10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-Q

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

For the quarterly period ended: March 31, 2016

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	x	Accelerated filer	¨
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 — 15,308,467 shares outstanding as of April 30, 2016.

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	27
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	44
ITEM 4.	CONTROLS AND PROCEDURES	46
PART II—OTHER INFORMATION		47
ITEM 1.	LEGAL PROCEEDINGS	47
ITEM 1A.	RISK FACTORS	47
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	47
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	47
ITEM 5.	OTHER INFORMATION	47
ITEM 6.	EXHIBITS	48
SIGNATURES		49

GLOSSARY OF DEFINITIONS

ASC: Accounting Standards Codification

ASU: Accounting Standards Update

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

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 or Chesapeake Utilities: 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 Utilities

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

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

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

Credit Agreement: An agreement between Chesapeake Utilities and the lenders related to the Revolver

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 Utilities

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

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 United States 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 Utilities

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

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

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

Gatherco: Gatherco, Inc.

GRIP: The Gas Reliability Infrastructure Program is a natural gas pipeline replacement program in Florida, pursuant to which we collect a surcharge from certain of our Florida customers to recover capital and other program-related costs associated with 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

JEA: The community-owned utility located in Jacksonville, Florida, formerly known as Jacksonville Electric Authority

Lenders: PNC, Bank of America N.A., Citizens Bank N.A., Royal Bank of Canada, and Wells Fargo Bank, National Association, which are collectively the lenders that entered into the Credit Agreement with Chesapeake Utilities on October 8, 2015

MDE: Maryland Department of Environment

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

NAM: Natural Attenuation Monitoring

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

Notes: Series A and B Unsecured Senior Notes that were entered into with the Note Holders

NYSE: New York Stock Exchange

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 not to schedule service for up to 90 days during the peak months of November through April

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

PNC: PNC Bank, National Association, the administrative agent and primary lender for our Revolver

Prudential: Prudential Investment Management Inc., an institutional investment management firm, with which we have entered into the Shelf Agreement for the future purchase of our Shelf Notes

PSC: Public Service Commission, which is the state agency that regulates the rates and services provided by Chesapeake Utilities’ 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 Utilities or FPU

Revolver: The unsecured revolving credit facility issued to us by the Lenders

Sandpiper: Sandpiper Energy, Inc., a wholly-owned subsidiary of Chesapeake Utilities providing a tariff-based distribution service to customers in Worcester County, Maryland

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

Shelf Agreement: An agreement entered into by Chesapeake Utilities and Prudential pursuant to which Chesapeake Utilities may request that Prudential purchase, over the next three years, up to $150.0 million of Shelf Notes at a fixed interest rate and with a maturity date not to exceed twenty years from the date of issuance

Shelf Notes: Unsecured senior promissory notes that we may request Prudential to purchase under the Shelf Agreement

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
	March 31,
	2016			2015
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	89,216		$	109,582
Unregulated Energy	57,080			60,499
Total Operating Revenues	146,296			170,081
Operating Expenses
Regulated Energy cost of sales	34,905			57,129
Unregulated Energy and other cost of sales	34,024			35,234
Operations	27,159			26,945
Maintenance	2,479			2,703
Depreciation and amortization	7,503			6,975
Other taxes	3,846			3,587
Total Operating Expenses	109,916			132,573
Operating Income	36,380			37,508
Other (Expense) Income, net	(34		)	133
Interest charges	2,650			2,448
Income Before Income Taxes	33,696			35,193
Income taxes	13,329			14,084
Net Income	$	20,367		$	21,109
Weighted Average Common Shares Outstanding:
Basic	15,286,842			14,604,841
Diluted	15,331,912			14,656,310
Earnings Per Share of Common Stock:
Basic	$	1.33		$	1.45
Diluted	$	1.33		$	1.44
Cash Dividends Declared Per Share of Common Stock	$	0.2875		$	0.2700

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

- 1

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended
	March 31,
	2016			2015
(in thousands)
Net Income	$	20,367		$	21,109
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(8) and $(7), respectively	(12		)	(10		)
Net gain, net of tax of $67 and $62, respectively	101			92
Cash Flow Hedges, net of tax:
Unrealized loss on commodity contract cash flow hedges, net of tax of $- and $17, respectively	—			26
Total Other Comprehensive Income	89			108
Comprehensive Income	$	20,456		$	21,217

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

- 2

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Assets	March 31, 2016			December 31, 2015
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	850,041		$	842,756
Unregulated Energy	147,221			145,734
Other businesses and eliminations	19,430			18,999
Total property, plant and equipment	1,016,692			1,007,489
Less: Accumulated depreciation and amortization	(222,650		)	(215,313		)
Plus: Construction work in progress	87,187			62,774
Net property, plant and equipment	881,229			854,950
Current Assets
Cash and cash equivalents	3,315			2,855
Accounts receivable (less allowance for uncollectible accounts of $684 and $909, respectively)	44,434			41,007
Accrued revenue	12,331			12,452
Propane inventory, at average cost	5,412			6,619
Other inventory, at average cost	4,289			3,803
Regulatory assets	6,451			8,268
Storage gas prepayments	1,213			3,410
Income taxes receivable	16,260			24,950
Prepaid expenses	4,982			7,146
Mark-to-market energy assets	—			153
Other current assets	1,688			1,044
Total current assets	100,375			111,707
Deferred Charges and Other Assets
Goodwill	15,070			14,548
Other intangible assets, net	2,128			2,222
Investments, at fair value	3,674			3,644
Regulatory assets	76,934			77,519
Receivables and other deferred charges	2,574			2,831
Total deferred charges and other assets	100,380			100,764
Total Assets	$	1,081,984		$	1,067,421

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

- 3

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Capitalization and Liabilities	March 31, 2016			December 31, 2015
(in thousands, except shares and per share data)
Capitalization
Stockholders’ equity
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)	$	7,449		$	7,432
Additional paid-in capital	190,389			190,311
Retained earnings	182,165			166,235
Accumulated other comprehensive loss	(5,751		)	(5,840		)
Deferred compensation obligation	2,221			1,883
Treasury stock	(2,221		)	(1,883		)
Total stockholders’ equity	374,252			358,138
Long-term debt, net of current maturities	148,602			149,006
Total capitalization	522,854			507,144
Current Liabilities
Current portion of long-term debt	9,163			9,151
Short-term borrowing	172,742			173,397
Accounts payable	36,299			39,300
Customer deposits and refunds	27,039			27,173
Accrued interest	3,021			1,311
Dividends payable	4,400			4,390
Accrued compensation	4,107			10,014
Regulatory liabilities	9,313			7,365
Mark-to-market energy liabilities	423			433
Other accrued liabilities	7,942			7,059
Total current liabilities	274,449			279,593
Deferred Credits and Other Liabilities
Deferred income taxes	197,416			192,600
Regulatory liabilities	42,946			43,064
Environmental liabilities	8,843			8,942
Other pension and benefit costs	32,848			33,481
Deferred investment tax credits and other liabilities	2,628			2,597
Total deferred credits and other liabilities	284,681			280,684
Other commitments and contingencies (Note 6)
Total Capitalization and Liabilities	$	1,081,984		$	1,067,421

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

- 4

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended
	March 31,
	2016			2015
(in thousands)
Operating Activities
Net income	$	20,367		$	21,109
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	7,503			6,975
Depreciation and accretion included in other costs	1,646			1,689
Deferred income taxes, net	4,326			(496		)
Realized (gain) loss on commodity contracts/sale of assets/investments	479			(840		)
Unrealized loss on investments/commodity contracts	18			21
Employee benefits and compensation	380			300
Share-based compensation	649			537
Other, net	24			4
Changes in assets and liabilities:
Accounts receivable and accrued revenue	(3,738		)	(8,014		)
Propane inventory, storage gas and other inventory	3,073			5,337
Regulatory assets/liabilities, net	3,941			16,507
Prepaid expenses and other current assets	1,358			2,500
Accounts payable and other accrued liabilities	(1,604		)	350
Income taxes receivable	8,841			21,753
Customer deposits and refunds	(134		)	(2,890		)
Accrued compensation	(5,943		)	(5,262		)
Other assets and liabilities, net	1,242			2,753
Net cash provided by operating activities	42,428			62,333
Investing Activities
Property, plant and equipment expenditures	(36,847		)	(25,482		)
Proceeds from sales of assets	51			198
Environmental expenditures	(99		)	(49		)
Net cash used in investing activities	(36,895		)	(25,333		)
Financing Activities
Common stock dividends	(4,204		)	(3,763		)
Issuance of stock for Dividend Reinvestment Plan	195			217
Change in cash overdrafts due to outstanding checks	(1,501		)	(2,191		)
Net borrowing (repayment) under line of credit agreements	839			(19,269		)
Repayment of long-term debt and capital lease obligation	(402		)	(398		)
Net cash used in financing activities	(5,073		)	(25,404		)
Net Increase in Cash and Cash Equivalents	460			11,596
Cash and Cash Equivalents—Beginning of Period	2,855			4,574
Cash and Cash Equivalents—End of Period	$	3,315		$	16,170

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

- 5

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, 2014	14,588,711	$	7,100	$	156,581		$	142,317		$	(5,676	)	$	1,258	$	(1,258	)	$	300,322
Net income		—		—			41,140			—			—		—			41,140
Other comprehensive loss	—	—		—			—			(164		)	—		—			(164		)
Dividend declared ($1.1325 per share)	—	—		—			(17,222		)	—			—		—			(17,222		)
Retirement savings plan and dividend reinvestment plan	43,275	21		2,214			—			—			—		—			2,235
Common stock issued in acquisition	592,970	289		29,876														30,165
Share-based compensation and tax benefit (2) (3)	45,703	22		1,640			—			—			—		—			1,662
Treasury stock activities	—	—		—			—			—			625		(625		)	—
Balance at December 31, 2015	15,270,659	7,432		190,311			166,235			(5,840		)	1,883		(1,883		)	358,138
Net income	—	—		—			20,367			—			—		—			20,367
Other comprehensive income	—	—		—			—			89			—		—			89
Dividend declared ($0.2875 per share) and dividend reinvestment plan	6,787	3		377			(4,437		)	—			—		—			(4,057		)
Share-based compensation and tax benefit (3)	27,522	14		(299		)	—			—			—		—			(285		)
Treasury stock activities	—	—		—			—			—			338		(338		)	—
Balance at March 31, 2016	15,304,968	$	7,449	$	190,389		$	182,165		$	(5,751	)	$	2,221	$	(2,221	)	$	374,252

⁽¹⁾  Includes 75,959 and 70,631 shares at March 31, 2016 and December 31, 2015, 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 three months ended March 31, 2016, and for the year ended December 31, 2015, we withheld 12,031 and 12,620 shares, respectively, for taxes.

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

- 6

NOTESTO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1.    Summary of Accounting Policies

Basis of Presentation

References in this document to the “Company,” “Chesapeake Utilities,” “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, 2015. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

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

We reclassified certain amounts in the condensed consolidated balance sheet as of December 31, 2015 and condensed consolidated statement of cash flows for the three months ended March 31, 2015 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our consolidated financial statements.

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

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 became effective for us on January 1, 2016, and we applied the provisions of this standard on a retrospective basis. As a result of the adoption of this standard, debt issuance costs totaling $323,000 and $333,000 at March 31, 2016 and December 31, 2015, respectively, previously presented as other deferred charges, a non-current asset, are now presented as a deduction from long-term debt, net of current maturities in our condensed consolidated balance sheets.

Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (ASC 350-40) - In April 2015, the FASB issued ASU 2015-05, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement. Under the new standard, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense in the period incurred. ASU 2015-05 became effective for us on January 1, 2016, and has been applied on a prospective basis. The standard did not have a material impact on our financial position or results of operations for the quarter.

Debt Issuance Costs (ASC 835-30) - In August 2015, the FASB issued ASU 2015-15, Simplifying the Presentation of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This standard clarifies treatment of debt issuance costs associated with line-of-credit arrangements that were not specifically addressed in ASU 2015-03. Issuance costs incurred in connection with line-of-credit arrangements may be treated as an asset and amortized over the term of the line-of-credit arrangement. ASU 2015-15 became effective for us on January 1, 2016. The standard did not have a material impact on our financial position and results of operations.

Business Combinations (ASC 805) - In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. The standard eliminates the requirement to restate prior period financial statements for measurement period adjustments. The guidance requires that the cumulative impact of a measurement-period adjustment (including the impact of prior periods) be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 was effective for our interim and annual financial statements issued after January 1, 2016 and was adopted on a prospective basis. Adoption of this standard did not have a material impact on our financial position and results of operations.

Balance Sheet Classification of Deferred Taxes (ASC 740) - In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which requires all deferred assets and liabilities along with any related valuation allowance to be classified as noncurrent on the balance sheet for our annual financial statements beginning January 1,

- 7

2017 and for our interim financial statements beginning January 1, 2018; however, early adoption is permitted. We adopted this standard in the first quarter of 2016 on a retrospective basis and adjusted the December 31, 2015 balance sheet, by eliminating the current deferred income taxes asset and decreasing noncurrent deferred income taxes liability by $831,000.

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 may have on our financial position and results of operations.

Inventory (ASC 330) - In July 2015, the FASB issued ASU 2015-11, Inventory. Under this guidance, inventories are required to be measured at the lower of cost or net realizable value. Net realizable value represents the estimated selling price less costs associated with completion, disposal and transportation. ASU 2015-11 will be effective for our interim and annual financial statements issued beginning January 1, 2017; however, early adoption is permitted. The standard is to be adopted on a prospective basis. We are assessing the impact this standard may have on our financial position and results of operations.

Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which provides updated guidance regarding accounting for leases. This update requires a lessee to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are evaluating the effect of this update on our financial position and results of operations.

Compensation (ASC 718) - In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which simplifies several aspects of accounting for employee share-based payment transactions, including accounting for income taxes, forfeitures, and statutory tax withholding requirements, and classification in the statement of cash flows. ASU 2016-09 will be effective for our annual and interim financial statements beginning January 1, 2017, although early adoption is permitted. The amendments included in this update are to be applied prospectively except for changes impacting the presentation of the cash flow statement that can be applied prospectively or retrospectively. We are evaluating the effect of this update on our financial position and results of operations.

- 8

2. Calculation of Earnings Per Share

	Three Months Ended
	March 31,
	2016		2015
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	20,367	$	21,109
Weighted average shares outstanding	15,286,842		14,604,841
Basic Earnings Per Share	$	1.33	$	1.45
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	20,367	$	21,109
Reconciliation of Denominator:
Weighted shares outstanding—Basic	15,286,842		14,604,841
Effect of dilutive securities:
Share-based compensation	45,070		51,469
Adjusted denominator—Diluted	15,331,912		14,656,310
Diluted Earnings Per Share	$	1.33	$	1.44

3. Acquisitions

Gatherco Acquisition

On April 1, 2015, we completed the merger with Gatherco, in which Gatherco merged with and into Aspire Energy, our then newly formed, wholly-owned subsidiary. Aspire Energy is an unregulated natural gas infrastructure company with approximately 2,500 miles of pipeline systems in 40 counties throughout Ohio.  The majority of Aspire Energy’s margin is derived from long-term supply agreements with Columbia Gas of Ohio and Consumers Gas Cooperative which together serve more than 20,000 end-use customers.  Aspire Energy sources gas primarily from 300 conventional producers. Aspire Energy also provides gathering and processing services necessary to maintain quality and reliability to its wholesale markets.

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. In addition, we paid $27.5 million in cash and assumed $1.7 million of existing outstanding debt, which we paid off on the same date. We also acquired $6.8 million of cash on hand at closing.

(in thousands)	Net Purchase Price
Chesapeake Utilities 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 provided for additional contingent cash consideration to Gatherco's shareholders of up to $15.0 million based on a percentage of revenue generated from potential new gathering opportunities over five years.

We incurred $1.3 million in transaction costs associated with this merger, $514,000 of which was expensed during 2015. Transaction costs were included in operations expense in the accompanying condensed consolidated statements of income. The revenue and net income from this acquisition for the three months ended March 31, 2016, included in our condensed consolidated statements of income, were $7.9 million and $1.7 million, respectively. This acquisition was accretive to earnings per share in the first full year of operations, generating $0.03 in additional earnings per share.

- 9

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

	Purchase price
(in thousands)	Allocation
Purchase price	$	57,658
Property plant and equipment	53,203
Cash	6,806
Accounts receivable	3,629
Income taxes receivable	3,163
Other assets	425
Total assets acquired	67,226
Long-term debt	1,696
Deferred income taxes	13,409
Accounts payable	3,837
Other current liabilities	745
Total liabilities assumed	19,687
Net identifiable assets acquired	47,539
Goodwill	$	10,119

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.

In December 2015 and during the first quarter of 2016, we adjusted the allocation of the purchase price based on additional information available. The adjustments resulted in a change in the fair value of property, plant and equipment, deferred income tax liabilities, inventory, income taxes receivable and other current liabilities. Goodwill from the merger decreased from $11.1 million to $10.1 million after incorporating these adjustments. The allocation of the purchase price and valuation of assets are final. The valuation of additional contingent cash consideration may be adjusted as additional information becomes available.

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 statements of income for the three months ended March 31, 2016 were not material.

4. Rates and Other Regulatory Activities

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake Utilities' 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

Rate Case Filing: On December 21, 2015, our Delaware division filed an application with the Delaware PSC for a base rate increase and certain other changes to its tariff. We proposed an increase of $4.7 million, or nearly ten percent, in our revenue requirement based on the test period ending March 31, 2016. We also proposed new service offerings to promote growth and a revenue decoupling mechanism for residential and small commercial customers. A decision on the application is expected during the fourth quarter of 2016. Pending the decision, the Delaware division increased rates on an interim

- 10

basis by $2.5 million effective February 19, 2016. These rates, which are subject to refund, represent a five percent increase over current rates.

Maryland

Sandpiper Rate Case Filing: On December 1, 2015, Sandpiper filed an application with the Maryland PSC for a base rate increase and certain other changes to its tariff. We proposed an increase of $950,000, or five percent, in our revenue requirement, based on the test period ended December 31, 2015. We also proposed a stratification of rate classes, based on cost of service, and a revenue-decoupling mechanism for residential and small commercial customers. A decision on the application is expected during the third quarter of 2016.

Florida

On September 1, 2015, FPU’s electric division filed to recover the cost of the proposed Florida Power & Light Company interconnect project through FPU's annual Fuel and Purchased Power Cost Recovery Clause filing. The interconnect project will enable FPU's electric division to negotiate a new power purchase agreement that will mitigate fuel costs for its Northeast division. This action was approved by the Florida PSC at its Agenda Conference held on December 3, 2015. On January 22, 2016, the Office of Public Counsel filed an appeal of the Florida PSC's decision with the Florida Supreme Court. Legal briefs have been filed, but no decision has been reached at this time.

On February 2, 2016, FPU’s natural gas division filed a petition with the Florida PSC for approval of an amendment to its existing transportation agreement with the City of Lake Worth, located in Palm Beach County, Florida. The amendment allows the city to resell natural gas distributed by FPU to the city’s compressed natural gas station. The city will then resell the natural gas, after compression, to its customers. The amendment to the transportation agreement was approved by the Florida PSC at its Agenda Conference held April 5, 2016.

