124,274		$	(2,533	)	$	1,124	$	(1,124	)	$	278,773
Net income	—	—		—		36,092			—			—		—			36,092
Other comprehensive loss	—	—		—		—			(3,143		)	—		—			(3,143		)
Dividend declared ($1.067 per share)	—	—		—		(15,675		)	—			—		—			(15,675		)
Retirement savings plan and dividend reinvestment plan	43,367	16		1,844		—			—			—		—			1,860
Conversion of debentures	47,313	15		520		—			—			—		—			535
Share-based compensation and tax benefit (2) (3)	40,686	13		1,876		—			—			—		—			1,889
Stock split in the form of stock dividend	—	2,365		—		(2,374		)	—			—		—			(9		)
Treasury stock activities	—	—		—		—			—			134		(134		)	—
Balance at December 31, 2014	14,588,711	7,100		156,581		142,317			(5,676		)	1,258		(1,258		)	300,322
Net income	—	—		—		27,403			—			—		—			27,403
Other comprehensive income	—	—		—		—			197			—		—			197
Dividend declared ($0.558 per share)	—	—		—		(8,387		)	—			—		—			(8,387		)
Dividend reinvestment plan	15,583	8		764		—			—			—		—			772
Common stock issued in acquisition	592,970	289		29,876		—			—			—		—			30,165
Share-based compensation and tax benefit (3)	45,703	22		682		—			—			—		—			704
Treasury stock activities	—	—		—		—			—			585		(585		)	—
Balance at June 30, 2015	15,242,967	$	7,419	$	187,903	$	161,333		$	(5,479	)	$	1,843	$	(1,843	)	$	351,176

⁽¹⁾  Includes 69,884 and 57,382 shares at June 30, 2015 and December 31, 2014, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.

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

⁽³⁾  The shares issued under the SICP are net of shares withheld for employee taxes. For the six months ended June 30, 2015, and for the year ended December 31, 2014, we withheld 12,620 and 12,687 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, 2014. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

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

Reclassifications

As a result of the sale of our advanced information services subsidiary in October 2014, we changed our operating segments (see Note 7, Segment Information). We reclassified certain amounts in the condensed consolidated income statement for the three and six months ended June 30, 2014 and condensed consolidated cash flows statement for the six months ended June 30, 2014 to conform to the current year's presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

Stock Dividend

On July 2, 2014, our Board of Directors approved a three-for-two stock split of our outstanding common stock to be effected in the form of a stock dividend. Each stockholder as of the close of business on the record date, August 13, 2014, received one additional share of common stock for every two shares of common stock owned. The additional shares were distributed on September 8, 2014. All share and per share data in this Form 10-Q are presented on a post-split basis. As a result of the stock split, we reclassified approximately $2.4 million from retained earnings to common stock in September of 2014, which represents $0.4867 par value per share of the shares issued in the stock split.

Gain Contingency

Effective May 29, 2015, we entered into a settlement agreement with a vendor related to the implementation of a customer billing system. Pursuant to the agreement we received $1.5 million in cash, which is reflected as "Gain from a settlement" in the accompanying condensed consolidated statements of income. Previously at December 31, 2014, we recorded a $6.5 million pretax, non-cash impairment loss related to the same billing system implementation. We may also receive $750,000 in additional cash and discounts on future services, however, the receipt or retention of additional cash and future discounts is contingent upon engaging this vendor to provide agreed-upon services over the next five years.

FASB Statements and Other Authoritative Pronouncements

Recent Accounting Standards Yet to be Adopted

Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. On July 9, 2015, the FASB affirmed its proposal to defer the implementation of this standard by one year. For public entities, this standard is effective for 2018 interim and annual financial statements. We are assessing the impact this standard will have on our financial position and results of operations.

Interest - Imputation of Interest (ASC 835-30) - In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. This standard requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. ASU 2015-03 is effective for our interim and annual financial statements issued beginning January 1, 2016. Early adoption is permitted

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for financial statements that have not been previously issued. As of June 30, 2015, we had $322,000 of unamortized debt issuance costs included in the accompanying condensed consolidated balance sheets. Upon adoption of ASU 2015-03, this will be presented as a deduction from long-term debt, net of current maturities.

2. Calculation of Earnings Per Share

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2015		2014		2015		2014
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	6,294	$	5,134	$	27,403	$	22,815
Weighted average shares outstanding	15,235,860		14,556,242		14,922,094		14,522,133
Basic Earnings Per Share	$	0.41	$	0.35	$	1.84	$	1.57
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	6,294	$	5,134	$	27,403	$	22,815
Reconciliation of Denominator:
Weighted shares outstanding—Basic	15,235,860		14,556,242		14,922,094		14,522,133
Effect of dilutive securities:
Share-based compensation	44,797		50,537		48,096		51,510
Adjusted denominator—Diluted	15,280,657		14,606,779		14,970,190		14,573,643
Diluted Earnings Per Share	$	0.41	$	0.35	$	1.83	$	1.57

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

3. Acquisitions

Gatherco Acquisition

On April 1, 2015, we completed the merger with Gatherco, in which Gatherco merged with and into Aspire Energy of Ohio, a newly formed, wholly-owned subsidiary of Chesapeake. As a result of this merger, Aspire Energy of Ohio provides natural gas midstream services through 16 gathering systems and over 2,000 miles of pipelines in Central and Eastern Ohio, including natural gas gathering services and natural gas liquid processing services to over 300 producers, and supplies natural gas to over 6,000 customers in Ohio through the Consumers Gas Cooperative, an independent entity, which Aspire Energy of Ohio manages under an operating agreement.

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

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

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The merger agreement provides for additional contingent cash consideration to Gatherco's shareholders of up to $15.0 million based on a percentage of revenue generated from potential future gathering opportunities over the next five years.

We incurred $1.3 million in transaction costs associated with this merger, $514,000 of which was expensed in the six months ended June 30, 2015. Transactions costs are included in operations expense in the accompanying condensed consolidated statement of income. The revenue and net loss from this acquisition for the three and six months ended June 2015, included in our condensed consolidated statement of income, was $5.2 million and $187,000, respectively. The financial results of Aspire Energy of Ohio are projected to have a minimal impact on our earnings per share in 2015, since the merger was completed after the first quarter. The first quarter includes key winter months, which have historically produced a significant portion of Gatherco's annual earnings. This acquisition is expected to be accretive to our earnings in the first full year of operations, which will include the first quarter of 2016.

The preliminary purchase price allocation of the Gatherco acquisition is as follows:

(in thousands)
Purchase price	$	57,658
Property plant and equipment	52,578
Cash	6,806
Accounts receivable	3,629
Income taxes receivable	3,012
Other assets	247
Total assets acquired	66,272
Long-term debt	1,696
Deferred income taxes	13,863
Accounts payable	3,837
Other current liabilities	314
Total liabilities assumed	19,710
Net identifiable assets acquired	46,562
Goodwill	$	11,096

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

The initial accounting for the Gatherco acquisition is not complete because the valuation necessary to assess the fair values of property, plant and equipment and the related impact on deferred income tax amounts is considered preliminary as we continue to evaluate these assets. The valuation of additional contingent cash consideration and potential environmental remediation costs may be adjusted as additional information becomes available. The purchase price allocation can be modified up to one year from the date of the acquisition, but we will complete the allocation as soon as practicable.

Other acquisitions

On May 7, 2015, we purchased certain propane distribution assets used to serve 253 customers in Citrus County, Florida for approximately $242,000. In connection with this acquisition, we recorded $186,000 in intangible assets related to a non-compete agreement and the customer list to be amortized over six and 10 years, respectively. The remaining purchase price was allocated to property, plant and equipment and accounts receivable. The revenue and net income from this acquisition that were included in our condensed consolidated statement of income for the three and six months ended June 30, 2015 were not material.

4. Rates and Other Regulatory Activities

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

Delaware

There were no significant rates and other regulatory activities in Delaware during the first six months of 2015.

Maryland

There were no significant rates and other regulatory activities in Maryland during the first six months of 2015.

Florida

On January 16, 2015, Chesapeake's Florida natural gas distribution division filed a petition with the Florida PSC for approval of a contract with its affiliate, Peninsula Pipeline, for additional natural gas transportation services in the vicinity of Haines City, located in Polk County, Florida. This petition was approved by the Florida PSC at its Agenda Conference on May 5, 2015.

On July 1, 2015, FPU's electric division filed a new depreciation study with the Florida PSC. Depending upon the Florida PSC's decision in this proceeding, we may be required to change depreciation expense for FPU's electric division. The PSC agenda date for review of the depreciation study has not yet been set.

Eastern Shore

White Oak Mainline Expansion Project: On November 21, 2014, Eastern Shore submitted an application to the FERC for a CP seeking authorization to construct, own, operate and maintain certain expansion facilities designed to provide 45,000 Dts/d of firm transportation service to an industrial customer in Kent County, Delaware. Eastern Shore proposes to construct approximately 7.2 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and 3,550 horsepower of additional compression at Eastern Shore’s existing Delaware City Compressor Station in New Castle County, Delaware. The estimated cost of the project is $29.8 million. On January 22, 2015, the FERC issued a Notice of Intent to Prepare an Environmental Assessment for this project. In February, April and May 2015, Eastern Shore filed environmental data in response to comments regarding evaluation of alternative routes for a segment of the pipeline route in the vicinity of the Kemblesville Historic District. On June 2, 2015, a field meeting was conducted to review the proposed route and alternative routes. At the field meeting, the FERC Staff concluded that Eastern Shore should move forward with evaluating an alternative route, using its existing right-of-way and provide pertinent environmental information. FERC will issue a public notice inviting further comments in advance of issuing an Environmental Assessment. Eastern Shore began survey work on this route on June 29, 2015. Eastern Shore anticipates FERC approval of this project in the fourth quarter of 2015, and estimates that construction will start in the first quarter of 2016.

System Reliability Project: On May 22, 2015, Eastern Shore submitted an application to the FERC for a CP seeking authorization to construct, own, operate and maintain approximately 10.1 miles of 16-inch pipeline looping and appurtenant auxiliary facilities in New Castle and Kent Counties, Delaware and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposes to reinforce critical points on its pipeline system. The total project will benefit all of Eastern Shore’s customers by modifying the pipeline system to respond to severe operational conditions experienced during actual winter peak days in 2014 and 2015. The estimated cost of the project is $32.1 million. Since the project is intended solely to improve system reliability, Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project and an order granting the CP by December 2015.

On June 8, 2015, the FERC filed a notice of the CP application, and the comment period ended on June 29, 2015. Eastern Shore anticipates FERC approval of this project in the fourth quarter of 2015 and estimates that construction will start in the first quarter of 2016.

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, assessment or remediation of, and have exposures at seven former MGP sites. Those sites are located in Salisbury, Maryland, Seaford, Delaware and Winter Haven, Key West, Pensacola, Sanford and

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West Palm Beach, Florida. We have also been in discussions with the MDE regarding another former MGP site located in Cambridge, Maryland.

As of June 30, 2015, we had approximately $10.1 million in environmental liabilities, representing our estimate of the future costs associated with all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites. FPU has approval to recover, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to all of its MGP sites, approximately $9.9 million of which has been recovered as of June 30, 2015, leaving approximately $4.1 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

In addition to the FPU MGP sites, we had $380,000 in environmental liabilities at June 30, 2015 related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of June 30, 2015, we had approximately $145,000 in regulatory and other assets for future recovery through Chesapeake’s rates.

During the first quarter of 2015, we established $273,000 in environmental liabilities related to Chesapeake’s MGP site in Seaford, Delaware, representing our estimate of future costs associated with this site, and recorded a regulatory asset for the same amount for probable future recovery through Chesapeake’s rates, although we have not yet sought Delaware PSC approval for recovery. As of June 30, 2015, we had approximately $245,000 in environmental liabilities and $273,000 in regulatory and other assets related to this site.

Environmental liabilities for all of our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates.

West Palm Beach, Florida

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

Sanford, Florida

FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP at this site. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of June 30, 2015, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements.

In December 2014, the EPA issued a preliminary close-out report, documenting the completion of all physical remediation construction activities at the Sanford site. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site. The total cost of the final remedy is estimated to be over $20.0 million, which includes long-term monitoring and the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.

As of June 30, 2015, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be $24,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million to implement the final remedy for this site, as provided in the Third Participation Agreement, or will pursue a claim against FPU for a sum in

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excess of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of June 30, 2015.

Key West, Florida

FPU formerly owned and operated a MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In 2010, after 17 years of regulatory inactivity, FDEP observed that some soil and groundwater standards were exceeded and requested implementation of additional soil and groundwater fieldwork. The scope of work is limited to the installation of two additional monitoring wells and periodic monitoring of the new and existing wells. The two additional monitoring wells were installed in November 2011, and groundwater monitoring began in December 2011. The first semi-annual report from the monitoring program was issued in May 2012. The data from the June 2012 and September 2012 monitoring events were submitted to the FDEP on October 4, 2012. FDEP responded on October 9, 2012 that, based on the data, NAM appears to be an appropriate remedy for the site.

In October 2012, FDEP issued a RAP approval order, which specified that a limited semi-annual monitoring program be conducted. The most recent groundwater-monitoring event was conducted on March 23, 2015. Natural attenuation default criteria were met at all locations sampled. The next semi-annual sampling event is scheduled for September 2015.

Although the duration of the FDEP-required limited NAM cannot be determined with certainty, we anticipate that total costs to complete the remedial action will not exceed $50,000. The annual cost to conduct the limited NAM program is not expected to exceed $8,000.

Pensacola, Florida

FPU formerly owned and operated a MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the FDOT. In October 2009, FDEP informed Gulf Power that it would approve a conditional No Further Action determination for the site with the requirement for institutional and engineering controls. On June 16, 2014, FDEP issued a draft memorandum of understanding between FDOT and FDEP to implement site closure with approved institutional and engineering controls for the site. We anticipate that FPU’s share of remaining legal and cleanup costs will not exceed $5,000.

Winter Haven, Florida

The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a consent order entered into with FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. Groundwater monitoring results have shown a continuing reduction in contaminant concentrations from the sparging system, which has been in operation since 2002. On September 12, 2014, FDEP issued a letter approving shutdown of the sparging operations on the northern portion of the site, contingent upon continued semi-annual monitoring.

Groundwater monitoring results on the southern portion of this site indicate that natural attenuation default criteria continue to be exceeded. Plans to modify the monitoring network on the southern portion of the site in order to collect additional data to support the development of a remedial plan were specified in a letter to FDEP, dated October 17, 2014. The well installation and abandonment program was implemented in October 2014, and documentation was reported in the semi-annual RAP implementation status report submitted January 8, 2015. Although specific remedial actions have not yet been identified, we estimate that future remediation costs for the subsurface soils and groundwater at the site should not exceed $443,000, which includes an estimate of $100,000 to implement additional actions, such as institutional controls, at the site. We continue to believe that the entire amount will be recoverable from customers through rates.

FDEP previously indicated that we could also be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, and our recent meeting with FDEP, we believe that corrective measures for lake sediments are not warranted and will not be required by FDEP; therefore, we have not recorded a liability for sediment remediation.

Salisbury, Maryland

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

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Seaford, Delaware

In a letter dated December 5, 2013, the DNREC notified us that it would be conducting a facility evaluation of a former MGP site in Seaford, Delaware. In a report issued in January 2015, DNREC provided the evaluation, which found several compounds within the groundwater and soil that require further investigation. We submitted an application to DNREC on April 2, 2015 to enter this site into the voluntary cleanup program, and at this time, DNREC is still considering our application. We estimate the cost of potential remedial actions, based on the findings of the DNREC report, to be between $273,000 and $465,000.

Other

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

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 natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. Our Delaware and Maryland natural gas distribution divisions have a contract through March 31, 2017, with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage capacity.

In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term. Approximately four years remain under this contract. Sandpiper's current annual commitment is estimated at approximately 6.5 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.

Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a six-year term. Sharp's current annual commitment is estimated at approximately 6.5 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement.

Chesapeake’s Florida natural gas distribution division has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including PESCO. Under the terms of these capacity release agreements, Chesapeake is contingently liable to FGT and Gulfstream should any party that acquired the capacity through release fail to pay the capacity charge.

In May 2015, PESCO renewed contracts to purchase natural gas from various suppliers. The total commitment is to purchase between 9,982 and 13,423 Dts/dduring the months of June 2015 to May 2016. These contracts expire in May 2016.

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) a fixed charge coverage ratio greater than 1.5 times. If FPU fails to comply with either of these ratios, it has 30 days to cure the default or, if the default is not cured, to provide an irrevocable letter of credit. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet either of these ratios, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of June 30, 2015, FPU was in compliance with all of the requirements of its fuel supply contracts.

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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 $50.0 million.

We have issued corporate guarantees to certain vendors of our subsidiaries, the largest portion of which is for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases, respectively, in the event that Xeron or PESCO defaults. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at June 30, 2015 was $32.0 million, with the guarantees expiring on various dates through June 29, 2016.

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

In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million, which expires on September 12, 2015, related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for $1.2 million, which expires on October 31, 2015, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company in 2010, we renewed and decreased the letter of credit for $40,000 to our former primary insurance company, which will expire on June 1, 2016. There have been no draws on these letters of credit as of June 30, 2015. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.

We provided a letter of credit for $2.3 million to TETLP related to the firm transportation service agreement with our Delaware and Maryland divisions.

Tax-related Contingencies

We are subject to various audits and reviews by the federal, state, local and other governmental authorities regarding income taxes and taxes other than income. As of June 30, 2015, we maintained a liability of $100,000 related to unrecognized income tax benefits and $525,000 related to contingencies for taxes other than income. As of December 31, 2014, we maintained a liability of $100,000 related to unrecognized income tax benefits and $724,000 related to contingencies for taxes other than income.

Other

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

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 two reportable segments:

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

• Unregulated Energy. The Unregulated Energy segment includes propane distribution and wholesale marketing operations, and natural gas marketing operations, which are unregulated as to their rates and services. Effective April 1, 2015, this segment includes Aspire Energy of Ohio, whose services include natural gas gathering and processing (See Note 3, Acquisitions, regarding the acquisition of Gatherco). Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services.

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

The following table presents financial information about our reportable segments:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	61,790		$	61,348		$	171,082		$	163,222
Unregulated Energy segment	30,892			34,299			91,681			114,173
Other businesses	—			4,850			—			9,439
Total operating revenues, unaffiliated customers	$	92,682		$	100,497		$	262,763		$	286,834
Intersegment Revenues (1)
Regulated Energy segment	$	270		$	298		$	560		$	590
Unregulated Energy segment	1,666			22			1,873			121
Other businesses	220			248			440			502
Total intersegment revenues	$	2,156		$	568		$	2,873		$	1,213
Operating Income (Loss)
Regulated Energy segment	$	13,605		$	10,711		$	35,788		$	31,802
Unregulated Energy segment	(540		)	(43		)	14,689			10,815
Other businesses and eliminations	105			(211		)	201			(538		)
Total operating income	13,170			10,457			50,678			42,079
Other income (loss), net of other expenses	(171		)	405			(38		)	413
Interest	2,485			2,303			4,933			4,459
Income before Income Taxes	10,514			8,559			45,707			38,033
Income taxes	4,220			3,425			18,304			15,218
Net Income	$	6,294		$	5,134		$	27,403		$	22,815

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

(in thousands)	June 30, 2015		December 31, 2014
Identifiable Assets
Regulated Energy segment	$	800,719	$	796,021
Unregulated Energy segment	147,102		84,732
Other businesses and eliminations	22,815		23,716
Total identifiable assets	$	970,636	$	904,469

Our operations are entirely domestic.

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8. Accumulated Other Comprehensive Income (Loss)

Defined benefit pension and postretirement plan items and unrealized gains (losses) of our propane swap agreements and call options, designated as commodity contracts cash flow hedges, are the components of our accumulated comprehensive income (loss). The following tables present the changes in the balance of accumulated other comprehensive loss for the six months endedJune 30, 2015 and 2014. All amounts are presented net of tax.

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

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2013	$	(2,533	)	$	—		$	(2,533	)
Other comprehensive loss before reclassifications	—			(1		)	(1		)
Amounts reclassified from accumulated other comprehensive loss	61			—			61
Net current-period other comprehensive income (loss)	61			(1		)	60
As of June 30, 2014	$	(2,472	)	$	(1	)	$	(2,473	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and six months endedJune 30, 2015 and 2014. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.

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	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	17		$	15		$	34		$	30
Net loss (1)	(155		)	(67		)	(310		)	(132		)
Total before income taxes	(138		)	(52		)	(276		)	(102		)
Income tax benefit	55			21			111			41
Net of tax	$	(83	)	$	(31	)	$	(165	)	$	(61	)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	(10	)	$	2		$	2		$	2
Call options (2)	—			—			(55		)	—
Total before income taxes	(10		)	2			(53		)	2
Income tax benefit	4			(1		)	21			(1		)
Net of tax	(6		)	1			(32		)	1
Total reclassifications for the period	$	(89	)	$	(30	)	$	(197	)	$	(60	)

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

⁽²⁾ These amounts are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments, for additional details.

Amortization of defined benefit pension and postretirement plan items is included in operations expense and gains and losses on propane swap agreements and call options are included in cost of sales in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.

9. Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three and six months endedJune 30, 2015 and 2014 are set forth in the following tables:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended June 30,	2015			2014			2015			2014			2015		2014		2015			2014			2015		2014
(in thousands)
Interest cost	$	102		$	106		$	626		$	647		$	23	$	23	$	11		$	13		$	15	$	16
Expected return on plan assets	(135		)	(132		)	(777		)	(772		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			2		5		(19		)	(20		)	—		—
Amortization of net loss	91			38			114			—			25		12		17			17			2		—
Net periodic cost (benefit)	58			12			(37		)	(125		)	50		40		9			10			17		16
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	58		$	12		$	154		$	66		$	50	$	40	$	9		$	10		$	19	$	18

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	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Six Months Ended June 30,	2015			2014			2015			2014			2015		2014		2015			2014			2015		2014
(in thousands)
Interest cost	$	204		$	213		$	1,251		$	1,294		$	46	$	46	$	22		$	26		$	30	$	33
Expected return on plan assets	(270		)	(265		)	(1,554		)	(1,545		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			5		9		(39		)	(39		)	—		—
Amortization of net loss	181			75			227			—			50		24		35			33			3		—
Net periodic cost (benefit)	115			23			(76		)	(251		)	101		79		18			20			33		33
Amortization of pre-merger regulatory asset	—			—			381			381			—		—		—			—			4		4
Total periodic cost	$	115		$	23		$	305		$	130		$	101	$	79	$	18		$	20		$	37	$	37

We expect to record pension and postretirement benefit costs of approximately $1.2 million for 2015. Included in these costs is $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations for the changes in funded status that occurred but were not recognized as part of net periodic benefit costs prior to the FPU merger. This was deferred as a regulatory asset by FPU prior to the merger to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was $3.2 million and $3.6 million at June 30, 2015 and December 31, 2014, respectively. The amortization included in pension expense is also being added to a net periodic loss of $381,000, which will increase our total expected benefit costs to $1.2 million.

Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs related to its regulated operations after the FPU merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake’s operations is recorded to accumulated other comprehensive income (loss). The following table presents the amounts included in the regulatory asset and accumulated other comprehensive income (loss) that were recognized as components of net periodic benefit cost during the three and six months ended June 30, 2015 and 2014:

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

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

For the Three Months Ended June 30, 2014	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	5	$	(20	)	$	—	$	(15	)
Net loss	38		—		12		17			—		67
Total recognized in net periodic benefit cost	$	38	$	—	$	17	$	(3	)	$	—	$	52
Recognized from accumulated other comprehensive loss (1)	$	38	$	—	$	17	$	(3	)	$	—	$	52
Recognized from regulatory asset	—		—		—		—			—		—
Total	$	38	$	—	$	17	$	(3	)	$	—	$	52

For the Six Months Ended June 30, 2014	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	9	$	(39	)	$	—	$	(30	)
Net loss	75		—		24		33			—		132
Total recognized in net periodic benefit cost	$	75	$	—	$	33	$	(6	)	$	—	$	102
Recognized from accumulated other comprehensive loss (1)	$	75	$	—	$	33	$	(6	)	$	—	$	102
Recognized from regulatory asset	—		—		—		—			—		—
Total	$	75	$	—	$	33	$	(6	)	$	—	$	102

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

During the three and six months ended June 30, 2015, we contributed $115,000 and $219,000, respectively to the Chesapeake Pension Plan and $381,000 and $723,000, respectively to the FPU Pension Plan. We expect to contribute a total of $475,000 and $1.6 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2015, which represent the minimum contribution payments required during the year.

The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three and six months ended June 30, 2015, were $38,000 and $71,000, respectively. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake Pension SERP in 2015. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three and six months ended June 30, 2015, were $13,000 and $28,000, respectively. We estimate that approximately $79,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2015. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and six months ended June 30, 2015, were $24,000 and $116,000, respectively. We estimate that approximately $207,000 will be paid for such benefits under the FPU Medical Plan in 2015.

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10. Investments

The investment balances at June 30, 2015 and December 31, 2014, consisted of the following:

(in thousands)	June 30, 2015		December 31, 2014
Rabbi trust (associated with the Deferred Compensation Plan)	$	3,649	$	3,678
Investments in equity securities	16		—
Total	$	3,665	$	3,678

We classify these investments as trading securities and report them at their fair value. For the three months ended June 30,2015 and 2014, we recorded a net unrealized gain of $4,000 and $114,000, respectively, in other income in the condensed consolidated statements of income related to these investments. For the six months ended June 30,2015 and 2014, we recorded a net unrealized gain of $107,000 and $152,000, respectively, in other income in the condensed consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the condensed consolidated balance sheets and is adjusted each month for the gains and losses incurred by the Rabbi Trust.

11. Share-Based Compensation

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

The table below presents the amounts included in net income related to share-based compensation expense for the three and six months endedJune 30, 2015 and 2014:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
(in thousands)
Awards to non-employee directors	$	160		$	132		$	311		$	256
Awards to key employees	250			295			636			809
Total compensation expense	410			427			947			1,065
Less: tax benefit	(165		)	(172		)	(381		)	(429		)
Share-based compensation amounts included in net income	$	245		$	255		$	566		$	636

Non-employee Directors

Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the date of the grant. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2015, each of our non-employee directors received an annual retainer of 1,207 shares of common stock under the SICP for Board service through the 2016 Annual Meeting of Stockholders. A summary of the stock activity for our non-employee directors during the six months ended June 30, 2015 is presented below:

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	Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2014	—		$	—
Granted	14,484		$	45.54
Vested	(14,484	)	$	45.54
Outstanding— June 30, 2015	—		$	—

At June 30, 2015, there was $550,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2016.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the six months ended June 30, 2015:

	Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2014	123,038		$	32.60
Granted	29,763		$	48.21
Vested	(43,839	)	$	28.01
Expired	(2,520	)	$	28.83
Outstanding— June 30, 2015	106,442		$	37.97

In January 2015, our Board of Directors granted awards of 29,763 shares of common stock to key employees under the SICP. The shares granted in January 2015 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2017. All of these stock awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprise both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the date each award is granted. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

At June 30, 2015, the aggregate intrinsic value of the SICP awards granted to key employees was $5.7 million. At June 30, 2015, there was $1.9 million of unrecognized compensation cost related to these awards, which is expected to be recognized during 2015 through 2017.

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 typically either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory or cash flow hedges of its future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of June 30, 2015, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Hedging Activities in 2015

In March, May and June 2015, Sharp paid $143,000 to purchase put options to protect against a decline in propane prices and related potential inventory losses associated with 2.5 million gallons for the propane price cap program in the upcoming heating season. The put options are exercised if propane prices fall below the strike prices of $0.4950, $0.4888 and $0.4500 per gallon in December 2015 through February 2016 and $0.4200 per gallon in January through March 2016. If exercised, we will receive the difference between the market price and the strike price during those months. We accounted for the put options as fair value hedges, and there is no ineffective portion of these hedges. As of June 30, 2015, the put options had a fair value of $110,000. The change in fair value of the put options effectively reduced our propane inventory balance.

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In March, May and June 2015, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 2.5 million gallons expected to be purchased for the upcoming heating season. Under these swap agreements, Sharp receives the difference between the index prices (Mont Belvieu prices in December 2015 through March 2016) and the swap prices of $0.5950, $0.5888, $0.5500 and $0.5200 per gallon for each swap agreement, to the extent the index prices exceed the swap prices. If the index prices are lower than the swap prices, Sharp will pay the difference. These swap agreements essentially fix the price of the 2.5 million gallons that we expect to purchase for the upcoming heating season. We accounted for the swap agreements as cash flow hedges, and there is no ineffective portion of these hedges. At June 30, 2015, two swap agreements had a liability fair value of $38,000 and two swap agreements had an asset fair value of $36,000. The change in the fair value of the swap agreements is recorded as unrealized gain/loss in other comprehensive income (loss).

Hedging Activities in 2014

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

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

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

Commodity Contracts for Trading Activities

Xeron engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under this method, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statement of income for the period of change. As of June 30, 2015, we had the following outstanding trading contracts, which we accounted for as derivatives:

	Quantity in	Estimated Market	Weighted Average
At June 30, 2015	Gallons	Prices	Contract Prices
Forward Contracts
Sale	4,620,000	$0.3475 - $0.5288	$	0.4760
Purchase	4,620,000	$0.3550 - $0.5025	$	0.4322

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

Xeron has entered into master netting agreements with two counterparties to mitigate exposure to counterparty credit risk. The master netting agreements enable Xeron to net these two counterparties' outstanding accounts receivable and payable, which are presented on a gross basis in the accompanying condensed consolidated balance sheets. At June 30, 2015, Xeron had a right to offset $654,000 and $222,000 of accounts receivable and accounts payable, respectively, with

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these two counterparties. At December 31, 2014, Xeron had a right to offset $1.6 million and $1.2 million of accounts receivable and accounts payable, respectively, with these two counterparties.

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of June 30, 2015 and December 31, 2014, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2015		December 31, 2014
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	212	$	407
Derivatives designated as fair value hedges
Put options	Mark-to-market energy assets	110		622
Derivatives designated as cash flow hedges
Call options	Mark-to-market energy assets	—		26
Propane swap agreements	Mark-to-market energy assets	36		—
Total asset derivatives		$	358	$	1,055

	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2015		December 31, 2014
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	9	$	283
Propane swap agreements	Mark-to-market energy liabilities	—		735
Derivatives designated as cash flow hedges
Propane swap agreements	Mark-to-market energy liabilities	38		—
Total liability derivatives		$	47	$	1,018

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

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(in thousands)	(Loss) on Derivatives	2015			2014			2015			2014
Derivatives not designated as hedging instruments
Realized gain (loss) on forward contracts (1)	Revenue	$	(71	)	$	84		$	206		$	1,330
Unrealized gain (loss) on forward contracts	Revenue	203			6			78			(62		)
Call option	Cost of sales	—			—			—			137
Propane swap agreements	Cost of sales	—			—			18			—
Derivatives designated as fair value hedges
Put options	Cost of sales	—			(29		)	506			(49		)
Put options (2)	Propane Inventory	(30		)	—			(34		)	—
Derivatives designated as cash flow hedges
Propane swap agreements	Other Comprehensive loss	10			(2		)	(2		)	(2		)
Call options	Cost of sales	—			—			(81		)	—
Total		$	112		$	59		$	691		$	1,354

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

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

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).

Financial Assets and Liabilities Measured at Fair Value

The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of June 30, 2015 and December 31, 2014:

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			Fair Value Measurements Using:
As of June 30, 2015	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments - equity securities	$	16	$	16	$	—	$	—
Investments—guaranteed income fund	$	335	$	—	$	—	$	335
Investments—other	$	3,314	$	3,314	$	—	$	—
Mark-to-market energy assets, incl. put options and swap agreements	$	358	$	—	$	358	$	—
Liabilities:
Mark-to-market energy liabilities incl. swap agreements	$	47	$	—	$	47	$	—

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

The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of June 30, 2015 and December 31, 2014:

Level 1 Fair Value Measurements:

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

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

Level 2 Fair Value Measurements:

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

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

Level 3 Fair Value Measurements:

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

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The following table sets forth the summary of the changes in the fair value of Level 3 investments for the six months ended June 30, 2015 and 2014:

	Six Months Ended   June 30,
	2015			2014
(in thousands)
Beginning Balance	$	287		$	458
Purchases and adjustments	49			(26		)
Transfers	(3		)	(25		)
Investment income	2			3
Ending Balance	$	335		$	410

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

At June 30, 2015, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its short maturities and because interest rates approximate current market rates (Level 3 measurement).

At June 30, 2015, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of $159.9 million. This compares to a fair value of $174.1 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At December 31, 2014, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of $161.5 million, compared to the estimated fair value of $180.7 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

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14. Long-Term Debt

Our outstanding long-term debt is shown below:

	June 30,			December 31,
(in thousands)	2015			2014
FPU secured first mortgage bonds (1) :
9.08% bond, due June 1, 2022	$	7,971		$	7,969
Uncollateralized senior notes:
6.64% note, due October 31, 2017	8,182			8,182
5.50% note, due October 12, 2020	12,000			12,000
5.93% note, due October 31, 2023	25,500			27,000
5.68% note, due June 30, 2026	29,000			29,000
6.43% note, due May 2, 2028	7,000			7,000
3.73% note, due December 16, 2028	20,000			20,000
3.88% note, due May 15, 2029	50,000			50,000
Promissory notes	238			314
Capital lease obligation	5,483			6,130
Total long-term debt	165,374			167,595
Less: current maturities	(9,127		)	(9,109		)
Total long-term debt, net of current maturities	$	156,247		$	158,486

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

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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, 2014, 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 the 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 recoverable in rates;

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

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

• the extent of our 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; and

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

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Introduction

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

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;

• continuing to build a branded culture that drives a shared mission, vision, and values;

• 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 is 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.

Shares and per share amounts for all periods presented reflect the three-for-two stock split declared on July 2, 2014, which was effected in the form of a stock dividend and distributed on September 8, 2014.

Unless otherwise noted, earnings per share information is presented on a diluted basis.

As a result of the sale of BravePoint in October 2014, we no longer report the Other segment.

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Results of Operations for the Three and Six Months endedJune 30, 2015

Overview and Highlights

Our net income for the quarter ended June 30, 2015 was $6.3 million, or $0.41 per share. This represents an increase of $1.2 million, or $0.06 per share, compared to net income of $5.1 million, or $0.35 per share, as reported for the same quarter in 2014. The increase in operating income from the Regulated Energy segment was the key driver in our net income growth. Also included in our results for the quarter ended June 30, 2015 was a $900,000 after-tax gain ($1.5 million in operating income), or $0.06 per share, related to cash received from a settlement with a vendor regarding a customer billing system implementation.

	Three Months Ended
	June 30,
	2015			2014			Increase
(in thousands except per share)
Business Segment:
Regulated Energy segment	$	13,605		$	10,711		$	2,894
Unregulated Energy segment	(540		)	(43		)	(497		)
Other businesses and eliminations	105			(211		)	316
Operating Income	13,170			10,457			2,713
Other Income (Loss), net of Other Expenses	(171		)	405			(576		)
Interest Charges	2,485			2,303			182
Pre-tax Income	10,514			8,559			1,955
Income Taxes	4,220			3,425			795
Net Income	$	6,294		$	5,134		$	1,160
Earnings Per Share of Common Stock
Basic	$	0.41		$	0.35		$	0.06
Diluted	$	0.41		$	0.35		$	0.06

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Key variances included:

(in thousands, except per share)	Pre-tax Income			Net Income			Earnings Per Share
Second Quarter of 2014 Reported Results	$	8,559		$	5,134		$	0.35
Adjusting for Unusual Items:
Gain from a settlement	1,500			900			0.06
Gain on sale of business, recorded in 2014	(397		)	(238		)	(0.02		)
Absence of BravePoint, which was sold in October 2014	319			191			0.01
	1,422			853			0.05
Increased (Decreased) Gross Margins:
Contribution from Aspire Energy of Ohio	1,624			974			0.07
Natural gas growth (excluding service expansions)	1,347			808			0.06
GRIP	1,067			640			0.04
Service expansions (See Major Projects Highlights table)	919			551			0.04
FPU Electric base rate increase	731			439			0.03
Higher retail propane margins	649			389			0.03
Decrease in customer consumption	(203		)	(122		)	(0.01		)
	6,134			3,679			0.26
Increased Other Operating Expenses:
Expenses from Aspire Energy of Ohio	(1,895		)	(1,137		)	(0.08		)
Higher payroll and benefits costs	(802		)	(481		)	(0.03		)
Increased accrual for incentive compensation	(606		)	(364		)	(0.02		)
Higher depreciation, asset removal and property tax costs due to recent capital investments	(495		)	(297		)	(0.02		)
Costs associated with billing system settlement and other initiatives	(465		)	(279		)	(0.02		)
Higher facility maintenance	(194		)	(116		)	(0.01		)
Higher amortization expense	(172		)	(103		)	(0.01		)
	(4,629		)	(2,777		)	(0.19		)
Interest Charges	(182		)	(109		)	(0.01		)
Net Other Changes (1)	$	(790	)	$	(486	)	$	(0.05	)
Second Quarter of 2015 Reported Results	$	10,514		$	6,294		$	0.41

⁽¹⁾ The earnings per share impact net of other changes shown above includes $(0.02) of dilution from the issuance of 592,970 shares of our common stock in conjunction with the merger of Gatherco into Aspire Energy of Ohio on April 1, 2015.

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Our net income for the six months endedJune 30, 2015 was $27.4 million, or $1.83 per share. This represents an increase of $4.6 million, or $0.26 per share, compared to net income of $22.8 million, or $1.57 per share, as reported for the same period in 2014. Increases in operating income from both the Regulated Energy and Unregulated Energy segments were the key drivers in our net income growth. Also included in our results for the six months ended June 30, 2015 was a $900,000 after-tax gain ($1.5 million in operating income), or $0.06 per share, related to cash received from a settlement with a vendor regarding a customer billing system implementation.

	Six Months Ended
	June 30,
	2015			2014			Increase
(in thousands except per share)
Business Segment:
Regulated Energy segment	$	35,788		$	31,802		$	3,986
Unregulated Energy segment	14,689			10,815			3,874
Other businesses and eliminations	201			(538		)	739
Operating Income	50,678			42,079			8,599
Other Income (Loss), net of Other Expenses	(38		)	413			(451		)
Interest Charges	4,933			4,459			474
Pre-tax Income	45,707			38,033			7,674
Income Taxes	18,304			15,218			3,086
Net Income	$	27,403		$	22,815		$	4,588
Earnings Per Share of Common Stock
Basic	$	1.84		$	1.57		$	0.27
Diluted	$	1.83		$	1.57		$	0.26

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Key variances included:

(in thousands, except per share)	Pre-tax Income			Net Income			Earnings Per Share
Six months ended June 30, 2014 Reported Results	$	38,033		$	22,815		$	1.57
Adjusting for Unusual Items:
Gain from a settlement	1,500			900			0.06
Absence of BravePoint, which was sold in October 2014	757			454			0.03
Gain on sale of business, recorded in 2014	(397		)	(238		)	(0.02		)
Weather impact	320			192			0.01
	2,180			1,308			0.08
Increased (Decreased) Gross Margins:
Higher retail propane margins	5,650			3,387			0.23
Natural gas growth (excluding service expansions)	2,378			1,426			0.10
Service expansions (See Major Projects Highlights table)	2,377			1,425			0.10
GRIP	1,822			1,092			0.07
FPU Electric base rate increase	1,693			1,015			0.07
Contribution from Aspire Energy of Ohio	1,624			974			0.07
Propane wholesale marketing	(984		)	(590		)	(0.04		)
Increase in customer consumption	408			245			0.02
	14,968			8,974			0.62
Increased Other Operating Expenses:
Expenses from Aspire Energy of Ohio	(1,895		)	(1,136		)	(0.08		)
Higher payroll and benefits costs	(1,654		)	(992		)	(0.07		)
Costs associated with billing system settlement and other transactions	(1,081		)	(648		)	(0.04		)
Higher depreciation, asset removal costs and property tax costs due to recent capital investments	(944		)	(566		)	(0.04		)
Higher service contractor and other consulting costs	(853		)	(511		)	(0.04		)
Increased accruals for incentive compensation	(837		)	(502		)	(0.03		)
Higher facility maintenance	(657		)	(394		)	(0.03		)
Higher amortization expense	(302		)	(181		)	(0.01		)
	(8,223		)	(4,930		)	(0.34		)
Interest Charges	(474		)	(284		)	(0.02		)
Net Other Changes (1)	$	(777	)	$	(480	)	$	(0.08	)
Six months ended June 30, 2015 Reported Results	45,707			27,403			1.83

⁽¹⁾ The earnings per share impact net of other changes shown above includes $(0.04) of dilution from the issuance of 592,970 shares of our common stock in conjunction with the merger of Gatherco into Aspire Energy of Ohio on April 1, 2015.

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Summary of Key Factors

The following information highlights certain key factors contributing to our results for the current and future periods.

Major Projects

Service Expansions

During 2014, Eastern Shore, our interstate pipeline subsidiary, executed a one-year contract with an industrial customer in New Castle County, Delaware to provide 50,000 Dts/d of additional transmission service from April 2014 to April 2015. This contract was subsequently amended to provide 55,580 Dts/d of transmission service at a lower reservation rate through August 2020. This contract, including the impact of the extension, generated additional gross margin of $111,000 and $842,000 for the three and six months ended June 30, 2015, respectively. The lower rate decreased gross margin by $183,000 for the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014, and will reduce the gross margin generated by this contract by $409,000 in the second half of 2015. The extension of the contract, net of the impact from the lower rate, generated additional gross margin of $659,000, for the six months ended June 30, 2015.

In December 2014, Eastern Shore executed another short-term contract with the same customer in New Castle County, Delaware to provide an additional 10,000 Dts/d of OPT ≤ 90 Service from December 2014 to March 2015. The OPT ≤ 90 Service is a new firm transportation service that allows Eastern Shore not to schedule service for up to 90 days during the peak months of November through April each year. This short-term contract generated additional gross margin of $233,000 for the six months ended June 30, 2015.

On October 1, 2014, Eastern Shore commenced a new lateral service to an industrial customer facility in Kent County, Delaware. This service commenced after construction of new facilities, including approximately 5.5 miles of pipeline lateral and metering facilities, extending from Eastern Shore's mainline to the new industrial customer facility. This new service generated $463,000 and $926,000, of gross margin for the three and six months endedJune 30, 2015, respectively. On an annual basis, this service is expected to generate $1.8 million of gross margin in 2015 and annual gross margin of approximately $1.2 million to $1.8 million during the 37-year service period.

In April 2015, Eastern Shore commenced interruptible service to the same industrial customer in Kent County, Delaware and generated additional gross margin of $398,000 for the three and six months ended June 30, 2015. The interruptible service is expected to generate $2.5 million of gross margin in 2015, and it is expected to be replaced by the new OPT ≤ 90 Service beginning late first quarter or early second quarter of 2016. (See the Future Service Expansion Initiatives section).

