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, 2018

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, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):

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

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

¨

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 — 16,363,792 shares outstanding as of April 30, 2018.

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	31
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	48
ITEM 4.	CONTROLS AND PROCEDURES	49
PART II—OTHER INFORMATION		50
ITEM 1.	LEGAL PROCEEDINGS	50
ITEM 1A.	RISK FACTORS	50
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	50
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	50
ITEM 5.	OTHER INFORMATION	50
ITEM 6.	EXHIBITS	51
SIGNATURES		52

GLOSSARY OF DEFINITIONS

ARM: ARM Energy Management, LLC, a natural gas supply and supply management company servicing commercial and industrial customers in Western Pennsylvania, which sold certain natural gas marketing assets to PESCO in August 2017

ASC: Accounting Standards Codification issued by the FASB

Aspire Energy: Aspire Energy of Ohio, LLC, a wholly-owned subsidiary of Chesapeake Utilities

ASU: Accounting Standards Update issued by the FASB

AutoGas: Alliance AutoGas, a national consortium of companies providing an industry-leading complete program for fleets interested in shifting from gasoline to clean-burning propane, of which Sharp is a member

CDD: Cooling 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 above 65 degrees Fahrenheit

Central Gas: Central Gas Company of Okeechobee, Incorporated, a propane distribution provider in Southeast Florida, which sold certain assets to Flo-gas in December 2017

CGC: Consumer Gas Cooperative, an Ohio natural gas cooperative

Chesapeake or Chesapeake Utilities: Chesapeake Utilities Corporation, and its direct and indirect 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

Chipola: Chipola Propane Gas Company, Inc., a propane distribution service provider in Northwest Florida, which sold certain assets to Flo-gas in August 2017

CHP: Combined heat and power plant

CIAC: Contributions from customers that are used to construct facilities

Columbia Gas: Columbia Gas of Ohio, an unaffiliated local distribution company based in Ohio

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

CP: Certificate of Public Convenience and Necessity

Credit Agreement: The Credit Agreement dated October 8, 2015, among 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 salaries and cash bonuses, executive performance shares, and directors’ retainers

Degree-Day: A degree-day is the measure of the variation in the weather based on the extent to which the average daily temperature (from 10:00 am to 10:00 am) falls above or below 65 degrees Fahrenheit

Delaware Division: Chesapeake Utilities' natural gas distribution operation serving customers in Delaware

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

DSR: Delivery Service Rate

Dt(s): Dekatherm(s), which is a natural gas unit of measurement that includes a standard measure for heating value

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, which owns and operates a CHP plant on Amelia Island, Florida, that supplies electricity to FPU and industrial steam to Rayonier

EPA: United States Environmental Protection Agency

ESG: Eastern Shore Gas Company and its affiliates

FASB: Financial Accounting Standards Board

FDEP: Florida Department of Environmental Protection

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

FGT: Florida Gas Transmission Company

Flo-gas: Flo-gas Corporation, a wholly-owned subsidiary of FPU

FPL: Florida Power & Light Company, an unaffiliated electric company that supplies electricity to FPU

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

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

Gulf Power: Gulf Power Company, an unaffiliated electric company that supplies electricity to FPU

Gulfstream: Gulfstream Natural Gas System, LLC, an unaffiliated pipeline network that supplies natural gas to FPU

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 unaffiliated 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

MDE: Maryland Department of Environment

MetLife: MetLife Investment Advisors, an institutional debt investment management firm, with which we entered into the MetLife Shelf Agreement

MetLife Shelf Agreement: An agreement entered into by Chesapeake Utilities and MetLife in March 2017 pursuant to which Chesapeake Utilities may request that MetLife purchase, through March 2, 2020, up to $150.0 million of unsecured senior debt at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance

MetLife Shelf Notes: Unsecured senior promissory notes issuable under the MetLife Shelf Agreement

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

MTM: Fair value (mark-to-market) accounting required for derivatives in accordance with ASC 815, Derivatives and Hedging

MW: Megawatts, which is a unit of measurement for electric base load power and capacity

NYL: New York Life Investors LLC, an institutional debt investment management firm, with which we entered into the NYL Shelf Agreement

NYL Shelf Agreement: An agreement entered into by Chesapeake Utilities and NYL pursuant to which Chesapeake Utilities may request that NYL purchase, through March 2, 2020, up to $100.0 million of unsecured senior debt at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance

NYL Shelf Notes: Unsecured senior promissory notes issuable under the NYL Shelf Agreement

OPT Service: Off Peak ≤ 30 or ≤ 90 Firm Transportation Service, a tariff associated with Eastern Shore's firm transportation service that allows Eastern Shore to not schedule service for up to 30 or 90 days during the peak months of November through April each year

OTC: Over-the-counter

Peninsula Pipeline: Peninsula Pipeline Company, Inc., Chesapeake Utilities' wholly-owned Florida intrastate pipeline subsidiary

PESCO: Peninsula Energy Services Company, Inc., Chesapeake Utilities' 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 Prudential Shelf Agreement

Prudential Shelf Agreement: An agreement entered into by Chesapeake Utilities and Prudential pursuant to which Chesapeake Utilities may request that Prudential purchase, through October 7, 2018, up to $150.0 million of Prudential Shelf Notes at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance

Prudential Shelf Notes: Unsecured senior promissory notes issuable under the Prudential Shelf Agreement

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

Rayonier: Rayonier Performance Fibers, LLC, the company that owns the property on which Eight Flags' CHP plant is located, and a customer of the steam generated by the CHP plant

Retirement Savings Plan: Chesapeake Utilities' qualified 401(k) retirement savings plan

Revolver: Our unsecured revolving credit facility with the Lenders

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

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

SEC: Securities and Exchange Commission

Senior Notes: Our unsecured long-term debt issued primarily to insurance companies on various dates

Sharp: Sharp Energy, Inc., Chesapeake Utilities' wholly-owned propane distribution subsidiary

SICP: 2013 Stock and Incentive Compensation Plan

SIR: A system improvement rate adder designed to fund system expansion costs within the city limits of Ocean City, Maryland

TCJA: The Tax Cuts and Jobs Act of 2017, which is legislation passed by Congress and signed into law by the President on December 22, 2017, and which, among other things, reduced the corporate income tax rate from 35 percent to 21 percent, effective January 1, 2018

TETLP: Texas Eastern Transmission, LP, an interstate pipeline interconnected with Eastern Shore's pipeline

Xeron: Xeron, Inc., an inactive subsidiary of Chesapeake Utilities, which previously engaged in propane and crude oil trading

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)

	Three Months Ended
	March 31,
	2018		2017
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	109,393	$	97,654
Unregulated Energy and other	129,963		87,506
Total Operating Revenues	239,356		185,160
Operating Expenses
Regulated Energy cost of sales	48,231		40,244
Unregulated Energy and other cost of sales	99,826		60,754
Operations	32,702		32,490
Maintenance	3,593		3,231
Depreciation and amortization	9,704		8,812
Other taxes	4,894		4,530
Total Operating Expenses	198,950		150,061
Operating Income	40,406		35,099
Other income (expense), net	68		(700		)
Interest charges	3,664		2,739
Income Before Income Taxes	36,810		31,660
Income taxes	9,955		12,516
Net Income	$	26,855	$	19,144
Weighted Average Common Shares Outstanding:
Basic	16,351,338		16,317,224
Diluted	16,402,985		16,363,796
Earnings Per Share of Common Stock:
Basic	$	1.64	$	1.17
Diluted	$	1.64	$	1.17
Cash Dividends Declared Per Share of Common Stock	$	0.3250	$	0.3050

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended
	March 31,
	2018			2017
(in thousands)
Net Income	$	26,855		$	19,144
Other Comprehensive (Loss) Income, net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(5) and $(8), respectively	(14		)	(11		)
Net gain, net of tax of $41 and $77, respectively	108			93
Cash Flow Hedges, net of tax:
Unrealized (loss)/gain on commodity contract cash flow hedges, net of tax of ($756) and $192, respectively	(1,788		)	338
Total Other Comprehensive (Loss) Income, net of tax	(1,694		)	420
Comprehensive Income	$	25,161		$	19,564

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Assets	March 31, 2018			December 31, 2017
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	1,083,004		$	1,073,736
Unregulated Energy	213,803			210,682
Other businesses and eliminations	27,892			27,699
Total property, plant and equipment	1,324,699			1,312,117
Less: Accumulated depreciation and amortization	(279,802		)	(270,599		)
Plus: Construction work in progress	131,640			84,509
Net property, plant and equipment	1,176,537			1,126,027
Current Assets
Cash and cash equivalents	5,996			5,614
Trade and other receivables (less allowance for uncollectible accounts of $901 and $936, respectively)	69,447			77,223
Accrued revenue	18,907			22,279
Propane inventory, at average cost	7,345			8,324
Other inventory, at average cost	4,607			12,022
Regulatory assets	10,833			10,930
Storage gas prepayments	1,197			5,250
Income taxes receivable	4,378			14,778
Prepaid expenses	8,199			13,621
Derivative assets, at fair value	208			1,286
Other current assets	6,717			7,260
Total current assets	137,834			178,587
Deferred Charges and Other Assets
Goodwill	22,104			22,104
Other intangible assets, net	4,482			4,686
Investments, at fair value	6,641			6,756
Regulatory assets	75,536			75,575
Other assets	4,316			3,699
Total deferred charges and other assets	113,079			112,820
Total Assets	$	1,427,450		$	1,417,434