Eastern Shore

White Oak Mainline Expansion Project: On November 21, 2014, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate 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. 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 alternate routes for a segment of the pipeline route in the vicinity of the Kemblesville, Pennsylvania Historic District. On June 2, 2015, a field meeting was conducted to review the proposed route and alternate routes. In response to comments received from the National Park Service and other stakeholders, the FERC requested that Eastern Shore conduct an additional investigation in relation to Eastern Shore's existing right-of-way. On July 9, 2015, the FERC issued a 30-day public scoping notice in advance of issuing an environmental assessment in order to solicit comments from the public regarding construction of the Kemblesville loop. On August 18, 2015, Eastern Shore submitted supplemental information to the FERC regarding the results of its investigation of the Kemblesville loop.

On November 18, 2015, Eastern Shore filed an amendment to this application, which indicated the preferred pipeline route. On February 10, 2016 the FERC issued a notice to prepare an environmental assessment and will combine both the White Oak Mainline Expansion project and System Reliability Project into a single assessment. The environmental assessment was issued on April 25, 2016, with the FERC's 90-day authorization decision to be issued on July 24, 2016.

On March 28, 2016, subsequent to the issuance of the schedule, FERC issued another environmental data request concerning the United States Department of Agriculture and an agricultural conservation easement on a tract of land where the White Oak Mainline Project would install a portion of the pipeline in its existing right-of way. On April 4, 2016, Eastern Shore responded to the data request.

System Reliability Project: On May 22, 2015, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate approximately 10.1 miles of 16-inch pipeline looping and 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. Since the project is intended to improve system reliability, Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project.

On June 8, 2015, the FERC filed a notice of the application, and the comment period ended on June 29, 2015. Two interested parties filed comments and protests with the FERC. Eastern Shore has filed answers to the comments and protests from the two parties.

- 11

On September 4, 2015, the FERC issued a notice of intent to prepare an environmental assessment, and Eastern Shore responded to the FERC Staff's environmental data requests. On February 10, 2016, the FERC issued a notice combining the System Reliability Project and White Oak Mainline Expansion project into a single environmental assessment. On March 2, 2016, the FERC issued a revised notice rescheduling the issuance of the combined environmental assessment to April 25, 2016, with the 90-day authorization decision to be issued on July 24, 2016.

TETLP Capacity Expansion Project: On October 13, 2015, Eastern Shore submitted an application to the FERC to make certain measurement and related improvements at its TETLP interconnect facilities, which would enable Eastern Shore to increase natural gas receipts from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. On December 22, 2015, the FERC authorized Eastern Shore to proceed with the project. On March 11, 2016, the capacity expansion project was placed into service.

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.

MGP Sites

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

As of March 31, 2016, we had approximately $10.0 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 $10.2 million of which has been recovered as of March 31, 2016, leaving approximately $3.8 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

In addition to the FPU MGP sites, we had $353,000 in environmental liabilities at March 31, 2016 related to Chesapeake Utilities' MGP sites in Salisbury, Maryland and Winter Haven, Florida, representing our estimate of future costs associated with these sites. As of March 31, 2016, we had approximately $58,000 in regulatory and other assets for future recovery through Chesapeake Utilities' rates.

During the first quarter of 2015, we established $273,000 in environmental liabilities related to Chesapeake Utilities' 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 Utilities' rates via our environmental rider. On February 23, 2016, the Delaware PSC approved an environmental surcharge for the recovery of Chesapeake Utilities' environmental expenses associated with the Seaford site for the period of October 1, 2014 through September 30, 2015. Chesapeake Utilities will file for recovery of its expenses incurred between October 1, 2015 and September 30, 2016 by October 31, 2016. As of March 31, 2016, we had approximately $186,000 in environmental liabilities and $269,000 in regulatory and other assets related to this site.

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

West Palm Beach, Florida

Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated a MGP. FPU is 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. The Start-Up and Monitoring Report, dated November 30, 2015, was submitted for review and comment. A letter dated January 6, 2016, was received from FDEP, which provided minor comments. On January 12, 2016, FDEP conducted a facility inspection and found no problems or deficiencies.

- 12

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

Sanford, Florida

FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP at this site. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of March 31, 2016, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements.

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

As of March 31, 2016, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be $24,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million to implement the final remedy for this site, as provided in the Third Participation Agreement, or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of March 31, 2016.

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, 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 requires a limited semi-annual monitoring program. The most recent groundwater-monitoring event was conducted in March of 2016. Natural Attenuation Default criteria were met at all locations sampled.

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

- 13

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 next semi-annual RAP implementation status report, submitted on January 8, 2015. FDEP approved the plan to expand the bio-sparging operations in the southern portion of the site, and additional sparge points were installed and connected to the operating system in the first quarter of 2016.

Although specific remedial actions for the site 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, the DNREC provided the evaluation, which found several compounds within the groundwater and soil that require further investigation. We submitted an application to the DNREC on April 2, 2015, which was approved on September 17, 2015, to enter this site into the voluntary cleanup program. A remedial investigation was conducted in December 2015, and a draft remedial investigation report was submitted to the DNREC on March 7, 2016. We anticipate submitting the final report, based on comments from the DNREC during the second quarter of 2016. We estimate the cost of potential remedial actions, based on the findings of the DNREC report, to be between $273,000 and $465,000. We also believe these costs will be recoverable from customers through rates.

Cambridge, Maryland

We are discussing with the MDE 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.

Ohio

We have also completed the investigation, assessment and remediation of eight natural gas pipeline facilities in Ohio that Aspire Energy acquired from Gatherco pursuant to the merger. The costs incurred to date associated with remediation activities for these facilities, is approximately $1.4 million. Pursuant to the merger agreement, an escrow was established to fund certain claims by Chesapeake Utilities and Aspire Energy for indemnification by Gatherco, including environmental claims. Gatherco's indemnification obligations for environmental matters apply to remediation costs in excess of $431,250 and are capped at $1.7 million. We have submitted our request for reimbursement to the escrow agent.

- 14

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. For our Delaware and Maryland natural gas distribution divisions, we have a contract with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage capacity, which expires on March 31, 2017.

In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term. Approximately three 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. Approximately three years remain under this contract. 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 Utilities' 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 Utilities 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 monthly purchase commitment ranges from 9,982 to 13,423 Dts/dfor a one-year term. PESCO is obtaining and reviewing proposals from suppliers and anticipates executing new agreements before the existing agreements expire.

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) a fixed charge coverage ratio greater than 1.5 times. If FPU fails to comply with either of these ratios, it has 30 days to cure the default or, if the default is not cured, to provide an irrevocable letter of credit. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet either of these ratios, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of March 31, 2016, FPU was in compliance with all of the requirements of its fuel supply contracts.

Corporate Guarantees

The Board of Directors has authorized the Company to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our obligations, including the obligations of our subsidiaries. The maximum authorized liability under such guarantees and letters of credit is $65.0 million.

We have issued corporate guarantees to certain vendors of our subsidiaries, the largest of which are for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event that Xeron or PESCO defaults. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at March 31, 2016 was $48.7 million, with the guarantees expiring on various dates through March 2017.

Chesapeake Utilities 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).

We issued letters of credit totaling $8.1 million related to the electric transmission services for FPU's northwest electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions and to our

- 15

current and previous primary insurance carriers. These letters of credit have various expiration dates through March 2017. There have been no draws on these letters of credit as of March 31, 2016. 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.

Tax-related Contingencies

We are subject to various audits and reviews by the federal, state, local and other governmental authorities regarding income taxes and taxes other than income. As of March 31, 2016, we maintained a liability of $50,000 related to unrecognized income tax benefits and $196,000 related to contingencies for taxes other than income. As of December 31, 2015, we maintained a liability of $50,000 related to unrecognized income tax benefits and $310,000 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, whose services include natural gas gathering, processing, transportation and supply (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.

The remainder of our operations is presented as “Other businesses and eliminations”, which consists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations.

- 16

The following table presents financial information about our reportable segments:

	Three Months Ended
	March 31,
	2016			2015
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	88,894		$	109,292
Unregulated Energy segment	57,402			60,789
Total operating revenues, unaffiliated customers	$	146,296		$	170,081
Intersegment Revenues (1)
Regulated Energy segment	$	322		$	290
Unregulated Energy segment	113			207
Other businesses	226			221
Total intersegment revenues	$	661		$	718
Operating Income
Regulated Energy segment	$	24,319		$	22,182
Unregulated Energy segment	11,936			15,229
Other businesses and eliminations	125			97
Total operating income	36,380			37,508
Other (Expense) income, net	(34		)	133
Interest	2,650			2,448
Income before Income Taxes	33,696			35,193
Income taxes	13,329			14,084
Net Income	$	20,367		$	21,109

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

(in thousands)	March 31, 2016		December 31, 2015
Identifiable Assets
Regulated Energy segment	$	879,878	$	872,065
Unregulated Energy segment	178,723		171,840
Other businesses and eliminations	23,383		23,516
Total identifiable assets	$	1,081,984	$	1,067,421

Our operations are entirely domestic.

- 17

8. Accumulated Other Comprehensive Loss

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements, call options and natural gas futures contracts, designated as commodity contracts cash flow hedges, are the components of our accumulated comprehensive income (loss). The following tables present the changes in the balance of accumulated other comprehensive loss for the three months endedMarch 31, 2016 and 2015. 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, 2015	$	(5,580	)	$	(260	)	$	(5,840	)
Other comprehensive loss before reclassifications	—			(283		)	(283		)
Amounts reclassified from accumulated other comprehensive loss	89			283			372
Net current-period other comprehensive income	89			—			89
As of March 31, 2016	$	(5,491	)	$	(260	)	$	(5,751	)

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2014	$	(5,643	)	$	(33	)	$	(5,676	)
Other comprehensive loss before reclassifications	—			(7		)	(7		)
Amounts reclassified from accumulated other comprehensive loss	82			33			115
Net prior-period other comprehensive income	82			26			108
As of March 31, 2015	$	(5,561	)	$	(7	)	$	(5,568	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three months endedMarch 31, 2016 and 2015. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.

- 18

	Three Months Ended
	March 31,
	2016			2015
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	20		$	17
Net loss (1)	(168		)	(154		)
Total before income taxes	(148		)	(137		)
Income tax benefit	59			55
Net of tax	$	(89	)	$	(82	)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	(322	)	$	—
Call options (2)	—			(55		)
Natural gas futures (2)	(149		)	—
Total before income taxes	(471		)	(55		)
Income tax benefit	188			22
Net of tax	(283		)	(33		)
Total reclassifications for the period	$	(372	)	$	(115	)

⁽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 months endedMarch 31, 2016 and 2015 are set forth in the following table:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended March 31,	2016			2015			2016			2015			2016		2015		2016			2015			2016		2015
(in thousands)
Interest cost	$	105		$	102		$	630		$	626		$	23	$	23	$	11		$	11		$	14	$	15
Expected return on plan assets	(131		)	(135		)	(701		)	(777		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			—		2		(20		)	(19		)	—		—
Amortization of net loss	104			90			128			114			22		25		18			17			—		2
Net periodic cost (benefit)	78			57			57			(37		)	45		50		9			9			14		17
Amortization of pre-merger regulatory asset	—			—			191			190			—		—		—			—			2		2
Total periodic cost	$	78		$	57		$	248		$	153		$	45	$	50	$	9		$	9		$	16	$	19

- 19

We expect to record pension and postretirement benefit costs of approximately $1.6 million for 2016. 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 in 2009. 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 $2.7 million and $2.8 million at March 31, 2016 and December 31, 2015, respectively. The amortization included in pension expense is also being added to a net periodic loss of $802,000, which will increase our total expected benefit costs to $1.6 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 Utilities' operations is recorded to accumulated other comprehensive loss. The following table presents the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three months ended March 31, 2016 and 2015:

For the Three Months Ended March 31, 2016	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	—	$	(20	)	$	—	$	(20	)
Net loss	104		128		22		18			—		272
Total recognized in net periodic benefit cost	$	104	$	128	$	22	$	(2	)	$	—	$	252
Recognized from accumulated other comprehensive loss (1)	$	104	$	24	$	22	$	(2	)	$	—	$	148
Recognized from regulatory asset	—		104		—		—			—		104
Total	$	104	$	128	$	22	$	(2	)	$	—	$	252

For the Three Months Ended March 31, 2015	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	2	$	(19	)	$	—	$	(17	)
Net loss	90		114		25		17			2		248
Total recognized in net periodic benefit cost	$	90	$	114	$	27	$	(2	)	$	2	$	231
Recognized from accumulated other comprehensive loss (1)	$	90	$	22	$	27	$	(2	)	$	—	$	137
Recognized from regulatory asset	—		92		—		—			2		94
Total	$	90	$	114	$	27	$	(2	)	$	2	$	231

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

During the three months ended March 31, 2016, we contributed $104,000 to the Chesapeake Pension Plan and $337,000 to the FPU Pension Plan. We expect to contribute a total of $508,000 and $1.6 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2016, which represent the minimum annual contribution payments required.

The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three months ended March 31, 2016, were $38,000. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake Pension SERP in 2016. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three months ended March 31, 2016, were $21,000. We estimate that approximately $82,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2016. Cash benefits paid under the FPU Medical Plan, primarily for medical claims

- 20

for the three months ended March 31, 2016, were $38,000. We estimate that approximately $149,000 will be paid for such benefits under the FPU Medical Plan in 2016.

10. Investments

The investment balances at March 31, 2016 and December 31, 2015, consisted of the following:

(in thousands)	March 31, 2016		December 31, 2015
Rabbi trust (associated with the Deferred Compensation Plan)	$	3,654	$	3,626
Investments in equity securities	20		18
Total	$	3,674	$	3,644

We classify these investments as trading securities and report them at their fair value. For the three months ended March 31,2016 and 2015, we recorded a net unrealized loss of $18,000 and a net unrealized gain of $104,000, 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 investments in 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 months endedMarch 31, 2016 and 2015:

	Three Months Ended
	March 31,
	2016			2015
(in thousands)
Awards to non-employee directors	$	165		$	150
Awards to key employees	484			387
Total compensation expense	649			537
Less: tax benefit	(261		)	(217		)
Share-based compensation amounts included in net income	$	388		$	320

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 grant date. 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 service as a director through the 2016 Annual Meeting of Stockholders. At March 31, 2016, there was $55,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2016.

- 21

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the three months endedMarch 31, 2016:

	Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2015	110,398		$	38.34
Granted	46,571		$	61.50
Vested	(39,553	)	$	31.79
Expired	(2,325	)	$	42.25
Outstanding— March 31, 2016	115,091		$	49.26

In February 2016, our Board of Directors granted awards of 46,571 shares of common stock to key employees under the SICP. The shares granted in February 2016 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2018. 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 grant date of each award. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

At March 31, 2016, the aggregate intrinsic value of the SICP awards granted to key employees was $7.2 million. At March 31, 2016, there was $3.3 million of unrecognized compensation cost related to these awards, which is expected to be recognized during 2016 through 2018.

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. Aspire Energy has entered into contracts with producers to secure natural gas to meet its obligations. 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 and natural gas marketing operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of March 31, 2016, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Hedging Activities in 2016

Beginning in October 2015, PESCO entered into natural gas futures contracts associated with the purchase and sale of natural gas to specific customers. These contracts expire within two years and we have accounted for them as cash flow hedges. There is no ineffective portion of these hedges. At March 31, 2016, PESCO had a total of 6,723 Dts/d hedged under natural gas futures contracts, with a liability fair value of $423,000. The change in fair value of the natural gas futures contracts is recorded as unrealized gain/loss in other comprehensive income (loss).

Hedging Activities in 2015

In March, May and June 2015, Sharp paid a total of $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 2015-2016 heating season. We exercised the put options as propane prices fell 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. We received $239,000 representing the difference between the market prices and the strike prices during those months. We accounted for the put options as fair value hedges.

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 purchased in December 2015 through March 2016. Under these swap agreements, Sharp would have received the difference between the index prices (Mont Belvieu prices in December 2015 through March 2016) and the swap prices, which ranged from $0.5200 to $0.5950 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 the 2.5 million gallons that we purchased during this period. We accounted for the swap agreements as cash flow hedges. Sharp paid $484,000,

- 22

representing the difference between the index prices and swap prices during those months of the swap agreements.

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 statements of income for the period of change. As of March 31, 2016, we had the following outstanding trading contracts, which we accounted for as derivatives:

	Quantity in	Estimated Market		Weighted Average
At March 31, 2016	Gallons	Prices		Contract Prices
Forward Contracts
Sale	630,000	$	0.4425	$	0.4425
Purchase	631,000	$	0.4413	$	0.4422

Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the second quarter of 2016.

Xeron entered into master netting agreements with two counterparties to mitigate exposure to counterparty credit risk. The master netting agreements enable Xeron to net these two counterparties' outstanding accounts receivable and payable, which are presented on a gross basis in the accompanying condensed consolidated balance sheets. At March 31, 2016, Xeron had no accounts receivable or accounts payable balances to offset with these two counterparties. At December 31, 2015, Xeron had a right to offset $431,000 of accounts payable with these two counterparties. At December 31, 2015, Xeron did not have outstanding accounts receivable with these two counterparties.

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of March 31, 2016 and December 31, 2015, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2016		December 31, 2015
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	—	$	1
Derivatives designated as fair value hedges
Put options	Mark-to-market energy assets			152
Total asset derivatives		$	—	$	153

	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2016		December 31, 2015
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	—	$	1
Derivatives designated as cash flow hedges
Propane swap agreements	Mark-to-market energy liabilities	—		323
Natural gas futures contracts	Mark-to-market energy liabilities	423		109
Total liability derivatives		$	423	$	433

- 23

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

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended March 31,
(in thousands)	(Loss) on Derivatives	2016			2015
Derivatives not designated as hedging instruments
Realized gain on forward contracts (1)	Revenue	$	187		$	277
Unrealized gain (loss) on forward contracts (1)	Revenue	1			(125		)
Propane swap agreements	Cost of sales	—			18
Derivatives designated as fair value hedges
Put /Call options	Cost of sales	73			506
Put /Call options (2)	Propane Inventory	—			(3		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	(364		)	—
Propane swap agreements	Other Comprehensive Loss	—			(12		)
Call options	Cost of sales	—			(81		)
Natural gas futures contracts	Cost of sales	149			—
Natural gas futures contracts	Other Comprehensive Loss	(462		)	—
Total		$	(416	)	$	580

⁽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 call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this 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 March 31, 2016 and December 31, 2015:

- 24

			Fair Value Measurements Using:
As of March 31, 2016	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	$	20	$	20	$	—	$	—
Investments—guaranteed income fund	$	525	$	—	$	—	$	525
Investments—mutual funds and other	$	3,129	$	3,129	$	—	$	—
Mark-to-market energy assets, incl. put options and swap agreements	$	—	$	—	$	—	$	—
Liabilities:
Mark-to-market energy liabilities incl. swap agreements	$	423	$	—	$	423	$	—

			Fair Value Measurements Using:
As of December 31, 2015	Fair Value		Quoted- Prices- in Active Markets (Level 1)		Significant- Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	18	$	18	$	—	$	—
Investments—guaranteed income fund	$	279	$	—	$	—	$	279
Investments—mutual funds and other	$	3,347	$	3,347	$	—	$	—
Mark-to-market energy assets, incl. put/call options	$	153	$	—	$	153	$	—
Liabilities:
Mark-to-market energy liabilities, incl. swap agreements	$	433	$	—	$	433	$	—

The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of March 31, 2016 and December 31, 2015:

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 - mutual funds and 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, swap agreements and natural gas futures contracts – The fair value of the propane put/call options, swap agreements and natural gas futures contracts are measured 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.