On January 16, 2015, the Florida PSC approved a firm transportation agreement between Peninsula Pipeline and Chesapeake's Florida natural gas distribution division. Under this agreement, Peninsula Pipeline provides natural gas transmission service to support Chesapeake's expansion of natural gas distribution service in Polk County, Florida at an annual rate of $1.6 million. Peninsula Pipeline began the initial phase of its service to Chesapeake in March 2015, which generated $134,000 and $161,000 of additional gross margin for the three and six months ended June 30, 2015, respectively. All phases of this service will generate $1.6 million of estimated annual gross margin.

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The following Major Project Highlights table summarizes our major projects initiated since 2014 (dollars in thousands):

	Gross Margin for the Period (1)
	Three Months Ended							Six Months Ended						Estimate		Total
	June 30,							June 30,						for		2014
	2015		2014		Variance			2015		2014		Variance		2015		Margin
Acquisition:
Aspire Energy of Ohio (formerly Gatherco) (2)	$	1,624	$	—	$	1,624		$	1,624	$	—	$	1,624	$	8,797	$	—
Service Expansions
Natural Gas Transmission:
Short-term
New Castle County, Delaware	$	523	$	599	$	(76	)	$	1,491	$	599	$	892	$	2,505	$	2,026
Kent County, Delaware (3)	398		—		398			398		—		398		2,516		—
Total short-term	921		599		322			1,889		599		1,290		5,021		2,026
Long-term
Kent County, Delaware	463		—		463			926		—		926		1,844		463
Polk County, Florida	134		—		134			161		—		161		908		—
Total long-term	$	597	$	—	$	597		$	1,087	$	—	$	1,087	$	2,752	$	463
Total Service Expansions	$	1,518	$	599	$	919		$	2,976	$	599	$	2,377	$	7,773	$	2,489
Total Major Projects	$	3,142	$	599	$	2,543		$	4,600	$	599	$	4,001	$	16,570	$	2,489

⁽¹⁾ Gross margin of $4.5 million and $11.8 million for the three and six months ended June 30, 2014, and $21.8 million for the year ended December 31, 2014, respectively, related to projects initiated prior to 2014. These projects were previously disclosed and are excluded from the above table as they no longer result in period-over-period variances.

⁽²⁾ During the three and six months ended June 30, 2015, we incurred $1.9 million in other operating expenses related to Aspire Energy of Ohio's operation. We expect to incur a total of $6.7 million in other operating expenses for all of 2015.

⁽³⁾ The gross margin is attributable to interruptible service Eastern Shore provided to an industrial customer beginning in April 2015. The interruptible service will be replaced by the OPT ≤ 90 Service beginning in late first quarter or early second quarter of 2016.

Future Service Expansion Initiatives

Eight Flags, one of our unregulated energy subsidiaries, is engaged in the development and construction of a CHP plant in Nassau County, Florida. This CHP plant, which will consist of a natural-gas-fired turbine and associated electric generator, is designed to generate approximately 20 megawatts of base load power and will include a heat recovery system generator capable of providing approximately 75,000 pounds per hour of unfired steam. Eight Flags will sell the power generated from the CHP plant to FPU for distribution to its retail electric customers pursuant to a 20-year power purchase agreement. It will also sell the steam to an industrial customer pursuant to a separate 20-year contract. FPU will transport natural gas through its distribution system to Eight Flags’ CHP plant, which will produce power and steam. On a consolidated basis, this project is expected to generate approximately $7.3 million in annual gross margin, which could fluctuate based upon various factors, including, but not limited to, the quantity of steam delivered and the CHP plant’s hours of operations. Eight Flags' CHP plant is expected to be operational in the third quarter of 2016. Our total projected investment, by Eight Flags and other Chesapeake affiliates, to construct the CHP plant and associated facilities is approximately $40.0 million.

In December 2014, Eastern Shore entered into a precedent agreement with an industrial customer in Kent County, Delaware, whereby Eastern Shore committed to provide a 20-year natural gas transmission service for 45,000 Dts/d for the customer's new facility, upon the satisfaction of certain conditions. This new service will be provided as OPT ≤ 90 Service and is expected to generate at least $5.8 million in annual gross margin. In November 2014, Eastern Shore requested the FERC's authorization to construct 7.2 miles of 16-inch pipeline looping and 3,550 horsepower of new compression in Delaware to provide this service. The cost of these new facilities is estimated to be approximately $30 million. Eastern Shore anticipates receiving the FERC’s authorization in 2015, with service targeted to commence in the late first quarter or early second quarter of 2016, following construction of the new facilities. As previously discussed, during the second quarter of 2015, we generated $398,000 in additional gross margin by providing interruptible service to this customer.

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The following table summarizes our future major expansion initiatives and opportunities with executed contracts (dollars in thousands):

Project	Estimated In Service Date	Projected Capital Cost	Estimated Annualized Margin
20-year OPT ≤ 90 Service to an industrial customer in Kent County, Delaware	Late first quarter or early second quarter of 2016	$30.0 million	$5.8 million
Eight Flags CHP plant in Nassau County, Florida	Third quarter of 2016	$40.0 million	$7.3 million

Other Natural Gas Growth - Distribution Operations

In addition to these service expansions, the natural gas distribution operations on the Delmarva Peninsula generated $395,000 and $845,000, respectively, in additional gross margin for the three and six months ended June 30, 2015 compared to the same periods in 2014, due to an increase in residential, commercial and industrial customers served. The number of residential customers on the Delmarva Peninsula increased by 2.6 percent in the second quarter of 2015, compared to the same quarter in 2014.The natural gas distribution operations in Florida generated $660,000 and $1.1 million, respectively, in additional gross margin for the three and six months ended June 30, 2015 compared to the same periods in 2014, due primarily to an increase in commercial and industrial customers in Florida.

Gatherco Acquisition

On April 1, 2015, we completed the merger with Gatherco, pursuant to which Gatherco merged with and into Aspire Energy of Ohio, a newly formed, wholly-owned subsidiary of Chesapeake. At closing, we issued 592,970 shares of the our common stock, valued at $30.2 million based on the closing price of our common stock as reported on the NYSE on April 1, 2015, and paid $27.5 million in cash. We also acquired $6.8 million of Gatherco's cash at the time of the closing and assumed $1.7 million of Gatherco’s debt, which was paid off on the same day. As a result of this merger, Aspire Energy of Ohio provides unregulated natural gas midstream services including natural gas gathering services and natural gas liquid processing services to over 300 producers through 16 gathering systems and over 2,000 miles of pipelines in Central and Eastern Ohio, and supplies natural gas to over 6,000 customers in Ohio through the Consumers Gas Cooperative, an independent entity, which Aspire Energy of Ohio manages under an operating agreement.

Our results for the three and six months ended June 30, 2015 included $1.6 million of gross margin and $1.9 million of other operating expenses from Aspire Energy of Ohio as a result of the acquisition of Gatherco. The results of Aspire Energy of Ohio are projected to have a minimal impact on our earnings per share in 2015, since the merger was completed after the first quarter, which has historically produced a significant portion of Gatherco's annual earnings. This acquisition is expected to be accretive to our earnings in the first full year of operations, which will include the first quarter of 2016.

Weather and Consumption

Weather was not a significant factor in the second quarter as the negative impact of warmer temperatures on the Delmarva Peninsula on the natural gas and propane distribution operations was offset by the positive impact of warmer temperatures in Florida on the electric distribution operation. Since the first quarter of 2015 and 2014 were both significantly colder than normal (10-year average weather) on the Delmarva Peninsula, weather was not a significant factor in the period-over-period variance. The following tables highlight the HDD and CDD information for the three and six months ended June 30, 2015 and 2014 and the gross margin variance resulting from weather fluctuations in those periods.

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HDD and CDD Information

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015		2014		Variance		2015		2014		Variance
Delmarva
Actual HDD	386		456		(70	)	3,208		3,173		35
10-Year Average HDD ("Normal")	443		459		(16	)	2,843		2,820		23
Variance from Normal	(57	)	(3	)			365		353
Florida
Actual HDD	—		17		(17	)	501		574		(73	)
10-Year Average HDD ("Normal")	24		26		(2	)	557		555		2
Variance from Normal	(24	)	(9	)			(56	)	19
Florida
Actual CDD	1,114		928		186		1,236		970		266
10-Year Average CDD ("Normal")	909		908		1		982		982		—
Variance from Normal	205		20				254		(12	)

Gross Margin Variance attributed to Weather

(in thousands)	Q2 2015 vs. Q2 2014			Q2 2015 vs. Normal			YTD 2015 vs. YTD 2014			YTD 2015 vs. Normal
Delmarva
Regulated Energy segment	$	(138	)	$	(182	)	$	185		$	906
Unregulated Energy segment	(253		)	2			77			978
Florida
Regulated Energy segment	151			229			68			(199		)
Unregulated Energy segment	—			—			(10		)	122
Total	$	(240	)	$	49		$	320		$	1,807

Propane prices

Higher retail margins per gallon generated $427,000 and $5.0 million in additional gross margin by the Delmarva propane distribution operation for the three and six months ended June 30, 2015, respectively, compared to the same periods in 2014. A large decline in propane prices in the first quarter of 2015, compared to the same quarter in 2014, had a significant impact on the amount of revenue and cost of sales associated with our propane distribution operations. Based on the Mont Belvieu wholesale propane index, propane prices in the first quarter of 2015 were approximately 59 percent lower than prices in the same quarter in 2014. As a result of favorable supply management and hedging activities, the Delmarva propane distribution operation experienced a decrease in its average propane inventory cost in addition to the decrease in wholesale prices, which generated increased retail margins per gallon. During the second quarter of 2015, wholesale propane prices continued to remain significantly lower than prices in the same quarter of 2014; however, retail margins per gallon reverted to more normal levels as a result of local market conditions. These market conditions, which include competition with other propane suppliers as well as the availability and price of alternative energy sources, may fluctuate based on changes in demand, supply and other energy commodity prices. The level of retail margins generated during the first six months of 2015 is not typical and, therefore, is not included in our long-term financial plans or forecasts.

Xeron, which benefits from wholesale price volatility by entering into trading transactions, did not have a significant quarter-over-quarter variance for the three months ended June 30, 2015. On a year-to-date basis, Xeron experienced a gross margin decrease of $984,000, compared to the same period in 2014, due to lower wholesale price volatility.

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Regulatory Initiatives

GRIP

GRIP is a natural gas pipe replacement program approved by the Florida PSC, designed to expedite the replacement of qualifying distribution mains and services (any material other than coated steel or plastic) to enhance reliability and integrity of natural gas distribution systems. This program allows recovery through rates of capital and other program-related costs, inclusive of a return on investment, associated with the replacement of the mains and services. Since the program's inception in August 2012, our Florida natural gas distribution operations have invested $61.0 million to replace 141 miles of qualifying distribution mains, $17.0 million of which was invested during the first six months of 2015. We expect to invest an additional $11.9 million in this program through the end of 2015. The increased investment in GRIP generated additional gross margin of $1.1 million and $1.8 millionfor the three and six months endedJune 30, 2015, respectively, compared to the same periods in 2014.

Florida Electric Rate Case

On September 15, 2014, the Florida PSC approved a settlement agreement between FPU and the Florida Office of Public Counsel in FPU's base rate case filing for its electric operation, which included, among other things, an increase in FPU's annual revenue requirement of approximately $3.8 million and a 10.25 percent rate of return on common equity. The new rates became effective for all meter reads on or after November 1, 2014. Previously, the Florida PSC approved interim rate relief, effective for meter readings on or after August 10, 2014. The higher base rates in FPU's electric operation generated $731,000 and $1.7 million in additional gross margin for the three and six months ended June 30, 2015, respectively.

Capital Expenditures

We forecast our capital expenditures in 2015, excluding amounts expended to acquire Gatherco, to be in the range of $160.0 million to $190.0 million, a significant increase over the average level of capital expenditures during the past three years, which equaled $94.8 million. The change from the original budget of $223.4 million, which also excluded amounts expended to acquire Gatherco, primarily reflects a shift in the timing of certain capital expenditures from 2015 to 2016. Major projects currently underway, such as the Eight Flags' CHP plant and associated facilities, anticipated new facilities to serve an industrial customer in Kent County, Delaware under the OPT ≤ 90 Service, and additional GRIP investments projected in 2015, account for approximately $99.0 million of the capital expenditures forecast for 2015. Eastern Shore is also seeking approval from the FERC for a $32.1 million project to construct additional facilities that will improve the overall reliability and flexibility of its pipeline system for the benefit of all customers. Other expansions of natural gas distribution and transmission systems, additional infrastructure and facility improvements and other strategic initiatives and investments, account for the remainder of the 2015 capital budget. Capital expenditures are subject to continuous review and modification by our management and Board of Directors, and some anticipated capital expenditures are subject to approval by the applicable regulators. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, changes in customer expectations or service needs, 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. In the past three years, our actual capital expenditures were between 82 percent and 88 percent of the originally budgeted amounts.

In order to fund the 2015 capital expenditures currently budgeted, we expect to increase the level of borrowings during 2015 to supplement cash provided by operating activities. We will look at other financing options as needed. Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent and we have maintained our equity between 54 percent and 60 percent of total capitalization, including short-term borrowings, in the past three years. If we increase the level of debt during 2015 to fund the budgeted capital expenditures, the ratio of equity to total capitalization, including short-term borrowings, will temporarily decline until we issue equity. The timing of any equity issuance(s) will be based on market conditions. We will seek to align, as much as feasible, any such equity issuance(s) with the commencement of service, and associated earnings, for larger revenue generating projects.

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Regulated Energy Segment

For the quarter ended June 30, 2015 compared to the quarter ended June 30, 2014

	Three Months Ended
	June 30,				Increase
	2015		2014		(decrease)
(in thousands)
Revenue	$	62,060	$	61,646	$	414
Cost of sales	21,124		24,672		(3,548		)
Gross margin	40,936		36,974		3,962
Operations & maintenance	18,484		18,109		375
Depreciation & amortization	6,080		5,623		457
Other taxes	2,767		2,531		236
Other operating expenses	27,331		26,263		1,068
Operating income	$	13,605	$	10,711	$	2,894

Operating income for the Regulated Energy segment for the quarter ended June 30, 2015 was $13.6 million, an increase of $2.9 million, or 27.0 percent, compared to the same quarter in 2014. The increased operating income reflects additional gross margin of $4.0 million, and a pre-tax gain from the billing system settlement of $1.5 million, which were partially offset by a net increase in other operating expenses of $2.6 million to support growth.

Gross Margin

Items contributing to the quarter-over-quarter increase of $4.0 million, or 10.7 percent, in gross margin are listed in the following table:

(in thousands)
Gross margin for the three months ended June 30, 2014	$	36,974
Factors contributing to the gross margin increase for the three months ended June 30, 2015:
Additional revenue from GRIP in Florida	1,067
Natural gas distribution customer growth	1,055
Service expansions	919
FPU electric base rate increase	731
Growth in natural gas transmission services (other than service expansions)	292
Decreased customer consumption - weather and other	(27		)
Other	(75		)
Gross margin for the three months ended June 30, 2015	$	40,936

The following is a narrative discussion of the significant items which we believe is necessary to understand the information disclosed in the foregoing table.

Additional Revenue from GRIP in Florida

Additional GRIP investments during 2014 and 2015 by our Florida natural gas distribution operations generated $1.1 million in additional gross margin.

Natural Gas Distribution Customer Growth

Increased gross margin from other growth in natural gas distribution services was generated primarily from the following:

• $660,000 from Florida natural gas customer growth due primarily to new services to commercial and industrial customers; and

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• $395,000 from a 2.6-percent increase in residential customers in the Delmarva natural gas distribution operations, as well as growth in commercial and industrial customers in Worcester County, Maryland.

Service Expansions

Increased gross margin from natural gas service expansions was generated primarily from the following:

• $463,000 from a new service to an industrial customer facility in Kent County, Delaware that commenced on October 1, 2014 upon completion of new facilities, which includes approximately 5.5 miles of pipeline lateral and metering facilities extending from Eastern Shore's mainline to the new industrial customer facility. This service is expected to generate $1.8 million of gross margin in 2015.

• $398,000 from interruptible service that commenced in April 2015 to the same industrial customer in Kent County, Delaware mentioned above. The interruptible service is expected to generate $2.5 million of gross margin in 2015, and it is expected to be replaced by the new OPT ≤ 90 Service beginning late first quarter or early second quarter of 2016.

• $134,000 from natural gas transmission service as part of the major expansion initiative in Polk County, Florida.

• These increases were partially offset by a decrease in gross margin of $76,000 due primarily to a decrease in the reservation rate for a short-term contract with an existing industrial customer in New Castle County, Delaware to provide 50,000 Dts/d of service from April 2014 to April 2015. This contract was subsequently amended to provide 55,580 Dts/d of service to August 2020 at a lower reservation rate, which will generate $2.3 million of gross margin in 2015 compared to $1.9 million of gross margin generated in 2014.

FPU Electric Base Rate Increase

FPU's electric distribution operation generated additional gross margin of $731,000 due to higher base rates approved by the Florida PSC in September 2014 as a result of the rate case settlement. The new rates became effective for all meter reads on or after November 1, 2014.

Growth in Natural Gas Transmission Services (Other Than Service Expansions)

Increased gross margin from other growth in natural gas transmission services was generated primarily from the following:

• $180,000 from natural gas transmission service to commercial customers in Florida, and

• $122,000 from interruptible service to an industrial customer in New Castle County, Delaware.

Other Operating Expenses

The increase in other operating expenses, net of the gain from the billing system settlement, was due primarily to:

• $614,000 in higher payroll and benefits costs as a result of additional personnel to support growth;

• $426,000 in higher depreciation, asset removal and property tax costs associated with recent capital investments to support growth;

• $417,000 in legal and consulting costs associated with the billing system settlement and other initiatives;

• $374,000 in higher accruals for incentive compensation as a result of the higher quarterly results; and

• $187,000 in additional amortization expense due to the change in the amortization of regulatory assets and liabilities, primarily in the FPU electric distribution operation.

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For the six months ended June 30, 2015 compared to the six months ended June 30, 2014

	Six Months Ended
	June 30,				Increase
	2015		2014		(decrease)
(in thousands)
Revenue	$	171,642	$	163,812	$	7,830
Cost of sales	78,253		78,980		(727		)
Gross margin	93,389		84,832		8,557
Operations & maintenance	39,768		36,510		3,258
Depreciation & amortization	11,979		11,150		829
Other taxes	5,854		5,370		484
Other operating expenses	57,601		53,030		4,571
Operating income	$	35,788	$	31,802	$	3,986

Operating income for the Regulated Energy segment for the six months ended June 30, 2015 was $35.8 million, an increase of $4.0 million, or 12.5 percent, compared to the same period in 2014. The increased operating income reflects additional gross margin of $8.6 million and $1.5 million received in connection with the billing system settlement, which were partially offset by an increase in other operating expenses of $6.1 million to support growth.

Gross Margin

Items contributing to the period-over-period increase of $8.6 million, or 10.1 percent, in gross margin are listed in the following table:

(in thousands)
Gross margin for the six months ended June 30, 2014	$	84,832
Factors contributing to the gross margin increase for the six months ended June 30, 2015:
Service expansions	2,377
Natural gas distribution customer growth	1,952
Additional revenue from GRIP in Florida	1,822
FPU electric base rates increase	1,693
Growth in natural gas transmission services (other than service expansions)	426
Increased customer consumption - weather and other	223
Other	64
Gross margin for the six months ended June 30, 2015	$	93,389

The following is a discussion of the significant items which we believe is necessary to understand the information disclosed in the foregoing table.

Service Expansions

Increased gross margin from natural gas service expansions was generated primarily from the following:

• $926,000 from a new service to an industrial customer facility in Kent County, Delaware that commenced on October 1, 2014 upon completion of new facilities, including approximately 5.5 miles of pipeline lateral and metering facilities extending from Eastern Shore's mainline to the new industrial customer facility. This service is expected to generate $1.8 million of gross margin in 2015.

• $659,000 from a short-term contract with an existing industrial customer in New Castle County, Delaware to provide 50,000 Dts/d of service from April 2014 to April 2015. This contract was subsequently amended to provide 55,580 Dts/d of service at a lower reservation rate through August 2020. The lower rate decreased gross margin by $183,000 for the six months ended June 30, 2015; however, the extension of the contract generated additional gross margin of $842,000 for the six months ended June 30, 2015. This service is expected to generate $2.3 million of gross margin in 2015 compared to $1.9 million of gross margin generated in 2014.

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• $398,000 from interruptible service that commenced in April 2015 to the same industrial customer in Kent County, Delaware mentioned above. The interruptible service is expected to generate $2.5 million in 2015, and it is expected to be replaced by the new OPT ≤ 90 Service beginning late first quarter or early second quarter of 2016.

• $233,000 from another short-term contract with the same industrial customer in New Castle County, Delaware, mentioned above, to provide an additional 10,000 Dts/d of OPT≤90 Service transmission service from December 2014 to March 2015.

• $161,000 from natural gas transmission service as part of the major expansion initiative in Polk County, Florida.

Natural Gas Distribution Customer Growth

Increased gross margin from other natural gas growth was generated primarily from the following:

• $1.1 million from Florida natural gas customer growth due primarily to new services to commercial and industrial customers; and

• $845,000 from a 2.7-percent increase in residential customers in the Delmarva natural gas distribution operations, as well as growth in commercial and industrial customers in Worcester County, Maryland.

Additional Revenue from GRIP in Florida

Additional GRIP investments during 2014 and 2015 by our Florida natural gas distribution operations generated $1.8 million in additional gross margin.

FPU Electric Base Rate Increase

FPU's electric distribution operation generated additional gross margin of $1.7 million due to higher base rates approved in September 2014 as a result of the rate case settlement. The new rates became effective for all meter reads on or after November 1, 2014.

Growth in Natural Gas Transmission Services (Other Than Service Expansions)

Increased gross margin from other growth in natural gas transmission services was generated primarily from the following:

• $323,000 from natural gas transmission service to commercial customers in Florida, and

• $91,000 from interruptible service to an industrial customer in New Castle County, Delaware.