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Capitalization and Liabilities	March 31, 2018			December 31, 2017
(in thousands, except shares and per share data)
Capitalization
Stockholders’ equity
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding	$	—		$	—
Common stock, par value $0.4867 per share (authorized 50,000,000 shares)	7,964			7,955
Additional paid-in capital	254,126			253,470
Retained earnings	250,024			229,141
Accumulated other comprehensive loss	(6,873		)	(4,272		)
Deferred compensation obligation	3,573			3,395
Treasury stock	(3,573		)	(3,395		)
Total stockholders’ equity	505,241			486,294
Long-term debt, net of current maturities	222,014			197,395
Total capitalization	727,255			683,689
Current Liabilities
Current portion of long-term debt	9,389			9,421
Short-term borrowing	229,108			250,969
Accounts payable	57,457			74,688
Customer deposits and refunds	34,795			34,751
Accrued interest	3,256			1,742
Dividends payable	5,318			5,312
Accrued compensation	5,444			13,112
Regulatory liabilities	18,503			6,485
Derivative liabilities, at fair value	2,359			6,247
Other accrued liabilities	8,694			10,273
Total current liabilities	374,323			413,000
Deferred Credits and Other Liabilities
Deferred income taxes	141,484			135,850
Regulatory liabilities	141,346			140,978
Environmental liabilities	8,215			8,263
Other pension and benefit costs	28,981			29,699
Deferred investment tax credits and other liabilities	5,846			5,955
Total deferred credits and other liabilities	325,872			320,745
Environmental and other commitments and contingencies (Note 5 and 6)
Total Capitalization and Liabilities	$	1,427,450		$	1,417,434

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Three Months Ended
	March 31,
	2018			2017
(in thousands)
Operating Activities
Net income	$	26,855		$	19,144
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	9,704			8,812
Depreciation and accretion included in other costs	2,276			1,939
Deferred income taxes	6,469			7,849
Realized gain on commodity contracts/sale of assets/investments	3,416			1,330
Unrealized loss on investments/commodity contracts	44			132
Employee benefits and compensation	228			423
Share-based compensation	1,520			639
Other, net	(12		)	(4		)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	9,649			5,095
Propane inventory, storage gas and other inventory	12,448			6,688
Regulatory assets/liabilities, net	11,511			6,103
Prepaid expenses and other current assets	8,095			1,136
Accounts payable and other accrued liabilities	(26,932		)	(5,897		)
Income taxes receivable	8,741			9,500
Customer deposits and refunds	44			400
Accrued compensation	(7,731		)	(4,966		)
Other assets and liabilities, net	347			1,631
Net cash provided by operating activities	66,672			59,954
Investing Activities
Property, plant and equipment expenditures	(63,116		)	(42,172		)
Proceeds from sales of assets	193			36
Environmental expenditures	(48		)	(57		)
Net cash used in investing activities	(62,971		)	(42,193		)
Financing Activities
Common stock dividends	(5,147		)	(4,815		)
(Purchase) issuance of stock under the Dividend Reinvestment Plan	(164		)	222
Tax withholding payments related to net settled stock compensation	(719		)	(692		)
Change in cash overdrafts due to outstanding checks	2,352			587
Net repayment under line of credit agreements and short-term borrowing under the Revolver	(24,213		)	(11,125		)
Proceeds from long-term debt under the Revolver	25,000			—
Repayment of long term debt and capital lease obligation	(428		)	(416		)
Net cash used in financing activities	(3,319		)	(16,239		)
Net Increase in Cash and Cash Equivalents	382			1,522
Cash and Cash Equivalents—Beginning of Period	5,614			4,178
Cash and Cash Equivalents—End of Period	$	5,996		$	5,700

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)

	Common Stock (1)
(in thousands, except shares and pershare data)	Number  of Shares(2)	Par Value		Additional  Paid-In Capital			Retained Earnings			Accumulated  Other Comprehensive Loss			Deferred Compensation		Treasury Stock			Total
Balance at December 31, 2016	16,303,499	$	7,935	$	250,967		$	192,062		$	(4,878	)	$	2,416	$	(2,416	)	$	446,086
Net income	—	—		—			58,124			—			—		—			58,124
Other comprehensive income	—	—		—			—			606			—		—			606
Dividend declared ($1.28 per share)	—	—		—			(21,045		)	—			—		—			(21,045		)
Dividend reinvestment plan	10,771	5		730			—			—			—		—			735
Stock issuance	—	—		(10		)	—			—			—		—			(10		)
Share-based compensation and tax benefit (3)(4)	30,172	15		1,783			—			—			—		—			1,798
Treasury stock activities	—	—		—			—			—			979		(979		)	—
Balance at December 31, 2017	16,344,442	7,955		253,470			229,141			(4,272		)	3,395		(3,395		)	486,294
Net income	—	—		—			26,855			—			—		—			26,855
Cumulative effect of the adoption of ASU 2014-09	—	—		—			(1,498		)	—			—		—			(1,498		)
Reclassification upon the adoption of ASU 2018-02	—	—		—			907			(907		)	—		—			—
Other comprehensive loss	—	—		—			—			(1,694		)	—		—			(1,694		)
Dividend declared ($0.3250 per share)	—	—		—			(5,381		)	—			—		—			(5,381		)
Dividend reinvestment plan	—	—		(1		)	—			—			—		—			(1		)
Share-based compensation and tax benefit (3)(4)	19,350	9		657			—			—			—		—			666
Treasury stock activities	—	—		—			—			—			178		(178		)	—
Balance at March 31, 2018	16,363,792	$	7,964	$	254,126		$	250,024		$	(6,873	)	$	3,573	$	(3,573	)	$	505,241

⁽¹⁾  2,000,000 shares of preferred stock at $0.01 par value have been authorized. None has been issued or is outstanding; accordingly, no information has been included in the statements of stockholders’ equity.

⁽²⁾  Includes 93,422 and 90,961 shares at March 31, 2018 and December 31, 2017, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.

⁽³⁾  Includes amounts for shares issued for directors’ compensation.

⁽⁴⁾  The shares issued under the SICP are net of shares withheld for employee taxes. For the three months ended March 31, 2018, and for the year ended December 31, 2017, we withheld 10,436 and 10,269 shares, respectively, for taxes.

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

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NOTESTO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1.    Summary of Accounting Policies

Basis of Presentation

References in this document to the “Company,” “Chesapeake 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, 2017. 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.

ARM, Chipola and Central Gas Asset Acquisitions

In August 2017, PESCO acquired certain natural gas marketing assets of ARM. We have accounted for the purchase of these assets as a business combination and recorded goodwill of $6.8 million, which is included in the Unregulated Energy segment. The acquired assets complement PESCO’s current asset portfolio and expanded our regional footprint and retail demand in a market where we had existing pipeline capacity and wholesale liquidity. In connection with the acquisition, we recorded a contingent liability of $2.5 million, which represents the expected future payment of additional consideration to ARM based on the achievement of certain performance targets. The payment, which is expected to be paid in 2019, is contingent upon the achievement of certain gross margin targets during the 2018 calendar year. The recorded liability is based upon our most recent gross margin projections for the acquired assets and is subject to change based on actual performance or changes in our gross margin projections.

In August 2017, Flo-gas acquired certain operating assets of Chipola, which provides propane distribution service to approximately 800 residential and commercial customers in Bay, Calhoun, Gadsden, Jackson, Liberty, and Washington Counties, Florida.

In December 2017, Flo-gas acquired certain operating assets of Central Gas, which provides propane distribution service to approximately 325 residential and commercial customers in Glades, Highlands, Martin, Okeechobee, and St. Lucie Counties, Florida.

The revenue and net income from these acquisitions that were included in our condensed consolidated statements of income for the three months ended March 31, 2018, were not material. The amounts recorded in conjunction with our acquisitions are preliminary and subject to adjustment based on additional valuations performed during the measurement period.

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

Revenue from Contracts with Customers (ASC 606) - On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and all the related amendments using the modified retrospective method. We recognized the cumulative effect of initially applying the new revenue standard to all of our contracts as an adjustment to the beginning balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. We expect the impact of the adoption of the new revenue standard to be immaterial to our net income on an ongoing basis.