- 25

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the three months ended March 31, 2016 and 2015:

	Three Months Ended   March 31,
	2016		2015
(in thousands)
Beginning Balance	$	279	$	287
Purchases and adjustments	2		(5		)
Transfers	242		(3		)
Investment income	2		1
Ending Balance	$	525	$	280

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

At March 31, 2016, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

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

At March 31, 2016, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of $153.6 million. This compares to a fair value of $171.4 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, 2015, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of $153.7 million, compared to the estimated fair value of $165.1 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

- 26

14. Long-Term Debt

Our outstanding long-term debt is shown below:

	March 31,			December 31,
(in thousands)	2016			2015
FPU secured first mortgage bonds (1) :
9.08% bond, due June 1, 2022	$	7,975		$	7,973
Uncollateralized senior notes:
6.64% note, due October 31, 2017	5,455			5,455
5.50% note, due October 12, 2020	10,000			10,000
5.93% note, due October 31, 2023	24,000			24,000
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	168			238
Capital lease obligation	4,490			4,824
Total long-term debt	158,088			158,490
Less: current maturities	(9,163		)	(9,151		)
Less: debt issuance costs	(323		)	(333		)
Total long-term debt, net of current maturities	$	148,602		$	149,006

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

Shelf Agreement

On October 8, 2015, we entered into a Shelf Agreement with Prudential. Under the terms of the Shelf Agreement, we may request that Prudential purchase, over the next three years, up to $150.0 million of our Shelf Notes at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance. Prudential is under no obligation to purchase any of the Shelf Notes. The interest rate and terms of payment of any series of Shelf Notes will be determined at the time of purchase. We currently anticipate the proceeds from the sale of any series of Shelf Notes will be used for general corporate purposes, including refinancing of short-term borrowing and/or repayment of outstanding indebtedness and financing capital expenditures on future projects; however, actual use of such proceeds will be determined at the time of a purchase, and each request for purchase with respect to a series of Shelf Notes will specify the exact use of the proceeds.

The Shelf Agreement sets forth certain business covenants to which we are subject when any Shelf Note is outstanding, including covenants that limit or restrict us and our subsidiaries from incurring indebtedness and incurring liens and encumbrances on any of our property.

15. Short-Term Borrowing

On October 8, 2015, we entered into a Credit Agreement with the Lenders for a $150.0 million Revolver for a term of five years subject to the terms and conditions of the Credit Agreement. Borrowings under the Revolver will be used for general corporate purposes, including repayments of short-term borrowings, working capital requirements and capital expenditures.

Borrowings under the Revolver will bear interest at: (i) the LIBOR Rate plus an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization, both as defined by the Credit Agreement, or (ii) the base rate plus 0.25 percent or less. Interest will be payable quarterly, and the Revolver is subject to a commitment fee on the unused portion of the facility. We may extend the expiration date for up to two years on any anniversary date of the Revolver, with such extension subject to the Lenders' approval. We may also request the Lenders to increase the Revolver to $200.0 million, with any increase at the sole discretion of each Lender. AtMarch 31, 2016 and December 31, 2015, we had borrowed $40.0 million and $35.0 million, respectively, under the Revolver.

- 27

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, 2015, 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 timing of certification authorizations;

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

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

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

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

• general economic conditions, including any potential effects arising from terrorist attacks and any 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 capital intensive nature of our regulated energy businesses;

• 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 on our cost and funding obligations under our pension and other post-retirement benefit plans of potential downturns in the financial markets, lower discount rates, and costs associated with the Patient Protection and Affordable Care Act;

• 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 ability to continue to hire, train and retain appropriately qualified personnel;

• 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 various energy businesses;

• the effect of competition on our businesses;

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

• possible increased federal, state and local regulation of the safety of our operations;

• the inherent hazards and risks involved in our energy businesses;

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

- 28

• risks related to cyber-attacks that could disrupt our business operations or result in failure of information technology systems.

Introduction

We are a diversified energy company engaged, directly or through our operating divisions and subsidiaries, in various energy and other 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 stockholders; 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.

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

- 29

Results of Operations for the Three Months endedMarch 31, 2016

Overview and Highlights

Our net income for the quarter ended March 31, 2016 was $20.4 million, or $1.33 per share. This represents a decrease of $742,000, or $0.11 per share, compared to net income of $21.1 million, or $1.44 per share, as reported for the same quarter in 2015.

	Three Months Ended
	March 31,					Increase
	2016			2015		(decrease)
(in thousands except per share)
Business Segment:
Regulated Energy segment	$	24,319		$	22,182	$	2,137
Unregulated Energy segment	11,936			15,229		(3,293		)
Other businesses and eliminations	125			97		28
Operating Income	$	36,380		$	37,508	(1,128		)
Other (Expense) Income, net	(34		)	133		(167		)
Interest Charges	2,650			2,448		202
Pre-tax Income	33,696			35,193		(1,497		)
Income Taxes	13,329			$	14,084	(755		)
Net Income	$	20,367		$	21,109	$	(742	)
Earnings Per Share of Common Stock
Basic	$	1.33		$	1.45	$	(0.12	)
Diluted	$	1.33		$	1.44	$	(0.11	)

- 30

Key variances included:

(in thousands, except per share data)	Pre-tax Income			Net Income			Earnings Per Share
First Quarter of 2015 Reported Results	$	35,193		$	21,109		$	1.44
Adjusting for Unusual Items:
Weather impact	(6,656		)	(3,992		)	(0.27		)
	(6,656		)	(3,992		)	(0.27		)
Increased (Decreased) Gross Margins:
Service expansions (See Major Projects and Initiatives table)	1,947			1,168			0.08
Lower retail propane margins	(1,837		)	(1,102		)	(0.07		)
GRIP	1,108			665			0.05
Natural gas growth (excluding service expansions)	745			447			0.03
	1,963			1,178			0.09
Decreased (Increased) Other Operating Expenses:
Higher depreciation, asset removal and property tax costs due to recent capital investments	(740		)	(444		)	(0.03		)
Decreased incentive compensation	717			430			0.03
	(23		)	(14		)	—
Net contribution from Aspire Energy, including impact of shares issued	2,633			1,676			0.06
Interest Charges	(202		)	(121		)	(0.01		)
Net Other Changes	788			531			0.02
First Quarter of 2016 Reported Results	$	33,696		$	20,367		$	1.33

- 31

Summary of Key Factors

Major Projects and Initiatives

The following table summarizes gross margin for our existing and future major projects and initiatives (dollars in thousands):

	Gross Margin for the Period
	Three Months Ended				Total
	March 31,				2015		Estimate for
	2016		2015		Margin		2016		2017		2018
Completed major projects and initiatives	$	11,445	$	4,149	$	25,270	$	40,791	$	42,350	$	44,846
Major projects and initiatives underway	—		—		—		3,700		9,550		11,800
	$	11,445	$	4,149	$	25,270	$	44,491	$	51,900	$	56,646

Completed Major Projects and Initiatives

The following table summarizes our major projects and initiatives completed since 2014 (dollars in thousands):

	Gross Margin for the Period
	Three Months Ended							Total
	March 31,							2015		Estimate for
	2016		2015		Variance			Margin		2016		2017		2018
Acquisition:
Aspire Energy	$	4,241	$	—	$	4,241		$	6,324	$	12,824	$	14,198	$	15,415
Natural Gas Transmission Expansions and Contracts:
Short-term contracts
New Castle County, Delaware	$	760	$	968	$	(208	)	$	2,682	$	2,607	$	1,578	$	677
Kent County, Delaware (1)	1,783		—		1,783			2,270		6,951		—		—
Total short-term contracts	$	2,543	$	968	$	1,575		$	4,952	$	9,558	$	1,578	$	677
Long-term contracts
Kent County, Delaware	$	455	$	463	$	(8	)	$	1,844	1,815		$	7,629	$	7,605
Polk County, Florida	407		27		380			908		1,627		1,627		1,627
Total long-term contracts	$	862	$	490	$	372		$	2,752	$	3,442	$	9,256	$	9,232
Total Expansions & Contracts	$	3,405	$	1,458	$	1,947		$	7,704	$	13,000	$	10,834	$	9,909
Florida GRIP	$	2,587	$	1,479	$	1,108		$	7,508	$	11,405	$	13,756	$	15,960
Florida Electric Rate Case	$	1,212	$	1,212	$	—		$	3,734	$	3,562	$	3,562	$	3,562
Total Completed Major Projects and Initiatives	$	11,445	$	4,149	$	7,296		$	25,270	$	40,791	$	42,350	$	44,846

⁽¹⁾ In April 2015, Eastern Shore, commenced interruptible service to an industrial customer facility in Kent County, Delaware. The interruptible service concluded in December 2015 and was replaced by a short-term OPT ≤ 90 Service. The short-term OPT ≤ 90 Service is expected to be replaced by a 20-year contract for OPT ≤ 90 Service in the first quarter of 2017.

- 32

Aspire Energy

On April 1, 2015, we completed the merger of Gatherco with and into Aspire Energy, a newly-formed, wholly-owned subsidiary of Chesapeake Utilities. Aspire Energy is an unregulated natural gas infrastructure company with approximately 2,500 miles of pipeline systems in 40 counties throughout Ohio. The majority of Aspire Energy's margin is derived from long-term supply agreements with Columbia Gas of Ohio and Consumers Gas Cooperative, which together serve more than 20,000 end-use customers. Aspire Energy sources gas primarily from 300 conventional producers. Aspire Energy also provides gathering and processing services necessary to maintain quality and reliability to its wholesale markets.

Aspire Energy generated $4.2 million in additional gross margin and incurred $1.6 million in other operating expenses for the three months ended March 31, 2016. This acquisition was accretive to our earnings per share in the first full year of operations, generating $0.03 in additional earnings per share.

Service Expansions

In April 2015, Eastern Shore commenced interruptible service to an industrial customer facility in Kent County, Delaware. The interruptible service concluded in December 2015 and was replaced by a short-term OPT ≤ 90 Service, which generated additional gross margin of $1.8 million during the three months ended March 31, 2016. The short-term OPT ≤ 90 Service is expected to be replaced by a 20-year contract for OPT ≤ 90 Service in the first quarter of 2017.

On January 16, 2015, the Florida PSC approved a firm transportation agreement between Peninsula Pipeline and our Florida natural gas distribution division. Under this agreement, Peninsula Pipeline provides natural gas transmission service to support our expansion of natural gas distribution service in Polk County, Florida. Peninsula Pipeline began the initial phase of its service to Chesapeake Utilities' Florida natural gas distribution division in March 2015. This new service generated $380,000 of additional gross margin for the three months ended March 31, 2016 compared to the same quarter in 2015. When all phases of this service are complete, this expansion will generate an estimated annual gross margin of $1.6 million.

On October 13, 2015, Eastern Shore submitted an application to the FERC to make certain measurement and related improvements at its TETLP interconnect facilities, which will enable Eastern Shore to increase natural gas receipts from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. In December 2015, the FERC authorized Eastern Shore to proceed with this project, which was completed and placed in service in March 2016. Currently, 8,100 Dts/d of the increased capacity have been subscribed on a firm service basis. This service will generate approximately $344,000 in additional gross margin through 2016. The remaining capacity is available for firm or interruptible service.

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 the Florida natural gas distribution systems. This program allows recovery, through regulated 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, we have invested $84.3 million to replace 174 miles of qualifying distribution mains, including $7.4 million during the first quarter of 2016. We expect to invest an additional $13.6 million in this program during the remainder of 2016. The increased investment in GRIP generated additional gross margin of $1.1 million for the three months ended March 31, 2016, compared to the same quarter in 2015.

Major Projects and Initiatives Underway

White Oak Mainline Expansion Project:In December 2014, Eastern Shore entered into a precedent agreement with an industrial customer in Kent County, Delaware, to provide a 20-year natural gas transmission service for 45,000 Dts/d for the customer's 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 authorization by the FERC to construct 7.2 miles of 16-inch pipeline looping and 3,550 horsepower of new compression in Delaware to provide this service. As previously discussed, during the three months ended March 31, 2016, we generated $1.8 million in additional gross margin by providing interruptible service and short-term OPT ≤ 90 Service to this customer. The estimated annual gross margin contribution from this project, once it is placed in service, is approximately $5.8 million.

- 33

System Reliability Project:On May 22, 2015, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate approximately 10.1 miles of 16-inch pipeline looping and 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. Since the project is intended 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 requested authorization. This project will be included in Eastern Shore's upcoming 2017 rate case filing. The estimated annual gross margin associated with this project, assuming recovery in the 2017 rate case filing, is approximately $4.5 million.

Eight Flags: 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 then produce the 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.

The following table summarizes estimated gross margin for the foregoing projects (dollars in thousands):

	Estimated Margin for (1)
Project	2016		2017		Annualized Margin
Eastern Shore System Reliability Project	$	—	$	2,250	$	4,500
Eight Flags CHP plant in Nassau County, Florida	3,700		7,300		7,300
Total Major Projects and Initiatives Underway (2)	$	3,700	$	9,550	$	11,800

⁽¹⁾Estimated gross margin for these projects is based on current tariff or negotiated rates.

⁽²⁾This table excludes gross margin associated with the White Oak Mainline Expansion project. The gross margin for short-term OPT ≤ 90 Service contract in place through December 2016, and for the long-term OPT ≤ 90 Service contract associated with this project are shown in the Completed Major Projects and Initiatives table above.

- 34

Other factors influencing gross margin

Weather and Consumption

Significantly warmer temperatures during the three months ended March 31, 2016 when the demand for natural gas and propane is normally high, had a large negative impact on our gross margin for that quarter. Lower customer consumption, directly attributable to warmer than normal temperatures during the three months ended March 31, 2016, reduced gross margin by $6.7 million compared to the same quarter in 2015. This reduction was significantly offset by increased gross margin from expansion services under long-term and short-term contracts, customer growth and Aspire Energy. The following tables summarize the HDD and CDD information for the three months ended March 31, 2016 and 2015 and the gross margin variance resulting from weather fluctuations in those periods.

HDD and CDD Information

	Three Months Ended
	March 31,
	2016		2015		Variance
Delmarva
Actual HDD	2,094		2,822		(728	)
10-Year Average HDD ("Delmarva Normal")	2,400		2,372		28
Variance from Delmarva Normal	(306	)	450
Florida
Actual HDD	597		501		96
10-Year Average HDD ("Florida Normal")	534		533		1
Variance from Florida Normal	63		(32	)
Ohio
Actual HDD	2,854		—		N/A
10-Year Average HDD ("Ohio Normal")	3,176		—		N/A
Variance from Ohio Normal	(322	)	—
Florida
Actual CDD	186		122		64
10-Year Average CDD ("Florida CDD Normal")	77		73		4
Variance from Florida CDD Normal	109		49

Gross Margin Variance Attributed to Weather

(in thousands)	Q1 2016 vs. Q1 2015			Q1 2016 vs. Normal			Q1 2015 vs. Normal
Delmarva
Regulated Energy segment	$	(2,036	)	$	(866	)	$	1,088
Unregulated Energy segment	(4,810		)	(2,985		)	1,185
Florida
Regulated Energy segment	(4		)	(85		)	(448		)
Unregulated Energy segment	194			(109		)	122
Total	$	(6,656	)	$	(4,045	)	$	1,947

- 35

Propane prices

Lower retail margins per gallon reduced gross margin by $2.0 million for our Delmarva propane distribution operation for the three months ended March 31, 2016, compared to the same period in 2015, as margins per retail gallon began to return to more normal levels. The decline in margin was principally driven by lower propane prices, as well as local market conditions. The level of retail margins per gallon generated during 2015 were not expected to be sustained over the long term; accordingly, we have assumed more normal levels of margins in our long-term financial plans and forecasts.

In Florida, higher retail propane margins per gallon as a result of local market conditions generated $122,000 of additional gross margin for the three months ended March 31, 2016.

These market conditions, which are influenced by 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.

Other Natural Gas Growth - Distribution Operations

In addition to service expansions, the natural gas distribution operations on the Delmarva Peninsula generated $346,000 in additional gross margin for the three months ended March 31, 2016, compared to the same period in 2015, due to an increase in residential, commercial and industrial customers served. The average number of residential customers on the Delmarva Peninsula increased by 2.6 percent in the first quarter of 2016, compared to the same quarter in 2015. The natural gas distribution operations in Florida generated $341,000 in additional gross margin for the three months ended March 31, 2016, compared to the same period in 2015, due primarily to an increase in commercial and industrial customers in Florida.

- 36

Regulated Energy Segment

For the quarter ended March 31, 2016 compared to the quarter ended March 31, 2015

	Three Months Ended
	March 31,				Increase
	2016		2015		(decrease)
(in thousands)
Revenue	$	89,216	$	109,582	$	(20,366	)
Cost of sales	34,905		57,129		(22,224		)
Gross margin	54,311		52,453		1,858
Operations & maintenance	20,460		21,283		(823		)
Depreciation & amortization	6,296		5,900		396
Other taxes	3,236		3,088		148
Other operating expenses	29,992		30,271		(279		)
Operating income	$	24,319	$	22,182	$	2,137

Operating income for the Regulated Energy segment for the quarter ended March 31, 2016 was $24.3 million, an increase of $2.1 million, or 9.6 percent, compared to the same quarter in 2015. The increased operating income was primarily due to an increase in gross margin of $1.9 million.

Gross Margin

Items contributing to the quarter-over-quarter increase of $1.9 million, or 3.5 percent, in gross margin are listed in the following table:

(in thousands)
Gross margin for the three months ended March 31, 2015	$	52,453
Factors contributing to the gross margin increase for the three months ended March 31, 2016:
Decreased customer consumption - weather and other	(2,445		)
Service expansions	1,947
Additional revenue from GRIP in Florida	1,108
Natural gas growth (excluding service expansions)	745
Other	503
Gross margin for the three months ended March 31, 2016	$	54,311

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

Decreased Customer Consumption—Weather and Other

In the first quarter of 2016, customer consumption of natural gas and electricity decreased primarily due to significantly warmer weather on the Delmarva Peninsula, which reduced gross margin by approximately $2.4 million.

Service Expansions

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

• $1.8 million from the short-term OPT ≤ 90 Service that commenced in December 2015 to an industrial customer in Kent County, Delaware following the conclusion of an interruptible service Eastern Shore had provided this customer. The short-term OPT ≤ 90 Service is expected to be replaced by a 20-year OPT ≤ 90 Service in the first quarter of 2017.

• $380,000 from natural gas transmission service as part of the major expansion initiative in Polk County, Florida.

- 37

Additional Revenue from GRIP in Florida

Additional GRIP investments during 2015 and 2016 by our Florida natural gas distribution operations generated $1.1 million in additional gross margin.

Natural Gas Growth (excluding service expansions)

Increased gross margin from other growth in natural gas (excluding service expansions) was generated primarily from the following:

• $341,000 from Florida natural gas customer growth due primarily to new services to commercial and industrial customers; and

• $346,000 from a 2.6 percent increase in the average number of residential customers in the Delmarva natural gas distribution operations, as well as growth in commercial and industrial customers.

Other Operating Expenses

Other operating expenses decreased by $279,000.

Unregulated Energy Segment

For the quarter ended March 31, 2016 compared to the quarter ended March 31, 2015

	Three Months Ended
	March 31,				Increase
	2016		2015		(decrease)
(in thousands)
Revenue	$	57,516	$	60,996	$	(3,480	)
Cost of sales	34,415		35,677		(1,262		)
Gross margin	23,101		25,319		(2,218		)
Operations & maintenance	9,389		8,557		832
Depreciation & amortization	1,183		1,051		132
Other taxes	593		482		111
Other operating expenses	11,165		10,090		1,075
Operating Income	$	11,936	$	15,229	$	(3,293	)

Operating income for the Unregulated Energy segment decreased by $3.3 million, to $11.9 million in the first quarter of 2016, compared to $15.2 million in the same quarter of 2015. The results for the first quarter include gross margin of $4.2 million and other operating expenses of $1.6 million from Aspire Energy. Excluding these impacts, gross margin decreased by $6.5 million, partially offset by a $533,000 increase in other operating expenses.