Increased Customer Consumption - Weather and Other

Additional gross margin of $223,000 was generated due to higher customer consumption on the Delmarva Peninsula and in Florida.

Other Operating Expenses

The increase in other operating expenses was due primarily to:

• $1.2 million in higher payroll and benefits costs as a result of additional personnel to support growth and increased overtime on the Delmarva Peninsula in early 2015 due to colder weather;

• $987,000 in legal and consulting costs associated with the billing system settlement and other initiatives;

• $837,000 in higher service contractor and other consulting costs;

• $805,000 in higher depreciation, asset removal and property tax costs associated with recent capital investments to support growth;

• $601,000 in higher accruals for incentive compensation as a result of year-to-date performance;

• $404,000 in additional costs for facility maintenance; and

• $332,000 in additional amortization expense due to a change in the amortization of regulatory assets and liabilities, primarily in the Florida electric distribution operation.

These increases were partially offset by a gain of $1.5 million from the billing system settlement, which reduced other operating expenses for the six months ended June 30, 2015.

Unregulated Energy Segment

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For the quarter ended June 30, 2015 compared to the quarter ended June 30, 2014

	Three Months Ended
	June 30,						Increase
	2015			2014			(decrease)
(in thousands)
Revenue	$	32,559		$	34,321		$	(1,762	)
Cost of sales	22,156			26,020			(3,864		)
Gross margin	10,403			8,301			2,102
Operations & maintenance	9,130			7,022			2,108
Depreciation & amortization	1,439			986			453
Other taxes	374			336			38
Other operating expenses	10,943			8,344			2,599
Operating Loss	$	(540	)	$	(43	)	$	(497	)

Operating loss for the Unregulated Energy segment increased by $497,000, to $540,000 in the second quarter of 2015, compared to $43,000 in the same quarter of 2014. The Unregulated Energy segment typically reports an operating loss, or modest operating income, in the second quarter due to the seasonal nature of our propane distribution operations, which represents a large portion of this segment. The results for the second quarter include gross margin of $1.6 million and other operating expenses of $1.9 million from Aspire Energy of Ohio following the acquisition of Gatherco. Historically, Gatherco reported the lowest volumes delivered and revenue in the second quarter due to the seasonality of its business. Excluding these impacts, gross margin increased by $478,000, which was offset by a $704,000 increase in other operating expenses.

Gross Margin

A significant decline in natural gas and propane commodity prices decreased both revenue and related cost of commodities sold to our propane distribution and natural gas marketing customers, resulting in a quarter-over-quarter increase of $2.1 million, or 25.3 percent, in gross margin. Items contributing to this increase are listed in the following table:

(in thousands)
Gross margin for the three months ended June 30, 2014	$	8,301
Factors contributing to the gross margin increase for the three months ended June 30, 2015:
Contributions from acquisitions	1,632
Increased retail propane margins	649
Decreased customer consumption - weather and other	(415		)
Other	236
Gross margin for the three months ended June 30, 2015	$	10,403

The following is a discussion of the significant items which we believe is necessary to understand the information disclosed in the foregoing table.

Contributions from Acquisitions

Aspire Energy of Ohio generated $1.6 million in additional gross margin for the three months ended June 30, 2015. Also, the acquisition of certain propane distribution assets used to serve 253 customers in Citrus County, Florida generated $8,000 in additional gross margin during the second quarter of 2015.

Increased Retail Propane Margins

Higher retail propane margins for our Delmarva Peninsula and Florida propane distribution operations during the second quarter of 2015 generated $427,000 and $222,000, respectively, in additional gross margin. The higher retail propane margins were due to the retail pricing strategy guided by local market conditions and lower propane inventory costs resulting from favorable supply management and hedging activities.

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Decreased Customer Consumption - Weather and Other

Lower customer consumption decreased gross margin by $415,000. This lower consumption was due primarily to a decrease in non-weather consumption by Florida customers and the timing of bulk deliveries on the Delmarva Peninsula.

Other Operating Expenses

Other operating expenses increased by $2.6 million due primarily to $1.9 million of other operating expenses contributed from Aspire Energy of Ohio, as a result of our acquisition of Gatherco.

For the six months ended June 30, 2015 compared to the six months ended June 30, 2014

	Six Months Ended
	June 30,				Increase
	2015		2014		(decrease)
(in thousands)
Revenue	$	93,555	$	114,294	$	(20,739	)
Cost of sales	57,833		85,179		(27,346		)
Gross margin	35,722		29,115		6,607
Operations & maintenance	17,687		15,447		2,240
Depreciation & amortization	2,490		1,966		524
Other taxes	856		887		(31		)
Other operating expenses	21,033		18,300		2,733
Operating Income	$	14,689	$	10,815	$	3,874

Operating income for the Unregulated Energy segment increased by $3.9 million, or 35.8 percent, to $14.7 million in the first six months of 2015, compared to $10.8 million in the same period of 2014. Excluding the impact generated by Aspire Energy of Ohio as a result of the Gatherco acquisition ($1.6 million in gross margin and $1.9 million of other operating expenses), the increased operating income was driven by a $5.0 million increase in gross margin, which was partially offset by an $838,000 increase in other operating expenses.

A significant decline in natural gas and propane commodity prices decreased both revenue and related cost of commodities sold to our propane distribution and natural gas marketing customers, resulting in a period-over-period increase of $6.6 million, or 22.7 percent, in gross margin. Items contributing to this increase are listed in the following table:

(in thousands)
Gross margin for the six months ended June 30, 2014	$	29,115
Factors contributing to the gross margin increase for the six months ended June 30, 2015:
Increase in retail propane sales	5,650
Contributions from acquisitions	1,632
Propane wholesale marketing	(984		)
Increased customer consumption - weather and other	474
Decreased wholesale propane sales	(392		)
Other	227
Gross margin for the six months ended June 30, 2015	$	35,722

The following is a discussion of the significant items which we believe is necessary to understand the information disclosed in the foregoing table.

Increased Retail Propane Margins

Higher retail propane margins for our Delmarva Peninsula and Florida propane distribution operations during the first six months of 2015 generated $5.0 million and $655,000, respectively, in additional gross margin. A large decline in wholesale propane prices during 2015, coupled with favorable supply management and hedging activities, resulted in a decrease in the average propane inventory cost for the Delmarva propane distribution operation, which generated increased retail propane margins per gallon.

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Contributions from Acquisitions

Aspire Energy of Ohio generated $1.6 million in additional gross margin in the first six months of 2015. Also, the acquisition of certain propane distribution assets used to serve 253 customers in Citrus County, Florida generated $8,000 in additional gross margin during the first six months of 2015.

Lower Propane Wholesale Marketing Results

Xeron's gross margin decreased by $984,000 during the first six months of 2015, compared to the same period in 2014, as a result of a 31-percent decrease in trading activity and lower margins on executed trades. In contrast, Xeron experienced higher price volatility and higher trading volumes in the first six months of 2014, which resulted in unusually high profitability during that period.

Increased Customer Consumption - Weather and Other

Higher customer consumption increased gross margin by $474,000. The increase was due to an increase in non-weather consumption on the Delmarva Peninsula partially offset by lower non-weather consumption in Florida.

Decreased Wholesale Propane Sales

Margins per gallon on our Delmarva wholesale propane sales decreased by $392,000 during the first six months of 2015, compared to the same period in 2014, as a result of a decline in the price difference between local wholesale prices and our inventory cost.

Other Operating Expenses

Other operating expenses increased by $2.7 million due primarily to $1.9 million of other operating expenses incurred by Aspire Energy of Ohio. The remaining increase in other operating expenses was due primarily to:

• $588,000 in higher payroll and benefits expense due to increased seasonal overtime and additional resources to support growth;

• $253,000 in additional costs for facility maintenance;

• $240,000 in increased accruals for incentive compensation as a result of year-to-date financial results in 2015; and

• $269,000 in lower expenses for credit and collections activities, which partially offset the above increases in expenses.

Interest Charges

For the quarter ended June 30, 2015 compared to the quarter ended June 30, 2014

Interest charges for the three months ended June 30, 2015 increased by approximately $182,000, or eight percent, compared to the same quarter in 2014. The increase in interest charges is attributable to an increase in long-term interest charges as a result of $50.0 million of Notes issued in May 2014.

For the six months ended June 30, 2015 compared to the six months ended June 30, 2014

Interest charges for the six months ended June 30, 2015 increased by approximately $474,000, or 11 percent, compared to the same period in 2014. The increase in interest charges is attributable to an increase of $418,000 in long-term interest charges as a result of $50.0 million of Notes issued in May 2014.

Income Taxes

For the quarter ended June 30, 2015 compared to the quarter ended June 30, 2014

Income tax expense was $4.2 million in the second quarter of 2015, compared to $3.4 million in the same quarter in 2014. The increase in income tax expense was due primarily to higher taxable income. Our effective income tax rate was at 40.1 percent for the second quarter of 2015 and 40.0 percent for the second quarter of 2014.

For the six months ended June 30, 2015 compared to the six months ended June 30, 2014

Income tax expense was $18.3 million in the six months ended June 30, 2015, compared to $15.2 million in the same period in 2014. The increase in income tax expense was due primarily to higher taxable income. Our effective income tax rate remained unchanged at 40.0 percent for the first six months of 2015 and 2014.

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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 natural gas, electric and propane distribution 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 by our natural gas, electric, 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.

Our largest capital requirements are for investments in new or acquired plant and equipment. We originally budgeted $223.4 million for capital expenditures during 2015. Our current forecast of capital expenditures during 2015 is in the range of $160.0 million to $190.0 million. The following table sets forth the original projected 2015 capital expenditures by segment:

	Range of Capital Expenditures
(dollars in thousands)	Low		High
Regulated Energy:
Natural gas distribution	$	61,815	$	76,815
Natural gas transmission	46,535		61,535
Electric distribution	6,331		6,331
Total Regulated Energy	114,681		144,681
Unregulated Energy:
Propane distribution	7,746		7,746
Other unregulated energy	27,942		27,942
Total Unregulated Energy	35,688		35,688
Other	9,631		9,631
Total 2015 projected capital expenditures	$	160,000	$	190,000

The current forecast of capital expenditures is a significant increase over our average level of capital expenditures over the past three years. This increase is due to expansions of our natural gas distribution and transmission systems, increased natural gas infrastructure improvement activities, improvement of our facilities and systems and other strategic initiatives and investments expected in 2015. The reduction from the original capital expenditure budget to the current forecast of capital expenditures is primarily due to a shift in the timing of certain capital expenditures from 2015 to 2016. 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.

The acquisition of Gatherco, which we completed on April 1, 2015, was not included in our original capital budget of $223.4 million or in our current 2015 capital expenditure projection shown above. At closing, we issued 592,970 shares of our common stock, valued at $30.2 million based on the closing price of our common stock, as reported on the NYSE on April 1, 2015, and paid $27.5 million in cash. We also acquired $6.8 million of Gatherco's cash at the time of the closing and assumed $1.7 million of Gatherco’s debt, which was paid off on the same day.

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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 June 30, 2015 and December 31, 2014:

	June 30, 2015				December 31, 2014
(in thousands)
Long-term debt, net of current maturities	$	156,247	31	%	$	158,486	35	%
Stockholders’ equity	351,176		69	%	300,322		65	%
Total capitalization, excluding short-term debt	$	507,423	100	%	$	458,808	100	%
	June 30, 2015				December 31, 2014
(in thousands)
Short-term debt	$	94,713	15	%	$	88,231	16	%
Long-term debt, including current maturities	165,374		27	%	167,595		30	%
Stockholders’ equity	351,176		58	%	300,322		54	%
Total capitalization, including short-term debt	$	611,263	100	%	$	556,148	100	%

Included in the long-term debt balances at June 30, 2015 and December 31, 2014, was a capital lease obligation associated with Sandpiper's capacity, supply and operating agreement ($4.2 million and $4.8 million, respectively, net of current maturities and $5.5 million and $6.1 million, respectively, including current maturities). Sandpiper entered into this six-year agreement at the closing of the ESG acquisition in May 2013. The capacity portion of this agreement is accounted for as a capital lease.

In order to fund the 2015 capital expenditures, which are currently estimated to be in the range of $160.0 million to $190.0 million, we expect to increase the level of borrowings during 2015 to supplement cash provided by operating activities. We will look at other financing options as needed. Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent, and we have maintained our equity between 54 percent and 60 percent of total capitalization, including short-term borrowings, in the past three years. If we increase the level of debt during 2015 to fund the budgeted capital expenditures, the ratio of equity to total capitalization, including short-term borrowings, will temporarily decline until we issue equity. The timing of any equity issuance(s) will be based on market conditions. We will seek to align, as much as feasible, any such equity issuance(s) with the commencement of service, and associated earnings, for larger revenue generating projects.

Short-term Borrowings

Our outstanding short-term borrowings at June 30, 2015 and December 31, 2014 were $94.7 million and $88.2 million, respectively, at weighted average interest rates of 1.08 percent and 1.15 percent, respectively.

We utilize bank lines of credit to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of the capital expenditure program. We have six unsecured bank credit facilities with three financial institutions with $210.0 million of total available credit. Three of these credit facilities, totaling $120.0 million, are available under committed lines of credit. Two of these credit facilities, totaling $40.0 million, are available under uncommitted lines of credit. None of these unsecured bank lines of credit requires compensating balances. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. In addition to these bank lines of credit, one of the lenders has made available a $50.0 million short-term revolving credit note. We are currently authorized by our Board of Directors to borrow up to $200.0 million of short-term borrowings, as required.

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Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the six months ended June 30, 2015 and 2014:

	Six Months Ended
	June 30,
	2015			2014
(in thousands)
Net cash provided by (used in):
Operating activities	$	87,771		$	58,563
Investing activities	(85,673		)	(42,502		)
Financing activities	(4,568		)	(16,888		)
Net decrease in cash and cash equivalents	(2,470		)	(827		)
Cash and cash equivalents—beginning of period	4,574			3,356
Cash and cash equivalents—end of period	$	2,104		$	2,529

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.

During the six months ended June 30, 2015 and 2014, net cash provided by operating activities was $87.8 million and $58.6 million, respectively, resulting in an increase in cash flows of $29.2 million. Significant operating activities generating the cash flow change were as follows:

• The changes in net regulatory assets and liabilities increased cash flows by $15.9 million, due primarily to the change in fuel costs collected through the various fuel cost recovery mechanisms;

• The change in income taxes receivable increased cash flows by $16.0 million, due primarily to the receipt of a tax refund related to our 2014 federal income tax obligation. Our tax deductions, which were higher-than-projected, due to bonus depreciation (approved by the President of the United States in December 2014), reduced our 2014 federal income tax obligation;

• The changes in net accounts receivable and payable decreased cash flows by $3.0 million, due to the timing of the collections and payments associated with trading contracts entered into by our propane wholesale marketing subsidiary and a decrease in net cash flows from receivables and payables in various other operations;

• Net income, adjusted for reconciling activities, increased cash flows by $4.1 million, due primarily to higher earnings; and

• Net cash flows from changes in propane, natural gas and materials inventories decreased by approximately $1.7 million, compared to 2014.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $85.7 million and $42.5 million during the six months ended June 30, 2015 and 2014, respectively, resulting in a decrease in cash flows of $43.2 million. Significant investing activities generating the cash flow change were as follows:

• An increase in cash paid for capital expenditures, due primarily to our GRIP investment in our Florida natural gas distribution operations and Eight Flags' construction of the CHP plant, decreased cash flows by $21.8 million; and

• We paid $20.7 million ($27.5 million paid less $6.8 million of cash acquired) in conjunction with the acquisition of Gatherco on April 1, 2015.

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Cash Flows Used in Financing Activities

Net cash used in financing activities totaled $4.6 million in the first six months of 2015, compared to $16.9 million in the same period in 2014. The decrease in net cash used in financing activities during the first six months of 2015 was due primarily to $61.1 million in lower repayments under our line of credit agreements and a $3.2 million change in cash overdrafts, which were partially offset by $50.0 million in proceeds from the issuance of long-term debt in May 2014 and $1.7 million of outstanding debt assumed in the Gatherco merger that was paid off immediately after the closing of the merger on April 1, 2015.

Off-Balance Sheet Arrangements

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily Xeron and PESCO, which provide for the payment of propane and natural gas purchases in the event that the subsidiary defaults. Neither subsidiary 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 June 30, 2015 was $32.0 million, with the guarantees expiring on various dates through June 29, 2016.

We issued a letter of credit for $1.0 million, which was renewed through September 12, 2015, related to the electric transmission services for FPU’s northwest electric division. We also issued a letter of credit to our current primary insurance company for $1.2 million, which expires on October 31, 2015, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company in 2010, we renewed and decreased to $40,000 the letter of credit to our former primary insurance company, which will expire on June 1, 2016. There have been no draws on these letters of credit as of June 30, 2015. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.

We provided a letter of credit for $2.3 million to TETLP related to the firm transportation service agreement with our Delaware and Maryland divisions.

Contractual Obligations

There has not been any material change in the contractual obligations presented in our 2014 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 commodity and forward contract obligations at June 30, 2015.

	Payments Due by Period
	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
(in thousands)
Purchase obligations - Commodity (1)	$	42,610	$	8,027	$	1,804	$	—	$	52,441
Forward purchase contracts - Propane (2)	1,997		—		—		—		1,997
Total	$	44,607	$	8,027	$	1,804	$	—	$	54,438

⁽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.

⁽²⁾  We have also entered into forward sale contracts. See Item 3, Quantitative and Qualitative Disclosures About Market Risk for further information.

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 June 30, 2015, 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.

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.

- 49

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 $159.9 million at June 30, 2015, as compared to a fair value of $174.1 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 our propane storage activities and entering into fixed price contracts for supply. We can store up to approximately 6.5 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 Intercontinental Exchange, Inc. 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. Quantitative information on forward and future contracts at June 30, 2015 is presented in the following table:

	Quantity in	Estimated Market	Weighted Average
At June 30, 2015	Gallons	Prices	Contract Prices
Forward Contracts
Sale	4,620,000	$0.3475 - $0.5288	$	0.4760
Purchase	4,620,000	$0.3550 - $0.5025	$	0.4322

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

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 June 30, 2015 and December 31, 2014, 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)	June 30, 2015		December 31, 2014
Mark-to-market energy assets, including put and call options and swap agreements	$	358	$	1,055
Mark-to-market energy liabilities, including swap agreements	$	47	$	1,018

- 50

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 June 30, 2015. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2015.

Changes in Internal Control over Financial Reporting

During the quarter ended June 30, 2015, 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.

- 51

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, 2014, 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 Quarterly Report on Form 10-Q. 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)
April 1, 2015 through April 30, 2015 (1)	342	$	52.87	—	—
May 1, 2015 through May 31, 2015	—	$	—	—	—
June 1, 2015 through June 30, 2015	—	$	—	—	—
Total	342	$	52.87	—	—

⁽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, 2014. During the quarter ended June 30, 2015, 342 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.

- 52

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 August 6, 2015.
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 August 6, 2015.
32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated August 6, 2015.
32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated August 6, 2015.
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.