This standard requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to receive in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. See Note 3, Revenue Recognition, for additional information.

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The following highlights the impact of the adoption of ASC 606 on our condensed consolidated income statement and condensed consolidated balance sheet for the three months ended March 31, 2018:

	Three months ended March 31, 2018
Income statement	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Regulated Energy operating revenues	$	109,393	$	110,357	$	(964	)
Regulated Energy cost of sales	$	48,231	$	48,803	$	(572	)
Depreciation and amortization	$	9,704	$	9,689	$	15
Income before income taxes	$	36,810	$	37,217	$	(407	)
Income taxes	$	9,955	$	10,077	$	(122	)
Net income	$	26,855	$	27,140	$	(285	)

	As of March 31, 2018
Balance sheet	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Assets
Accrued revenues	$	18,907	$	20,213	$	(1,306	)
Other assets	$	4,316	$	4,508	$	(192	)
Capitalization
Retained earnings	$	250,024	$	251,522	$	(1,498	)

The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $407,000 in annual revenue from 2018 to future years and a cumulative adjustment that decreased retained earnings and other assets by $1.5 million, associated with a long-term firm transmission contract with an industrial customer.

Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update allows for capitalization of the service cost component when applicable. We adopted ASU 2017-07 on January 1, 2018 and applied the changes in the presentation of the service cost and other components of net benefit costs, retrospectively. Aside from changes in presentation, the implementation of this standard did not have a material impact on our financial position or results of operations.

Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain transactions are classified in the statement of cash flows. We adopted ASU 2016-15 on January 1, 2018. The implementation of this new standard did not have a material impact on our condensed consolidated statement of cash flows.

Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scopeof ModificationAccounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) changes because of a change in the terms or conditions of the award. We adopted ASU 2017-09, prospectively, on January 1, 2018. The implementation of this new standard did not have a material impact on our financial position or results of operations.

Income Statement - Reporting Comprehensive Income (ASC 220) - In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. We elected to early adopt ASU 2018-02 on January 1, 2018 and reclassified stranded tax effects from accumulated other comprehensive loss related to our employee benefit plans and commodity contracts cash flows hedges. The implementation

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of this new standard did not have a material impact on our financial position and results of operations. See Note 8, Stockholders' Equity, for additional information.

Recent Accounting Standards Yet to be Adopted

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.

The FASB allows companies to elect several practical expedients, in order to simplify the transition to the new standard. The following three expedients must all be elected together:

• An entity need not reassess whether any expired or existing contracts are or contain leases.

• An entity need not reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840 will continue to be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will continue to be classified as capital leases).

•An entity need not reassess initial direct costs for any existing leases.

Other practical expedients that can be elected individually are:

• An entity may elect to use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets.

• An entity may elect to apply the provisions of the new lease guidance at the effective date, without adjusting the comparative periods presented.

We expect to use the practical expedients to assist in implementation of this standard. We have assessed all of our leases and have concluded that we may have some operating leases that qualify for the short-term lease exception. Upon adoption, we will record the right-of-use assets and the lease liabilities related to our operating leases with a lease term in excess of one year. We do not believe that this will have a material impact on our financial position, results of operations or cash flows.

In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, which provides a practical expedient under Topic 842 to not evaluate existing or expired land easements that were not previously accounted for as leases. We plan to utilize the provided practical expedient for existing and expired land easements and will assess all new or modified land easements and right-of-way agreements, under the guidance of ASU 2016-02, following its adoption.

Intangibles-Goodwill (ASC 350) - In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. ASU 2017-04 will be effective for our annual and interim financial statements beginning January 1, 2020, although early adoption is permitted. The amendments included in this ASU are to be applied prospectively. We believe that the implementation of this new standard will not have a material impact on our financial position or results of operations.

Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Among other changes to hedge designation, ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument included in the assessment of hedge effectiveness to be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. For disclosures, ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges, and it eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. ASU 2017-12 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We intend to adopt the updated hedge accounting standard in 2018, which we expect will reduce the MTM volatility in PESCO’s results due to better alignment of risk management activities and financial reporting, risk component hedging and certain other simplifications of hedge accounting guidance.

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2. Calculation of Earnings Per Share

	Three Months Ended
	March 31,
	2018		2017
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	26,855	$	19,144
Weighted average shares outstanding	16,351,338		16,317,224
Basic Earnings Per Share	$	1.64	$	1.17
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	26,855	$	19,144
Reconciliation of Denominator:
Weighted shares outstanding—Basic	16,351,338		16,317,224
Effect of dilutive securities—Share-based compensation	51,647		46,572
Adjusted denominator—Diluted	16,402,985		16,363,796
Diluted Earnings Per Share	$	1.64	$	1.17

3.     Revenue Recognition

We recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the subsequent month following the satisfaction of our performance obligation.

The following table is a breakdown of our revenue by major source based on product and service type for the three months ended March 31, 2018:

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	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Florida natural gas division	$	5,864		$	—		$	—		$	5,864
Delaware natural gas division	32,072			—			—			32,072
FPU electric distribution	18,741			—			—			18,741
FPU natural gas distribution	23,213			—			—			23,213
Maryland natural gas division	10,672			—			—			10,672
Sandpiper	8,964			—			—			8,964
Total energy distribution	99,526			—			—			99,526
Energy transmission
Aspire Energy	—			12,077			—			12,077
Eastern Shore	15,597			—			—			15,597
Peninsula Pipeline	2,098			—			—			2,098
Total energy transmission	17,695			12,077			—			29,772
Energy generation
Eight Flags	—			4,378			—			4,378
Propane delivery
Delmarva Peninsula propane delivery	—			45,470			—			45,470
Florida propane delivery	—			6,634			—			6,634
Total propane delivery	—			52,104			—			52,104
Energy services
PESCO	—			81,559			—			81,559
Other and eliminations
Eliminations	(7,828		)	(5,245		)	(15,598		)	(28,671		)
Other	—			494			194			688
Total other and eliminations	(7,828		)	(4,751		)	(15,404		)	(27,983		)
Total operating revenues (1)	$	109,393		$	145,367		$	(15,404	)	$	239,356

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $(589,000) and $73,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to weather normalization for Maryland division and Sandpiper and late fees.

Regulated Energy segment

Our businesses within the Regulated Energy segment are regulated utilities whose operations and customer contracts are subject to tariff rates approved by the state regulators or the FERC.

Our energy distribution operations deliver natural gas or electricity to customers and we bill the customers for both the delivery of natural gas or electricity and the related commodity, where applicable. In most jurisdictions, our customers are also required to purchase the commodity from us, although certain customers in some jurisdictions may purchase the commodity from a third party retailer (in which case we only provide delivery service). We consider the delivery of natural gas or electricity and/or the related commodity sale as one performance obligation because the commodity and its delivery are highly interrelated with two-way dependency on one another. Our performance obligation is satisfied over time as natural gas or electricity is delivered and consumed by the customer. We recognize revenues based on monthly meter readings, which are based on quantity of natural gas or electricity used and the approved rates. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period to the extent that billing and delivery do not coincide.

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Revenues for Eastern Shore are based on rates approved by the FERC. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to negotiated rates. Eastern Shore's services can be firm or interruptible. Firm services are offered on a guaranteed basis and are available at all times unless prevented by force majeure or other permitted curtailments. Interruptible customers only receive service when there is available capacity or supply. Our performance obligation is satisfied over time as we deliver natural gas to the customers' locations. We recognize revenues based on meter readings at the end of the month, which are based on capacity used or reserved and the fixed monthly charge.

Peninsula Pipeline is engaged in natural gas intra-state transmission to third-party customers and certain affiliates in the state of Florida. Our performance obligation is satisfied over time as the natural gas is transported to customers. We recognize revenue based on rates approved by the Florida PSC and the capacity used or reserved. Since we bill customers at the end of each month, we do not have any unbilled revenue.

Unregulated Energy segment

Revenues generated from the Unregulated Energy segment are not subject to any federal, state, or local pricing regulations. Aspire Energy primarily sources gas from hundreds of conventional producers and performs gathering and processing functions to maintain the quality and reliability of its gas for its wholesale customers. Aspire Energy's performance obligation is satisfied over time as natural gas is delivered to its customers. Aspire Energy recognizes revenue based on the deliveries of natural gas at contractually agreed upon rates (which are based upon an index price that is established monthly and a monthly operating fee, as applicable). For natural gas customers, we accrue unbilled revenues for natural gas that has been delivered, but not yet billed, at the end of an accounting period to the extent that billing and delivery do not coincide with the end of the accounting period.

Eight Flags' CHP plant, which is located on land leased from Rayonier, produces three sources of energy: electricity, steam and heated water. Rayonier purchases the steam (unfired and fired) and heated water, which is used in Rayonier’s production facility. Our electric distribution operation purchases the electricity generated by the CHP plant for distribution to its customers. Eight Flags' performance obligation is satisfied over time as deliveries of heated water, steam and electricity occur. Eight Flags recognizes revenues over time based on the amount of heated water, steam and electricity generated and delivered to its customers.