Gross Margin

Items contributing to the quarter-over-quarter decrease of $2.2 million, or 8.8 percent, in gross margin are listed in the following table:

(in thousands)
Gross margin for the three months ended March 31, 2015	$	25,319
Factors contributing to the gross margin decrease for the three months ended March 31, 2016:
Decreased customer consumption - weather and other	(4,329		)
Margin generated by Aspire Energy	4,241
Decrease in retail propane margins	(1,837		)
Other	(293		)
Gross margin for the three months ended March 31, 2016	$	23,101

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

- 38

Decreased Customer Consumption - Weather and Other

Gross margin decreased by $4.3 million due to lower customer consumption of propane. The decrease was mainly driven by weather as a result of warmer temperatures on the Delmarva Peninsula during the first quarter of 2016 compared to significantly colder temperatures during the first quarter of 2015.

Margin generated by Aspire Energy

Aspire Energy generated $4.2 million in additional gross margin for the three months ended March 31, 2016. Since Aspire Energy commenced operations on April 1, 2015, it had no operating results for the quarter ended March 31, 2015.

Decrease in Retail Propane Margins

Lower retail propane margins for our Delmarva propane distribution operation decreased gross margin by $2.0 million, as margins per retail gallon returned to more normal levels. The decline in margin was principally driven by lower propane prices, as well as local market conditions. The level of retail margins per gallon generated during 2015 were not expected to be sustained over the long term; accordingly, we have assumed more normal levels of margins in our long-term financial plans and forecasts.

This decrease was partially offset by $122,000 in higher retail propane margins per gallon for our Florida propane distribution operation as a result of local market conditions.

Other Operating Expenses

The increase in other operating expenses, which was due primarily to $1.6 million in other operating expenses incurred by Aspire Energy, was partially offset by $436,000 in lower accruals for incentive compensation as a result of the lower financial results, due to the impact of weather on financial results during the quarter.

Interest Charges

For the quarter ended March 31, 2016 compared to the quarter ended March 31, 2015

Interest charges for the three months ended March 31, 2016 increased slightly by approximately $202,000, compared to the same quarter in 2015.

Income Taxes

For the quarter ended March 31, 2016 compared to the quarter ended March 31, 2015

Income tax expense was $13.3 million in the first quarter of 2016, compared to $14.1 million in the same quarter in 2015. The decrease in income tax expense was due primarily to lower taxable income. Our effective income tax rate was 39.6 percent and 40.0 percent, for the first quarter of 2016 and 2015, respectively.

- 39

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 temporarily finance capital expenditures. We may also issue long-term debt and equity to fund capital expenditures and to more closely align our capital structure to target.

Our energy businesses are weather-sensitive and seasonal. We normally generate a large portion of our annual net income and subsequent increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas, electricity, and propane delivered by our natural gas, electric, and propane distribution operations and our natural gas gathering and processing operation 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 capital expenditures for the three months ended March 31, 2016 were approximately $30.4 million. We budgeted $179.3 million for capital expenditures in 2016. The following table shows the 2016 capital expenditure budget by segment and business line:

(dollars in thousands)
Regulated Energy:
Natural gas distribution	$	73,285
Natural gas transmission	66,938
Electric distribution	7,566
Total Regulated Energy	147,789
Unregulated Energy:
Propane distribution	11,141
Other unregulated energy	13,504
Total Unregulated Energy	24,645
Other	6,871
Total 2016 capital expenditures	$	179,305

The 2016 budget is a significant increase over prior years’ average annual level of capital expenditures, excluding the Gatherco acquisition, due to a shifting in the capital outlay from 2015 to 2016 for several ongoing projects, including but not limited to the Eight Flags' CHP plant, anticipated new facilities to serve an industrial customer in Kent County, Delaware under the OPT ≤90 Service and Eastern Shore's system reliability projects; additional expansions of our natural gas distribution and transmission systems; continued natural gas infrastructure improvement activities as well as expenditures for continued replacement under the Florida GRIP; replacement of several facilities and systems; and other strategic initiatives and investments expected in 2016. In addition, $30.0 million is included in the 2016 capital budget for projects that are in the early development stage.

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 timing of capital expenditures can vary based on securing environmental reviews and other permits. The regulatory application and approval process has lengthened compared to our previous filings, and we expect this trend to continue.

- 40

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 table presents our capitalization, excluding and including short-term borrowings, as of March 31, 2016 and December 31, 2015:

	March 31, 2016				December 31, 2015
(in thousands)
Long-term debt, net of current maturities	$	148,602	28	%	$	149,006	29	%
Stockholders’ equity	374,252		72	%	358,138		71	%
Total capitalization, excluding short-term debt	$	522,854	100	%	$	507,144	100	%
	March 31, 2016				December 31, 2015
(in thousands)
Short-term debt	$	172,742	25	%	$	173,397	25	%
Long-term debt, including current maturities	157,765		22	%	158,157		23	%
Stockholders’ equity	374,252		53	%	358,138		52	%
Total capitalization, including short-term debt	$	704,759	100	%	$	689,692	100	%

Included in the long-term debt balances at March 31, 2016 and December 31, 2015, was a capital lease obligation associated with Sandpiper's capacity, supply and operating agreement ($3.1 million and $3.5 million, respectively, net of current maturities and $4.5 million and $4.8 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.

Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. We have maintained a ratio of equity to total capitalization, including short-term borrowings, between 52 percent and 54 percent during the past three years. Our equity as a percent of total capital declined in 2015 as we financed several large revenue generating capital projects with short-term borrowings. As we continue to construct these projects in 2016, the ratio of equity to total capitalization, including short-term borrowings, will further decline temporarily.

As described below under “Short-term Borrowings,” we entered into a new Revolver with the Lenders on October 8, 2015, which increased our borrowing capacity by $150.0 million. To facilitate the refinancing of a portion of the short-term borrowings into long-term debt, as appropriate, we also entered into a long-term private placement Shelf Agreement with Prudential that is further described below under “Shelf Agreement.”

We will seek to align, as much as feasible, any such long-term debt or equity issuance(s) with the commencement of service, and associated earnings, for larger revenue generating capital projects. In addition, the exact timing of any long-term debt or equity issuance(s) will be based on market conditions.

Short-term Borrowings

Our outstanding short-term borrowings at March 31, 2016 and December 31, 2015 were $172.7 million and $173.4 million, respectively. The weighted average interest rates for our short-term borrowings were 1.42 percent and 1.09 percent, for the three months endedMarch 31, 2016 and 2015, 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. As of March 31, 2016, we had four unsecured bank credit facilities with three financial institutions totaling $170.0 million in total available credit. In addition, since October 2015, we have $150.0 million of additional short-term debt capacity available under a Revolver with five participating Lenders. The terms of the Revolver are described in further detail below. We also had access to two credit facilities, which totaled $40.0 million; however, these credit facilities expired on October 31, 2015 and were not renewed given the addition of the new Revolver. None of the unsecured bank lines of credit requires compensating balances. We are currently authorized by our Board of Directors to borrow up to $275.0 million of short-term borrowing.

The $150.0 million Revolver for five years is subject to specified terms and conditions. Borrowings under the Revolver will be used for general corporate purposes, including repayments of short-term borrowings, working capital requirements and capital expenditures. Borrowings under the Revolver will bear interest at: (i) the LIBOR Rate plus an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization, both as defined by the Credit Agreement,

- 41

or (ii) the base rate plus 0.25% or less. Interest is payable quarterly, and the Revolver is subject to a commitment fee on the unused portion of the facility. We may extend the expiration date for up to two years on any anniversary date of the Revolver, with such extension subject to the Lenders' approval. We may also request the Lenders to increase the Revolver to $200.0 million, with any increase at the sole discretion of each Lender. At March 31, 2016 and December 31, 2015, we had borrowed $40.0 million and $35.0 million, respectively, under the Revolver.

Shelf Agreement

On October 8, 2015, we entered into a committed Shelf Agreement with Prudential and other purchasers that may become a party to the Shelf Agreement. Under the terms of the Shelf Agreement, we may request that Prudential purchase, over the next three years, up to $150.0 million of our Shelf Notes at a fixed interest rate and with a maturity date not to exceed twenty years from the date of issuance. Prudential and its affiliates are under no obligation to purchase any of the Shelf Notes. The interest rate and terms of payment of any series of Shelf Notes will be determined at the time of purchase. We currently anticipate that the proceeds from the sale of any series of Shelf Notes will be used for general corporate purposes, including refinancing of short-term borrowings and/or repayment of outstanding indebtedness and financing of capital expenditures on future projects; however, actual use of such proceeds will be determined at the time of a purchase and each request for purchase with respect to a series of Shelf Notes will specify the use of the proceeds.

The Shelf Agreement sets forth certain business covenants to which we are subject when any Shelf Note is outstanding, including covenants that limit or restrict us and our subsidiaries from incurring indebtedness and incurring liens and encumbrances on any of our property.

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the three months ended March 31, 2016 and 2015:

	Three Months Ended
	March 31,
	2016			2015
(in thousands)
Net cash provided by (used in):
Operating activities	$	42,428		$	62,333
Investing activities	(36,895		)	(25,333		)
Financing activities	(5,073		)	(25,404		)
Net increase in cash and cash equivalents	460			11,596
Cash and cash equivalents—beginning of period	2,855			4,574
Cash and cash equivalents—end of period	$	3,315		$	16,170

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, 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 three months ended March 31, 2016 and 2015, net cash provided by operating activities was $42.4 million and $62.3 million, respectively, resulting in a decrease in cash flows of $19.9 million. Significant operating activities generating the cash flows change were as follows:

• The changes in net regulatory assets and liabilities decreased cash flows by $12.6 million, due primarily to the change in fuel costs collected through the various fuel cost recovery mechanisms.

• The change in income taxes receivable decreased cash flows by $12.9 million, due primarily to the absence of a large tax refund received during the first three months of 2015, related to our 2014 federal income tax obligation. The tax refund was due to bonus depreciation (approved by the President of the United States in December 2014), which reduced our 2014 federal income tax obligation.

• Net cash flows from changes in propane, natural gas and materials inventories decreased by approximately $2.3 million.

- 42

• Net income, adjusted for reconciling activities, increased cash flows by $6.1 million, due primarily to an increase in deferred income taxes as a result of availability and implementation of bonus depreciation in the first quarter of 2016, which resulted in higher book-to-tax timing difference, and higher non-cash adjustments for depreciation and amortization.

• Changes in customer deposits and refunds increased cash flows by $2.8 million.

• The changes in net accounts receivable and payable increased cash flows by $2.3 million, due primarily to an increase in net cash flows from receivables and payables from natural gas and electric distribution operations, partially offset by the timing of the collections and payments associated with our natural gas marketing subsidiary.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $36.9 million and $25.3 million during the three months ended March 31, 2016 and 2015, respectively, resulting in a decrease in cash flows of $11.6 million. The decrease was due primarily to an increase in cash used for capital expenditures.

Cash Flows Used in Financing Activities

Net cash used in financing activities totaled $5.1 million in the first three months of 2016, compared to $25.4 million in the same period in 2015, resulting in an increase in cash flows of $20.3 million. The decrease in net cash used in financing activities during the first three months of 2016 was due primarily to $20.1 million in higher borrowing under our line of credit agreements and a $690,000 increase in cash overdrafts.

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 March 31, 2016 was $48.7 million, with the guarantees expiring on various dates through March 31, 2017.

We have issued letters of credit totaling $8.1 million related to the electric transmission services for FPU's northwest electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through March 2017. There have been no draws on these letters of credit as of March 31, 2016. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that they will be renewed to the extent necessary in the future. Additional information is presented inItem 1, Financial Statements, Note 6, Other Commitments and Contingencies in the Condensed Consolidated Financial Statements.

Contractual Obligations

There has been no material change in the contractual obligations presented in our 2015 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 March 31, 2016.

	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)	$	19,155	$	7,334	$	—	$	—	$	26,489
Forward purchase contracts - Propane (2)	279		—		—		—		279
Total	$	19,434	$	7,334	$	—	$	—	$	26,768

⁽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.

- 43

Rates and Regulatory Matters

Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by the respective state PSC; Eastern Shore is subject to regulation by the FERC; and Peninsula Pipeline is subject to regulation by the Florida PSC. At March 31, 2016, we were involved in regulatory matters in each of the jurisdictions in which we operate. Our significant regulatory matters are 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.

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 $153.6 million at March 31, 2016, as compared to a fair value of $171.4 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 6.6 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 March 31, 2016 is presented in the following table:

	Quantity in	Estimated Market		Weighted Average
At March 31, 2016	Gallons	Prices		Contract Prices
Forward Contracts
Sale	630,000	$	0.4425	$	0.4425
Purchase	631,000	$	0.4413	$	0.4422

Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the second quarter of 2016.

- 44

Our natural gas distribution, electric distribution and natural gas marketing operations have entered into agreements with various suppliers to purchase natural gas, electricity and propane for resale to their customers. Purchases under these contracts either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis.

At March 31, 2016 and December 31, 2015, we marked these forward and other contracts to market, using market transactions in either the listed or OTC markets, which resulted in the following assets and liabilities:

(in thousands)	March 31, 2016		December 31, 2015
Mark-to-market energy assets, including put and call options and swap agreements	$	—	$	153
Mark-to-market energy liabilities, including swap agreements	$	423	$	433

- 45

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of the Company, with the participation of other Company officials, have evaluated our “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e), promulgated under the Securities Exchange Act of 1934, as amended) as of March 31, 2016. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of March 31, 2016.

Changes in Internal Control over Financial Reporting

During the quarter ended March 31, 2016, 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.

- 46

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, 2015, 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)
January 1, 2016 through January 31, 2016 (1)	379	$	53.54	—	—
February 1, 2016 through February 29, 2016	—	$	—	—	—
March 1, 2016 through March 31, 2016	—	$	—	—	—
Total	379	$	53.54	—	—

⁽¹⁾  Chesapeake Utilities 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, 2015. During the quarter ended March 31, 2016, 379 shares were purchased through the reinvestment of dividends on deferred stock units.

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

Item 3. Defaults upon Senior Securities

None.

Item 5. Other Information

None.

- 47

Item 6. Exhibits

31.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated May 4, 2016.
31.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934, dated May 4, 2016.
32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 4, 2016.
32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, dated May 4, 2016.
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.

- 48

SIGNATURES

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

CHESAPEAKE UTILITIES CORPORATION

/S/ BETH W. COOPER

Beth W. Cooper

Senior Vice President and Chief Financial Officer

Date: May 5, 2016

- 49

EX-31.1

EXHIBIT 31.1

CERTIFICATE PURSUANT TO RULE 13A-14(A)

UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Michael P. McMasters, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2016 of Chesapeake Utilities Corporation;

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

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

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

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

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

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

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

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

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

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

Date: May 5, 2016

/S/ MICHAEL P. MCMASTERS

Michael P. McMasters

President and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATE PURSUANT TO RULE 13A-14(A)

UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Beth W. Cooper, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended March 31, 2016 of Chesapeake Utilities Corporation;

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

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

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

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

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

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

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

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

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

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

Date: May 5, 2016

/S/ BETH W. COOPER

Beth W. Cooper

Senior Vice President and Chief Financial Officer

EX-32.1

EXHIBIT 32.1

Certificate of Chief Executive Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, Michael P. McMasters, President and Chief Executive Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Quarterly Report on Form 10-Q of Chesapeake Utilities Corporation (“Chesapeake”) for the period ended March 31, 2016, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/S/ MICHAEL P. MCMASTERS

Michael P. McMasters

May 5, 2016

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

EX-32.2

EXHIBIT 32.2

Certificate of Chief Financial Officer

of

Chesapeake Utilities Corporation

(pursuant to 18 U.S.C. Section 1350)

I, Beth W. Cooper, Senior Vice President and Chief Financial Officer of Chesapeake Utilities Corporation, certify that, to the best of my knowledge, the Quarterly Report on Form 10-Q of Chesapeake Utilities Corporation (“Chesapeake”) for the period ended March 31, 2016, filed with the Securities and Exchange Commission on the date hereof (i) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934, as amended, and (ii) the information contained therein fairly presents, in all material respects, the financial condition and results of operations of Chesapeake.

/S/ BETH W. COOPER

Beth W. Cooper

May 5, 2016

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

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2016	Apr. 30, 2016
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	Large Accelerated Filer
Document Type	10-Q
Document Period End Date	Mar. 31, 2016
Document Fiscal Year Focus	2016
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		15,308,467

XML

Condensed Consolidated Statements of Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating Revenues
Regulated Energy	$ 89,216	$ 109,582
Unregulated Energy	57,080	60,499
Total Operating Revenues	146,296	170,081
Operating Expenses
Regulated Energy cost of sales	34,905	57,129
Unregulated Energy and other cost of sales	34,024	35,234
Operations	27,159	26,945
Maintenance	2,479	2,703
Depreciation and amortization	7,503	6,975
Other taxes	3,846	3,587
Total Operating Expenses	109,916	132,573
Operating Income	36,380	37,508
Other (Expense) Income, net	(34)	133
Interest charges	2,650	2,448
Income Before Income Taxes	33,696	35,193
Income taxes	13,329	14,084
Net Income	$ 20,367	$ 21,109
Weighted Average Common Shares Outstanding:
Basic (shares)	15,286,842	14,604,841
Diluted (shares)	15,331,912	14,656,310
Earnings Per Share of Common Stock:
Basic (in dollars per share)	$ 1.33	$ 1.45
Diluted (in dollars per share)	1.33	1.44
Cash Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.2875	$ 0.27

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Net Income	$ 20,367	$ 21,109
Other Comprehensive Income (Loss), net of tax:
Amortization of prior service cost, net of tax of $(8) and $(7), respectively	(12)	(10)
Net gain, net of tax of $67 and $62, respectively	101	92
Cash Flow Hedges, net of tax:
Unrealized loss on commodity contract cash flow hedges, net of tax of $- and $17, respectively	0	26
Total Other Comprehensive Income	89	108
Comprehensive Income	$ 20,456	$ 21,217

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Statement of Comprehensive Income [Abstract]
Amortization of prior service cost, tax	$ (8)	$ (7)
Net gain, tax	67	62
Unrealized loss on commodity contract cash flow hedges, tax	$ 0	$ 17