- 53

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: August 6, 2015

- 54

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 June 30, 2015 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: August 6, 2015

/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 June 30, 2015 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: August 6, 2015

/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 June 30, 2015, 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

August 6, 2015

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 June 30, 2015, 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

August 6, 2015

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

Acquisitions Purchase Considerations (Details) - Gatherco [Member] - USD ($) $ in Thousands		6 Months Ended
	Apr. 01, 2015	Jun. 30, 2015
Business Acquisition [Line Items]
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned	$ 30,200	$ 30,164
Payments to Acquire Businesses, Gross	27,500	27,494
Long-term debt	1,696	1,696
Business Combination, Consideration Transferred		57,658
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents	$ (6,800)	(6,806)
Gross [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred		59,354
Net [Member]
Business Acquisition [Line Items]
Business Combination, Consideration Transferred		$ 52,548

XML

Share-Based Compensation - Summary of Stock Activity under the SICP (Detail) - 6 months ended Jun. 30, 2015 - $ / shares	Total
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Shares, Granted	1,207
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Shares, Outstanding - December 31, 2014	123,038
Number of Shares, Granted	29,763
Number of Shares, Vested	(43,839)
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expired In Period	(2,520)
Number of Shares, Outstanding - June 30, 2015	106,442.000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Fair Value, Outstanding - December 31, 2014	$ 32.60
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	48.21
Weighted Average Fair Value, Vested	28.01
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expirations Weighted Average Grant Date Fair Value	28.83
Weighted Average Fair Value, Outstanding - June 30, 2015	$ 37.97
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number of Shares [Roll Forward]
Number of Shares, Outstanding - December 31, 2014	0
Number of Shares, Granted	14,484
Number of Shares, Vested	(14,484)
Number of Shares, Outstanding - June 30, 2015	0
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value [Roll Forward]
Weighted Average Fair Value, Outstanding - December 31, 2014	$ 0.00
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period, Weighted Average Grant Date Fair Value	45.54
Weighted Average Fair Value, Vested	45.54
Weighted Average Fair Value, Outstanding - June 30, 2015	$ 0.00

XML

Employee Benefit Plans - Employee Benefit Plans (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Defined Benefit Plan Disclosure [Line Items]
Document Period End Date			Jun. 30, 2015
Amortization of prior service cost	$ (17)	$ (15)	$ (34)	$ (30)
Amortization of net loss	249	67	496	132
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	15	16	30	33
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	0	0	0	0
Amortization of net loss	2	0	3	0
Net periodic cost (benefit)	17	16	33	33
Amortization of pre-merger regulatory asset	2	2	4	4
Total periodic cost	19	18	37	37
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	11	13	22	26
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	(19)	(20)	(39)	(39)
Amortization of net loss	17	17	35	33
Net periodic cost (benefit)	9	10	18	20
Amortization of pre-merger regulatory asset	0	0	0	0
Total periodic cost	9	10	18	20
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	23	23	46	46
Expected return on plan assets	0	0	0	0
Amortization of prior service cost	2	5	5	9
Amortization of net loss	25	12	50	24
Net periodic cost (benefit)	50	40	101	79
Amortization of pre-merger regulatory asset	0	0	0	0
Total periodic cost	50	40	101	79
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	626	647	1,251	1,294
Expected return on plan assets	(777)	(772)	(1,554)	(1,545)
Amortization of prior service cost	0	0	0	0
Amortization of net loss	114	0	227	0
Net periodic cost (benefit)	(37)	(125)	(76)	(251)
Amortization of pre-merger regulatory asset	191	191	381	381
Total periodic cost	154	66	305	130
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	102	106	204	213
Expected return on plan assets	(135)	(132)	(270)	(265)
Amortization of prior service cost	0	0	0	0
Amortization of net loss	91	38	181	75
Net periodic cost (benefit)	58	12	115	23
Amortization of pre-merger regulatory asset	0	0	0	0
Total periodic cost	$ 58	$ 12	$ 115	$ 23

XML

Share-Based Compensation - Additional Information (Detail) - Jun. 30, 2015 - USD ($) $ in Thousands	Total
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards, shares	1,207
Employee Service Share-based Compensation, Nonvested Awards, Compensation Cost Not yet Recognized	$ 1,900
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Amortization of expense equally over a service period	1 year
Unrecognized compensation expense related to the awards to non-employee directors	$ 550
Granted awards, shares	14,484
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards, shares	29,763
Vesting period	3 years
Intrinsic value of the SICP awards	$ 5,700

XML

Accumulated Other Comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	$ (5,676)	$ (2,533)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(1)	(1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	198	61
Net current-period other comprehensive income (loss)	197	60
Ending balance	(5,479)	(2,473)
UnrealizedGainsLossesFromDefinedBenefitPensionAndPostretirementPlanItems [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	(5,643)	(2,533)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	165	61
Net current-period other comprehensive income (loss)	165	61
Ending balance	(5,478)	(2,472)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	(33)	0
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(1)	(1)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	33	0
Net current-period other comprehensive income (loss)	32	(1)
Ending balance	$ (1)	$ (1)

XML

Fair Value of Financial Instruments (Tables)

6 Months Ended

Jun. 30, 2015

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 as of June 30, 2015 and December 31, 2014:

			Fair Value Measurements Using:
As of June 30, 2015	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments - equity securities	$	16	$	16	$	—	$	—
Investments—guaranteed income fund	$	335	$	—	$	—	$	335
Investments—other	$	3,314	$	3,314	$	—	$	—
Mark-to-market energy assets, incl. put options and swap agreements	$	358	$	—	$	358	$	—
Liabilities:
Mark-to-market energy liabilities incl. swap agreements	$	47	$	—	$	47	$	—

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

Summary of Changes in Fair Value of Investments

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the six months ended June 30, 2015 and 2014:

	Six Months Ended   June 30,
	2015			2014
(in thousands)
Beginning Balance	$	287		$	458
Purchases and adjustments	49			(26		)
Transfers	(3		)	(25		)
Investment income	2			3
Ending Balance	$	335		$	410

XML

Derivative Instruments - Additional Information (Detail) gal in Thousands	6 Months Ended	12 Months Ended
	Jun. 30, 2015 USD ($) Counterparty $ / gal gal	Dec. 31, 2014 USD ($) Counterparty $ / gal gal
Propane Swap Agreement [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal	2,500	630
Cash Paid On Derivative Settlement	$ 1,100,000
Other Comprehensive Income Loss Adjustments AOCI Swap Agreements		$ 735,000
Call options [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal		1,300
Payments for Derivative Instrument, Financing Activities		$ 98,000
Put Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal	2,500	630
Payments for Derivative Instrument, Financing Activities	$ 143,000	$ 128,000
Cash Received On Derivative Settlement	$ 868,000
Forward Contracts [Member]
Derivative [Line Items]
Number Of Counterparties With Master Repurchase Agreements | Counterparty	2	2
Accounts Receivable Subject To Master Netting Arrangement	$ 654,000	$ 1,600,000
Accounts Payable Subject To Master Netting Arrangement	222,000	$ 1,200,000
Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Cash Flow Hedge Derivative Instrument Assets at Fair Value	36,000
Mark To Market Energy Liabilities [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Cash Flow Hedge Derivative Instrument Liabilities at Fair Value	38,000
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Put Option [Member]
Derivative [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral	$ 110,000
Strike Price 1 [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements | $ / gal	0.595	1.1350
Strike Price 2 [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements | $ / gal	0.5888	1.0975
Strike Price 3 [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements | $ / gal	0.5500	1.0475
Strike Price 4 [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements | $ / gal	0.5200
Put Option Strike Price 1 [Member] | Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price | $ / gal	0.4950	1.0350
Put Option Strike Price 2 [Member] | Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price | $ / gal	0.4888	0.9975
Put Option Strike Price 3 [Member] | Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price | $ / gal	0.4500	0.9475
Put Option Strike Price 4 [Member] | Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price | $ / gal	0.4200
Strike Price 1 [Member] | Call options [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price | $ / gal	1.0875
Strike Price 2 [Member] | Call options [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price | $ / gal	1.0650

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Calculation of Earnings Per Share (Tables)

6 Months Ended

Jun. 30, 2015

Earnings Per Share [Abstract]

Calculation of Basic and Diluted Earnings Per Share

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2015		2014		2015		2014
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	6,294	$	5,134	$	27,403	$	22,815
Weighted average shares outstanding	15,235,860		14,556,242		14,922,094		14,522,133
Basic Earnings Per Share	$	0.41	$	0.35	$	1.84	$	1.57
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	6,294	$	5,134	$	27,403	$	22,815
Reconciliation of Denominator:
Weighted shares outstanding—Basic	15,235,860		14,556,242		14,922,094		14,522,133
Effect of dilutive securities:
Share-based compensation	44,797		50,537		48,096		51,510
Adjusted denominator—Diluted	15,280,657		14,606,779		14,970,190		14,573,643
Diluted Earnings Per Share	$	0.41	$	0.35	$	1.83	$	1.57

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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	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	$ (17)	$ (15)	$ (34)	$ (30)
Net loss	249	67	496	132
Recognized from accumulated other comprehensive loss	138	52	276	102
Recognized from regulatory asset	94	0	186	0
Total recognized in net periodic benefit cost	232	52	462	102
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	0	0	0	0
Net loss	91	38	181	75
Recognized from accumulated other comprehensive loss	91	38	181	75
Recognized from regulatory asset	0	0	0	0
Total recognized in net periodic benefit cost	91	38	181	75
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	0	0	0	0
Net loss	114	0	227	0
Recognized from accumulated other comprehensive loss	22	0	43	0
Recognized from regulatory asset	92	0	184	0
Total recognized in net periodic benefit cost	114	0	227	0
Chesapeake Pension SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	2	5	5	9
Net loss	25	12	50	24
Recognized from accumulated other comprehensive loss	27	17	55	33
Recognized from regulatory asset	0	0	0	0
Total recognized in net periodic benefit cost	27	17	55	33
Chesapeake Postretirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	(19)	(20)	(39)	(39)
Net loss	17	17	35	33
Recognized from accumulated other comprehensive loss	(2)	(3)	(4)	(6)
Recognized from regulatory asset	0	0	0	0
Total recognized in net periodic benefit cost	(2)	(3)	(4)	(6)
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)	0	0	0	0
Net loss	2	0	3	0
Recognized from accumulated other comprehensive loss	0	0	1	0
Recognized from regulatory asset	2	0	2	0
Total recognized in net periodic benefit cost	$ 2	$ 0	$ 3	$ 0

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Environmental Commitments and Contingencies - Additional Information (Detail) $ in Thousands	6 Months Ended
	Jun. 30, 2015 USD ($) site	Jun. 30, 2014 USD ($)	Dec. 31, 2014 USD ($)
Environmental Commitments And Contingencies [Line Items]
Company's exposure in number of former Manufactured Gas Plant Sites | site	7
Environmental liabilities	$ 9,043		$ 8,923
Amount paid for funding requirements	73	$ 79
Seaford [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	273
Accrual for Environmental Loss Contingencies	245
Regulatory Assets	273
Estimated costs of remediation range, minimum	273
Estimated costs of remediation range, maximum	465
Winter Haven Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental remediation expense	443
Additional remediation costs	100
West Palm Beach Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	4,500
Estimated costs of remediation range, maximum	15,400
Sanford Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, maximum	13,000
Cost of remedy for settlements of claims	20,000
Environmental remediation expense	24
FPU [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	10,100
Approval of recovery of environmental costs	14,000
Environmental costs recovered	9,900
FPU [Member] | Sanford Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, maximum	$ 650
Environmental remediation expense percent	5.00%
Amount paid for funding requirements	$ 650
FPU [Member] | Manufactured Gas Plant [Member]
Environmental Commitments And Contingencies [Line Items]
Regulatory Assets	4,100
Chesapeake [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	380
Regulatory Assets	$ 145

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Calculation of Earnings Per Share - Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Calculation of Basic Earnings Per Share:
Net Income	$ 6,294	$ 5,134	$ 27,403	$ 22,815	$ 36,092
Weighted shares outstanding - Basic (in shares)	15,235,860	14,556,242	14,922,094	14,522,133
Basic Earnings Per Share (in usd per share)	$ 0.41	$ 0.35	$ 1.84	$ 1.57
Reconciliation of Numerator:
Net Income	$ 6,294	$ 5,134	$ 27,403	$ 22,815	$ 36,092
Reconciliation of Denominator:
Weighted shares outstanding - Basic (in shares)	15,235,860	14,556,242	14,922,094	14,522,133
Effect of dilutive securities:
Share-based Compensation (in shares)	44,797	50,537	48,096	51,510
Adjusted denominator-Diluted (in shares)	15,280,657	14,606,779	14,970,190	14,573,643
Diluted Earnings Per Share (in usd per share)	$ 0.41	$ 0.35	$ 1.83	$ 1.57

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Investments Schedule of Investments (Details) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Investments schedule [Line Items]
Investments, at fair value	$ 3,665	$ 3,678
Rabbi Trust Associated With Deferred Compensation Plan [Member]
Investments schedule [Line Items]
Investments, at fair value	3,649	3,678
Equity Securities [Member]
Investments schedule [Line Items]
Investments, at fair value	$ 16	$ 0

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Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 287	$ 458
Purchases and adjustments	49	(26)
Transfers	(3)	(25)
Investment Income	2	3
Ending Balance	$ 335	$ 410

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Accumulated Other Comprehensive Income (Loss) - Reclassifications of Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands		3 Months Ended		6 Months Ended
		Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Amortization of pension and postretirement items:
Tax benefit		$ (4,220)	$ (3,425)	$ (18,304)	$ (15,218)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Amortization of pension and postretirement items:
Net of tax		(89)	(30)	(197)	(60)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Amortization of pension and postretirement items:
Prior service cost	[1]	17	15	34	30
Net loss	[1]	155	67	310	132
Total before tax		(138)	(52)	(276)	(102)
Tax benefit		55	21	111	41
Net of tax		(83)	(31)	(165)	(61)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of pension and postretirement items:
Total before tax		(10)	2	(53)	2
Tax benefit		4	(1)	21	(1)
Net of tax		(6)	1	(32)	1
Other Comprehensive Income Loss Adjustments AOCI Swap Agreements		(10)	2	2	2
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax		$ 0	$ 0	$ (55)	$ 0

[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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Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) - $ / shares	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2015	Jun. 30, 2015	Dec. 31, 2014
Deferred compensation plan held Rabbi Trust (in shares)	69,884	69,884	57,382
Shares issued under the performance incentive plan withheld for employee taxes (in shares)		12,620	12,687
Cash Dividends Declared Per Share of Common Stock (in usd per share)	$ 0.288	$ 0.558	$ 1.067

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Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Jun. 30, 2015	Dec. 31, 2014
Fair Value Disclosures [Abstract]
Long-term debt including current maturities	$ 159.9	$ 161.5
Fair value of long-term debt	$ 174.1	$ 180.7

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Environmental Commitments and Contingencies - Additional Information 1 (Detail) - Jun. 30, 2015 - USD ($)	Total
Key West Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Period of regulatory inactivity	17 years
Costs to resolve liability	$ 50,000
Key West Florida [Member] | Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Costs to resolve liability	8,000
Pensacola Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Costs to resolve liability	5,000
Winter Haven Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental remediation expense	443,000
Additional remediation costs	100,000
Salisbury Maryland [Member]
Environmental Commitments And Contingencies [Line Items]
Monitoring well remaining maximum cost	$ 5,000

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Employee Benefit Plans (Tables)

6 Months Ended

Jun. 30, 2015

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

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

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

For the Three Months Ended June 30, 2014	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	5	$	(20	)	$	—	$	(15	)
Net loss	38		—		12		17			—		67
Total recognized in net periodic benefit cost	$	38	$	—	$	17	$	(3	)	$	—	$	52
Recognized from accumulated other comprehensive loss (1)	$	38	$	—	$	17	$	(3	)	$	—	$	52
Recognized from regulatory asset	—		—		—		—			—		—
Total	$	38	$	—	$	17	$	(3	)	$	—	$	52

For the Six Months Ended June 30, 2014	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	9	$	(39	)	$	—	$	(30	)
Net loss	75		—		24		33			—		132
Total recognized in net periodic benefit cost	$	75	$	—	$	33	$	(6	)	$	—	$	102
Recognized from accumulated other comprehensive loss (1)	$	75	$	—	$	33	$	(6	)	$	—	$	102
Recognized from regulatory asset	—		—		—		—			—		—
Total	$	75	$	—	$	33	$	(6	)	$	—	$	102

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended June 30,	2015			2014			2015			2014			2015		2014		2015			2014			2015		2014
(in thousands)
Interest cost	$	102		$	106		$	626		$	647		$	23	$	23	$	11		$	13		$	15	$	16
Expected return on plan assets	(135		)	(132		)	(777		)	(772		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			2		5		(19		)	(20		)	—		—
Amortization of net loss	91			38			114			—			25		12		17			17			2		—
Net periodic cost (benefit)	58			12			(37		)	(125		)	50		40		9			10			17		16
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	58		$	12		$	154		$	66		$	50	$	40	$	9		$	10		$	19	$	18

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Six Months Ended June 30,	2015			2014			2015			2014			2015		2014		2015			2014			2015		2014
(in thousands)
Interest cost	$	204		$	213		$	1,251		$	1,294		$	46	$	46	$	22		$	26		$	30	$	33
Expected return on plan assets	(270		)	(265		)	(1,554		)	(1,545		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			5		9		(39		)	(39		)	—		—
Amortization of net loss	181			75			227			—			50		24		35			33			3		—
Net periodic cost (benefit)	115			23			(76		)	(251		)	101		79		18			20			33		33
Amortization of pre-merger regulatory asset	—			—			381			381			—		—		—			—			4		4
Total periodic cost	$	115		$	23		$	305		$	130		$	101	$	79	$	18		$	20		$	37	$	37

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Accumulated Other Comprehensive Income (Loss) (Tables)

6 Months Ended

Jun. 30, 2015

Equity [Abstract]

Changes in Accumulated Other Comprehensive Loss

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

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2013	$	(2,533	)	$	—		$	(2,533	)
Other comprehensive loss before reclassifications	—			(1		)	(1		)
Amounts reclassified from accumulated other comprehensive loss	61			—			61
Net current-period other comprehensive income (loss)	61			(1		)	60
As of June 30, 2014	$	(2,472	)	$	(1	)	$	(2,473	)

Reclassifications out of Accumulated Other Comprehensive Income (Loss)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	17		$	15		$	34		$	30
Net loss (1)	(155		)	(67		)	(310		)	(132		)
Total before income taxes	(138		)	(52		)	(276		)	(102		)
Income tax benefit	55			21			111			41
Net of tax	$	(83	)	$	(31	)	$	(165	)	$	(61	)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	(10	)	$	2		$	2		$	2
Call options (2)	—			—			(55		)	—
Total before income taxes	(10		)	2			(53		)	2
Income tax benefit	4			(1		)	21			(1		)
Net of tax	(6		)	1			(32		)	1
Total reclassifications for the period	$	(89	)	$	(30	)	$	(197	)	$	(60	)

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Derivative Instruments Outstanding Trading Contracts (Details) - Jun. 30, 2015 - Forward Contracts [Member] gal in Thousands	$ / gal gal
Sales [Member]
Derivative [Line Items]
Quantity In Gallons | gal	4,620
Weighted Average Contract Prices	0.4760
Sales [Member] | Minimum [Member]
Derivative [Line Items]
Estimated Market Prices	0.3475
Sales [Member] | Maximum [Member]
Derivative [Line Items]
Estimated Market Prices	0.5288
Purchase [Member]
Derivative [Line Items]
Quantity In Gallons | gal	4,620
Weighted Average Contract Prices	0.4322
Purchase [Member] | Minimum [Member]
Derivative [Line Items]
Estimated Market Prices	0.3550
Purchase [Member] | Maximum [Member]
Derivative [Line Items]
Estimated Market Prices	0.5025

XML

Other Commitments and Contingencies - Additional Information (Detail) gal in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2015 USD ($) dekatherm / d gal	Dec. 31, 2014 USD ($) dekatherm / d
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 | gal	6.5
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	Jun. 30, 2015
Maximum authorized liability under such guarantees and letters of credit	$ 50,000,000
Aggregate guaranteed amount	32,000,000
Draws on letters of credit	0
Liability for Uncertain Tax Positions, Noncurrent	100,000	$ 100,000
Unrecognized Tax Benefits	$ 525,000	$ 724,000
Purchase Commitment Minimum Volume | dekatherm / d	9,982
Purchase Commitment Maximum Volume | dekatherm / d		13,423
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	1,200,000
June 1, 2014 [Member]
Other Contingencies And Commitments [Line Items]
Amount of letter of credit to our current primary insurance company	40,000
TETLP Letter of Credit [Member] | Texas Eastern Transmission, LP [Member]
Other Contingencies And Commitments [Line Items]
Amount of letter of credit to our current primary insurance company	$ 2,300,000

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Investments Investments (Tables)

6 Months Ended

Jun. 30, 2015

Investments, Debt and Equity Securities [Abstract]

Investments schedule [Table Text Block]

(in thousands)	June 30, 2015		December 31, 2014
Rabbi trust (associated with the Deferred Compensation Plan)	$	3,649	$	3,678
Investments in equity securities	16		—
Total	$	3,665	$	3,678

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Share-Based Compensation (Tables)

6 Months Ended

Jun. 30, 2015

Shares awarded to non-employee directors [Line Items]

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

The table below presents the amounts included in net income related to share-based compensation expense for the three and six months endedJune 30, 2015 and 2014:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
(in thousands)
Awards to non-employee directors	$	160		$	132		$	311		$	256
Awards to key employees	250			295			636			809
Total compensation expense	410			427			947			1,065
Less: tax benefit	(165		)	(172		)	(381		)	(429		)
Share-based compensation amounts included in net income	$	245		$	255		$	566		$	636

Awards to non-employee directors [Member]

Shares awarded to non-employee directors [Line Items]

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

A summary of the stock activity for our non-employee directors during the six months ended June 30, 2015 is presented below:

	Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2014	—		$	—
Granted	14,484		$	45.54
Vested	(14,484	)	$	45.54
Outstanding— June 30, 2015	—		$	—

Award to key employees [Member]

Shares awarded to non-employee directors [Line Items]

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

The table below presents the summary of the stock activity for awards to key employees for the six months ended June 30, 2015:

	Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2014	123,038		$	32.60
Granted	29,763		$	48.21
Vested	(43,839	)	$	28.01
Expired	(2,520	)	$	28.83
Outstanding— June 30, 2015	106,442		$	37.97

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Condensed Consolidated Statements of Stockholders' Equity - USD ($) $ in Thousands		Total	Common Stock [Member]	Additional Paid-In Capital [Member]	Retained Earnings [Member]	Accumulated Other Comprehensive Loss [Member]	Deferred Compensation [Member]	Treasury Stock [Member]
Beginning Balances, shares at Dec. 31, 2013	[1]		14,457,345
Beginning Balances at Dec. 31, 2013		$ 278,773	$ 4,691	$ 152,341	$ 124,274	$ (2,533)	$ 1,124	$ (1,124)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		36,092			36,092
Other comprehensive loss		(3,143)				(3,143)
Common Stock Dividends, Shares			0
Dividends		(15,675)			(15,675)
Stock Issued During The Period Shares Retirement Savings Plan And Dividend Reinvestment Plan			43,367
Stock Issued During The Period Value Retirement Savings Plan And Dividend Reinvestment Plan		1,860	$ 16	1,844
Conversion of debentures, shares	[1]		47,313
Stock Issued During Period, Value, Conversion of Convertible Securities		535	$ 15	520
Share-based compensation, shares	[1],[2],[3]		40,686
Share-based compensation and tax benefit	[2],[3]	1,889	$ 13	1,876
Stock Split in Form of Stock Dividend Adjustment to Retained Earnings		(9)	$ 2,365		(2,374)
Treasury stock activities		0					134	(134)
Ending Balances, shares at Dec. 31, 2014	[1]		14,588,711
Ending Balances at Dec. 31, 2014		300,322	$ 7,100	156,581	142,317	(5,676)	1,258	(1,258)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		27,403			27,403
Other comprehensive loss		197				197
Common Stock Dividends, Shares			0
Dividends		(8,387)			(8,387)
Stock Issued During Period, Shares, Dividend Reinvestment Plan			15,583
Stock Issued During Period, Value, Dividend Reinvestment Plan		772	$ 8	764
Stock Issued During Period, Shares, Acquisitions			592,970
Stock Issued During Period, Value, Acquisitions		30,165	$ 289	29,876
Share-based compensation, shares	[1],[2],[3]		45,703
Share-based compensation and tax benefit	[2],[3]	704	$ 22	682
Treasury stock activities		0					585	(585)
Ending Balances, shares at Jun. 30, 2015	[1]		15,242,967
Ending Balances at Jun. 30, 2015		$ 351,176		$ 187,903	$ 161,333	$ (5,479)	$ 1,843	$ (1,843)

[1] Includes 69,884 and 57,382 shares at June 30, 2015 and December 31, 2014, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.