For our propane delivery operations, we recognize revenue based upon customer type and service offered. Generally, for propane bulk delivery customers (customers without meters) and wholesale sales, our performance obligation is satisfied when we deliver propane to the customers' locations (point-in-time basis). We recognize revenue from these customers based on the number of gallons delivered and the price per gallon at the point-in-time of delivery. For our propane delivery customers with meters, we satisfy our performance obligation over time when we deliver propane to customers. We recognize revenue over time based on the amount of propane consumed and the applicable price per unit. For propane delivery metered customers, we accrue unbilled revenues for propane that has been delivered, but not yet billed, at the end of an accounting period to the extent that billing and delivery do not coincide with the end of the accounting period.

PESCO provides natural gas supply and asset management services to customers (including Chesapeake Utilities affiliates) located primarily in Florida, the Delmarva Peninsula, and the Appalachian Basin. PESCO's performance obligation is satisfied over time as natural gas is delivered to its customers. PESCO recognizes revenue over time based on customer meter readings, on a monthly basis. We accrue unbilled revenues for natural gas that has been delivered, but not yet billed, at the end of an accounting period to the extent that billing and delivery do not coincide with the end of the accounting period.

Contract balances

The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our consolidated balance sheets. The opening and closing balances of our trade receivables, contract assets, and contract liability are as follows:

	Trade Receivables			Contract Assets (Non-current)		Contract Liability (Current)
in thousands
Balance at 12/31/2017	$	74,962		$	1,270	$	407
Balance at 3/31/2018	67,828			1,305		244
Increase (decrease)	$	(7,134	)	$	35	$	(163	)

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Our trade receivables are included in trade and other receivables in the condensed consolidated balance sheets. Our non-current contract assets are included in other assets in the condensed consolidated balance sheet and relate to operations and maintenance costs that have not yet been recovered through rates for the sale of electricity to our electric distribution operation pursuant to a long-term service agreement.

At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. At March 31, 2018 and December 31, 2017, we had a contract liability, which was included in other accrued liabilities in the condensed consolidated balance sheet, of $244,000 and $407,000, respectively, and which relates to non-refundable prepaid fixed fees for our Delmarva Peninsula propane delivery operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the three months ended March 31, 2018, we recognized revenue of $251,000.

Practical expedients

For our businesses with agreements that contain variable consideration, we use the invoice practical expedient method. We determined that the amounts invoiced to customers correspond directly with the value to our customers and our performance to date.

For our long-term contracts, the revenue we recognize corresponds directly to the amount we have the right to invoice, which corresponds directly to our performance obligation. Our performance obligations under our long-term contracts are satisfied over time. As a practical expedient, we do not disclose information about remaining, or unsatisfied, performance obligations for these long-term contracts since the revenue recognized corresponds to the amount we have the right to invoice.

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, as separate entities, by the Florida PSC.

Delaware

Effect of the TCJA on ratepayers: As result of the enactment of the TCJA, the Delaware PSC issued an order requiring all rate-regulated utilities to file estimates of the impact of the TCJA on their cost of service for the most recent test year available (including new rate schedules). The order also required utilities to propose procedures for changing rates to reflect those impacts on or before March 31, 2018. Our Delaware Division filed the requisite reports with the Delaware PSC on March 30, 2018. If, after reviewing our report, the Delaware PSC determines to reduce our rates, it will open a new docket and establish a procedural schedule for conducting an evidentiary hearing regarding the impacts of the TCJA on our operations and existing rates. We believe that the ultimate resolution of this matter will not have a material impact on our financial position or results of operations.

In addition, on February 1, 2018, the Delaware PSC issued an order requiring Delaware rate-regulated public utilities to accrue regulatory liabilities to reflect the impacts of the Delaware jurisdictional revenue requirement in light of the changes to the federal corporate income tax laws. In compliance with this order, we have established a regulatory liability to reflect the estimated impacts of the changes in the federal corporate income tax rate.

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Maryland Division and Sandpiper

Effect of the TCJA on ratepayers: The Maryland PSC issued an order requiring all Maryland public utilities whose rates are explicitly grossed-up for income taxes to track the impacts of the TCJA beginning January 1, 2018. The order required utilities to: (a) apply regulatory accounting treatment, which includes the use of regulatory assets and liabilities for all impacts of the TCJA; (b) file, on or before February 15, 2018, an explanation of the expected effects of the TCJA on their expenses and revenues; and (c) explain when and how they expect to pass on to their customers the net results of those effects. We established a regulatory liability to reflect the estimated impacts of the changes in the federal corporate income tax rate in compliance with the Maryland PSC’s order. In addition, on February 15, 2018, our Maryland natural gas division and Sandpiper filed preliminary estimates of the annual impact of the change in the statutory federal income tax rate from 35 percent to 21 percent and requested that the Maryland PSC grant us additional time to finalize our calculations. In March 2018, our Maryland natural gas division and Sandpiper supplemented their initial filings to include, among other items, an explanation of when and how they propose to pass the tax impacts on to their customers. In April 2018, the Maryland PSC issued orders directing our Maryland natural gas division and Sandpiper to: (1) file tariff pages reflective of the Maryland PSC's recommended rates with an effective date of May 1, 2018; (2) implement a one-time bill credit for the regulatory liability established for refunds; and, (3) make an informational filing within 60 days after the distribution of the one-time refunds. The orders further directed that, if any additional tax savings are later identified by either our natural gas divisions, we make a filing with the Maryland PSC to return those savings to customers as soon as possible.

Florida

Florida Electric Reliability/Modernization Pilot Program: In July 2017, FPU’s electric division filed a petition with the Florida PSC, requesting approval to include $15.2 million of certain capital project expenditures in its rate base and to adjust its base rates accordingly. These expenditures are designed to improve the stability and safety of the electric system, while enhancing the capability of FPU’s electrical grid. An interconnection project with FPL, which enables FPU to mitigate fuel costs for its electric customers, was included in the $15.2 million capital project expenditures. In December 2017, the Florida PSC approved this petition, effective January 1, 2018. The settlement agreement prescribed the methodology for adjusting the new rates based on the lower federal income tax rate and the process and methodology regarding the refund of deferred income taxes, reclassified as a regulatory liability, as a result of the TCJA. We have established a regulatory liability to reflect the impacts of the changes in the federal corporate income tax rate in compliance with the settlement agreement.

Electric Limited Proceeding-Storm Recovery: In February 2018, FPU’s electric division filed a petition with the Florida PSC, requesting recovery of incremental storm restoration costs related to several hurricanes and tropical storms, along with the replenishment of FPU’s storm reserve to its pre-storm level of $1.5 million. As a result of these hurricanes and tropical storms, FPU’s storm reserve was depleted and is currently at a deficit of $779,000. FPU is requesting approval of a surcharge of $1.82 per kilowatt per hour for two years to recover and replenish storm-related costs. At this time, no date for approval of this petition has been scheduled by the Florida PSC.

Effect of the TCJA on ratepayers: The Office of Public Counsel filed a petition requesting that the Florida PSC establish a general docket to investigate and adjust rates for all investor-owned utilities related to the passage of the TCJA. The Florida PSC issued a Memorandum with a recommendation that, if utilities do not agree to a January 1, 2018 effective date, then the effective date should be February 6, 2018. On January 30, 2018, the Florida PSC scheduled informal meetings between its staff and interested persons to discuss the impact of the TCJA. Meetings to discuss the impact for natural gas utilities, electric utilities and water and wastewater utilities were held in mid-February 2018. In December 2017, the Florida PSC issued an order regarding the limited proceeding for FPU's electric division, which prescribes the applicability, timing and treatment of the implications of the TCJA. We established a regulatory liability to reflect the impacts of the changes in the federal corporate income tax rate in compliance with the settlement agreement. We believe that the ultimate resolution of this matter will not have a material impact on our financial position or results of operations.

Eastern Shore

2017 Expansion Project: In May 2016, the FERC approved Eastern Shore's request to initiate the pre-filing review process for its 2017 Expansion Project. The 2017 Expansion Project's facilities include approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional compressor unit at Eastern Shore’s existing Daleville compressor station in Chester County, Pennsylvania; and approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware. Eastern Shore entered into precedent agreements with seven existing customers, including three affiliates of Chesapeake Utilities, for a total of 61,162 Dts/d of additional firm natural gas transportation service on Eastern Shore’s pipeline system with an additional 52,500 Dts/d of firm transportation service at certain Eastern Shore receipt facilities.

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In December 2016, Eastern Shore submitted an application for a CP authorizing construction of the expansion facilities, which the FERC issued in October 2017. The estimated cost of the 2017 Expansion Project is approximately $117.0 million. Eastern Shore submitted its Implementation Plan in October 2017 addressing the actions Eastern Shore will undertake to meet the environmental conditions set forth in the FERC's order.