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment
Regulated Energy	$ 850,041	$ 842,756
Unregulated Energy	147,221	145,734
Other businesses and eliminations	19,430	18,999
Total property, plant and equipment	1,016,692	1,007,489
Less: Accumulated depreciation and amortization	(222,650)	(215,313)
Plus: Construction work in progress	87,187	62,774
Net property, plant and equipment	881,229	854,950
Current Assets
Cash and cash equivalents	3,315	2,855
Accounts receivable (less allowance for uncollectible accounts of $684 and $909, respectively)	44,434	41,007
Accrued revenue	12,331	12,452
Propane inventory, at average cost	5,412	6,619
Other inventory, at average cost	4,289	3,803
Regulatory assets	6,451	8,268
Storage gas prepayments	1,213	3,410
Income taxes receivable	16,260	24,950
Prepaid expenses	4,982	7,146
Mark-to-market energy assets	0	153
Other current assets	1,688	1,044
Total current assets	100,375	111,707
Deferred Charges and Other Assets
Goodwill	15,070	14,548
Other intangible assets, net	2,128	2,222
Investments, at fair value	3,674	3,644
Regulatory assets	76,934	77,519
Receivables and other deferred charges	2,574	2,831
Total deferred charges and other assets	100,380	100,764
Total Assets	1,081,984	1,067,421
Stockholders’ equity
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)	7,449	7,432
Additional paid-in capital	190,389	190,311
Retained earnings	182,165	166,235
Accumulated other comprehensive loss	(5,751)	(5,840)
Deferred compensation obligation	2,221	1,883
Treasury stock	(2,221)	(1,883)
Total stockholders’ equity	374,252	358,138
Long-term debt, net of current maturities	148,602	149,006
Total capitalization	522,854	507,144
Current Liabilities
Current portion of long-term debt	9,163	9,151
Short-term borrowing	172,742	173,397
Accounts payable	36,299	39,300
Customer deposits and refunds	27,039	27,173
Accrued interest	3,021	1,311
Dividends payable	4,400	4,390
Accrued compensation	4,107	10,014
Regulatory liabilities	9,313	7,365
Mark-to-market energy liabilities	423	433
Other accrued liabilities	7,942	7,059
Total current liabilities	274,449	279,593
Deferred Credits and Other Liabilities
Deferred income taxes	197,416	192,600
Regulatory liabilities	42,946	43,064
Environmental liabilities	8,843	8,942
Other pension and benefit costs	32,848	33,481
Deferred investment tax credits and other liabilities	2,628	2,597
Total deferred credits and other liabilities	$ 284,681	$ 280,684
Other commitments and contingencies
Total Capitalization and Liabilities	$ 1,081,984	$ 1,067,421

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 684	$ 909
Common stock, par value (in dollars per share)	$ 0.4867	$ 0.4867
Common stock, shares authorized (shares)	25,000,000	25,000,000

XML

Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Operating Activities
Net Income	$ 20,367	$ 21,109
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	7,503	6,975
Depreciation and accretion included in other costs	1,646	1,689
Deferred income taxes, net	4,326	(496)
Realized (gain) loss on commodity contracts/sale of assets/investments	479	(840)
Unrealized loss on investments/commodity contracts	18	21
Employee benefits and compensation	380	300
Share-based compensation	649	537
Other, net	24	4
Changes in assets and liabilities:
Accounts receivable and accrued revenue	(3,738)	(8,014)
Propane inventory, storage gas and other inventory	3,073	5,337
Regulatory assets/liabilities, net	3,941	16,507
Prepaid expenses and other current assets	1,358	2,500
Accounts payable and other accrued liabilities	(1,604)	350
Income taxes receivable	8,841	21,753
Customer deposits and refunds	(134)	(2,890)
Accrued compensation	(5,943)	(5,262)
Other assets and liabilities, net	1,242	2,753
Net cash provided by operating activities	42,428	62,333
Investing Activities
Property, plant and equipment expenditures	(36,847)	(25,482)
Proceeds from sales of assets	51	198
Environmental expenditures	(99)	(49)
Net cash used in investing activities	(36,895)	(25,333)
Financing Activities
Common stock dividends	(4,204)	(3,763)
Issuance of stock for Dividend Reinvestment Plan	195	217
Change in cash overdrafts due to outstanding checks	(1,501)	(2,191)
Net borrowing (repayment) under line of credit agreements	839	(19,269)
Repayment of long-term debt and capital lease obligation	(402)	(398)
Net cash used in financing activities	(5,073)	(25,404)
Net Increase in Cash and Cash Equivalents	460	11,596
Cash and Cash Equivalents—Beginning of Period	2,855	4,574
Cash and Cash Equivalents—End of Period	$ 3,315	$ 16,170

XML

Condensed Consolidated Statements of Stockholders' Equity (Unaudited) - 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, 2014	[1]		14,588,711
Beginning 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		41,140			41,140
Other comprehensive loss		(164)				(164)
Dividend declared ($1.1325 per share)		(17,222)			(17,222)
Retirement savings plan and dividend reinvestment plan (shares)			43,275
Retirement savings plan and dividend reinvestment plan		2,235	$ 21	2,214
Common stock issued in acquisition (shares)			592,970
Common stock issued in acquisition		30,165	$ 289	29,876
Share-based compensation (shares)	[1],[2],[3]		45,703
Share-based compensation and tax benefit	[2],[3]	1,662	$ 22	1,640
Treasury stock activities		0					625	(625)
Ending Balances (shares) at Dec. 31, 2015	[1]		15,270,659
Ending Balances at Dec. 31, 2015		358,138	$ 7,432	190,311	166,235	(5,840)	1,883	(1,883)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		20,367			20,367
Other comprehensive loss		89				89
Dividend declared ($0.2875 per share) and dividend reinvestment plan (shares)			6,787
Dividend declared ($0.2875 per share) and dividend reinvestment plan		(4,057)	$ 3	377	(4,437)
Share-based compensation (shares)	[1],[2],[3]		27,522
Share-based compensation and tax benefit	[2],[3]	(285)	$ 14	(299)
Treasury stock activities		0					338	(338)
Ending Balances (shares) at Mar. 31, 2016	[1]		15,304,968
Ending Balances at Mar. 31, 2016		$ 374,252	$ 7,449	$ 190,389	$ 182,165	$ (5,751)	$ 2,221	$ (2,221)

[1] Includes 75,959 and 70,631 shares at March 31, 2016 and December 31, 2015, 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 three months ended March 31, 2016, and for the year ended December 31, 2015, we withheld 12,031 and 12,620 shares, respectively, for taxes.

XML

Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) (Unaudited) - $ / shares	3 Months Ended	12 Months Ended
	Mar. 31, 2016	Dec. 31, 2015
Statement of Stockholders' Equity [Abstract]
Dividend declared (in dollars per share)	$ 0.2875	$ 1.1325
Deferred compensation plan held Rabbi Trust (shares)	75,959	70,631
Shares issued under the performance incentive plan withheld for employee taxes (shares)	12,031	12,620

XML

Summary of Accounting Policies

3 Months Ended

Mar. 31, 2016

Accounting Policies [Abstract]

Summary of Accounting Policies

Summary of Accounting Policies

Basis of Presentation

References in this document to the “Company,” “Chesapeake Utilities,” “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, 2015. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

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

We reclassified certain amounts in the condensed consolidated balance sheet as of December 31, 2015 and condensed consolidated statement of cash flows for the three months ended March 31, 2015 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our consolidated financial statements.

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

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 became effective for us on January 1, 2016, and we applied the provisions of this standard on a retrospective basis. As a result of the adoption of this standard, debt issuance costs totaling $323,000 and $333,000 at March 31, 2016 and December 31, 2015, respectively, previously presented as other deferred charges, a non-current asset, are now presented as a deduction from long-term debt, net of current maturities in our condensed consolidated balance sheets.

Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (ASC 350-40) - In April 2015, the FASB issued ASU 2015-05, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement. Under the new standard, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense in the period incurred. ASU 2015-05 became effective for us on January 1, 2016, and has been applied on a prospective basis. The standard did not have a material impact on our financial position or results of operations for the quarter.

Debt Issuance Costs (ASC 835-30) - In August 2015, the FASB issued ASU 2015-15, Simplifying the Presentation of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This standard clarifies treatment of debt issuance costs associated with line-of-credit arrangements that were not specifically addressed in ASU 2015-03. Issuance costs incurred in connection with line-of-credit arrangements may be treated as an asset and amortized over the term of the line-of-credit arrangement. ASU 2015-15 became effective for us on January 1, 2016. The standard did not have a material impact on our financial position and results of operations.

Business Combinations (ASC 805) - In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. The standard eliminates the requirement to restate prior period financial statements for measurement period adjustments. The guidance requires that the cumulative impact of a measurement-period adjustment (including the impact of prior periods) be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 was effective for our interim and annual financial statements issued after January 1, 2016 and was adopted on a prospective basis. Adoption of this standard did not have a material impact on our financial position and results of operations.

Balance Sheet Classification of Deferred Taxes (ASC 740) - In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which requires all deferred assets and liabilities along with any related valuation allowance to be classified as noncurrent on the balance sheet for our annual financial statements beginning January 1, 2017 and for our interim financial statements beginning January 1, 2018; however, early adoption is permitted. We adopted this standard in the first quarter of 2016 on a retrospective basis and adjusted the December 31, 2015 balance sheet, by eliminating the current deferred income taxes asset and decreasing noncurrent deferred income taxes liability by $831,000.

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 may have on our financial position and results of operations.

Inventory (ASC 330) - In July 2015, the FASB issued ASU 2015-11, Inventory. Under this guidance, inventories are required to be measured at the lower of cost or net realizable value. Net realizable value represents the estimated selling price less costs associated with completion, disposal and transportation. ASU 2015-11 will be effective for our interim and annual financial statements issued beginning January 1, 2017; however, early adoption is permitted. The standard is to be adopted on a prospective basis. We are assessing the impact this standard may have on our financial position and results of operations.

Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which provides updated guidance regarding accounting for leases. This update requires a lessee to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are evaluating the effect of this update on our financial position and results of operations.

Compensation (ASC 718) - In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which simplifies several aspects of accounting for employee share-based payment transactions, including accounting for income taxes, forfeitures, and statutory tax withholding requirements, and classification in the statement of cash flows. ASU 2016-09 will be effective for our annual and interim financial statements beginning January 1, 2017, although early adoption is permitted. The amendments included in this update are to be applied prospectively except for changes impacting the presentation of the cash flow statement that can be applied prospectively or retrospectively. We are evaluating the effect of this update on our financial position and results of operations.

XML

Calculation of Earnings Per Share

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Calculation of Earnings Per Share

Calculation of Earnings Per Share

	Three Months Ended
	March 31,
	2016		2015
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	20,367	$	21,109
Weighted average shares outstanding	15,286,842		14,604,841
Basic Earnings Per Share	$	1.33	$	1.45
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	20,367	$	21,109
Reconciliation of Denominator:
Weighted shares outstanding—Basic	15,286,842		14,604,841
Effect of dilutive securities:
Share-based compensation	45,070		51,469
Adjusted denominator—Diluted	15,331,912		14,656,310
Diluted Earnings Per Share	$	1.33	$	1.44

XML

Acquisitions

3 Months Ended

Mar. 31, 2016

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, our then newly formed, wholly-owned subsidiary. Aspire Energy is an unregulated natural gas infrastructure company with approximately 2,500 miles of pipeline systems in 40 counties throughout Ohio.  The majority of Aspire Energy’s margin is derived from long-term supply agreements with Columbia Gas of Ohio and Consumers Gas Cooperative which together serve more than 20,000 end-use customers.  Aspire Energy sources gas primarily from 300 conventional producers. Aspire Energy also provides gathering and processing services necessary to maintain quality and reliability to its wholesale markets.

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. In addition, we paid $27.5 million in cash and assumed $1.7 million of existing outstanding debt, which we paid off on the same date. We also acquired $6.8 million of cash on hand at closing.

(in thousands)	Net Purchase Price
Chesapeake Utilities 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 provided for additional contingent cash consideration to Gatherco's shareholders of up to $15.0 million based on a percentage of revenue generated from potential new gathering opportunities over five years.

We incurred $1.3 million in transaction costs associated with this merger, $514,000 of which was expensed during 2015. Transaction costs were included in operations expense in the accompanying condensed consolidated statements of income. The revenue and net income from this acquisition for the three months ended March 31, 2016, included in our condensed consolidated statements of income, were $7.9 million and $1.7 million, respectively. This acquisition was accretive to earnings per share in the first full year of operations, generating $0.03 in additional earnings per share.

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

	Purchase price
(in thousands)	Allocation
Purchase price	$	57,658
Property plant and equipment	53,203
Cash	6,806
Accounts receivable	3,629
Income taxes receivable	3,163
Other assets	425
Total assets acquired	67,226
Long-term debt	1,696
Deferred income taxes	13,409
Accounts payable	3,837
Other current liabilities	745
Total liabilities assumed	19,687
Net identifiable assets acquired	47,539
Goodwill	$	10,119

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.

In December 2015 and during the first quarter of 2016, we adjusted the allocation of the purchase price based on additional information available. The adjustments resulted in a change in the fair value of property, plant and equipment, deferred income tax liabilities, inventory, income taxes receivable and other current liabilities. Goodwill from the merger decreased from $11.1 million to $10.1 million after incorporating these adjustments. The allocation of the purchase price and valuation of assets are final. The valuation of additional contingent cash consideration may be adjusted as additional information becomes available.

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 statements of income for the three months ended March 31, 2016 were not material.

XML

Rates and Other Regulatory Activities

3 Months Ended

Mar. 31, 2016

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 Utilities' 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

Rate Case Filing: On December 21, 2015, our Delaware division filed an application with the Delaware PSC for a base rate increase and certain other changes to its tariff. We proposed an increase of $4.7 million, or nearly ten percent, in our revenue requirement based on the test period ending March 31, 2016. We also proposed new service offerings to promote growth and a revenue decoupling mechanism for residential and small commercial customers. A decision on the application is expected during the fourth quarter of 2016. Pending the decision, the Delaware division increased rates on an interim basis by $2.5 million effective February 19, 2016. These rates, which are subject to refund, represent a five percent increase over current rates.

Maryland

Sandpiper Rate Case Filing: On December 1, 2015, Sandpiper filed an application with the Maryland PSC for a base rate increase and certain other changes to its tariff. We proposed an increase of $950,000, or five percent, in our revenue requirement, based on the test period ended December 31, 2015. We also proposed a stratification of rate classes, based on cost of service, and a revenue-decoupling mechanism for residential and small commercial customers. A decision on the application is expected during the third quarter of 2016.

Florida

On September 1, 2015, FPU’s electric division filed to recover the cost of the proposed Florida Power & Light Company interconnect project through FPU's annual Fuel and Purchased Power Cost Recovery Clause filing. The interconnect project will enable FPU's electric division to negotiate a new power purchase agreement that will mitigate fuel costs for its Northeast division. This action was approved by the Florida PSC at its Agenda Conference held on December 3, 2015. On January 22, 2016, the Office of Public Counsel filed an appeal of the Florida PSC's decision with the Florida Supreme Court. Legal briefs have been filed, but no decision has been reached at this time.

On February 2, 2016, FPU’s natural gas division filed a petition with the Florida PSC for approval of an amendment to its existing transportation agreement with the City of Lake Worth, located in Palm Beach County, Florida. The amendment allows the city to resell natural gas distributed by FPU to the city’s compressed natural gas station. The city will then resell the natural gas, after compression, to its customers. The amendment to the transportation agreement was approved by the Florida PSC at its Agenda Conference held April 5, 2016.

Eastern Shore

White Oak Mainline Expansion Project: On November 21, 2014, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate 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. 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 alternate routes for a segment of the pipeline route in the vicinity of the Kemblesville, Pennsylvania Historic District. On June 2, 2015, a field meeting was conducted to review the proposed route and alternate routes. In response to comments received from the National Park Service and other stakeholders, the FERC requested that Eastern Shore conduct an additional investigation in relation to Eastern Shore's existing right-of-way. On July 9, 2015, the FERC issued a 30-day public scoping notice in advance of issuing an environmental assessment in order to solicit comments from the public regarding construction of the Kemblesville loop. On August 18, 2015, Eastern Shore submitted supplemental information to the FERC regarding the results of its investigation of the Kemblesville loop.

On November 18, 2015, Eastern Shore filed an amendment to this application, which indicated the preferred pipeline route. On February 10, 2016 the FERC issued a notice to prepare an environmental assessment and will combine both the White Oak Mainline Expansion project and System Reliability Project into a single assessment. The environmental assessment was issued on April 25, 2016, with the FERC's 90-day authorization decision to be issued on July 24, 2016.

On March 28, 2016, subsequent to the issuance of the schedule, FERC issued another environmental data request concerning the United States Department of Agriculture and an agricultural conservation easement on a tract of land where the White Oak Mainline Project would install a portion of the pipeline in its existing right-of way. On April 4, 2016, Eastern Shore responded to the data request.

System Reliability Project: On May 22, 2015, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate approximately 10.1 miles of 16-inch pipeline looping and 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. Since the project is intended to improve system reliability, Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project.

On June 8, 2015, the FERC filed a notice of the application, and the comment period ended on June 29, 2015. Two interested parties filed comments and protests with the FERC. Eastern Shore has filed answers to the comments and protests from the two parties.

On September 4, 2015, the FERC issued a notice of intent to prepare an environmental assessment, and Eastern Shore responded to the FERC Staff's environmental data requests. On February 10, 2016, the FERC issued a notice combining the System Reliability Project and White Oak Mainline Expansion project into a single environmental assessment. On March 2, 2016, the FERC issued a revised notice rescheduling the issuance of the combined environmental assessment to April 25, 2016, with the 90-day authorization decision to be issued on July 24, 2016.

TETLP Capacity Expansion Project: On October 13, 2015, Eastern Shore submitted an application to the FERC to make certain measurement and related improvements at its TETLP interconnect facilities, which would enable Eastern Shore to increase natural gas receipts from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. On December 22, 2015, the FERC authorized Eastern Shore to proceed with the project. On March 11, 2016, the capacity expansion project was placed into service.

XML

Environmental Commitments and Contingencies

3 Months Ended

Mar. 31, 2016

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.

MGP Sites

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

As of March 31, 2016, we had approximately $10.0 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 $10.2 million of which has been recovered as of March 31, 2016, leaving approximately $3.8 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

In addition to the FPU MGP sites, we had $353,000 in environmental liabilities at March 31, 2016 related to Chesapeake Utilities' MGP sites in Salisbury, Maryland and Winter Haven, Florida, representing our estimate of future costs associated with these sites. As of March 31, 2016, we had approximately $58,000 in regulatory and other assets for future recovery through Chesapeake Utilities' rates.

During the first quarter of 2015, we established $273,000 in environmental liabilities related to Chesapeake Utilities' 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 Utilities' rates via our environmental rider. On February 23, 2016, the Delaware PSC approved an environmental surcharge for the recovery of Chesapeake Utilities' environmental expenses associated with the Seaford site for the period of October 1, 2014 through September 30, 2015. Chesapeake Utilities will file for recovery of its expenses incurred between October 1, 2015 and September 30, 2016 by October 31, 2016. As of March 31, 2016, we had approximately $186,000 in environmental liabilities and $269,000 in regulatory and other assets related to this site.

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

West Palm Beach, Florida

Remedial options are being evaluated to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated a MGP. FPU is 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. The Start-Up and Monitoring Report, dated November 30, 2015, was submitted for review and comment. A letter dated January 6, 2016, was received from FDEP, which provided minor comments. On January 12, 2016, FDEP conducted a facility inspection and found no problems or deficiencies.

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

Sanford, Florida

FPU is the current owner of property in Sanford, Florida, which was a former MGP site that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP at this site. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of March 31, 2016, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements.

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

As of March 31, 2016, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be $24,000. However, we are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense to liability for costs exceeding $13.0 million to implement the final remedy for this site, as provided in the Third Participation Agreement, or will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid under the Third Participation Agreement. No such claims have been made as of March 31, 2016.

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, 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 requires a limited semi-annual monitoring program. The most recent groundwater-monitoring event was conducted in March of 2016. Natural Attenuation Default criteria were met at all locations sampled.

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 next semi-annual RAP implementation status report, submitted on January 8, 2015. FDEP approved the plan to expand the bio-sparging operations in the southern portion of the site, and additional sparge points were installed and connected to the operating system in the first quarter of 2016.