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

[3] The shares issued under the SICP are net of shares withheld for employee taxes. For the six months ended June 30, 2015, and for the year ended December 31, 2014, we withheld 12,620 and 12,687 shares, respectively, for taxes.

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Derivative Instruments (Tables)

6 Months Ended

Jun. 30, 2015

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Outstanding Trading Contracts

	Quantity in	Estimated Market	Weighted Average
At June 30, 2015	Gallons	Prices	Contract Prices
Forward Contracts
Sale	4,620,000	$0.3475 - $0.5288	$	0.4760
Purchase	4,620,000	$0.3550 - $0.5025	$	0.4322

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

Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet

air values of the derivative contracts recorded in the condensed consolidated balance sheets as of June 30, 2015 and December 31, 2014, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2015		December 31, 2014
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	212	$	407
Derivatives designated as fair value hedges
Put options	Mark-to-market energy assets	110		622
Derivatives designated as cash flow hedges
Call options	Mark-to-market energy assets	—		26
Propane swap agreements	Mark-to-market energy assets	36		—
Total asset derivatives		$	358	$	1,055

	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2015		December 31, 2014
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	9	$	283
Propane swap agreements	Mark-to-market energy liabilities	—		735
Derivatives designated as cash flow hedges
Propane swap agreements	Mark-to-market energy liabilities	38		—
Total liability derivatives		$	47	$	1,018

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

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

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(in thousands)	(Loss) on Derivatives	2015			2014			2015			2014
Derivatives not designated as hedging instruments
Realized gain (loss) on forward contracts (1)	Revenue	$	(71	)	$	84		$	206		$	1,330
Unrealized gain (loss) on forward contracts	Revenue	203			6			78			(62		)
Call option	Cost of sales	—			—			—			137
Propane swap agreements	Cost of sales	—			—			18			—
Derivatives designated as fair value hedges
Put options	Cost of sales	—			(29		)	506			(49		)
Put options (2)	Propane Inventory	(30		)	—			(34		)	—
Derivatives designated as cash flow hedges
Propane swap agreements	Other Comprehensive loss	10			(2		)	(2		)	(2		)
Call options	Cost of sales	—			—			(81		)	—
Total		$	112		$	59		$	691		$	1,354

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Acquisitions Gatherco purchase price allocation (Details) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Apr. 01, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Goodwill	$ 16,048		$ 4,952
Gatherco [Member]
Business Acquisition [Line Items]
Purchase price	57,658
Property plant and equipment	52,578
Cash	6,806	$ 6,800
Accounts receivable	3,629
Income taxes receivable	3,012
Other assets	247
Total assets acquired	66,272
Long-term debt	1,696	$ 1,696
Deferred income taxes	13,863
Accounts payable	3,837
Other current liabilities	314
Total liabilities assumed	19,710
Net identifiable assets acquired	46,562
Goodwill	$ 11,096

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Share-Based Compensation - Share-Based Compensation Amounts Included in Net Income (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 410	$ 427	$ 947	$ 1,065
Less: tax benefit	(165)	(172)	(381)	(429)
Share-Based Compensation amounts included in net income	245	255	566	636
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	160	132	311	256
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 250	$ 295	$ 636	$ 809

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Condensed Consolidated Statements of Income - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Operating Revenues
Regulated energy	$ 62,060	$ 61,646	$ 171,642	$ 163,812
Unregulated energy	30,622	38,851	91,121	123,022
Total Operating Revenues	92,682	100,497	262,763	286,834
Operating Expenses
Regulated energy cost of sales	21,124	24,672	78,253	78,979
Unregulated energy and other cost of sales	20,272	28,442	55,507	89,766
Operations	26,190	24,615	53,133	51,242
Maintenance	2,727	2,457	5,431	4,606
Gain from a settlement	(1,500)	0	(1,500)	0
Depreciation and amortization	7,543	6,736	14,518	13,371
Other taxes	3,156	3,118	6,743	6,791
Total Operating Expenses	79,512	90,040	212,085	244,755
Operating Income	13,170	10,457	50,678	42,079
Other income, net of other expenses	(171)	405	(38)	413
Interest charges	2,485	2,303	4,933	4,459
Income Before Income Taxes	10,514	8,559	45,707	38,033
Income taxes	4,220	3,425	18,304	15,218
Net Income	$ 6,294	$ 5,134	$ 27,403	$ 22,815
Weighted Average Common Shares Outstanding:
Basic (in shares)	15,235,860	14,556,242	14,922,094	14,522,133
Diluted (in shares)	15,280,657	14,606,779	14,970,190	14,573,643
Earnings Per Share of Common Stock:
Basic (in usd per share)	$ 0.41	$ 0.35	$ 1.84	$ 1.57
Diluted (in usd per share)	0.41	0.35	1.83	1.57
Cash Dividends Declared Per Share of Common Stock (in usd per share)	$ 0.288	$ 0.27	$ 0.558	$ 0.527

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Segment Information - Schedule of Segment Reporting Information by Segment (Detail) - USD ($) $ in Thousands		3 Months Ended				6 Months Ended		12 Months Ended
		Jun. 30, 2015		Jun. 30, 2014		Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		$ 92,682		$ 100,497		$ 262,763	$ 286,834
Intersegment Revenues
Total operating revenues, unaffiliated customers		92,682		100,497		262,763	286,834
Operating Income
Total operating income		13,170		10,457		50,678	42,079
Other income, net of other expenses		(171)		405		(38)	413
Interest		2,485		2,303		4,933	4,459
Income Before Income Taxes		10,514		8,559		45,707	38,033
Income taxes		4,220		3,425		18,304	15,218
Net Income		6,294		5,134		27,403	22,815	$ 36,092
Identifiable Assets
Total identifiable assets		970,636				970,636		904,469
Regulated Energy [Member]
Operating Income
Total operating income		13,605		10,711		35,788	31,802
Identifiable Assets
Total identifiable assets		800,719				800,719		796,021
Unregulated Energy [Member]
Operating Income
Total operating income		(540)		(43)		14,689	10,815
Identifiable Assets
Total identifiable assets		147,102				147,102		84,732
Other [Member]
Identifiable Assets
Total identifiable assets		22,815				22,815		$ 23,716
Other and eliminations [Member]
Operating Income
Total operating income		105		(211)		201	(538)
Operating Revenues, Unaffiliated Customers [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		92,682		100,497		262,763	286,834
Intersegment Revenues
Total operating revenues, unaffiliated customers		92,682		100,497		262,763	286,834
Operating Revenues, Unaffiliated Customers [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		61,790		61,348		171,082	163,222
Intersegment Revenues
Total operating revenues, unaffiliated customers		61,790		61,348		171,082	163,222
Operating Revenues, Unaffiliated Customers [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		30,892		34,299		91,681	114,173
Intersegment Revenues
Total operating revenues, unaffiliated customers		30,892		34,299		91,681	114,173
Operating Revenues, Unaffiliated Customers [Member] | Other [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		0		4,850		0	9,439
Intersegment Revenues
Total operating revenues, unaffiliated customers		0		4,850		0	9,439
Intersegment Revenues [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		2,156	[1]	568	[1]	2,873	1,213
Intersegment Revenues
Total operating revenues, unaffiliated customers		2,156	[1]	568	[1]	2,873	1,213
Intersegment Revenues [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	270		298		560	590
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	270		298		560	590
Intersegment Revenues [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	1,666		22		1,873	121
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	1,666		22		1,873	121
Intersegment Revenues [Member] | Other [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	220		248		440	502
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	$ 220		$ 248		$ 440	$ 502

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

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Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 1,146	$ 1,120
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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Derivative Instruments - Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 112	$ 59	$ 691	$ 1,354
Revenue [Member] | Derivatives not designated as hedging instruments [Member] | Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	203	6	78	(62)
Cost of Sales [Member] | Derivatives not designated as hedging instruments [Member] | Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0	0	137
Cost of Sales [Member] | Derivatives not designated as hedging instruments [Member] | Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0	18	0
Cost of Sales [Member] | Derivatives designated as fair value hedges [Member] | Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	0	(81)	0
Cost of Sales [Member] | Derivatives designated as fair value hedges [Member] | Put/Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	(29)	506	(49)
Inventories [Member] | Derivatives designated as fair value hedges [Member] | Put/Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	(30)	0	(34)	0
Other Comprehensive Income (Loss) [Member] | Derivatives designated as fair value hedges [Member] | Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	10	(2)	(2)	(2)
Options [Member] | Revenue [Member] | Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ (71)	$ 84	$ 206	$ 1,330

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Summary of Accounting Policies Stock Dividend (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2014	Jun. 30, 2015
Summary Of Accounting Policies [Line Items]
Stock Split in Form of Stock Dividend Adjustment to Retained Earnings	$ 9
Common Stock, Par or Stated Value Per Share	$ 0.4867	$ 0.4867
Common Stock [Member]
Summary Of Accounting Policies [Line Items]
Stock Split in Form of Stock Dividend Adjustment to Retained Earnings	$ (2,365)

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Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Debt Instrument [Line Items]
Total long-term debt	$ 159,900		$ 161,500
Repayments of Long-term Debt	3,934	$ 1,921
5.68% note, due June 30, 2026 [Member]
Debt Instrument [Line Items]
Total long-term debt	$ 29,000		29,000
Long-term debt, interest percentage	5.68%
Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member]
Debt Instrument [Line Items]
Total long-term debt	$ 50,000		50,000
Long-term debt, interest percentage	3.88%
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Total long-term debt	$ 20,000		$ 20,000
Long-term debt, interest percentage	3.73%

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Fair Value of Financial Instruments

6 Months Ended

Jun. 30, 2015

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).

Financial Assets and Liabilities Measured at Fair Value

The following table summarizes our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of June 30, 2015 and December 31, 2014:

			Fair Value Measurements Using:
As of June 30, 2015	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments - equity securities	$	16	$	16	$	—	$	—
Investments—guaranteed income fund	$	335	$	—	$	—	$	335
Investments—other	$	3,314	$	3,314	$	—	$	—
Mark-to-market energy assets, incl. put options and swap agreements	$	358	$	—	$	358	$	—
Liabilities:
Mark-to-market energy liabilities incl. swap agreements	$	47	$	—	$	47	$	—

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

The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of June 30, 2015 and December 31, 2014:

Level 1 Fair Value Measurements:

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

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

Level 2 Fair Value Measurements:

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

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

Level 3 Fair Value Measurements:

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

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the six months ended June 30, 2015 and 2014:

	Six Months Ended   June 30,
	2015			2014
(in thousands)
Beginning Balance	$	287		$	458
Purchases and adjustments	49			(26		)
Transfers	(3		)	(25		)
Investment income	2			3
Ending Balance	$	335		$	410

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

At June 30, 2015, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its short maturities and because interest rates approximate current market rates (Level 3 measurement).

At June 30, 2015, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of $159.9 million. This compares to a fair value of $174.1 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At December 31, 2014, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of $161.5 million, compared to the estimated fair value of $180.7 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

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Summary of Accounting Policies Summary of Accounting policies (Details) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Accounting Policies [Abstract]
Gain From A Settlement	$ 1,500	$ 0	$ 1,500	$ 0
Gain Contingency, Unrecorded Amount	750		$ 750
Asset Impairment Charges					$ 6,500
Period Additional Cash And Discounts On Future Services Is Based On			5 years
Debt Instrument, Unamortized Discount	$ 322		$ 322

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Summary of Accounting Policies (Policies)

6 Months Ended

Jun. 30, 2015

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2014. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

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

Reclassifications

As a result of the sale of our advanced information services subsidiary in October 2014, we changed our operating segments (see Note 7, Segment Information). We reclassified certain amounts in the condensed consolidated income statement for the three and six months ended June 30, 2014 and condensed consolidated cash flows statement for the six months ended June 30, 2014 to conform to the current year's presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

Stock Dividend

On July 2, 2014, our Board of Directors approved a three-for-two stock split of our outstanding common stock to be effected in the form of a stock dividend. Each stockholder as of the close of business on the record date, August 13, 2014, received one additional share of common stock for every two shares of common stock owned. The additional shares were distributed on September 8, 2014. All share and per share data in this Form 10-Q are presented on a post-split basis. As a result of the stock split, we reclassified approximately $2.4 million from retained earnings to common stock in September of 2014, which represents $0.4867 par value per share of the shares issued in the stock split.

Gain Contingency

Effective May 29, 2015, we entered into a settlement agreement with a vendor related to the implementation of a customer billing system. Pursuant to the agreement we received $1.5 million in cash, which is reflected as "Gain from a settlement" in the accompanying condensed consolidated statements of income. Previously at December 31, 2014, we recorded a $6.5 million pretax, non-cash impairment loss related to the same billing system implementation. We may also receive $750,000 in additional cash and discounts on future services, however, the receipt or retention of additional cash and future discounts is contingent upon engaging this vendor to provide agreed-upon services over the next five years.

Recent Accounting Standards Yet to be Adopted

FASB Statements and Other Authoritative Pronouncements

Recent Accounting Standards Yet to be Adopted

Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. On July 9, 2015, the FASB affirmed its proposal to defer the implementation of this standard by one year. For public entities, this standard is effective for 2018 interim and annual financial statements. We are assessing the impact this standard will have on our financial position and results of operations.

Interest - Imputation of Interest (ASC 835-30) - In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. This standard requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. ASU 2015-03 is effective for our interim and annual financial statements issued beginning January 1, 2016. Early adoption is permitted for financial statements that have not been previously issued. As of June 30, 2015, we had $322,000 of unamortized debt issuance costs included in the accompanying condensed consolidated balance sheets. Upon adoption of ASU 2015-03, this will be presented as a deduction from long-term debt, net of current maturities.

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Condensed Consolidated Statements of Cash Flows - Entity [Domain] - USD ($) $ in Thousands	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014
Operating Activities
Net Income	$ 27,403	$ 22,815
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	14,518	13,371
Depreciation and accretion included in other costs	3,486	3,447
Deferred income taxes, net	(1,366)	166
Realized gain on commodity contracts/sales of assets/investments	(686)	(420)
Unrealized loss on investments/commodity contracts	(187)	(90)
Employee benefits	601	319
Share-based compensation	947	1,065
Other, net	8	(1)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	20,194	36,713
Propane inventory, storage gas and other inventory	4,405	6,074
Increase (Decrease) in Regulatory Assets and Liabilities	12,728	(3,147)
Prepaid expenses and other current assets	3,261	3,183
Accounts payable and other accrued liabilities	(8,990)	(22,491)
Income taxes receivable	19,300	3,305
Customer deposits and refunds	(3,748)	(2,658)
Accrued compensation	(3,788)	(2,975)
Other assets and liabilities, net	(315)	(113)
Net cash provided by operating activities	87,771	58,563
Investing Activities
Property, plant and equipment expenditures	(64,719)	(42,882)
Proceeds from sales of assets	49	459
Acquisitions, net of cash acquired	(20,930)	0
Environmental expenditures	(73)	(79)
Net cash used in investing activities	(85,673)	(42,502)
Financing Activities
Common stock dividends	(7,532)	(7,120)
Purchase of stock for Dividend Reinvestment Plan	417	(26)
Change in cash overdrafts due to outstanding checks	2,367	(806)
Net borrowing (repayment) under line of credit agreements	4,114	(56,990)
Proceeds from Issuance of Long-term Debt	0	49,975
Repayment of long-term debt	(3,934)	(1,921)
Net cash used in financing activities	(4,568)	(16,888)
Net Decrease in Cash and Cash Equivalents	(2,470)	(827)
Cash and Cash Equivalents-Beginning of Period	4,574	3,356
Cash and Cash Equivalents-End of Period	$ 2,104	$ 2,529

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Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Net Income	$ 6,294	$ 5,134	$ 27,403	$ 22,815
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(7), $(6), $(14) and $(12), respectively	(10)	(9)	(20)	(18)
Net gain, net of tax of $62, $27, $125 and $53, respectively	93	40	185	79
Commodity Contract Cash Flow Hedges [Abstract]
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $4, ($1), $21 and ($1), respectively.	6	(1)	32	(1)
Total other comprehensive income	89	30	197	60
Comprehensive Income	$ 6,383	$ 5,164	$ 27,600	$ 22,875

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Accumulated Other Comprehensive Income (Loss)

6 Months Ended

Jun. 30, 2015

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Income (Loss)

Defined benefit pension and postretirement plan items and unrealized gains (losses) of our propane swap agreements and call options, designated as commodity contracts cash flow hedges, are the components of our accumulated comprehensive income (loss). The following tables present the changes in the balance of accumulated other comprehensive loss for the six months endedJune 30, 2015 and 2014. All amounts are presented net of tax.

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

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2013	$	(2,533	)	$	—		$	(2,533	)
Other comprehensive loss before reclassifications	—			(1		)	(1		)
Amounts reclassified from accumulated other comprehensive loss	61			—			61
Net current-period other comprehensive income (loss)	61			(1		)	60
As of June 30, 2014	$	(2,472	)	$	(1	)	$	(2,473	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and six months endedJune 30, 2015 and 2014. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	17		$	15		$	34		$	30
Net loss (1)	(155		)	(67		)	(310		)	(132		)
Total before income taxes	(138		)	(52		)	(276		)	(102		)
Income tax benefit	55			21			111			41
Net of tax	$	(83	)	$	(31	)	$	(165	)	$	(61	)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	(10	)	$	2		$	2		$	2
Call options (2)	—			—			(55		)	—
Total before income taxes	(10		)	2			(53		)	2
Income tax benefit	4			(1		)	21			(1		)
Net of tax	(6		)	1			(32		)	1
Total reclassifications for the period	$	(89	)	$	(30	)	$	(197	)	$	(60	)

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

⁽²⁾ These amounts are included in the effects of gains and losses from derivative instruments. See Note 12, Derivative Instruments, for additional details.

Amortization of defined benefit pension and postretirement plan items is included in operations expense and gains and losses on propane swap agreements and call options are included in cost of sales in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.

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Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2015	Jul. 31, 2015
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	Jun. 30, 2015
Document Fiscal Year Focus	2015
Document Fiscal Period Focus	Q2
Amendment Flag	false
Entity Common Stock, Shares Outstanding		15,260,473

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Employee Benefit Plans

6 Months Ended

Jun. 30, 2015

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three and six months endedJune 30, 2015 and 2014 are set forth in the following tables:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended June 30,	2015			2014			2015			2014			2015		2014		2015			2014			2015		2014
(in thousands)
Interest cost	$	102		$	106		$	626		$	647		$	23	$	23	$	11		$	13		$	15	$	16
Expected return on plan assets	(135		)	(132		)	(777		)	(772		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			2		5		(19		)	(20		)	—		—
Amortization of net loss	91			38			114			—			25		12		17			17			2		—
Net periodic cost (benefit)	58			12			(37		)	(125		)	50		40		9			10			17		16
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	58		$	12		$	154		$	66		$	50	$	40	$	9		$	10		$	19	$	18

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Six Months Ended June 30,	2015			2014			2015			2014			2015		2014		2015			2014			2015		2014
(in thousands)
Interest cost	$	204		$	213		$	1,251		$	1,294		$	46	$	46	$	22		$	26		$	30	$	33
Expected return on plan assets	(270		)	(265		)	(1,554		)	(1,545		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			5		9		(39		)	(39		)	—		—
Amortization of net loss	181			75			227			—			50		24		35			33			3		—
Net periodic cost (benefit)	115			23			(76		)	(251		)	101		79		18			20			33		33
Amortization of pre-merger regulatory asset	—			—			381			381			—		—		—			—			4		4
Total periodic cost	$	115		$	23		$	305		$	130		$	101	$	79	$	18		$	20		$	37	$	37

We expect to record pension and postretirement benefit costs of approximately $1.2 million for 2015. Included in these costs is $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations for the changes in funded status that occurred but were not recognized as part of net periodic benefit costs prior to the FPU merger. This was deferred as a regulatory asset by FPU prior to the merger to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was $3.2 million and $3.6 million at June 30, 2015 and December 31, 2014, respectively. The amortization included in pension expense is also being added to a net periodic loss of $381,000, which will increase our total expected benefit costs to $1.2 million.

Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset a portion of the unrecognized pension and postretirement benefit costs related to its regulated operations after the FPU merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake’s operations is recorded to accumulated other comprehensive income (loss). The following table presents the amounts included in the regulatory asset and accumulated other comprehensive income (loss) that were recognized as components of net periodic benefit cost during the three and six months ended June 30, 2015 and 2014:

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

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

For the Three Months Ended June 30, 2014	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	5	$	(20	)	$	—	$	(15	)
Net loss	38		—		12		17			—		67
Total recognized in net periodic benefit cost	$	38	$	—	$	17	$	(3	)	$	—	$	52
Recognized from accumulated other comprehensive loss (1)	$	38	$	—	$	17	$	(3	)	$	—	$	52
Recognized from regulatory asset	—		—		—		—			—		—
Total	$	38	$	—	$	17	$	(3	)	$	—	$	52

For the Six Months Ended June 30, 2014	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	9	$	(39	)	$	—	$	(30	)
Net loss	75		—		24		33			—		132
Total recognized in net periodic benefit cost	$	75	$	—	$	33	$	(6	)	$	—	$	102
Recognized from accumulated other comprehensive loss (1)	$	75	$	—	$	33	$	(6	)	$	—	$	102
Recognized from regulatory asset	—		—		—		—			—		—
Total	$	75	$	—	$	33	$	(6	)	$	—	$	102

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

During the three and six months ended June 30, 2015, we contributed $115,000 and $219,000, respectively to the Chesapeake Pension Plan and $381,000 and $723,000, respectively to the FPU Pension Plan. We expect to contribute a total of $475,000 and $1.6 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2015, which represent the minimum contribution payments required during the year.