In December 2017, the TETLP interconnect upgrade was placed into service, as Eastern Shore requested. The remaining segments of the 2017 Expansion Project are expected to be placed into service in various phases during the remainder of 2018.

2017 Rate Case Filing: In January 2017, Eastern Shore filed a base rate proceeding with the FERC, as required by the terms of its 2012 rate case settlement agreement. Eastern Shore's proposed rates were based on the mainline cost of service of approximately $60.0 million resulting in an overall requested revenue increase of approximately $18.9 million and a requested rate of return on common equity of 13.75 percent. In March 2017, the FERC issued an order suspending the tariff rates for the usual five-month period.

In August 2017, Eastern Shore implemented new rates, subject to refund, based upon the outcome of the rate proceeding.  Eastern Shore recorded incremental revenue of approximately $3.7 million for the year ended December 31, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates until the rate case settlement is approved by the FERC and customers receive refunds according to the terms of the settlement agreement. Eastern Shore filed an uncontested settlement agreement and a motion to place interim settlement rates into effect beginning on January 1, 2018, which interim settlement rates were approved by the FERC in December 2017. The settlement agreement was approved by the FERC in February 2018, and became final in March 2018. Eastern Shore will recover the costs of its 2016 System Reliability Project, along with the cost of investments and expenses associated with various expansion, reliability and safety initiatives. Not considering the effects of the TCJA, base rates will increase, on an annual basis, by approximately $9.8 million.

Effect of the TCJA on ratepayers: In March 2018, Eastern Shore filed with the FERC its revised base rates, reflecting the change in its federal corporate income tax rate. These adjusted base rates became effective April 1, 2018 and will generate approximately $6.6 million, on an annual basis. Any excess accumulated deferred income tax balances will flow back to customers over the period determined in the next rate case, absent any transition rule included in the TCJA or other statutes or rules that would govern the flow-back period. In April 2018, Eastern Shore refunded its customers, with interest, the difference between the proposed rates and the settlement rates. The refund to customers also reflected the difference in rates due to the impact of TCJA.

In March 2018, the FERC issued a Notice of Proposed Rulemaking proposing a process that will allow it to determine which jurisdictional natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the TCJA and changes to the FERC’s income tax allowance policies following the United Airlines, Inc. v. FERC decision. The Notice of Proposed Rulemaking proposed requiring interstate natural gas pipelines to provide an informational filing to allow the FERC to evaluate the impact of the TCJA on the pipelines’ revenue requirement. In April 2018, Eastern Shore filed comments in this proceeding requesting confirmation that Eastern Shore is not required to provide an informational filing because it has already implemented lower rates based on the 21 percent tax rate in accordance with the settlement agreement in its 2017 rate case approved by the FERC. We believe that the ultimate resolution of this matter will not have a material impact on our financial position or results of operations.

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.

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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, 2018, we had approximately $9.6 million in environmental liabilities related to 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 its MGP sites. Approximately $11.1 million has been recovered as of March 31, 2018, leaving approximately $2.9 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

Environmental liabilities for 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.

The following is a summary of our remediation status and estimated costs to implement clean-up of our key MGP sites:

Jurisdiction	MGP Site	Status	Cost to Clean up	Recovery through Rates
Florida	West Palm Beach	Remedial actions approved by the FDEP have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions.	Between $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.	Yes
Florida	Sanford	In March 2018, the EPA approved a "site-wide ready for anticipated use" status, which is the final step before delisting a site. Construction has been completed and restrictive covenants are in place to ensure protection of human health. The only remaining activity is long-term groundwater monitoring. It is unlikely that FPU will incur any significant future costs associated with the site.	FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be less than $10,000.	Yes
Florida	Winter Haven	Remediation is ongoing.	Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site.	Yes
Delaware	Seaford	Proposed plan for implementation approved by the DNREC in July 2017.	Between $273,000 and $465,000.	Yes
Maryland	Cambridge	Currently in discussions with the MDE.	Unable to estimate.	N/A

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6. Other Commitments and Contingencies

Natural Gas, Electric and Propane Supply

We have entered into contractual commitments to purchase natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. In 2017, our Delmarva Peninsula natural gas distribution operations entered into asset management agreements with PESCO to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017, and each has a three-year term, expiring on March 31, 2020. Previously, the Delaware PSC approved PESCO to serve as an asset manager with respect to our Delaware Division.

In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term ending in May 2019. Sandpiper's current annual commitment is approximately 2.5 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 ending in May 2019. Sharp's current annual commitment is approximately 2.5 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 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.

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with FPL requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If this ratio is not met by FPU, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times) and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of March 31, 2018, FPU was in compliance with all of the requirements of its fuel supply contracts.

Eight Flags provides electricity and steam generation services through its CHP plant located on Amelia Island, Florida. In June 2016, Eight Flags began selling power generated from the CHP plant to FPU pursuant to a 20-year power purchase agreement for distribution to its retail electric customers. In July 2016, Eight Flags also started selling steam, pursuant to a separate 20-year contract, to Rayonier, the landowner on which the CHP plant is located. The CHP plant is powered by natural gas transported by FPU through its distribution system and Peninsula Pipeline through its intrastate pipeline.

Corporate Guarantees

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily PESCO. These corporate guarantees provide for the payment of natural gas purchases in the event that PESCO defaults. PESCO has never defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at March 31, 2018 was approximately $72.7 million, with the guarantees expiring on various dates through March 2019.

Chesapeake Utilities also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under this 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).

Letters of Credit

As of March 31, 2018, we have issued letters of credit totaling approximately $5.0 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, the payment of natural gas purchases for PESCO, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through December 2019. There have been

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no draws on these letters of credit as of March 31, 2018. We do not anticipate that the counterparties will draw upon these letters of credit, and we expect that the letters of credit will be renewed to the extent necessary in the future.

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.

Our operations are comprised of two reportable segments:

• Regulated Energy. Includes energy distribution and transmission services (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. Includes energy transmission, energy generation, propane delivery, and other energy services (propane distribution, the operations of our Eight Flags' CHP plant, as well as natural gas marketing, gathering, processing, transportation and supply). These operations are unregulated as to their rates and services. Through March 2017, this segment also included the operations of Xeron, our propane and crude oil trading subsidiary that wound down its operations shortly after the first quarter of 2017. 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.

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The following table presents financial information about our reportable segments:

	Three Months Ended
	March 31,
	2018		2017
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	105,954	$	96,446
Unregulated Energy segment and other businesses	133,402		88,714
Total operating revenues, unaffiliated customers	$	239,356	$	185,160
Intersegment Revenues (1)
Regulated Energy segment	$	3,439	$	1,208
Unregulated Energy segment	11,965		4,011
Other businesses	194		228
Total intersegment revenues	$	15,598	$	5,447
Operating Income
Regulated Energy segment	$	26,711	$	23,395
Unregulated Energy segment	13,684		11,575
Other businesses and eliminations	11		129
Total operating income	40,406		35,099
Other income (expense), net	68		(700		)
Interest charges	3,664		2,739
Income before Income Taxes	36,810		31,660
Income taxes	9,955		12,516
Net Income	$	26,855	$	19,144

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

(in thousands)	March 31, 2018		December 31, 2017
Identifiable Assets
Regulated Energy segment	$	1,148,635	$	1,121,673
Unregulated Energy segment	246,230		261,541
Other businesses and eliminations	32,585		34,220
Total identifiable assets	$	1,427,450	$	1,417,434

Our operations are entirely domestic.

8. Stockholder's Equity

Preferred Stock

We had 2,000,000 authorized and unissued shares of preferred stock, $0.01 par value per share, as of March 31, 2018 and December 31, 2017. Shares of preferred stock may be issued from time to time, by authorization of our Board of Directors and without the necessity of further action or authorization by stockholders, in one or more series and with such voting powers, designations, preferences and relative, participating, optional or other special rights and qualifications as the Board of Directors may, in its discretion, determine.

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 other comprehensive loss. During the first quarter of 2018, we elected to early adopt ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. Accordingly, we reclassified

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stranded tax effects resulting from the TCJA from accumulated other comprehensive loss to retained earnings, related to our employee benefit plans and commodity contracts cash flows hedges.

The following tables present the changes in the balance of accumulated other comprehensive (loss)/income for the three months endedMarch 31, 2018 and 2017. All amounts except the stranded tax reclassification are presented net of tax.