Although specific remedial actions for the site 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, the DNREC provided the evaluation, which found several compounds within the groundwater and soil that require further investigation. We submitted an application to the DNREC on April 2, 2015, which was approved on September 17, 2015, to enter this site into the voluntary cleanup program. A remedial investigation was conducted in December 2015, and a draft remedial investigation report was submitted to the DNREC on March 7, 2016. We anticipate submitting the final report, based on comments from the DNREC during the second quarter of 2016. We estimate the cost of potential remedial actions, based on the findings of the DNREC report, to be between $273,000 and $465,000. We also believe these costs will be recoverable from customers through rates.

Cambridge, Maryland

We are discussing with the MDE 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.

Ohio

We have also completed the investigation, assessment and remediation of eight natural gas pipeline facilities in Ohio that Aspire Energy acquired from Gatherco pursuant to the merger. The costs incurred to date associated with remediation activities for these facilities, is approximately $1.4 million. Pursuant to the merger agreement, an escrow was established to fund certain claims by Chesapeake Utilities and Aspire Energy for indemnification by Gatherco, including environmental claims. Gatherco's indemnification obligations for environmental matters apply to remediation costs in excess of $431,250 and are capped at $1.7 million. We have submitted our request for reimbursement to the escrow agent.

XML

Other Commitments and Contingencies

3 Months Ended

Mar. 31, 2016

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. For our Delaware and Maryland natural gas distribution divisions, we have a contract with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage capacity, which expires on March 31, 2017.

In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term. Approximately three 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. Approximately three years remain under this contract. 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 Utilities' 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 Utilities 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 monthly purchase commitment ranges from 9,982 to 13,423 Dts/dfor a one-year term. PESCO is obtaining and reviewing proposals from suppliers and anticipates executing new agreements before the existing agreements expire.

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times, and (b) a fixed charge coverage ratio greater than 1.5 times. If FPU fails to comply with either of these ratios, it has 30 days to cure the default or, if the default is not cured, to provide an irrevocable letter of credit. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet either of these ratios, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of March 31, 2016, FPU was in compliance with all of the requirements of its fuel supply contracts.

Corporate Guarantees

The Board of Directors has authorized the Company to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our obligations, including the obligations of our subsidiaries. The maximum authorized liability under such guarantees and letters of credit is $65.0 million.

We have issued corporate guarantees to certain vendors of our subsidiaries, the largest of which are for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event that Xeron or PESCO defaults. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at March 31, 2016 was $48.7 million, with the guarantees expiring on various dates through March 2017.

Chesapeake Utilities 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).

We issued letters of credit totaling $8.1 million related to the electric transmission services for FPU's northwest electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through March 2017. There have been no draws on these letters of credit as of March 31, 2016. 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.

Tax-related Contingencies

We are subject to various audits and reviews by the federal, state, local and other governmental authorities regarding income taxes and taxes other than income. As of March 31, 2016, we maintained a liability of $50,000 related to unrecognized income tax benefits and $196,000 related to contingencies for taxes other than income. As of December 31, 2015, we maintained a liability of $50,000 related to unrecognized income tax benefits and $310,000 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.

XML

Segment Information

3 Months Ended

Mar. 31, 2016

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, whose services include natural gas gathering, processing, transportation and supply (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.

The remainder of our operations is presented as “Other businesses and eliminations”, which consists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations.

The following table presents financial information about our reportable segments:

	Three Months Ended
	March 31,
	2016			2015
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	88,894		$	109,292
Unregulated Energy segment	57,402			60,789
Total operating revenues, unaffiliated customers	$	146,296		$	170,081
Intersegment Revenues (1)
Regulated Energy segment	$	322		$	290
Unregulated Energy segment	113			207
Other businesses	226			221
Total intersegment revenues	$	661		$	718
Operating Income
Regulated Energy segment	$	24,319		$	22,182
Unregulated Energy segment	11,936			15,229
Other businesses and eliminations	125			97
Total operating income	36,380			37,508
Other (Expense) income, net	(34		)	133
Interest	2,650			2,448
Income before Income Taxes	33,696			35,193
Income taxes	13,329			14,084
Net Income	$	20,367		$	21,109

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

(in thousands)	March 31, 2016		December 31, 2015
Identifiable Assets
Regulated Energy segment	$	879,878	$	872,065
Unregulated Energy segment	178,723		171,840
Other businesses and eliminations	23,383		23,516
Total identifiable assets	$	1,081,984	$	1,067,421

Our operations are entirely domestic.

XML

Accumulated Other Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 2016

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Loss

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements, call options and natural gas futures contracts, designated as commodity contracts cash flow hedges, are the components of our accumulated comprehensive income (loss). The following tables present the changes in the balance of accumulated other comprehensive loss for the three months endedMarch 31, 2016 and 2015. 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, 2015	$	(5,580	)	$	(260	)	$	(5,840	)
Other comprehensive loss before reclassifications	—			(283		)	(283		)
Amounts reclassified from accumulated other comprehensive loss	89			283			372
Net current-period other comprehensive income	89			—			89
As of March 31, 2016	$	(5,491	)	$	(260	)	$	(5,751	)

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2014	$	(5,643	)	$	(33	)	$	(5,676	)
Other comprehensive loss before reclassifications	—			(7		)	(7		)
Amounts reclassified from accumulated other comprehensive loss	82			33			115
Net prior-period other comprehensive income	82			26			108
As of March 31, 2015	$	(5,561	)	$	(7	)	$	(5,568	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three months endedMarch 31, 2016 and 2015. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.

	Three Months Ended
	March 31,
	2016			2015
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	20		$	17
Net loss (1)	(168		)	(154		)
Total before income taxes	(148		)	(137		)
Income tax benefit	59			55
Net of tax	$	(89	)	$	(82	)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	(322	)	$	—
Call options (2)	—			(55		)
Natural gas futures (2)	(149		)	—
Total before income taxes	(471		)	(55		)
Income tax benefit	188			22
Net of tax	(283		)	(33		)
Total reclassifications for the period	$	(372	)	$	(115	)

⁽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.

XML

Employee Benefit Plans

3 Months Ended

Mar. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three months endedMarch 31, 2016 and 2015 are set forth in the following table:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended March 31,	2016			2015			2016			2015			2016		2015		2016			2015			2016		2015
(in thousands)
Interest cost	$	105		$	102		$	630		$	626		$	23	$	23	$	11		$	11		$	14	$	15
Expected return on plan assets	(131		)	(135		)	(701		)	(777		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			—		2		(20		)	(19		)	—		—
Amortization of net loss	104			90			128			114			22		25		18			17			—		2
Net periodic cost (benefit)	78			57			57			(37		)	45		50		9			9			14		17
Amortization of pre-merger regulatory asset	—			—			191			190			—		—		—			—			2		2
Total periodic cost	$	78		$	57		$	248		$	153		$	45	$	50	$	9		$	9		$	16	$	19

We expect to record pension and postretirement benefit costs of approximately $1.6 million for 2016. 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 in 2009. 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 $2.7 million and $2.8 million at March 31, 2016 and December 31, 2015, respectively. The amortization included in pension expense is also being added to a net periodic loss of $802,000, which will increase our total expected benefit costs to $1.6 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 Utilities' operations is recorded to accumulated other comprehensive loss. The following table presents the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three months ended March 31, 2016 and 2015:

For the Three Months Ended March 31, 2016	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	—	$	(20	)	$	—	$	(20	)
Net loss	104		128		22		18			—		272
Total recognized in net periodic benefit cost	$	104	$	128	$	22	$	(2	)	$	—	$	252
Recognized from accumulated other comprehensive loss (1)	$	104	$	24	$	22	$	(2	)	$	—	$	148
Recognized from regulatory asset	—		104		—		—			—		104
Total	$	104	$	128	$	22	$	(2	)	$	—	$	252

For the Three Months Ended March 31, 2015	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	2	$	(19	)	$	—	$	(17	)
Net loss	90		114		25		17			2		248
Total recognized in net periodic benefit cost	$	90	$	114	$	27	$	(2	)	$	2	$	231
Recognized from accumulated other comprehensive loss (1)	$	90	$	22	$	27	$	(2	)	$	—	$	137
Recognized from regulatory asset	—		92		—		—			2		94
Total	$	90	$	114	$	27	$	(2	)	$	2	$	231

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

During the three months ended March 31, 2016, we contributed $104,000 to the Chesapeake Pension Plan and $337,000 to the FPU Pension Plan. We expect to contribute a total of $508,000 and $1.6 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2016, which represent the minimum annual contribution payments required.

The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three months ended March 31, 2016, were $38,000. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake Pension SERP in 2016. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three months ended March 31, 2016, were $21,000. We estimate that approximately $82,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2016. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three months ended March 31, 2016, were $38,000. We estimate that approximately $149,000 will be paid for such benefits under the FPU Medical Plan in 2016.

XML

Investments

3 Months Ended

Mar. 31, 2016

Investments, Debt and Equity Securities [Abstract]

Investments

Investments

The investment balances at March 31, 2016 and December 31, 2015, consisted of the following:

(in thousands)	March 31, 2016		December 31, 2015
Rabbi trust (associated with the Deferred Compensation Plan)	$	3,654	$	3,626
Investments in equity securities	20		18
Total	$	3,674	$	3,644

We classify these investments as trading securities and report them at their fair value. For the three months ended March 31,2016 and 2015, we recorded a net unrealized loss of $18,000 and a net unrealized gain of $104,000, 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 investments in the Rabbi Trust.

XML

Share-Based Compensation

3 Months Ended

Mar. 31, 2016

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 months endedMarch 31, 2016 and 2015:

	Three Months Ended
	March 31,
	2016			2015
(in thousands)
Awards to non-employee directors	$	165		$	150
Awards to key employees	484			387
Total compensation expense	649			537
Less: tax benefit	(261		)	(217		)
Share-based compensation amounts included in net income	$	388		$	320

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 grant date. 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 service as a director through the 2016 Annual Meeting of Stockholders. At March 31, 2016, there was $55,000 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 three months endedMarch 31, 2016:

	Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2015	110,398		$	38.34
Granted	46,571		$	61.50
Vested	(39,553	)	$	31.79
Expired	(2,325	)	$	42.25
Outstanding— March 31, 2016	115,091		$	49.26

In February 2016, our Board of Directors granted awards of 46,571 shares of common stock to key employees under the SICP. The shares granted in February 2016 are multi-year awards that will vest at the end of the three-year service period ending December 31, 2018. 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 grant date of each award. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

At March 31, 2016, the aggregate intrinsic value of the SICP awards granted to key employees was $7.2 million. At March 31, 2016, there was $3.3 million of unrecognized compensation cost related to these awards, which is expected to be recognized during 2016 through 2018.

XML

Derivative Instruments

3 Months Ended

Mar. 31, 2016

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. Aspire Energy has entered into contracts with producers to secure natural gas to meet its obligations. 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 and natural gas marketing operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of March 31, 2016, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Hedging Activities in 2016

Beginning in October 2015, PESCO entered into natural gas futures contracts associated with the purchase and sale of natural gas to specific customers. These contracts expire within two years and we have accounted for them as cash flow hedges. There is no ineffective portion of these hedges. At March 31, 2016, PESCO had a total of 6,723 Dts/d hedged under natural gas futures contracts, with a liability fair value of $423,000. The change in fair value of the natural gas futures contracts is recorded as unrealized gain/loss in other comprehensive income (loss).

Hedging Activities in 2015

In March, May and June 2015, Sharp paid a total of $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 2015-2016 heating season. We exercised the put options as propane prices fell 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. We received $239,000 representing the difference between the market prices and the strike prices during those months. We accounted for the put options as fair value hedges.

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 purchased in December 2015 through March 2016. Under these swap agreements, Sharp would have received the difference between the index prices (Mont Belvieu prices in December 2015 through March 2016) and the swap prices, which ranged from $0.5200 to $0.5950 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 the 2.5 million gallons that we purchased during this period. We accounted for the swap agreements as cash flow hedges. Sharp paid $484,000, representing the difference between the index prices and swap prices during those months of the swap agreements.

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 statements of income for the period of change. As of March 31, 2016, we had the following outstanding trading contracts, which we accounted for as derivatives:

	Quantity in	Estimated Market		Weighted Average
At March 31, 2016	Gallons	Prices		Contract Prices
Forward Contracts
Sale	630,000	$	0.4425	$	0.4425
Purchase	631,000	$	0.4413	$	0.4422

Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the second quarter of 2016.

Xeron entered into master netting agreements with two counterparties to mitigate exposure to counterparty credit risk. The master netting agreements enable Xeron to net these two counterparties' outstanding accounts receivable and payable, which are presented on a gross basis in the accompanying condensed consolidated balance sheets. At March 31, 2016, Xeron had no accounts receivable or accounts payable balances to offset with these two counterparties. At December 31, 2015, Xeron had a right to offset $431,000 of accounts payable with these two counterparties. At December 31, 2015, Xeron did not have outstanding accounts receivable with these two counterparties.

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of March 31, 2016 and December 31, 2015, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2016		December 31, 2015
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	—	$	1
Derivatives designated as fair value hedges
Put options	Mark-to-market energy assets			152
Total asset derivatives		$	—	$	153

	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2016		December 31, 2015
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	—	$	1
Derivatives designated as cash flow hedges
Propane swap agreements	Mark-to-market energy liabilities	—		323
Natural gas futures contracts	Mark-to-market energy liabilities	423		109
Total liability derivatives		$	423	$	433

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

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended March 31,
(in thousands)	(Loss) on Derivatives	2016			2015
Derivatives not designated as hedging instruments
Realized gain on forward contracts (1)	Revenue	$	187		$	277
Unrealized gain (loss) on forward contracts (1)	Revenue	1			(125		)
Propane swap agreements	Cost of sales	—			18
Derivatives designated as fair value hedges
Put /Call options	Cost of sales	73			506
Put /Call options (2)	Propane Inventory	—			(3		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	(364		)	—
Propane swap agreements	Other Comprehensive Loss	—			(12		)
Call options	Cost of sales	—			(81		)
Natural gas futures contracts	Cost of sales	149			—
Natural gas futures contracts	Other Comprehensive Loss	(462		)	—
Total		$	(416	)	$	580

⁽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 call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this put option effectively changed the value of propane inventory.

XML

Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2016

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 March 31, 2016 and December 31, 2015:

			Fair Value Measurements Using:
As of March 31, 2016	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	$	20	$	20	$	—	$	—
Investments—guaranteed income fund	$	525	$	—	$	—	$	525
Investments—mutual funds and other	$	3,129	$	3,129	$	—	$	—
Mark-to-market energy assets, incl. put options and swap agreements	$	—	$	—	$	—	$	—
Liabilities:
Mark-to-market energy liabilities incl. swap agreements	$	423	$	—	$	423	$	—

			Fair Value Measurements Using:
As of December 31, 2015	Fair Value		Quoted- Prices- in Active Markets (Level 1)		Significant- Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	18	$	18	$	—	$	—
Investments—guaranteed income fund	$	279	$	—	$	—	$	279
Investments—mutual funds and other	$	3,347	$	3,347	$	—	$	—
Mark-to-market energy assets, incl. put/call options	$	153	$	—	$	153	$	—
Liabilities:
Mark-to-market energy liabilities, incl. swap agreements	$	433	$	—	$	433	$	—

The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of March 31, 2016 and December 31, 2015:

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 - mutual funds and 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, swap agreements and natural gas futures contracts – The fair value of the propane put/call options, swap agreements and natural gas futures contracts are measured using market transactions for similar assets and liabilities in either the listed or OTC markets.

Level 3 Fair Value Measurements:

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

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the three months ended March 31, 2016 and 2015:

	Three Months Ended   March 31,
	2016		2015
(in thousands)
Beginning Balance	$	279	$	287
Purchases and adjustments	2		(5		)
Transfers	242		(3		)
Investment income	2		1
Ending Balance	$	525	$	280

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

At March 31, 2016, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

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

At March 31, 2016, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of $153.6 million. This compares to a fair value of $171.4 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, 2015, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of $153.7 million, compared to the estimated fair value of $165.1 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

XML

Long-Term Debt

3 Months Ended

Mar. 31, 2016

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Our outstanding long-term debt is shown below:

	March 31,			December 31,
(in thousands)	2016			2015
FPU secured first mortgage bonds (1) :
9.08% bond, due June 1, 2022	$	7,975		$	7,973
Uncollateralized senior notes:
6.64% note, due October 31, 2017	5,455			5,455
5.50% note, due October 12, 2020	10,000			10,000
5.93% note, due October 31, 2023	24,000			24,000
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	168			238
Capital lease obligation	4,490			4,824
Total long-term debt	158,088			158,490
Less: current maturities	(9,163		)	(9,151		)
Less: debt issuance costs	(323		)	(333		)
Total long-term debt, net of current maturities	$	148,602		$	149,006

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

Shelf Agreement

On October 8, 2015, we entered into a Shelf Agreement with Prudential. Under the terms of the Shelf Agreement, we may request that Prudential purchase, over the next three years, up to $150.0 million of our Shelf Notes at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance. Prudential is under no obligation to purchase any of the Shelf Notes. The interest rate and terms of payment of any series of Shelf Notes will be determined at the time of purchase. We currently anticipate the proceeds from the sale of any series of Shelf Notes will be used for general corporate purposes, including refinancing of short-term borrowing and/or repayment of outstanding indebtedness and financing capital expenditures on future projects; however, actual use of such proceeds will be determined at the time of a purchase, and each request for purchase with respect to a series of Shelf Notes will specify the exact use of the proceeds.

The Shelf Agreement sets forth certain business covenants to which we are subject when any Shelf Note is outstanding, including covenants that limit or restrict us and our subsidiaries from incurring indebtedness and incurring liens and encumbrances on any of our property.

XML

Short-Term Borrowing

3 Months Ended

Mar. 31, 2016

Short-term Borrowing [Abstract]

Short-Term Borrowing

Short-Term Borrowing

On October 8, 2015, we entered into a Credit Agreement with the Lenders for a $150.0 million Revolver for a term of five years subject to the terms and conditions of the Credit Agreement. Borrowings under the Revolver will be used for general corporate purposes, including repayments of short-term borrowings, working capital requirements and capital expenditures.

Borrowings under the Revolver will bear interest at: (i) the LIBOR Rate plus an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization, both as defined by the Credit Agreement, or (ii) the base rate plus 0.25 percent or less. Interest will be payable quarterly, and the Revolver is subject to a commitment fee on the unused portion of the facility. We may extend the expiration date for up to two years on any anniversary date of the Revolver, with such extension subject to the Lenders' approval. We may also request the Lenders to increase the Revolver to $200.0 million, with any increase at the sole discretion of each Lender. AtMarch 31, 2016 and December 31, 2015, we had borrowed $40.0 million and $35.0 million, respectively, under the Revolver.

XML

Summary of Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2016

Accounting Policies [Abstract]

Basis of Presentation

Basis of Presentation

References in this document to the “Company,” “Chesapeake Utilities,” “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, 2015. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

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

We reclassified certain amounts in the condensed consolidated balance sheet as of December 31, 2015 and condensed consolidated statement of cash flows for the three months ended March 31, 2015 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our consolidated financial statements.

New Accounting Pronouncements and Changes in Accounting Principles [Text Block]

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

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 became effective for us on January 1, 2016, and we applied the provisions of this standard on a retrospective basis. As a result of the adoption of this standard, debt issuance costs totaling $323,000 and $333,000 at March 31, 2016 and December 31, 2015, respectively, previously presented as other deferred charges, a non-current asset, are now presented as a deduction from long-term debt, net of current maturities in our condensed consolidated balance sheets.