The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three and six months ended June 30, 2015, were $38,000 and $71,000, respectively. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake Pension SERP in 2015. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three and six months ended June 30, 2015, were $13,000 and $28,000, respectively. We estimate that approximately $79,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2015. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and six months ended June 30, 2015, were $24,000 and $116,000, respectively. We estimate that approximately $207,000 will be paid for such benefits under the FPU Medical Plan in 2015.

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Condensed Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Tax expense recognized on the amortization of prior service cost	$ (7)	$ (6)	$ (14)	$ (12)
Tax expense recognized on the net gain (loss)	62	27	125	53
Other Comprehensive Income (Loss), Unrealized Gain (Loss) on Derivatives Arising During Period, Tax	$ 4	$ (1)	$ 21	$ (1)

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Acquisitions

6 Months Ended

Jun. 30, 2015

Business Combinations [Abstract]

Acquisitions

Acquisitions

Gatherco Acquisition

On April 1, 2015, we completed the merger with Gatherco, in which Gatherco merged with and into Aspire Energy of Ohio, a newly formed, wholly-owned subsidiary of Chesapeake. As a result of this merger, Aspire Energy of Ohio provides natural gas midstream services through 16 gathering systems and over 2,000 miles of pipelines in Central and Eastern Ohio, including natural gas gathering services and natural gas liquid processing services to over 300 producers, and supplies natural gas to over 6,000 customers in Ohio through the Consumers Gas Cooperative, an independent entity, which Aspire Energy of Ohio manages under an operating agreement.

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

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

The merger agreement provides for additional contingent cash consideration to Gatherco's shareholders of up to $15.0 million based on a percentage of revenue generated from potential future gathering opportunities over the next five years.

We incurred $1.3 million in transaction costs associated with this merger, $514,000 of which was expensed in the six months ended June 30, 2015. Transactions costs are included in operations expense in the accompanying condensed consolidated statement of income. The revenue and net loss from this acquisition for the three and six months ended June 2015, included in our condensed consolidated statement of income, was $5.2 million and $187,000, respectively. The financial results of Aspire Energy of Ohio are projected to have a minimal impact on our earnings per share in 2015, since the merger was completed after the first quarter. The first quarter includes key winter months, which have historically produced a significant portion of Gatherco's annual earnings. This acquisition is expected to be accretive to our earnings in the first full year of operations, which will include the first quarter of 2016.

The preliminary purchase price allocation of the Gatherco acquisition is as follows:

(in thousands)
Purchase price	$	57,658
Property plant and equipment	52,578
Cash	6,806
Accounts receivable	3,629
Income taxes receivable	3,012
Other assets	247
Total assets acquired	66,272
Long-term debt	1,696
Deferred income taxes	13,863
Accounts payable	3,837
Other current liabilities	314
Total liabilities assumed	19,710
Net identifiable assets acquired	46,562
Goodwill	$	11,096

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

The initial accounting for the Gatherco acquisition is not complete because the valuation necessary to assess the fair values of property, plant and equipment and the related impact on deferred income tax amounts is considered preliminary as we continue to evaluate these assets. The valuation of additional contingent cash consideration and potential environmental remediation costs may be adjusted as additional information becomes available. The purchase price allocation can be modified up to one year from the date of the acquisition, but we will complete the allocation as soon as practicable.

Other acquisitions

On May 7, 2015, we purchased certain propane distribution assets used to serve 253 customers in Citrus County, Florida for approximately $242,000. In connection with this acquisition, we recorded $186,000 in intangible assets related to a non-compete agreement and the customer list to be amortized over six and 10 years, respectively. The remaining purchase price was allocated to property, plant and equipment and accounts receivable. The revenue and net income from this acquisition that were included in our condensed consolidated statement of income for the three and six months ended June 30, 2015 were not material.

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Calculation of Earnings Per Share

6 Months Ended

Jun. 30, 2015

Earnings Per Share [Abstract]

Calculation of Earnings Per Share

Calculation of Earnings Per Share

	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2015		2014		2015		2014
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	6,294	$	5,134	$	27,403	$	22,815
Weighted average shares outstanding	15,235,860		14,556,242		14,922,094		14,522,133
Basic Earnings Per Share	$	0.41	$	0.35	$	1.84	$	1.57
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	6,294	$	5,134	$	27,403	$	22,815
Reconciliation of Denominator:
Weighted shares outstanding—Basic	15,235,860		14,556,242		14,922,094		14,522,133
Effect of dilutive securities:
Share-based compensation	44,797		50,537		48,096		51,510
Adjusted denominator—Diluted	15,280,657		14,606,779		14,970,190		14,573,643
Diluted Earnings Per Share	$	0.41	$	0.35	$	1.83	$	1.57

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

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Long-Term Debt

6 Months Ended

Jun. 30, 2015

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Our outstanding long-term debt is shown below:

	June 30,			December 31,
(in thousands)	2015			2014
FPU secured first mortgage bonds (1) :
9.08% bond, due June 1, 2022	$	7,971		$	7,969
Uncollateralized senior notes:
6.64% note, due October 31, 2017	8,182			8,182
5.50% note, due October 12, 2020	12,000			12,000
5.93% note, due October 31, 2023	25,500			27,000
5.68% note, due June 30, 2026	29,000			29,000
6.43% note, due May 2, 2028	7,000			7,000
3.73% note, due December 16, 2028	20,000			20,000
3.88% note, due May 15, 2029	50,000			50,000
Promissory notes	238			314
Capital lease obligation	5,483			6,130
Total long-term debt	165,374			167,595
Less: current maturities	(9,127		)	(9,109		)
Total long-term debt, net of current maturities	$	156,247		$	158,486

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

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Investments

6 Months Ended

Jun. 30, 2015

Investments, Debt and Equity Securities [Abstract]

Investments

Investments

The investment balances at June 30, 2015 and December 31, 2014, consisted of the following:

(in thousands)	June 30, 2015		December 31, 2014
Rabbi trust (associated with the Deferred Compensation Plan)	$	3,649	$	3,678
Investments in equity securities	16		—
Total	$	3,665	$	3,678

We classify these investments as trading securities and report them at their fair value. For the three months ended June 30,2015 and 2014, we recorded a net unrealized gain of $4,000 and $114,000, respectively, in other income in the condensed consolidated statements of income related to these investments. For the six months ended June 30,2015 and 2014, we recorded a net unrealized gain of $107,000 and $152,000, respectively, in other income in the condensed consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the condensed consolidated balance sheets and is adjusted each month for the gains and losses incurred by the Rabbi Trust.

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Other Commitments and Contingencies

6 Months Ended

Jun. 30, 2015

Commitments and Contingencies Disclosure [Abstract]

Other Commitments and Contingencies

Other Commitments and Contingencies

Natural Gas, Electric and Propane Supply

Our natural gas, electric and propane distribution operations have entered into contractual commitments to purchase natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. Our Delaware and Maryland natural gas distribution divisions have a contract through March 31, 2017, with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage capacity.

In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term. Approximately four years remain under this contract. Sandpiper's current annual commitment is estimated at approximately 6.5 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.

Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a six-year term. Sharp's current annual commitment is estimated at approximately 6.5 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement.

Chesapeake’s Florida natural gas distribution division has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including PESCO. Under the terms of these capacity release agreements, Chesapeake is contingently liable to FGT and Gulfstream should any party that acquired the capacity through release fail to pay the capacity charge.

In May 2015, PESCO renewed contracts to purchase natural gas from various suppliers. The total commitment is to purchase between 9,982 and 13,423 Dts/dduring the months of June 2015 to May 2016. These contracts expire in May 2016.

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) a fixed charge coverage ratio greater than 1.5 times. If FPU fails to comply with either of these ratios, it has 30 days to cure the default or, if the default is not cured, to provide an irrevocable letter of credit. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet either of these ratios, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of June 30, 2015, FPU was in compliance with all of the requirements of its fuel supply contracts.

Corporate Guarantees

The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our obligations, including the obligations of our subsidiaries. The maximum authorized liability under such guarantees and letters of credit is $50.0 million.

We have issued corporate guarantees to certain vendors of our subsidiaries, the largest portion of which is for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases, respectively, in the event that Xeron or PESCO defaults. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at June 30, 2015 was $32.0 million, with the guarantees expiring on various dates through June 29, 2016.

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

In addition to the corporate guarantees, we have issued a letter of credit for $1.0 million, which expires on September 12, 2015, related to the electric transmission services for FPU’s northwest electric division. We have also issued a letter of credit to our current primary insurance company for $1.2 million, which expires on October 31, 2015, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company in 2010, we renewed and decreased the letter of credit for $40,000 to our former primary insurance company, which will expire on June 1, 2016. There have been no draws on these letters of credit as of June 30, 2015. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.

We provided a letter of credit for $2.3 million to TETLP related to the firm transportation service agreement with our Delaware and Maryland divisions.

Tax-related Contingencies

We are subject to various audits and reviews by the federal, state, local and other governmental authorities regarding income taxes and taxes other than income. As of June 30, 2015, we maintained a liability of $100,000 related to unrecognized income tax benefits and $525,000 related to contingencies for taxes other than income. As of December 31, 2014, we maintained a liability of $100,000 related to unrecognized income tax benefits and $724,000 related to contingencies for taxes other than income.

Other

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

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Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014	Dec. 31, 2013
Assets:
Investments	$ 3,665	$ 3,678
Equity Securities [Member]
Assets:
Investments	16	0
Quoted Prices in Active Markets (Level 1) [Member] | Mark-to-market energy liabilities [Member]
Liabilities:
Mark-to-market energy liabilities	0	0
Quoted Prices in Active Markets (Level 1) [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	0	0
Quoted Prices in Active Markets (Level 1) [Member] | Equity Securities [Member]
Assets:
Investments	16
Quoted Prices in Active Markets (Level 1) [Member] | Investments - other [Member]
Assets:
Investments	3,314	3,391
Quoted Prices in Active Markets (Level 1) [Member] | Mark To Market Energy Assets Including Put Option [Member]
Assets:
Mark-to-market energy assets	0	0
Significant Other Observable Inputs (Level 2) [Member] | Mark-to-market energy liabilities [Member]
Liabilities:
Mark-to-market energy liabilities	47	1,018
Significant Other Observable Inputs (Level 2) [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	0	0
Significant Other Observable Inputs (Level 2) [Member] | Equity Securities [Member]
Assets:
Investments	0
Significant Other Observable Inputs (Level 2) [Member] | Investments - other [Member]
Assets:
Investments	0	0
Significant Other Observable Inputs (Level 2) [Member] | Mark To Market Energy Assets Including Put Option [Member]
Assets:
Mark-to-market energy assets	358	1,055
Significant Unobservable Inputs (Level 3) [Member] | Mark-to-market energy liabilities [Member]
Assets:
Mark-to-market energy assets	0	0	$ 0
Significant Unobservable Inputs (Level 3) [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	335	287
Significant Unobservable Inputs (Level 3) [Member] | Equity Securities [Member]
Assets:
Investments	0
Significant Unobservable Inputs (Level 3) [Member] | Investments - other [Member]
Assets:
Investments	0	0
Recurring [Member] | Mark-to-market energy liabilities [Member]
Liabilities:
Mark-to-market energy liabilities	47	1,018
Recurring [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	335	287
Recurring [Member] | Equity Securities [Member]
Assets:
Investments	16
Recurring [Member] | Investments - other [Member]
Assets:
Investments	3,314	3,391
Recurring [Member] | Mark To Market Energy Assets Including Put Option [Member]
Assets:
Mark-to-market energy assets	$ 358	$ 1,055

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Rates and Other Regulatory Activities

6 Months Ended

Jun. 30, 2015

Regulated Operations [Abstract]

Rates and Other Regulatory Activities

Rates and Other Regulatory Activities

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

Delaware

There were no significant rates and other regulatory activities in Delaware during the first six months of 2015.

Maryland

There were no significant rates and other regulatory activities in Maryland during the first six months of 2015.

Florida

On January 16, 2015, Chesapeake's Florida natural gas distribution division filed a petition with the Florida PSC for approval of a contract with its affiliate, Peninsula Pipeline, for additional natural gas transportation services in the vicinity of Haines City, located in Polk County, Florida. This petition was approved by the Florida PSC at its Agenda Conference on May 5, 2015.

On July 1, 2015, FPU's electric division filed a new depreciation study with the Florida PSC. Depending upon the Florida PSC's decision in this proceeding, we may be required to change depreciation expense for FPU's electric division. The PSC agenda date for review of the depreciation study has not yet been set.

Eastern Shore

White Oak Mainline Expansion Project: On November 21, 2014, Eastern Shore submitted an application to the FERC for a CP seeking authorization to construct, own, operate and maintain certain expansion facilities designed to provide 45,000 Dts/d of firm transportation service to an industrial customer in Kent County, Delaware. Eastern Shore proposes to construct approximately 7.2 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and 3,550 horsepower of additional compression at Eastern Shore’s existing Delaware City Compressor Station in New Castle County, Delaware. The estimated cost of the project is $29.8 million. On January 22, 2015, the FERC issued a Notice of Intent to Prepare an Environmental Assessment for this project. In February, April and May 2015, Eastern Shore filed environmental data in response to comments regarding evaluation of alternative routes for a segment of the pipeline route in the vicinity of the Kemblesville Historic District. On June 2, 2015, a field meeting was conducted to review the proposed route and alternative routes. At the field meeting, the FERC Staff concluded that Eastern Shore should move forward with evaluating an alternative route, using its existing right-of-way and provide pertinent environmental information. FERC will issue a public notice inviting further comments in advance of issuing an Environmental Assessment. Eastern Shore began survey work on this route on June 29, 2015. Eastern Shore anticipates FERC approval of this project in the fourth quarter of 2015, and estimates that construction will start in the first quarter of 2016.

System Reliability Project: On May 22, 2015, Eastern Shore submitted an application to the FERC for a CP seeking authorization to construct, own, operate and maintain approximately 10.1 miles of 16-inch pipeline looping and appurtenant auxiliary facilities in New Castle and Kent Counties, Delaware and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposes to reinforce critical points on its pipeline system. The total project will benefit all of Eastern Shore’s customers by modifying the pipeline system to respond to severe operational conditions experienced during actual winter peak days in 2014 and 2015. The estimated cost of the project is $32.1 million. Since the project is intended solely to improve system reliability, Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project and an order granting the CP by December 2015.

On June 8, 2015, the FERC filed a notice of the CP application, and the comment period ended on June 29, 2015. Eastern Shore anticipates FERC approval of this project in the fourth quarter of 2015 and estimates that construction will start in the first quarter of 2016.

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Environmental Commitments and Contingencies

6 Months Ended

Jun. 30, 2015

Environmental Remediation Obligations [Abstract]

Environmental Commitments and Contingencies

Environmental Commitments and Contingencies

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

We have participated in the investigation, assessment or remediation of, and have exposures at seven former MGP sites. Those sites are located in Salisbury, Maryland, Seaford, Delaware and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the MDE regarding another former MGP site located in Cambridge, Maryland.

As of June 30, 2015, we had approximately $10.1 million in environmental liabilities, representing our estimate of the future costs associated with all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites. FPU has approval to recover, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to all of its MGP sites, approximately $9.9 million of which has been recovered as of June 30, 2015, leaving approximately $4.1 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

In addition to the FPU MGP sites, we had $380,000 in environmental liabilities at June 30, 2015 related to Chesapeake’s MGP sites in Maryland and Florida, representing our estimate of future costs associated with these sites. As of June 30, 2015, we had approximately $145,000 in regulatory and other assets for future recovery through Chesapeake’s rates.

During the first quarter of 2015, we established $273,000 in environmental liabilities related to Chesapeake’s MGP site in Seaford, Delaware, representing our estimate of future costs associated with this site, and recorded a regulatory asset for the same amount for probable future recovery through Chesapeake’s rates, although we have not yet sought Delaware PSC approval for recovery. As of June 30, 2015, we had approximately $245,000 in environmental liabilities and $273,000 in regulatory and other assets related to this site.

Environmental liabilities for all of our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates.

West Palm Beach, Florida

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

Sanford, Florida

FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP at this site. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of June 30, 2015, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements.

In December 2014, the EPA issued a preliminary close-out report, documenting the completion of all physical remediation construction activities at the Sanford site. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site. The total cost of the final remedy is estimated to be over $20.0 million, which includes long-term monitoring and the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation. In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU has advised the other members of the Sanford Group that it is unwilling at this time to agree to pay any sum in excess of the $650,000 committed by FPU in the Third Participation Agreement.

As of June 30, 2015, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be $24,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million to implement the final remedy for this site, as provided in the Third Participation Agreement, or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of June 30, 2015.

Key West, Florida

FPU formerly owned and operated a MGP in Key West, Florida. Field investigations performed in the 1990s identified limited environmental impacts at the site, which is currently owned by an unrelated third party. In 2010, after 17 years of regulatory inactivity, FDEP observed that some soil and groundwater standards were exceeded and requested implementation of additional soil and groundwater fieldwork. The scope of work is limited to the installation of two additional monitoring wells and periodic monitoring of the new and existing wells. The two additional monitoring wells were installed in November 2011, and groundwater monitoring began in December 2011. The first semi-annual report from the monitoring program was issued in May 2012. The data from the June 2012 and September 2012 monitoring events were submitted to the FDEP on October 4, 2012. FDEP responded on October 9, 2012 that, based on the data, NAM appears to be an appropriate remedy for the site.

In October 2012, FDEP issued a RAP approval order, which specified that a limited semi-annual monitoring program be conducted. The most recent groundwater-monitoring event was conducted on March 23, 2015. Natural attenuation default criteria were met at all locations sampled. The next semi-annual sampling event is scheduled for September 2015.

Although the duration of the FDEP-required limited NAM cannot be determined with certainty, we anticipate that total costs to complete the remedial action will not exceed $50,000. The annual cost to conduct the limited NAM program is not expected to exceed $8,000.

Pensacola, Florida

FPU formerly owned and operated a MGP in Pensacola, Florida, which was subsequently owned by Gulf Power. Portions of the site are now owned by the City of Pensacola and the FDOT. In October 2009, FDEP informed Gulf Power that it would approve a conditional No Further Action determination for the site with the requirement for institutional and engineering controls. On June 16, 2014, FDEP issued a draft memorandum of understanding between FDOT and FDEP to implement site closure with approved institutional and engineering controls for the site. We anticipate that FPU’s share of remaining legal and cleanup costs will not exceed $5,000.

Winter Haven, Florida

The Winter Haven site is located on the eastern shoreline of Lake Shipp, in Winter Haven, Florida. Pursuant to a consent order entered into with FDEP, we are obligated to assess and remediate environmental impacts at this former MGP site. Groundwater monitoring results have shown a continuing reduction in contaminant concentrations from the sparging system, which has been in operation since 2002. On September 12, 2014, FDEP issued a letter approving shutdown of the sparging operations on the northern portion of the site, contingent upon continued semi-annual monitoring.

Groundwater monitoring results on the southern portion of this site indicate that natural attenuation default criteria continue to be exceeded. Plans to modify the monitoring network on the southern portion of the site in order to collect additional data to support the development of a remedial plan were specified in a letter to FDEP, dated October 17, 2014. The well installation and abandonment program was implemented in October 2014, and documentation was reported in the semi-annual RAP implementation status report submitted January 8, 2015. Although specific remedial actions have not yet been identified, we estimate that future remediation costs for the subsurface soils and groundwater at the site should not exceed $443,000, which includes an estimate of $100,000 to implement additional actions, such as institutional controls, at the site. We continue to believe that the entire amount will be recoverable from customers through rates.

FDEP previously indicated that we could also be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, and our recent meeting with FDEP, we believe that corrective measures for lake sediments are not warranted and will not be required by FDEP; therefore, we have not recorded a liability for sediment remediation.

Salisbury, Maryland

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

Seaford, Delaware

In a letter dated December 5, 2013, the DNREC notified us that it would be conducting a facility evaluation of a former MGP site in Seaford, Delaware. In a report issued in January 2015, DNREC provided the evaluation, which found several compounds within the groundwater and soil that require further investigation. We submitted an application to DNREC on April 2, 2015 to enter this site into the voluntary cleanup program, and at this time, DNREC is still considering our application. We estimate the cost of potential remedial actions, based on the findings of the DNREC report, to be between $273,000 and $465,000.

Other

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

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Segment Information

6 Months Ended

Jun. 30, 2015

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 two reportable segments:

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

• Unregulated Energy. The Unregulated Energy segment includes propane distribution and wholesale marketing operations, and natural gas marketing operations, which are unregulated as to their rates and services. Effective April 1, 2015, this segment includes Aspire Energy of Ohio, whose services include natural gas gathering and processing (See Note 3, Acquisitions, regarding the acquisition of Gatherco). Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services.