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flows
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)
Other comprehensive loss before reclassifications	—			(2,232		)	(2,232		)
Amounts reclassified from accumulated other comprehensive income	94			444			538
Net current-period other comprehensive income/(loss)	94			(1,788		)	(1,694		)
Stranded tax reclassification to retained earnings	(1,022		)	115			(907		)
As of March 31, 2018	$	(5,671	)	$	(1,202	)	$	(6,873	)

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	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flows
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)
Other comprehensive income/(loss) before reclassifications	(9		)	1,278			1,269
Amounts reclassified from accumulated other comprehensive income/(loss)	91			(940		)	(849		)
Net prior-period other comprehensive income	82			338			420
As of March 31, 2017	$	(5,278	)	$	820		$	(4,458	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three months endedMarch 31, 2018 and 2017. Deferred gains or losses for our commodity contracts cash flows hedges are recognized in earnings upon settlement.

	Three Months Ended
	March 31,
	2018			2017
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit (1)	$	19		$	19
Net loss(1)	(149		)	(170		)
Total before income taxes	(130		)	(151		)
Income tax benefit	36			60
Net of tax	$	(94	)	$	(91	)
Gains and losses on commodity contracts cash flow hedges:
Propane swap agreements (2)	$	(464	)	$	388
Natural gas swaps (2)	(450		)	—
Natural gas futures (2)	298			1,150
Total before income taxes	(616		)	1,538
Income tax benefit (expense)	172			(598		)
Net of tax	(444		)	940
Total reclassifications for the period	$	(538	)	$	849

⁽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, call options and natural gas futures contracts are included in cost of sales in the accompanying consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying consolidated statements of income.

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9. Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three months endedMarch 31, 2018 and 2017 are set forth in the following tables:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended March 31,	2018			2017			2018			2017			2018		2017		2018			2017			2018		2017
(in thousands)
Interest cost	$	97		$	103		$	592		$	623		$	21	$	22	$	10		$	10		$	12	$	13
Expected return on plan assets	(138		)	(127		)	(774		)	(699		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(19		)	(19		)	—		—
Amortization of net loss	88			107			109			131			25		22		15			16			—		—
Net periodic cost (benefit) (1)	47			83			(73		)	55			46		44		6			7			12		13
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	47		$	83		$	118		$	246		$	46	$	44	$	6		$	7		$	14	$	15

⁽¹⁾As a result of our adoption of ASU 2017-07 on January 1, 2018, the "other than service" cost components of net periodic costs have been recorded or reclassified to other income (expense), net in the condensed consolidated statements of income.

We expect to record pension and postretirement benefit costs of approximately $913,000 for 2018. Included in these costs is approximately $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 approximately $1.1 million and approximately $1.3 million at March 31, 2018 and December 31, 2017, respectively.

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 tables present 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, 2018 and 2017:

For the Three Months Ended March 31, 2018	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	88		109		25		15			—		237
Total recognized in net periodic benefit cost	88		109		25		(4		)	—		218
Recognized from accumulated other comprehensive loss (1)	88		21		25		(4		)	—		130
Recognized from regulatory asset	—		88		—		—			—		88
Total	$	88	$	109	$	25	$	(4	)	$	—	$	218

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For the Three Months Ended March 31, 2017	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	107		131		22		16			—		276
Total recognized in net periodic benefit cost	107		131		22		(3		)	—		257
Recognized from accumulated other comprehensive loss (1)	107		25		22		(3		)	—		151
Recognized from regulatory asset	—		106		—		—			—		106
Total	$	107	$	131	$	22	$	(3	)	$	—	$	257

⁽¹⁾ See Note 8, Stockholder's Equity.

During the three months ended March 31, 2018, we contributed approximately $72,000 to the Chesapeake Pension Plan and approximately $309,000 to the FPU Pension Plan. We expect to contribute a total of approximately $359,000 and approximately $1.5 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2018, which represents 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 endedMarch 31, 2018, were approximately $38,000. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake SERP in 2018. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three months endedMarch 31, 2018, were approximately $12,000. We estimate that approximately $97,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2018. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three months ended March 31, 2018, were approximately $11,000. We estimate that approximately $88,000 will be paid for such benefits under the FPU Medical Plan in 2018.

10. Investments

The investment balances at March 31, 2018 and December 31, 2017, consisted of the following:

(in thousands)	March 31, 2018		December 31, 2017
Rabbi trust (associated with the Deferred Compensation Plan)	$	6,621	$	6,734
Investments in equity securities	20		22
Total	$	6,641	6,756

We classify these investments as trading securities and report them at their fair value. For the three months ended March 31,2018 and 2017, we recorded a net unrealized loss of approximately $44,000 and a net unrealized gain of approximately $252,000, respectively, in other expense, net 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 consolidated balance sheets and is adjusted each period 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, 2018 and 2017:

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	Three Months Ended
	March 31,
	2018			2017
(in thousands)
Awards to non-employee directors	$	135		$	135
Awards to key employees	1,385			504
Total compensation expense	1,520			639
Less: tax benefit	(416		)	(257		)
Share-based compensation amounts included in net income	$	1,104		$	382

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 one-year service period. In May 2017, each of our non-employee directors received an annual retainer of 835 shares of common stock under the SICP for service as a director through the 2018 Annual Meeting of Stockholders. At March 31, 2018, there was approximately $45,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2018.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the three months endedMarch 31, 2018:

	Number of Shares		Weighted Average Fair Value
Outstanding—December 31, 2017	132,642		$	59.31
Granted	49,494		$	67.76
Vested	(29,786	)	$	47.39
Expired	(3,933	)	$	49.66
Outstanding—March 31, 2018	148,417		$	66.53

In February 2018, our Board of Directors granted awards of 49,494 shares of common stock to key employees under the SICP. The shares granted are multi-year awards that will vest at the end of the three-year service period ending December 31, 2020. 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.

In March 2018, upon the election of certain of our executive officers, we withheld shares with a value at least equivalent to each such executive officer’s minimum statutory obligation for applicable income and other employment taxes related to shares that we awarded for the performance period ended December 31, 2017, remitted the cash to the appropriate taxing authorities, and paid the balance of such awarded shares to each such executive officer. We withheld 10,436 shares, based on the value of the shares on their award date, determined by the average of the high and low prices of our common stock. Total combined payments for the employees’ tax obligations to the taxing authorities were approximately $719,000.

At March 31, 2018, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $10.4 million. At March 31, 2018, there was approximately $4.2 million of unrecognized compensation cost related to these awards, which is expected to be recognized from 2018 through 2020.

Stock Options

We did not have any stock options outstanding at March 31, 2018 or 2017, nor were any stock options issued during these periods.

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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 our 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 normal 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, 2018, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Hedging Activities in 2018

PESCO enters into natural gas futures contracts associated with the purchase and sale of natural gas to specific customers. These contracts are effective through March 2022, and we designate and account for them as cash flow hedges. There is no ineffective portion of these hedges. At March 31, 2018, PESCO had a total of 22.9 million Dts hedged under natural gas futures contracts, with a liability fair value of approximately $1.6 million. 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 2017

In 2017, Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 7.7 million gallons of propane expected to be purchased from October 2017 through March 2019, of which positions covering 2.1 million gallons of forecasted future purchases were outstanding as of March 31, 2018. Under the futures and swap agreements, Sharp will receive the difference between the index prices (Mont Belvieu prices in October 2017 through March 2019) and the swap prices of $0.59 per gallon, to the extent the index price exceeds the contracted price. If the index prices are lower than the swap prices, Sharp will pay the difference. Sharp received a total of approximately $464,000, which represented the difference between the index prices and the contracted prices during the first quarter of 2018 related to hedging activities originated in 2017 and received $3,000, which represented the mark-to-market activities for the three months ended March 31, 2018. At March 31, 2018, the futures and swap agreements had a fair value asset of approximately $204,000 and a fair value liability of $16,000. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss).

The impact on Sharp's financial instruments that were not designated as hedges in our consolidated financial statements as of March 31, 2018 was $4,000, which was recorded as a decrease in propane costs during the three months ended March 31, 2018 and is associated with 18,000 gallons of propane.

In August 2017, PESCO entered into natural gas swap agreements associated with financial contracts acquired in the ARM acquisition to mitigate the risk of fluctuations in wholesale natural gas prices associated with 702,000 Dts of natural gas PESCO expects to purchase through January 2020. We accounted for these swap agreements as cash flow hedges, which have a fair value liability of approximately $404,000 at March 31, 2018. The change in fair value of the natural gas swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss).

The impact on PESCO's financial instruments that were not designated as hedges in our consolidated financial statements as of March 31, 2018 was $300,000, which was recorded as an increase in gas costs during the three months ended March 31, 2018 and is associated with 87,500 Dts of natural gas.