Customer's Accounting for Fees Paid in a Cloud Computing Arrangement (ASC 350-40) - In April 2015, the FASB issued ASU 2015-05, Customer's Accounting for Fees Paid in a Cloud Computing Arrangement. Under the new standard, unless a software arrangement includes specific elements enabling customers to possess and operate software on platforms other than that offered by the cloud-based provider, the cost of such arrangements is to be accounted for as an operating expense in the period incurred. ASU 2015-05 became effective for us on January 1, 2016, and has been applied on a prospective basis. The standard did not have a material impact on our financial position or results of operations for the quarter.

Debt Issuance Costs (ASC 835-30) - In August 2015, the FASB issued ASU 2015-15, Simplifying the Presentation of Debt Issuance Costs Associated with Line-of-Credit Arrangements. This standard clarifies treatment of debt issuance costs associated with line-of-credit arrangements that were not specifically addressed in ASU 2015-03. Issuance costs incurred in connection with line-of-credit arrangements may be treated as an asset and amortized over the term of the line-of-credit arrangement. ASU 2015-15 became effective for us on January 1, 2016. The standard did not have a material impact on our financial position and results of operations.

Business Combinations (ASC 805) - In September 2015, the FASB issued ASU 2015-16, Simplifying the Accounting for Measurement-Period Adjustments. The standard eliminates the requirement to restate prior period financial statements for measurement period adjustments. The guidance requires that the cumulative impact of a measurement-period adjustment (including the impact of prior periods) be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 was effective for our interim and annual financial statements issued after January 1, 2016 and was adopted on a prospective basis. Adoption of this standard did not have a material impact on our financial position and results of operations.

Balance Sheet Classification of Deferred Taxes (ASC 740) - In November 2015, the FASB issued ASU 2015-17, Balance Sheet Classification of Deferred Taxes, which requires all deferred assets and liabilities along with any related valuation allowance to be classified as noncurrent on the balance sheet for our annual financial statements beginning January 1, 2017 and for our interim financial statements beginning January 1, 2018; however, early adoption is permitted. We adopted this standard in the first quarter of 2016 on a retrospective basis and adjusted the December 31, 2015 balance sheet, by eliminating the current deferred income taxes asset and decreasing noncurrent deferred income taxes liability by $831,000.

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 may have on our financial position and results of operations.

Inventory (ASC 330) - In July 2015, the FASB issued ASU 2015-11, Inventory. Under this guidance, inventories are required to be measured at the lower of cost or net realizable value. Net realizable value represents the estimated selling price less costs associated with completion, disposal and transportation. ASU 2015-11 will be effective for our interim and annual financial statements issued beginning January 1, 2017; however, early adoption is permitted. The standard is to be adopted on a prospective basis. We are assessing the impact this standard may have on our financial position and results of operations.

Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which provides updated guidance regarding accounting for leases. This update requires a lessee to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. We are evaluating the effect of this update on our financial position and results of operations.

Compensation (ASC 718) - In March 2016, the FASB issued ASU 2016-09, Improvements to Employee Share-Based Payment Accounting, which simplifies several aspects of accounting for employee share-based payment transactions, including accounting for income taxes, forfeitures, and statutory tax withholding requirements, and classification in the statement of cash flows. ASU 2016-09 will be effective for our annual and interim financial statements beginning January 1, 2017, although early adoption is permitted. The amendments included in this update are to be applied prospectively except for changes impacting the presentation of the cash flow statement that can be applied prospectively or retrospectively. We are evaluating the effect of this update on our financial position and results of operations.

XML

Calculation of Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2016

Earnings Per Share [Abstract]

Calculation of Basic and Diluted Earnings Per Share

	Three Months Ended
	March 31,
	2016		2015
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	20,367	$	21,109
Weighted average shares outstanding	15,286,842		14,604,841
Basic Earnings Per Share	$	1.33	$	1.45
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	20,367	$	21,109
Reconciliation of Denominator:
Weighted shares outstanding—Basic	15,286,842		14,604,841
Effect of dilutive securities:
Share-based compensation	45,070		51,469
Adjusted denominator—Diluted	15,331,912		14,656,310
Diluted Earnings Per Share	$	1.33	$	1.44

XML

Acquisitions Acquisitions (Tables)

3 Months Ended

Mar. 31, 2016

Business Combinations [Abstract]

Merger Consideration paid [Table Text Block]

(in thousands)	Net Purchase Price
Chesapeake Utilities 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]

	Purchase price
(in thousands)	Allocation
Purchase price	$	57,658
Property plant and equipment	53,203
Cash	6,806
Accounts receivable	3,629
Income taxes receivable	3,163
Other assets	425
Total assets acquired	67,226
Long-term debt	1,696
Deferred income taxes	13,409
Accounts payable	3,837
Other current liabilities	745
Total liabilities assumed	19,687
Net identifiable assets acquired	47,539
Goodwill	$	10,119

XML

Acquisitions Purchase Price Allocation (Tables)

3 Months Ended

Mar. 31, 2016

Business Combinations [Abstract]

Schedule of Recognized Identified Assets Acquired and Liabilities Assumed [Table Text Block]

	Purchase price
(in thousands)	Allocation
Purchase price	$	57,658
Property plant and equipment	53,203
Cash	6,806
Accounts receivable	3,629
Income taxes receivable	3,163
Other assets	425
Total assets acquired	67,226
Long-term debt	1,696
Deferred income taxes	13,409
Accounts payable	3,837
Other current liabilities	745
Total liabilities assumed	19,687
Net identifiable assets acquired	47,539
Goodwill	$	10,119

XML

Segment Information (Tables)

3 Months Ended

Mar. 31, 2016

Segment Reporting [Abstract]

Schedule of Segment Reporting Information by Segment

The following table presents financial information about our reportable segments:

	Three Months Ended
	March 31,
	2016			2015
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	88,894		$	109,292
Unregulated Energy segment	57,402			60,789
Total operating revenues, unaffiliated customers	$	146,296		$	170,081
Intersegment Revenues (1)
Regulated Energy segment	$	322		$	290
Unregulated Energy segment	113			207
Other businesses	226			221
Total intersegment revenues	$	661		$	718
Operating Income
Regulated Energy segment	$	24,319		$	22,182
Unregulated Energy segment	11,936			15,229
Other businesses and eliminations	125			97
Total operating income	36,380			37,508
Other (Expense) income, net	(34		)	133
Interest	2,650			2,448
Income before Income Taxes	33,696			35,193
Income taxes	13,329			14,084
Net Income	$	20,367		$	21,109

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

(in thousands)	March 31, 2016		December 31, 2015
Identifiable Assets
Regulated Energy segment	$	879,878	$	872,065
Unregulated Energy segment	178,723		171,840
Other businesses and eliminations	23,383		23,516
Total identifiable assets	$	1,081,984	$	1,067,421

XML

Accumulated Other Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2016

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, 2015	$	(5,580	)	$	(260	)	$	(5,840	)
Other comprehensive loss before reclassifications	—			(283		)	(283		)
Amounts reclassified from accumulated other comprehensive loss	89			283			372
Net current-period other comprehensive income	89			—			89
As of March 31, 2016	$	(5,491	)	$	(260	)	$	(5,751	)

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2014	$	(5,643	)	$	(33	)	$	(5,676	)
Other comprehensive loss before reclassifications	—			(7		)	(7		)
Amounts reclassified from accumulated other comprehensive loss	82			33			115
Net prior-period other comprehensive income	82			26			108
As of March 31, 2015	$	(5,561	)	$	(7	)	$	(5,568	)

Reclassifications out of Accumulated Other Comprehensive Income (Loss)

	Three Months Ended
	March 31,
	2016			2015
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost (1)	$	20		$	17
Net loss (1)	(168		)	(154		)
Total before income taxes	(148		)	(137		)
Income tax benefit	59			55
Net of tax	$	(89	)	$	(82	)
Gains and losses on commodity contracts cash flow hedges
Propane swap agreements (2)	$	(322	)	$	—
Call options (2)	—			(55		)
Natural gas futures (2)	(149		)	—
Total before income taxes	(471		)	(55		)
Income tax benefit	188			22
Net of tax	(283		)	(33		)
Total reclassifications for the period	$	(372	)	$	(115	)

XML

Employee Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2016

Compensation and Retirement Disclosure [Abstract]

Employee Benefit Plans

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended March 31,	2016			2015			2016			2015			2016		2015		2016			2015			2016		2015
(in thousands)
Interest cost	$	105		$	102		$	630		$	626		$	23	$	23	$	11		$	11		$	14	$	15
Expected return on plan assets	(131		)	(135		)	(701		)	(777		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			—		2		(20		)	(19		)	—		—
Amortization of net loss	104			90			128			114			22		25		18			17			—		2
Net periodic cost (benefit)	78			57			57			(37		)	45		50		9			9			14		17
Amortization of pre-merger regulatory asset	—			—			191			190			—		—		—			—			2		2
Total periodic cost	$	78		$	57		$	248		$	153		$	45	$	50	$	9		$	9		$	16	$	19

For the Three Months Ended March 31, 2016	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	—	$	(20	)	$	—	$	(20	)
Net loss	104		128		22		18			—		272
Total recognized in net periodic benefit cost	$	104	$	128	$	22	$	(2	)	$	—	$	252
Recognized from accumulated other comprehensive loss (1)	$	104	$	24	$	22	$	(2	)	$	—	$	148
Recognized from regulatory asset	—		104		—		—			—		104
Total	$	104	$	128	$	22	$	(2	)	$	—	$	252

For the Three Months Ended March 31, 2015	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	2	$	(19	)	$	—	$	(17	)
Net loss	90		114		25		17			2		248
Total recognized in net periodic benefit cost	$	90	$	114	$	27	$	(2	)	$	2	$	231
Recognized from accumulated other comprehensive loss (1)	$	90	$	22	$	27	$	(2	)	$	—	$	137
Recognized from regulatory asset	—		92		—		—			2		94
Total	$	90	$	114	$	27	$	(2	)	$	2	$	231

XML

Investments Investments (Tables)

3 Months Ended

Mar. 31, 2016

Investments, Debt and Equity Securities [Abstract]

Investments schedule [Table Text Block]

(in thousands)	March 31, 2016		December 31, 2015
Rabbi trust (associated with the Deferred Compensation Plan)	$	3,654	$	3,626
Investments in equity securities	20		18
Total	$	3,674	$	3,644

XML

Share-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2016

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

The table below presents the amounts included in net income related to share-based compensation expense for the three months endedMarch 31, 2016 and 2015:

	Three Months Ended
	March 31,
	2016			2015
(in thousands)
Awards to non-employee directors	$	165		$	150
Awards to key employees	484			387
Total compensation expense	649			537
Less: tax benefit	(261		)	(217		)
Share-based compensation amounts included in net income	$	388		$	320

Award to key employees [Member]

Shares awarded to non-employee directors [Line Items]

Schedule of Share-based Compensation, Activity

The table below presents the summary of the stock activity for awards to key employees for the three months endedMarch 31, 2016:

	Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2015	110,398		$	38.34
Granted	46,571		$	61.50
Vested	(39,553	)	$	31.79
Expired	(2,325	)	$	42.25
Outstanding— March 31, 2016	115,091		$	49.26

XML

Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2016

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Outstanding Trading Contracts

	Quantity in	Estimated Market		Weighted Average
At March 31, 2016	Gallons	Prices		Contract Prices
Forward Contracts
Sale	630,000	$	0.4425	$	0.4425
Purchase	631,000	$	0.4413	$	0.4422

Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the second quarter of 2016.

Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet

air values of the derivative contracts recorded in the condensed consolidated balance sheets as of March 31, 2016 and December 31, 2015, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2016		December 31, 2015
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	—	$	1
Derivatives designated as fair value hedges
Put options	Mark-to-market energy assets			152
Total asset derivatives		$	—	$	153

	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2016		December 31, 2015
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	—	$	1
Derivatives designated as cash flow hedges
Propane swap agreements	Mark-to-market energy liabilities	—		323
Natural gas futures contracts	Mark-to-market energy liabilities	423		109
Total liability derivatives		$	423	$	433

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

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

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended March 31,
(in thousands)	(Loss) on Derivatives	2016			2015
Derivatives not designated as hedging instruments
Realized gain on forward contracts (1)	Revenue	$	187		$	277
Unrealized gain (loss) on forward contracts (1)	Revenue	1			(125		)
Propane swap agreements	Cost of sales	—			18
Derivatives designated as fair value hedges
Put /Call options	Cost of sales	73			506
Put /Call options (2)	Propane Inventory	—			(3		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	(364		)	—
Propane swap agreements	Other Comprehensive Loss	—			(12		)
Call options	Cost of sales	—			(81		)
Natural gas futures contracts	Cost of sales	149			—
Natural gas futures contracts	Other Comprehensive Loss	(462		)	—
Total		$	(416	)	$	580

XML

Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2016

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 March 31, 2016 and December 31, 2015:

			Fair Value Measurements Using:
As of March 31, 2016	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	$	20	$	20	$	—	$	—
Investments—guaranteed income fund	$	525	$	—	$	—	$	525
Investments—mutual funds and other	$	3,129	$	3,129	$	—	$	—
Mark-to-market energy assets, incl. put options and swap agreements	$	—	$	—	$	—	$	—
Liabilities:
Mark-to-market energy liabilities incl. swap agreements	$	423	$	—	$	423	$	—

			Fair Value Measurements Using:
As of December 31, 2015	Fair Value		Quoted- Prices- in Active Markets (Level 1)		Significant- Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	18	$	18	$	—	$	—
Investments—guaranteed income fund	$	279	$	—	$	—	$	279
Investments—mutual funds and other	$	3,347	$	3,347	$	—	$	—
Mark-to-market energy assets, incl. put/call options	$	153	$	—	$	153	$	—
Liabilities:
Mark-to-market energy liabilities, incl. swap agreements	$	433	$	—	$	433	$	—

Summary of Changes in Fair Value of Investments

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the three months ended March 31, 2016 and 2015:

	Three Months Ended   March 31,
	2016		2015
(in thousands)
Beginning Balance	$	279	$	287
Purchases and adjustments	2		(5		)
Transfers	242		(3		)
Investment income	2		1
Ending Balance	$	525	$	280

XML

Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2016

Debt Disclosure [Abstract]

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below:

	March 31,			December 31,
(in thousands)	2016			2015
FPU secured first mortgage bonds (1) :
9.08% bond, due June 1, 2022	$	7,975		$	7,973
Uncollateralized senior notes:
6.64% note, due October 31, 2017	5,455			5,455
5.50% note, due October 12, 2020	10,000			10,000
5.93% note, due October 31, 2023	24,000			24,000
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	168			238
Capital lease obligation	4,490			4,824
Total long-term debt	158,088			158,490
Less: current maturities	(9,163		)	(9,151		)
Less: debt issuance costs	(323		)	(333		)
Total long-term debt, net of current maturities	$	148,602		$	149,006

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

XML

Summary of Accounting policies (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Accounting Policies [Abstract]
Deferred Tax Assets, Net of Valuation Allowance, Current		$ 831
Less: debt issuance costs	$ (323)	$ (333)

XML

Calculation of Earnings Per Share - Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Calculation of Basic Earnings Per Share:
Net Income	$ 20,367	$ 21,109	$ 41,140
Weighted shares outstanding (shares)	15,286,842	14,604,841
Basic Earnings Per Share (in dollars per share)	$ 1.33	$ 1.45
Reconciliation of Numerator:
Net Income	$ 20,367	$ 21,109	$ 41,140
Reconciliation of Denominator:
Weighted shares outstanding - Basic (shares)	15,286,842	14,604,841
Effect of dilutive securities:
Share-based compensation (shares)	45,070	51,469
Adjusted denominator-Diluted (shares)	15,331,912	14,656,310
Diluted Earnings Per Share (in dollars per share)	$ 1.33	$ 1.44

XML

Acquisitions - Additional Information (Detail) $ / shares in Units, $ in Thousands			3 Months Ended		12 Months Ended
	May. 07, 2015 USD ($)	Apr. 01, 2015 USD ($) mi	Mar. 31, 2016 USD ($) $ / shares shares	Mar. 31, 2015 USD ($) $ / shares	Dec. 31, 2015 USD ($)
Business Acquisition [Line Items]
Transaction costs					$ (514)
Revenues			$ 146,296	$ 170,081
Net income			$ 20,367	$ 21,109	41,140
Diluted (in dollars per share) | $ / shares			$ 1.33	$ 1.44
Goodwill			$ 15,070		14,548
Gatherco [Member]
Business Acquisition [Line Items]
Number of pipeline miles | mi		2,500
Number of counties served		40
Number of producers served		300
Number of customers served		20,000
Purchase price			$ 57,658
Shares of common stock issued at closing (shares) | shares			592,970
Common stock issued at closing		$ 30,200	$ 30,164
Cash paid		27,500	27,494
Long-term debt		1,696	1,696
Cash acquired		6,800	6,806
Additional contingent cash consideration			$ 15,000
Period for revenue generated from potential new gathering opportunities			5 years
Transaction costs					$ (1,300)
Revenues			$ 7,900
Net income			$ 1,676
Diluted (in dollars per share) | $ / shares			$ 0.03
Goodwill		$ 11,100	$ 10,119
Propane Distribution [Member]
Business Acquisition [Line Items]
Number of customers served	253
Purchase price	$ 242
Intangible assets	$ 186
Minimum [Member] | Propane Distribution [Member]
Business Acquisition [Line Items]
Amortization period			6 years
Maximum [Member] | Propane Distribution [Member]
Business Acquisition [Line Items]
Amortization period			10 years

XML

Acquisitions - Purchase Considerations (Details) - Gatherco [Member] - USD ($) $ in Thousands		3 Months Ended
	Apr. 01, 2015	Mar. 31, 2016
Business Acquisition [Line Items]
Chesapeake Utilities common stock	$ 30,200	$ 30,164
Cash	27,500	27,494
Acquired debt	1,696	1,696
Purchase price		57,658
Less: cash acquired	$ (6,800)	(6,806)
Gross [Member]
Business Acquisition [Line Items]
Purchase price		59,354
Net [Member]
Business Acquisition [Line Items]
Purchase price		$ 52,548

XML

Acquisitions - Gatherco purchase price allocation (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Dec. 31, 2015	Apr. 01, 2015
Business Acquisition [Line Items]
Goodwill	$ 15,070	$ 14,548
Gatherco [Member]
Business Acquisition [Line Items]
Purchase price	57,658
Property plant and equipment	53,203
Cash	6,806		$ 6,800
Accounts receivable	3,629
Income taxes receivable	3,163
Other assets	425
Total assets acquired	67,226
Long-term debt	1,696		1,696
Deferred income taxes	13,409
Accounts payable	3,837
Other current liabilities	745
Total liabilities assumed	19,687
Net identifiable assets acquired	47,539
Goodwill	$ 10,119		$ 11,100

XML

Rates and Other Regulatory Activities - Additional Information (Detail)				1 Months Ended	3 Months Ended
	Feb. 19, 2016 USD ($)	Dec. 21, 2015 USD ($)	Oct. 13, 2015 dekatherm / d	Dec. 31, 2015 USD ($)	Mar. 31, 2016 dekatherm / d in mi
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Interim Rate Increase (Decrease), Amount | $	$ 2,500,000
Public Utilities Interim Requested Rate Increase (Decrease) Percentage	5.00%
DELAWARE
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount | $		$ 4,700,000
Public Utilities, Requested Rate Increase (Decrease), Percentage		10.00%
MARYLAND
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Requested Rate Increase (Decrease), Amount | $				$ 950,000
Public Utilities, Requested Rate Increase (Decrease), Percentage				5.00%
Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Volume The Expansion Project Is Expected to Provide | dekatherm / d			53,000
Total Capacity After Pipeline Improvements | dekatherm / d			160,000
White Oak Lateral Mainline Expansion [Member] | Eastern Shore [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
System Reliability Project [Member] | Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Number of pipeline miles | mi					10.1
Lateral diamater of pipeline to be installed | in					16