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

The following table presents financial information about our reportable segments:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	61,790		$	61,348		$	171,082		$	163,222
Unregulated Energy segment	30,892			34,299			91,681			114,173
Other businesses	—			4,850			—			9,439
Total operating revenues, unaffiliated customers	$	92,682		$	100,497		$	262,763		$	286,834
Intersegment Revenues (1)
Regulated Energy segment	$	270		$	298		$	560		$	590
Unregulated Energy segment	1,666			22			1,873			121
Other businesses	220			248			440			502
Total intersegment revenues	$	2,156		$	568		$	2,873		$	1,213
Operating Income (Loss)
Regulated Energy segment	$	13,605		$	10,711		$	35,788		$	31,802
Unregulated Energy segment	(540		)	(43		)	14,689			10,815
Other businesses and eliminations	105			(211		)	201			(538		)
Total operating income	13,170			10,457			50,678			42,079
Other income (loss), net of other expenses	(171		)	405			(38		)	413
Interest	2,485			2,303			4,933			4,459
Income before Income Taxes	10,514			8,559			45,707			38,033
Income taxes	4,220			3,425			18,304			15,218
Net Income	$	6,294		$	5,134		$	27,403		$	22,815

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

(in thousands)	June 30, 2015		December 31, 2014
Identifiable Assets
Regulated Energy segment	$	800,719	$	796,021
Unregulated Energy segment	147,102		84,732
Other businesses and eliminations	22,815		23,716
Total identifiable assets	$	970,636	$	904,469

Our operations are entirely domestic.

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Long-Term Debt - Outstanding Long-Term Debt- Supplemental Information (Detail) - Jun. 30, 2015	Total
9.08% bond, due June 1, 2022 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	9.08%
Debt instrument, maturity date	Jun. 01, 2022
6.64% note, due October 31, 2017 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.64%
Debt instrument, maturity date	Oct. 31, 2017
5.50% note, due October 12, 2020 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.50%
Debt instrument, maturity date	Oct. 12, 2020
5.93% note, due October 31, 2023 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.93%
Debt instrument, maturity date	Oct. 31, 2023
5.68% note, due June 30, 2026 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	5.68%
Debt instrument, maturity date	Jun. 30, 2026
Uncollateralized Senior Notes Due On May Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.43%
Debt instrument, maturity date	May 02, 2028
Uncollateralized Senior Note Two Due on December Two Thousand Twenty Eight [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.73%
Debt instrument, maturity date	Dec. 16, 2028
Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.88%
Debt instrument, maturity date	May 15, 2029

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Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands		Jun. 30, 2015	Dec. 31, 2014
Debt Instrument [Line Items]
Total long-term debt		$ 159,900	$ 161,500
Capital Lease Obligations		5,483	6,130
Total Long-term debt		165,374	167,595
Less: current maturities		(9,127)	(9,109)
Total long-term debt, net of current maturities		156,247	158,486
9.08% bond, due June 1, 2022 [Member]
Debt Instrument [Line Items]
Total long-term debt	[1]	7,971	7,969
6.64% note, due October 31, 2017 [Member]
Debt Instrument [Line Items]
Total long-term debt		8,182	8,182
5.50% note, due October 12, 2020 [Member]
Debt Instrument [Line Items]
Total long-term debt		12,000	12,000
5.93% note, due October 31, 2023 [Member]
Debt Instrument [Line Items]
Total long-term debt		25,500	27,000
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
Uncollateralized Senior Notes Due On Two Thousand Twenty Nine [Member]
Debt Instrument [Line Items]
Total long-term debt		50,000	50,000
Promissory note [Member]
Debt Instrument [Line Items]
Total long-term debt		$ 238	$ 314

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

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Long-Term Debt (Tables)

6 Months Ended

Jun. 30, 2015

Debt Disclosure [Abstract]

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below:

	June 30,			December 31,
(in thousands)	2015			2014
FPU secured first mortgage bonds (1) :
9.08% bond, due June 1, 2022	$	7,971		$	7,969
Uncollateralized senior notes:
6.64% note, due October 31, 2017	8,182			8,182
5.50% note, due October 12, 2020	12,000			12,000
5.93% note, due October 31, 2023	25,500			27,000
5.68% note, due June 30, 2026	29,000			29,000
6.43% note, due May 2, 2028	7,000			7,000
3.73% note, due December 16, 2028	20,000			20,000
3.88% note, due May 15, 2029	50,000			50,000
Promissory notes	238			314
Capital lease obligation	5,483			6,130
Total long-term debt	165,374			167,595
Less: current maturities	(9,127		)	(9,109		)
Total long-term debt, net of current maturities	$	156,247		$	158,486

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

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Investments - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014
Investments, Debt and Equity Securities [Abstract]
Unrealized gain, net of other expenses	$ 4	$ 114	$ 107	$ 152

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Derivative Instruments

6 Months Ended

Jun. 30, 2015

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 typically either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis. Our propane distribution operation may also enter into fair value hedges of its inventory or cash flow hedges of its future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of June 30, 2015, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Hedging Activities in 2015

In March, May and June 2015, Sharp paid $143,000 to purchase put options to protect against a decline in propane prices and related potential inventory losses associated with 2.5 million gallons for the propane price cap program in the upcoming heating season. The put options are exercised if propane prices fall below the strike prices of $0.4950, $0.4888 and $0.4500 per gallon in December 2015 through February 2016 and $0.4200 per gallon in January through March 2016. If exercised, we will receive the difference between the market price and the strike price during those months. We accounted for the put options as fair value hedges, and there is no ineffective portion of these hedges. As of June 30, 2015, the put options had a fair value of $110,000. The change in fair value of the put options effectively reduced our propane inventory balance.

In March, May and June 2015, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 2.5 million gallons expected to be purchased for the upcoming heating season. Under these swap agreements, Sharp receives the difference between the index prices (Mont Belvieu prices in December 2015 through March 2016) and the swap prices of $0.5950, $0.5888, $0.5500 and $0.5200 per gallon for each swap agreement, to the extent the index prices exceed the swap prices. If the index prices are lower than the swap prices, Sharp will pay the difference. These swap agreements essentially fix the price of the 2.5 million gallons that we expect to purchase for the upcoming heating season. We accounted for the swap agreements as cash flow hedges, and there is no ineffective portion of these hedges. At June 30, 2015, two swap agreements had a liability fair value of $38,000 and two swap agreements had an asset fair value of $36,000. The change in the fair value of the swap agreements is recorded as unrealized gain/loss in other comprehensive income (loss).

Hedging Activities in 2014

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

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

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

Commodity Contracts for Trading Activities

Xeron engages in trading activities using forward and futures contracts. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under this method, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statement of income for the period of change. As of June 30, 2015, we had the following outstanding trading contracts, which we accounted for as derivatives:

	Quantity in	Estimated Market	Weighted Average
At June 30, 2015	Gallons	Prices	Contract Prices
Forward Contracts
Sale	4,620,000	$0.3475 - $0.5288	$	0.4760
Purchase	4,620,000	$0.3550 - $0.5025	$	0.4322

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

Xeron has entered into master netting agreements with two counterparties to mitigate exposure to counterparty credit risk. The master netting agreements enable Xeron to net these two counterparties' outstanding accounts receivable and payable, which are presented on a gross basis in the accompanying condensed consolidated balance sheets. At June 30, 2015, Xeron had a right to offset $654,000 and $222,000 of accounts receivable and accounts payable, respectively, with these two counterparties. At December 31, 2014, Xeron had a right to offset $1.6 million and $1.2 million of accounts receivable and accounts payable, respectively, with these two counterparties.

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of June 30, 2015 and December 31, 2014, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2015		December 31, 2014
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	212	$	407
Derivatives designated as fair value hedges
Put options	Mark-to-market energy assets	110		622
Derivatives designated as cash flow hedges
Call options	Mark-to-market energy assets	—		26
Propane swap agreements	Mark-to-market energy assets	36		—
Total asset derivatives		$	358	$	1,055

	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2015		December 31, 2014
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	9	$	283
Propane swap agreements	Mark-to-market energy liabilities	—		735
Derivatives designated as cash flow hedges
Propane swap agreements	Mark-to-market energy liabilities	38		—
Total liability derivatives		$	47	$	1,018

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

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(in thousands)	(Loss) on Derivatives	2015			2014			2015			2014
Derivatives not designated as hedging instruments
Realized gain (loss) on forward contracts (1)	Revenue	$	(71	)	$	84		$	206		$	1,330
Unrealized gain (loss) on forward contracts	Revenue	203			6			78			(62		)
Call option	Cost of sales	—			—			—			137
Propane swap agreements	Cost of sales	—			—			18			—
Derivatives designated as fair value hedges
Put options	Cost of sales	—			(29		)	506			(49		)
Put options (2)	Propane Inventory	(30		)	—			(34		)	—
Derivatives designated as cash flow hedges
Propane swap agreements	Other Comprehensive loss	10			(2		)	(2		)	(2		)
Call options	Cost of sales	—			—			(81		)	—
Total		$	112		$	59		$	691		$	1,354

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

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

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Acquisitions Acquisitions (Tables)

6 Months Ended

Jun. 30, 2015

Business Combinations [Abstract]

Merger Consideration paid [Table Text Block]

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

Purchase price allocation [Table Text Block]

(in thousands)
Purchase price	$	57,658
Property plant and equipment	52,578
Cash	6,806
Accounts receivable	3,629
Income taxes receivable	3,012
Other assets	247
Total assets acquired	66,272
Long-term debt	1,696
Deferred income taxes	13,863
Accounts payable	3,837
Other current liabilities	314
Total liabilities assumed	19,710
Net identifiable assets acquired	46,562
Goodwill	$	11,096

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Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		6 Months Ended
	Jun. 30, 2015	Jun. 30, 2014	Jun. 30, 2015	Jun. 30, 2014	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Document Period End Date			Jun. 30, 2015
Expected pension and postretirement benefit costs			$ 1,200
Expected amortization of pre merger regulatory asset			769
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	$ 17	$ 16	33	$ 33
Contribution to pension plan	24		116
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year			207
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	9	10	18	20
Contribution to pension plan	13		28
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year			79
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	50	40	101	79
Contribution to pension plan	38		71
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year			151
Consolidated [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost			(381)
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	58	12	115	23
Contribution to pension plan	115		219
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year			475
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Unamortized balance of regulatory asset	3,200		3,200		$ 3,600
Defined Benefit Plan, Net Periodic Benefit Cost	(37)	$ (125)	(76)	$ (251)
Contribution to pension plan	$ 381		723
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year			$ 1,600

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Rates and Other Regulatory Activities - Additional Information (Detail) - Eastern Shore [Member] $ in Millions	6 Months Ended	12 Months Ended
	Jun. 30, 2015 USD ($) dekatherm / d in mi	Dec. 31, 2014 USD ($)
White Oak Lateral Mainline Expansion [Member]
Rates and Other Regulatory Activities [Line Items]
Volume The Expansion Project Is Expected to Provide | dekatherm / d	45,000
Number of Pipeline Miles | mi	7.2
Lateral diamater of pipeline to be installed | in	16
Horsepower Of Additional Compression	3,550
Estimated capital cost	$ 29.8
System Reliability Project [Member]
Rates and Other Regulatory Activities [Line Items]
Number of Pipeline Miles | mi	10.1
Lateral diamater of pipeline to be installed | in	16
Estimated capital cost		$ 32.1

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Condensed Consolidated Balance Sheets - Entity [Domain] - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Property, Plant and Equipment
Regulated energy	$ 795,331	$ 766,855
Unregulated energy	139,174	84,773
Other	19,051	18,497
Total property, plant and equipment	953,556	870,125
Less: Accumulated depreciation and amortization	(205,030)	(193,369)
Plus: Construction work in progress	41,923	13,006
Net property, plant and equipment	790,449	689,762
Current Assets
Cash and cash equivalents	2,104	4,574
Accounts receivable (less allowance for uncollectible accounts of $1,146 and $1,120, respectively)	42,270	53,300
Accrued revenue	8,091	13,617
Propane inventory, at average cost	4,151	7,250
Other inventory, at average cost	4,305	3,699
Regulatory assets	7,587	8,967
Storage gas prepayments	2,498	4,258
Income taxes receivable	2,518	18,806
Deferred income taxes	128	0
Prepaid expenses	4,223	6,652
Mark-to-market energy assets	358	1,055
Other current assets	285	195
Total current assets	78,518	122,373
Deferred Charges and Other Assets
Goodwill	16,048	4,952
Other intangible assets, net	2,415	2,404
Investments, at fair value	3,665	3,678
Regulatory assets	77,657	78,136
Receivables and other deferred charges	1,884	3,164
Total deferred charges and other assets	101,669	92,334
Total Assets	970,636	904,469
Stockholders' equity
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)	7,419	7,100
Additional paid-in capital	187,903	156,581
Retained earnings	161,333	142,317
Accumulated other comprehensive loss	(5,479)	(5,676)
Deferred compensation obligation	1,843	1,258
Treasury stock	(1,843)	(1,258)
Total stockholders' equity	351,176	300,322
Long-term debt, net of current maturities	156,247	158,486
Total capitalization	507,423	458,808
Current Liabilities
Current portion of long-term debt	9,127	9,109
Short-term borrowing	94,713	88,231
Accounts payable	38,173	44,610
Customer deposits and refunds	21,449	25,197
Accrued interest	1,256	1,352
Dividends payable	4,382	3,939
Deferred Tax Liabilities, Net, Current	0	832
Accrued compensation	6,500	10,076
Regulatory liabilities	15,205	3,268
Mark-to-market energy liabilities	47	1,018
Other accrued liabilities	8,756	6,603
Total current liabilities	199,608	194,235
Deferred Credits and Other Liabilities
Deferred income taxes	173,821	160,232
Regulatory liabilities	43,307	43,419
Environmental liabilities	9,043	8,923
Other pension and benefit costs	33,614	35,027
Deferred investment credits and Other liabilities	3,820	3,825
Total deferred credits and other liabilities	$ 263,605	$ 251,426
Other commitments and contingencies (Note 6)
Total Capitalization and Liabilities	$ 970,636	$ 904,469

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Summary of Accounting Policies

6 Months Ended

Jun. 30, 2015

Accounting Policies [Abstract]

Summary of Accounting Policies

Summary of Accounting Policies

Basis of Presentation

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2014. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

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

Reclassifications

As a result of the sale of our advanced information services subsidiary in October 2014, we changed our operating segments (see Note 7, Segment Information). We reclassified certain amounts in the condensed consolidated income statement for the three and six months ended June 30, 2014 and condensed consolidated cash flows statement for the six months ended June 30, 2014 to conform to the current year's presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

Stock Dividend

On July 2, 2014, our Board of Directors approved a three-for-two stock split of our outstanding common stock to be effected in the form of a stock dividend. Each stockholder as of the close of business on the record date, August 13, 2014, received one additional share of common stock for every two shares of common stock owned. The additional shares were distributed on September 8, 2014. All share and per share data in this Form 10-Q are presented on a post-split basis. As a result of the stock split, we reclassified approximately $2.4 million from retained earnings to common stock in September of 2014, which represents $0.4867 par value per share of the shares issued in the stock split.

Gain Contingency

Effective May 29, 2015, we entered into a settlement agreement with a vendor related to the implementation of a customer billing system. Pursuant to the agreement we received $1.5 million in cash, which is reflected as "Gain from a settlement" in the accompanying condensed consolidated statements of income. Previously at December 31, 2014, we recorded a $6.5 million pretax, non-cash impairment loss related to the same billing system implementation. We may also receive $750,000 in additional cash and discounts on future services, however, the receipt or retention of additional cash and future discounts is contingent upon engaging this vendor to provide agreed-upon services over the next five years.

FASB Statements and Other Authoritative Pronouncements

Recent Accounting Standards Yet to be Adopted

Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. On July 9, 2015, the FASB affirmed its proposal to defer the implementation of this standard by one year. For public entities, this standard is effective for 2018 interim and annual financial statements. We are assessing the impact this standard will have on our financial position and results of operations.

Interest - Imputation of Interest (ASC 835-30) - In April 2015, the FASB issued ASU 2015-03, Simplifying the Presentation of Debt Issuance Costs. This standard requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. ASU 2015-03 is effective for our interim and annual financial statements issued beginning January 1, 2016. Early adoption is permitted for financial statements that have not been previously issued. As of June 30, 2015, we had $322,000 of unamortized debt issuance costs included in the accompanying condensed consolidated balance sheets. Upon adoption of ASU 2015-03, this will be presented as a deduction from long-term debt, net of current maturities.

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Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands	Jun. 30, 2015	Dec. 31, 2014
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 47	$ 1,018
Energy Marketing Contracts Assets, Current	358	1,055
Mark To Market Energy Assets [Member] | Forward Contracts [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	212	407
Mark To Market Energy Assets [Member] | Call options [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	0	26
Mark To Market Energy Assets [Member] | Put Option [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	110	622
Mark To Market Energy Assets [Member] | Swap [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	36
Mark-to-market energy liabilities [Member] | Forward Contracts [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	9	283
Mark-to-market energy liabilities [Member] | Propane Swap Agreement [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 38	$ 735

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Segment Information (Tables)

6 Months Ended

Jun. 30, 2015

Segment Reporting [Abstract]

Schedule of Segment Reporting Information by Segment

The following table presents financial information about our reportable segments:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	61,790		$	61,348		$	171,082		$	163,222
Unregulated Energy segment	30,892			34,299			91,681			114,173
Other businesses	—			4,850			—			9,439
Total operating revenues, unaffiliated customers	$	92,682		$	100,497		$	262,763		$	286,834
Intersegment Revenues (1)
Regulated Energy segment	$	270		$	298		$	560		$	590
Unregulated Energy segment	1,666			22			1,873			121
Other businesses	220			248			440			502
Total intersegment revenues	$	2,156		$	568		$	2,873		$	1,213
Operating Income (Loss)
Regulated Energy segment	$	13,605		$	10,711		$	35,788		$	31,802
Unregulated Energy segment	(540		)	(43		)	14,689			10,815
Other businesses and eliminations	105			(211		)	201			(538		)
Total operating income	13,170			10,457			50,678			42,079
Other income (loss), net of other expenses	(171		)	405			(38		)	413
Interest	2,485			2,303			4,933			4,459
Income before Income Taxes	10,514			8,559			45,707			38,033
Income taxes	4,220			3,425			18,304			15,218
Net Income	$	6,294		$	5,134		$	27,403		$	22,815

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

(in thousands)	June 30, 2015		December 31, 2014
Identifiable Assets
Regulated Energy segment	$	800,719	$	796,021
Unregulated Energy segment	147,102		84,732
Other businesses and eliminations	22,815		23,716
Total identifiable assets	$	970,636	$	904,469

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Acquisitions - Additional Information (Detail) $ in Thousands			3 Months Ended		6 Months Ended		12 Months Ended
	May. 07, 2015 USD ($)	Apr. 01, 2015 USD ($) mi	Jun. 30, 2015 USD ($)	Jun. 30, 2014 USD ($)	Jun. 30, 2015 USD ($) shares	Jun. 30, 2014 USD ($)	Dec. 31, 2014 USD ($)
Business Acquisition [Line Items]
Business Combination, Separately Recognized Transactions, Additional Disclosures, Acquisition Cost Expensed					$ (514)
Revenues			$ 92,682	$ 100,497	262,763	$ 286,834
Net Income (Loss) Attributable to Parent			6,294	$ 5,134	$ 27,403	$ 22,815	$ 36,092
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life					10 years
Gatherco [Member]
Business Acquisition [Line Items]
Number Of Gathering Stations		16
Number of Pipeline Miles | mi		2,000
Number of Producers Served		300
Number of Customers Served		6,000
Business Combination, Consideration Transferred					$ 57,658
Business Acquisition, Equity Interest Issued or Issuable, Number of Shares | shares					592,970
Business Acquisition, Equity Interest Issued or Issuable, Value Assigned		$ 30,200	30,164		$ 30,164
Payments to Acquire Businesses, Gross		27,500			27,494
Long-term debt		1,696	1,696		1,696
Business Combination, Recognized Identifiable Assets Acquired and Liabilities Assumed, Cash and Equivalents		$ 6,800	6,806		6,806
Business Combination Contingent Cash Consideration Payable			15,000		$ 15,000
Period Additional Contingent Cash Consideration Will Be Based On					5 years
Business Combination, Separately Recognized Transactions, Additional Disclosures, Acquisition Cost Expensed					$ (1,300)
Revenues			5,200
Net Income (Loss) Attributable to Parent			$ (187)
Propane Distribution [Member]
Business Acquisition [Line Items]
Number of Customers Served	253
Business Combination, Consideration Transferred	$ 242
Finite-lived Intangible Assets Acquired	$ 186
Acquired Finite-lived Intangible Assets, Weighted Average Useful Life					6 years

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Share-Based Compensation

6 Months Ended

Jun. 30, 2015

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

Share-Based Compensation

Share-Based Compensation

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

The table below presents the amounts included in net income related to share-based compensation expense for the three and six months endedJune 30, 2015 and 2014:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2015			2014			2015			2014
(in thousands)
Awards to non-employee directors	$	160		$	132		$	311		$	256
Awards to key employees	250			295			636			809
Total compensation expense	410			427			947			1,065
Less: tax benefit	(165		)	(172		)	(381		)	(429		)
Share-based compensation amounts included in net income	$	245		$	255		$	566		$	636

Non-employee Directors

Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the date of the grant. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2015, each of our non-employee directors received an annual retainer of 1,207 shares of common stock under the SICP for Board service through the 2016 Annual Meeting of Stockholders. A summary of the stock activity for our non-employee directors during the six months ended June 30, 2015 is presented below:

	Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2014	—		$	—
Granted	14,484		$	45.54
Vested	(14,484	)	$	45.54
Outstanding— June 30, 2015	—		$	—

At June 30, 2015, there was $550,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2016.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the six months ended June 30, 2015:

	Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2014	123,038		$	32.60
Granted	29,763		$	48.21
Vested	(43,839	)	$	28.01
Expired	(2,520	)	$	28.83
Outstanding— June 30, 2015	106,442		$	37.97

In January 2015, our Board of Directors granted awards of 29,763 shares of common stock to key employees under the SICP. The shares granted in January 2015 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2017. All of these stock awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprise both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the date each award is granted. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

At June 30, 2015, the aggregate intrinsic value of the SICP awards granted to key employees was $5.7 million. At June 30, 2015, there was $1.9 million of unrecognized compensation cost related to these awards, which is expected to be recognized during 2015 through 2017.