Balance sheet offsetting

PESCO has entered into master netting agreements with counterparties that enable it to net the counterparties' outstanding accounts receivable and payable, which are presented on a net basis in the consolidated balance sheets. The following table summarizes the accounts receivable and payables on a gross and net basis at March 31, 2018 and December 31, 2017:

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	At March 31, 2018
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	6,555	$	2,092	$	4,463
Accounts payable	$	13,912	$	2,092	$	11,820

	At December 31, 2017
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	8,283	$	2,391	$	5,892
Accounts payable	$	16,643	$	2,391	$	14,252

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, 2018 and December 31, 2017, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	4	$	13
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative assets, at fair value	—		92
Propane swap agreements	Derivative assets, at fair value	204		1,181
Total asset derivatives		$	208	$	1,286

	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative liabilities, at fair value	$	300	$5,776
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative liabilities, at fair value	1,639		469
Natural gas swap contracts	Derivative liabilities, at fair value	404		2
Propane swap agreements	Derivative liabilities, at fair value	16		—
Total liability derivatives		$	2,359	$	6,247

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

		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended March 31,
(in thousands)	(Loss) on Derivatives	2018			2017
Derivatives not designated as hedging instruments
Realized gain on forward contracts and options (1)	Revenue	$	—		$	112
Natural gas futures contracts	Cost of sales	(2,835		)	124
Propane swap agreements	Cost of sales	(9		)	(4		)
Derivatives designated as fair value hedges
Put /Call option (2)	Cost of sales	—			(9		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	(464		)	388
Propane swap agreements	Other comprehensive loss	(992		)	(557		)
Natural gas futures contracts	Cost of sales	298			1,150
Natural gas swap contracts	Cost of sales	(450		)	1,087
Natural gas futures agreements	Other comprehensive income	65			—
Natural gas swap agreements	Other comprehensive loss	(1,732		)	—
Total		$	(6,119	)	$	2,291

⁽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 on the condensed consolidated balance sheets.

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, 2018 and December 31, 2017:

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			Fair Value Measurements Using:
As of March 31, 2018	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	602		—		—		602
Investments—mutual funds and other	6,019		6,019		—		—
Total investments	6,641		6,039		—		602
Derivative assets	208		—		208		—
Total assets	$	6,849	$	6,039	$	208	$	602
Liabilities:
Derivative liabilities	$	2,359	$	—	$	2,359	$	—

			Fair Value Measurements Using:
As of December 31, 2017	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	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	648		—		—		648
Investments—mutual funds and other	6,086		6,086		—		—
Total investments	6,756		6,108		—		648
Derivative assets	1,286		—		1,286		—
Total assets	$	8,042	$	6,108	$	1,286	$	648
Liabilities:
Derivative liabilities	$	6,247	$	—	$	6,247	$	—

The following valuation techniques were used to measure the fair value of assets and liabilities in the tables above:

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:

Derivative assets and liabilities — The fair values of forward contracts are measured using market transactions in either the listed or OTC markets. 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.

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The following table sets forth the summary of the changes in the fair value of Level 3 investments for the three months ended March 31, 2018 and 2017:

	Three Months Ended   March 31,
	2018			2017
(in thousands)
Beginning Balance	$	648		$	561
Purchases and adjustments	(48		)	2
Transfers	—			—
Distribution	—			—
Investment income	2			2
Ending Balance	$	602		$	565

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

At March 31, 2018, 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, 2018, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of approximately $230.1 million. This compares to a fair value of approximately $237.9 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At December 31, 2017, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of approximately $205.2 million, compared to the estimated fair value of approximately $215.4 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

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14. Long-Term Debt

Our outstanding long-term debt is shown below:

	March 31,			December 31,
(in thousands)	2018			2017
FPU secured first mortgage bonds (1) :
9.08% bond, due June 1, 2022	$	7,983		$	7,982
Uncollateralized senior notes:
5.50% note, due October 12, 2020	6,000			6,000
5.93% note, due October 31, 2023	18,000			18,000
5.68% note, due June 30, 2026	26,100			26,100
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
3.25% note, due April 30, 2032	70,000			70,000
Long-term portion of the Revolver(2)	25,000			—
Promissory notes	26			97
Capital lease obligation	1,712			2,070
Less: debt issuance costs	(418		)	(433		)
Total long-term debt	231,403			206,816
Less: current maturities	(9,389		)	(9,421		)
Total long-term debt, net of current maturities	$	222,014		$	197,395

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

⁽²⁾ In January 2018, we borrowed an additional $25.0 million under the Revolver, which we classified as long-term debt. The maturity date of the Revolver is October 8, 2020. The interest rate on the Revolver is a variable interest rate that is dependent on various factors and resets every thirty days. As of March 31, 2018, the interest rate on the Revolver was LIBOR + 1.00% or 2.88%.

Shelf Agreements

In October 2015, we entered into the $150.0 million Prudential Shelf Agreement, under which we may request that Prudential purchase up to $150.0 million of our unsecured senior debt. As of March 31, 2018, we have issued $70.0 million of 3.25% Prudential Shelf Notes.

In March 2017, we entered into the MetLife Shelf Agreement and the NYL Shelf Agreement, under which we may request that MetLife and NYL, through March 2, 2020, purchase up to $150.0 million and $100.0 million, respectively, of our unsecured senior debt. The unsecured senior debt would have a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance. MetLife and NYL are under no obligation to purchase any unsecured senior debt. The interest rate and terms of payment of any series of unsecured senior debt will be determined at the time of purchase.

In November 2017, NYL agreed to purchase $50.0 million of 3.48% Series A notes and $50.0 million of 3.58% Series B notes. The Series A notes and Series B notes will be issued on or before May 21, 2018 and November 20, 2018, respectively. The proceeds received from the issuances of these NYL Shelf Notes will be used to reduce long and short-term borrowings under the Revolver and/or lines of credit and/or to fund capital expenditures. The NYL Shelf Agreement has been fully utilized.

As of March 31, 2018, we have $230.0 million of additional potential borrowing capacity under the Prudential and MetLife Shelf Agreements. The Prudential Shelf Agreement and the NYL Shelf Agreement set forth certain business covenants to which we are subject when any note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K for the year ended December 31, 2017, 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. Forward-looking statements speak only as of the date they are made or as of the date indicated and we do not undertake any obligation to update forward-looking statements as a result of new information, future events or otherwise. These statements are subject to many risks, uncertainties and other important factors that could cause actual future results to differ materially from those expressed in the forward-looking statements. In addition to the risk factors described under Item 1A, Risk Factors in our 2017 Annual Report on Form 10-K, 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 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 impact of significant changes to current tax regulations and rates;

• the timing of certification authorizations associated with new capital projects;

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

• 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;

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

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

• long-term global climate change, which could adversely affect customer demand or cause extreme weather conditions that disrupt the Company's operations;

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

• customers' preferred energy sources;

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

• the effect of competition on our businesses;

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

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

• the effect of spot, forward and future market prices on our various energy businesses;

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

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

• 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 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 impact on our costs 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 ability to continue to hire, train and retain appropriately qualified personnel;

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

• the timing and success of technological improvements; and

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• risks related to cyber-attacks or cyber-terrorism 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 regulated and unregulated energy businesses. These businesses center around energy distribution, energy transmission, energy generation, propane delivery and other energy services.

Our strategy is focused on growing earnings from a stable utility foundation and investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. We are focused on identifying and developing opportunities across the energy value chain, with emphasis on midstream and downstream investments that are accretive to earnings per share and consistent with our long-term growth strategy.

The key elements of this strategy include:

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

• expanding our energy distribution and transmission businesses organically as well as into new geographic areas;

• providing new services in our current service territories;

• expanding our footprint in potential growth markets through strategic acquisitions;

• entering new unregulated energy markets and business lines that will complement our existing operating units and growth strategy while capitalizing on opportunities across the energy value chain; and

• differentiating the Company as a full-service energy supplier/partner/provider through a customer-centric model.

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 later in the document on operating income and segment results include the use of the term “gross margin," which 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, and excludes depreciation, amortization and accretion. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. We believe that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by us under our allowed rates for regulated energy operations and under our competitive pricing structures for unregulated energy operations. 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.

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Results of Operations for the Three Months endedMarch 31, 2018

Overview

Chesapeake Utilities is a Delaware corporation formed in 1947. We are a diversified energy company engaged, through our operating divisions and subsidiaries, in regulated energy, unregulated energy and other businesses. We operate primarily on the Delmarva Peninsula and in Florida, Pennsylvania and Ohio and provide services centered on energy distribution, energy transmission, energy generation, propane delivery and other energy services. These services include: natural gas distribution, transmission, supply, gathering, processing and marketing; electric distribution and generation; propane distribution; steam generation; and other energy-related services.

Operational Highlights

Our net income for the quarter ended March 31, 2018 was $26.9 million, or $1.64 per share. This represents an increase of $7.7 million, or $0.47 per share, compared to net income of $19.1 million, or $1.17 per share, reported for the same quarter in 2017. Operating income increased by $5.3 million for the three months ended March 31, 2018, compared to the same period in the prior year. This increase was driven by a $7.1 million, or 8.5 percent, increase in gross margin, which was partially offset by a $1.2 million increase in depreciation, amortization and property taxes and a $616,000 increase in other operating expenses. Excluding the estimated customer refunds reserved during the first quarter of 2018 associated with the TCJA, gross margin and operating income increased by $10.3 million, or 12.2 percent, and $8.5 million, or 24.1 percent, respectively, compared to the same period in the prior year. A decrease in income taxes, due mainly to the lower effective tax rate, also positively impacted our earnings.