XML

Environmental Commitments and Contingencies - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2016 USD ($) site claim	Mar. 31, 2015 USD ($)	Dec. 31, 2015 USD ($)
Environmental Commitments And Contingencies [Line Items]
Company's exposure in number of former Manufactured Gas Plant Sites | site	7
Environmental liabilities	$ 8,843,000		$ 8,942,000
Amount paid for funding requirements	99,000	$ 49,000
Seaford [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	273,000
Accrual for Environmental Loss Contingencies	186,000
Regulatory Assets	269,000
Estimated costs of remediation range, minimum	273,000
Estimated costs of remediation range, maximum	465,000
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]
Maximum Costs Of Monitoring Well	5,000
West Palm Beach Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	4,500,000
Estimated costs of remediation range, maximum	15,400,000
Sanford Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, maximum	13,000,000
Cost of remedy for settlements of claims	$ 20,000,000
Loss Contingency, Pending Claims, Number | claim	2
Environmental remediation expense	$ 24,000
Key West Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Period Of Regulatory Inactivity	17 years
Environmental Exit Costs, Anticipated Cost	$ 50,000
Aspire Energy [Member]
Environmental Commitments And Contingencies [Line Items]
Number Of Environmental Sites | site	8
Cost of remedy for settlements of claims	$ 1,400,000
Minimum Environmental Remediation Expenditures	431,250
Business Combination, Indemnification Assets, Range of Outcomes, Value, High	1,700,000
FPU [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	10,000,000
Approval of recovery of environmental costs	14,000,000
Environmental costs recovered	10,200,000
FPU [Member] | Sanford Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, maximum	$ 650,000
Environmental remediation expense percent	5.00%
FPU [Member] | Manufactured Gas Plant [Member]
Environmental Commitments And Contingencies [Line Items]
Regulatory Assets	$ 3,800,000
Chesapeake [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	353,000
Regulatory Assets	58,000
Maximum [Member] | Key West Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Anticipated Cost	8,000
Maximum [Member] | Pensacola Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental Exit Costs, Anticipated Cost	$ 5,000

XML

Other Commitments and Contingencies - Additional Information (Detail) $ in Thousands, gal in Millions	3 Months Ended
	Mar. 31, 2016 USD ($) dekatherm / d gal	Dec. 31, 2015 USD ($)
Commitments and Contingencies Disclosure [Abstract]
Number of years to purchase propane under contract	6 years
Remaining contract term	3 years
Estimated current annual commitment | gal	6.5
Monthly purchase commitment, minimum | dekatherm / d	9,982
Monthly purchase commitment, maximum | dekatherm / d	13,423
Total liabilities to tangible net worth minimum times	3.75
Fixed charge coverage ratio minimum times	1.5
Time to cure ratio	30 days
Funds from operations interest coverage ratio minimum times	2
Total debt to capital maximum	0.65
Maximum authorized liability under such guarantees and letters of credit	$ 65,000
Aggregate guaranteed amount	48,700
Draws on letters of credit	8,100
Liability related to unrecognized income tax benefits	50	$ 50
Liability related to contingencies for taxes other than income	$ 196	$ 310

XML

Segment Information - Schedule of Segment Reporting Information by Segment (Detail) - USD ($) $ in Thousands		3 Months Ended		12 Months Ended
		Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		$ 146,296	$ 170,081
Intersegment Revenues
Total operating revenues, unaffiliated customers		146,296	170,081
Operating Income
Total operating income		36,380	37,508
Other income, net of other expenses		(34)	133
Interest		2,650	2,448
Income Before Income Taxes		33,696	35,193
Income taxes		13,329	14,084
Net Income		20,367	21,109	$ 41,140
Identifiable Assets
Total identifiable assets		1,081,984		1,067,421
Regulated Energy [Member]
Operating Income
Total operating income		24,319	22,182
Identifiable Assets
Total identifiable assets		879,878		872,065
Unregulated Energy [Member]
Operating Income
Total operating income		11,936	15,229
Identifiable Assets
Total identifiable assets		178,723		171,840
Other [Member]
Identifiable Assets
Total identifiable assets		23,383		$ 23,516
Other and eliminations [Member]
Operating Income
Total operating income		125	97
Operating Revenues, Unaffiliated Customers [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		146,296	170,081
Intersegment Revenues
Total operating revenues, unaffiliated customers		146,296	170,081
Operating Revenues, Unaffiliated Customers [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		88,894	109,292
Intersegment Revenues
Total operating revenues, unaffiliated customers		88,894	109,292
Operating Revenues, Unaffiliated Customers [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		57,402	60,789
Intersegment Revenues
Total operating revenues, unaffiliated customers		57,402	60,789
Intersegment Revenues [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	661	718
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	661	718
Intersegment Revenues [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	322	290
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	322	290
Intersegment Revenues [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	113	207
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	113	207
Intersegment Revenues [Member] | Other [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	226	221
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	$ 226	$ 221

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

XML

Accumulated Other Comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	$ (5,840)	$ (5,676)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(283)	(7)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	372	115
Net current-period other comprehensive income (loss)	89	108
Ending balance	(5,751)	(5,568)
UnrealizedGainsLossesFromDefinedBenefitPensionAndPostretirementPlanItems [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	(5,580)	(5,643)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	0
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(89)	82
Net current-period other comprehensive income (loss)	89	82
Ending balance	(5,491)	(5,561)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	(260)	(33)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(283)	(7)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	(283)	(33)
Net current-period other comprehensive income (loss)	0	26
Ending balance	$ (260)	$ (7)

XML

Accumulated Other Comprehensive Income (Loss) - Reclassifications of Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Amortization of pension and postretirement items:
Tax benefit		$ (13,329)	$ (14,084)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Amortization of pension and postretirement items:
Net of tax		(372)	(115)
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Amortization of pension and postretirement items:
Prior service cost	[1]	20	17
Net loss	[1]	168	154
Total before tax		(148)	(137)
Tax benefit		59	55
Net of tax		(89)	(82)
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		(471)	(55)
Tax benefit		188	22
Net of tax		(283)	(33)
Other Comprehensive Income Loss Adjustments AOCI Swap Agreements	[2]	(322)	0
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax	[2]	0	(55)
Natural Gas Futures [Member] | Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Amortization of pension and postretirement items:
Other Comprehensive Income (Loss), Reclassification Adjustment from AOCI on Derivatives, before Tax		$ (149)	$ 0

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

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

XML

Employee Benefit Plans (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Amortization of prior service cost	$ (20)	$ (17)
Amortization of net loss	272	248
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	14	15
Expected return on plan assets	0	0
Amortization of prior service cost	0	0
Amortization of net loss	0	2
Net periodic cost (benefit)	14	17
Amortization of pre-merger regulatory asset	2	2
Total periodic cost	16	19
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	11	11
Expected return on plan assets	0	0
Amortization of prior service cost	(20)	(19)
Amortization of net loss	18	17
Net periodic cost (benefit)	9	9
Amortization of pre-merger regulatory asset	0	0
Total periodic cost	9	9
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	23	23
Expected return on plan assets	0	0
Amortization of prior service cost	0	2
Amortization of net loss	22	25
Net periodic cost (benefit)	45	50
Amortization of pre-merger regulatory asset	0	0
Total periodic cost	45	50
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	630	626
Expected return on plan assets	(701)	(777)
Amortization of prior service cost	0	0
Amortization of net loss	128	114
Net periodic cost (benefit)	57	(37)
Amortization of pre-merger regulatory asset	191	190
Total periodic cost	248	153
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost	105	102
Expected return on plan assets	(131)	(135)
Amortization of prior service cost	0	0
Amortization of net loss	104	90
Net periodic cost (benefit)	78	57
Amortization of pre-merger regulatory asset	0	0
Total periodic cost	$ 78	$ 57

XML

Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Expected pension and postretirement benefit costs	$ 1,600
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	14	$ 17
Contribution to pension plan	38
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	149
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	9	9
Contribution to pension plan	21
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	82
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	45	50
Contribution to pension plan	38
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	(802)
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined Benefit Plan, Net Periodic Benefit Cost	78	57
Contribution to pension plan	104
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	508
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Unamortized balance of regulatory asset	2,700		$ 2,800
Defined Benefit Plan, Net Periodic Benefit Cost	57	$ (37)
Contribution to pension plan	337
Defined Benefit Plans, Estimated Future Employer Contributions in Current Fiscal Year	$ 1,600

XML

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
		Mar. 31, 2016	Mar. 31, 2015
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		$ (20)	$ (17)
Net loss		272	248
Recognized from accumulated other comprehensive loss	[1]	148	137
Recognized from regulatory asset		104	94
Total recognized in net periodic benefit cost		252	231
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		0	0
Net loss		104	90
Recognized from accumulated other comprehensive loss	[1]	104	90
Recognized from regulatory asset		0	0
Total recognized in net periodic benefit cost		104	90
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		0	0
Net loss		128	114
Recognized from accumulated other comprehensive loss	[1]	24	22
Recognized from regulatory asset		104	92
Total recognized in net periodic benefit cost		128	114
Chesapeake Pension SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		0	2
Net loss		22	25
Recognized from accumulated other comprehensive loss	[1]	22	27
Recognized from regulatory asset		0	0
Total recognized in net periodic benefit cost		22	27
Chesapeake Postretirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		(20)	(19)
Net loss		18	17
Recognized from accumulated other comprehensive loss	[1]	(2)	(2)
Recognized from regulatory asset		0	0
Total recognized in net periodic benefit cost		(2)	(2)
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		0	0
Net loss		0	2
Recognized from accumulated other comprehensive loss	[1]	0	0
Recognized from regulatory asset		0	2
Total recognized in net periodic benefit cost		$ 0	$ 2

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

XML

Investments - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Investments, Debt and Equity Securities [Abstract]
Unrealized gain, net of other expenses	$ (18)	$ 104

XML

Investments - Schedule of Investments (Details) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Investments schedule [Line Items]
Investments, at fair value	$ 3,674	$ 3,644
Rabbi Trust Associated With Deferred Compensation Plan [Member]
Investments schedule [Line Items]
Investments, at fair value	3,654	3,626
Equity Securities [Member]
Investments schedule [Line Items]
Investments, at fair value	$ 20	$ 18

XML

Share-Based Compensation - Share-Based Compensation Amounts Included in Net Income (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 649	$ 537
Less: tax benefit	(261)	(217)
Share-Based Compensation amounts included in net income	388	320
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	165	150
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 484	$ 387

XML

Share-Based Compensation - Summary of Stock Activity under the SICP (Detail)	3 Months Ended
	Mar. 31, 2016 $ / shares shares
Number of Shares
Granted (shares)	1,207
Award to key employees [Member]
Number of Shares
Outstanding - December 31, 2015 (shares)	110,398
Granted (shares)	46,571
Vested (shares)	(39,553)
Expired (shares)	(2,325)
Outstanding - March 31, 2016 (shares)	115,091.000
Weighted Average Fair Value
Outstanding - December 31, 2015 (in dollars per share) | $ / shares	$ 38.34
Granted (in dollars per share) | $ / shares	61.50
Vested (in dollars per share) | $ / shares	31.79
Expired (in dollars per share) | $ / shares	42.25
Outstanding - March 31, 2016 (in dollars per share) | $ / shares	$ 49.26

XML

Share-Based Compensation - Additional Information (Detail) $ in Thousands	3 Months Ended
	Mar. 31, 2016 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards (shares) | shares	1,207
Unrecognized compensation cost	$ 3,300
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	$ 55
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards (shares) | shares	46,571
Vesting period	3 years
Intrinsic value of the SICP awards	$ 7,200

XML

Derivative Instruments - Outstanding Trading Contracts (Details) - Forward Contracts [Member] gal in Thousands	Mar. 31, 2016 $ / gal gal
Sales [Member]
Derivative [Line Items]
Quantity In Gallons | gal	630
Weighted Average Contract Prices	0.4425
Sales [Member] | Minimum [Member]
Derivative [Line Items]
Estimated Market Prices	0.4425
Sales [Member] | Maximum [Member]
Derivative [Line Items]
Estimated Market Prices	0.4425
Purchase [Member]
Derivative [Line Items]
Quantity In Gallons | gal	631
Weighted Average Contract Prices	0.4422
Purchase [Member] | Minimum [Member]
Derivative [Line Items]
Estimated Market Prices	0.4413
Purchase [Member] | Maximum [Member]
Derivative [Line Items]
Estimated Market Prices	0.4413

XML

Derivative Instruments - Additional Information (Detail) $ in Thousands, gal in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016 USD ($) Counterparty	Dec. 31, 2015 USD ($) dekatherm / d Counterparty $ / gal gal
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ 423	$ 433
Propane Swap Agreement [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal		2.5
Cash Paid On Derivative Settlement	500
Put Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal		2.5
Payments for Derivative Instrument, Financing Activities		$ 143
Cash Received On Derivative Settlement	$ 239
Forward Contracts [Member]
Derivative [Line Items]
Number Of Counterparties With Master Repurchase Agreements | Counterparty	2	2
Accounts Payable Subject To Master Netting Arrangement		$ 400
Mark To Market Energy Assets [Member] | Future [Member]
Derivative [Line Items]
Natural Gas Futures Nonmonetary Notional Amount Volume | dekatherm / d		6,723
Energy Marketing Contract Liabilities, Current		$ 423
Mark To Market Energy Liabilities [Member] | Future [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ 423	109
Mark To Market Energy Liabilities [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	0	323
Mark To Market Energy Liabilities [Member] | Forward Contracts [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ 0	1
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		$ 152
Strike Price 2 [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements | $ / gal		0.5950
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
Put Option Strike Price 2 [Member] | Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price | $ / gal		0.4888
Put Option Strike Price 3 [Member] | Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price | $ / gal		0.4500
Put Option Strike Price 4 [Member] | Put Option [Member]
Derivative [Line Items]
Derivative, Price Risk Option Strike Price | $ / gal		0.4200

XML

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 423	$ 433
Energy Marketing Contracts Assets, Current	0	153
Mark To Market Energy Assets [Member] | Forward Contracts [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 0	1
Mark To Market Energy Assets [Member] | Put Option [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current
Mark To Market Energy Assets [Member] | Put Option [Member] | Derivatives designated as fair value hedges [Member]
Derivatives, Fair Value [Line Items]
Derivative Asset, Fair Value, Amount Not Offset Against Collateral		152
Mark To Market Energy Assets [Member] | Future [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current		423
Mark-to-market energy liabilities [Member] | Forward Contracts [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 0	1
Mark-to-market energy liabilities [Member] | Propane Swap Agreement [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	0	323
Mark-to-market energy liabilities [Member] | Future [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 423	$ 109

XML

Derivative Instruments - Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements (Detail) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2016	Mar. 31, 2015
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ (416)	$ 580
Revenue [Member] | Derivatives not designated as hedging instruments [Member] | Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives	[1]	1	(125)
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	18
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	(81)
Cost of Sales [Member] | Derivatives designated as fair value hedges [Member] | Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		(364)
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		73	506
Cost of Sales [Member] | Derivatives designated as fair value hedges [Member] | Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives		149	0
Inventories [Member] | Derivatives designated as fair value hedges [Member] | Put/Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives		0	(3)
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		0	(12)
Other Comprehensive Income (Loss) [Member] | Derivatives designated as fair value hedges [Member] | Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Gain (Loss) on derivatives		(462)	0
Options [Member] | Revenue [Member] | Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ 187	$ 277

[1] {F|ahBzfndlYmZpbGluZ3MtaHJkcmoLEgZYTUxEb2MiXlhCUkxEb2NHZW5JbmZvOjg0OTAxODlhMmE5MzQwMmFiNzgxMGRmZTQ4ZjE5ZmMxfFRleHRTZWxlY3Rpb246RENCN0NBOTI2RDJENTk5MTgxNzg5QTA1QTdEMTEyMTYM}

XML

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Mar. 31, 2016	Dec. 31, 2015
Assets:
Investments	$ 3,674	$ 3,644
Equity Securities [Member]
Assets:
Investments	20	18
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	20	18
Quoted Prices in Active Markets (Level 1) [Member] | Investments - other [Member]
Assets:
Investments	3,129	3,347
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	423	433
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	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	0	153
Significant Unobservable Inputs (Level 3) [Member] | Mark-to-market energy liabilities [Member]
Assets:
Mark-to-market energy assets	0	0
Significant Unobservable Inputs (Level 3) [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	525	279
Significant Unobservable Inputs (Level 3) [Member] | Equity Securities [Member]
Assets:
Investments	0	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	423	433
Recurring [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	525	279
Recurring [Member] | Equity Securities [Member]
Assets:
Investments	20	18
Recurring [Member] | Investments - other [Member]
Assets:
Investments	3,129	3,347
Recurring [Member] | Mark To Market Energy Assets Including Put Option [Member]
Assets:
Mark-to-market energy assets	$ 0	$ 153

XML

Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2016	Mar. 31, 2015
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 279	$ 287
Purchases and adjustments	2	(5)
Transfers	242	(3)
Investment Income	2	1
Ending Balance	$ 525	$ 280

XML

Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Mar. 31, 2016	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Long-term debt including current maturities	$ 153.6	$ 153.7
Fair value of long-term debt	$ 171.4	$ 165.1

XML

Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands		Mar. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Total long-term debt		$ 153,600	$ 153,700
Capital lease obligation		4,490	4,824
Total Long-term debt		158,088	158,490
Less: current maturities		(9,163)	(9,151)
Less: debt issuance costs		(323)	(333)
Total long-term debt, net of current maturities		148,602	149,006
9.08% bond, due June 1, 2022 [Member]
Debt Instrument [Line Items]
Total long-term debt	[1]	7,975	7,973
6.64% note, due October 31, 2017 [Member]
Debt Instrument [Line Items]
Total long-term debt		5,455	5,455
5.50% note, due October 12, 2020 [Member]
Debt Instrument [Line Items]
Total long-term debt		10,000	10,000
5.93% note, due October 31, 2023 [Member]
Debt Instrument [Line Items]
Total long-term debt		24,000	24,000
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		$ 168	$ 238

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

XML

Long-Term Debt - Outstanding Long-Term Debt- Supplemental Information (Detail)	3 Months Ended
	Mar. 31, 2016
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

XML

Long-Term Debt - Additional Information (Detail) - Notes Payable, Other Payables [Member] - Shelf Notes [Member] $ in Millions	3 Months Ended
	Mar. 31, 2016 USD ($)
Debt Instrument [Line Items]
Period to purchase	3 years
Senior notes	$ 150.0
Maturity date term	20 years

XML

Short-Term Borrowing (Details) - USD ($)		3 Months Ended
	Oct. 08, 2015	Mar. 31, 2016	Dec. 31, 2015
Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Current borrowing capacity	$ 150,000,000.0
Expiration period	5 years
Expiration period from anniversary (up to)		2 years
Maximum borrowing capacity		$ 200,000,000.0
Uncommitted Line Of Credit Facility One [Member]
Short-term Debt [Line Items]
Line of credit		$ 40,000,000	$ 35,000,000
London Interbank Offered Rate (LIBOR) [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Interest rate		125.00%
Base Rate [Member] | Revolving Credit Facility [Member]
Short-term Debt [Line Items]
Interest rate		25.00%