	Three Months Ended
	March 31,					Increase
	2018		2017			(decrease)
(in thousands except per share)
Business Segment:
Regulated Energy segment	$	26,711	$	23,395		$	3,316
Unregulated Energy segment	13,684		11,575			2,109
Other businesses and eliminations	11		129			(118		)
Operating Income	$	40,406	$	35,099		$	5,307
Other income (expense), net	68		(700		)	768
Interest charges	3,664		2,739			925
Pre-tax Income	36,810		31,660			5,150
Income taxes	9,955		12,516			(2,561		)
Net Income	$	26,855	$	19,144		$	7,711
Earnings Per Share of Common Stock
Basic	$	1.64	$	1.17		$	0.47
Diluted	$	1.64	$	1.17		$	0.47

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Key variances, between the first quarter of 2018 and the first quarter of 2017, included:

(in thousands, except per share data)	Pre-tax Income			Net Income			Earnings Per Share
First Quarter of 2017 Reported Results	$	31,660		$	19,144		$	1.17
Increased Gross Margins:
Return to more normal weather	3,914			2,855			0.17
TCJA impact - estimated refunds to ratepayers (1)	(3,155		)	(2,302		)	(0.14		)
Implementation of Eastern Shore settled rates* (2)	2,843			2,074			0.13
PESCO	(2,292		)	(1,672		)	(0.10		)
Unregulated Energy customer consumption (non-weather)	1,682			1,227			0.07
Regulated Energy customer consumption (non-weather)	949			692			0.04
Natural gas growth (excluding service expansions)	802			585			0.04
Service expansions*	565			412			0.03
Florida electric reliability/modernization program*	372			272			0.02
GRIP*	298			217			0.01
Sandpiper's margin from an industrial customer and natural gas conversions	257			188			0.01
	6,235			4,548			0.28
Decreased (Increased) Other Operating Expenses:
Higher payroll expense	(1,559		)	(1,137		)	(0.07		)
Higher depreciation, asset removal and property tax costs due to new capital investments	(1,216		)	(887		)	(0.05		)
Absence of Xeron expenses, including wind-down expenses	697			508			0.03
Lower outside services and facilities maintenance costs	665			485			0.03
Lower regulatory expenses	242			177			0.01
Lower benefit and other employee-related expenses	240			175			0.01
	(931		)	(679		)	(0.04		)
Interest charges	(926		)	(675		)	(0.04		)
Income taxes - TCJA impact - decreased effective tax rate	—			4,594			0.28
Net other changes	772			(77		)	(0.01		)
	(154		)	3,842			0.23
First Quarter of 2018 Reported Results	$	36,810		$	26,855		$	1.64

⁽¹⁾ Offset for the reserve to ratepayers is shown within this table under "Income taxes."

⁽²⁾ We reserved an estimated $900,000 to refund to customers, which is included in the line above "TCJA impact - estimated refunds to ratepayers." The refunds were made to customers through April 30, 2018, are offset by the corresponding decrease in federal income taxes and are expected to have no net impact on net income.

*See the Major Projects and Initiatives table.

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Summary of Key Factors

Recently Completed and Ongoing Major Projects and Initiatives

We constantly seek and develop additional projects and initiatives in order to increase shareholder value and serve our customers. The following table represents the major projects currently underway. In the future, we will add new projects to this table as projects are initiated.

	Gross Margin for the Period (1)
in thousands	Quarter Ended March 31, 2018		Quarter Ended March 31, 2017		Fiscal 2017		Fiscal 2018 Estimate		Fiscal 2019 Estimate
Florida GRIP	$	3,565	$	3,267	$	13,454	$	14,287	$	14,370
Eastern Shore Rate Case	2,843		—		3,693		9,800		9,800
Florida Electric Reliability/Modernization Pilot Program	372		—		94		1,558		1,558
New Smyrna Beach, Florida Project	352		—		235		1,409		1,409
2017 Eastern Shore System Expansion Project - including interim services	1,040		—		433		7,446		15,799
Northwest Florida Expansion Project	—		—		—		3,484		6,032
(Palm Beach County) Belvedere, Florida Project	—		—		—		635		1,131
Total	$	8,172	$	3,267	$	17,909	$	38,619	$	50,099

^{(1 )} Gross margin amount included in this table has not been adjusted to reflect the impact of TCJA. Any reductions implemented would be offset by lower federal income taxes due to the TCJA.

Ongoing Growth Initiatives

GRIP

GRIP is a natural gas pipe replacement program approved by the Florida PSC that allows automatic 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 $117.0 million to replace 250 miles of qualifying distribution mains, including $3.2 million during the first three months of 2018. The increased investments in GRIP generated additional gross margin of $298,000 for the three months ended March 31, 2018 compared to the same period in 2017.

Regulatory Proceedings

Eastern Shore Rate Case

In February 2018, the FERC approved Eastern Shore's rate case settlement agreement. The settlement became final on April 1, 2018, upon the expiration of the right to a rehearing. Under the terms of the settlement agreement, Eastern Shore will recover costs of its 2016 System Reliability Project, along with the cost of investments and expenses associated with various expansion, reliability and safety initiatives. Pursuant to the settlement agreement, Eastern Shore's annual base rates will increase by approximately $9.8 million, prior to any impact from the TCJA, and will recognize approximately $6.6 million, on an annual basis, after reflecting the impact of the change in its federal corporate income tax rate. For the three months ended March 31, 2018, Eastern Shore recognized incremental gross margin of approximately $2.8 million, a portion of which was reserved as a regulatory liability to be refunded to customers. Eastern Shore refunded to its customers, with interest, the difference between the proposed rates and the settlement rates on April 30, 2018. The settlement rates were effective January 1, 2018.

Florida Electric Reliability/Modernization Pilot Program

In December 2017, the Florida PSC approved a settlement agreement related to FPU’s electric limited proceeding filing, which included a $1.6 million annualized rate increase, effective January 2018, for the recovery of a limited number of investments and costs related to reliability, safety and modernization for FPU's electric distribution system. This increase will continue through at least the last billing cycle of December 2019. For the three months ended March 31, 2018, additional margin of $372,000 was generated. The settlement agreement prescribes the methodology for adjusting the new rates as a result of the TCJA.

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Major Projects and Initiatives Currently Underway

New Smyrna Beach, Florida Project

In the fourth quarter of 2017, we commenced construction of a 14-mile transmission pipeline that interconnects with FGT's pipeline to provide additional capacity to serve current and planned growth in Florida natural gas customers in our current New Smyrna Beach service area. The project was partially placed into service at the end of 2017 and is expected to be fully in service in September 2018. For the three months ended March 31, 2018, we recognized incremental gross margin of approximately $352,000 from this project.

2017 Eastern Shore Pipeline Expansion Project

We expect to invest approximately $117.0 million in 2018 to increase Eastern Shore's capacity by 26 percent. The new transportation services contracted for this capacity will generate approximately $15.8 million of gross margin in the first full year of service. In December 2017, the first phase of the project was placed into service, with the remaining segments expected to be placed into service over the remainder of 2018. For the three months ended March 31, 2018, we recognized incremental gross margin of $1.0 million.

Northwest Florida Expansion Project

Peninsula Pipeline and our Florida natural gas division are constructing a pipeline that will interconnect with the FGT interstate pipeline. The project consists of transmission lines that will be operated by Peninsula Pipeline, and lateral distribution lines that will be operated by the Florida natural gas division. We have signed agreements to serve two large customers and continue to market to other customers close to the facilities. The estimated annual gross margin from this project is $6.0 million, and the project is currently expected to be in service by the end of the second quarter of 2018.

(Palm Beach County) Belvedere, Florida Project

Peninsula Pipeline is constructing a pipeline that will interconnect with FGT's pipeline and bring gas directly to FPU’s distribution system in West Palm Beach, Florida. We expect this project to be completed by the end of the third quarter of 2018. Estimated annual gross margin associated with the project is approximately $1.1 million.

Other major factors influencing gross margin

Weather and Consumption

Gross margin increased by $3.9 million in the first quarter of 2018, primarily as a result of colder temperatures, as compared to the extremely warm temperatures experienced during the first quarter of 2017. Despite colder temperatures in the first quarter of 2018, as compared to the prior year period, the temperatures experienced in the first quarter of 2018 were still warmer than normal. We estimate that an additional $1.7 million of gross margin would have been generated if the temperatures in the first quarter of 2018 were consistent with temperatures in a normal first quarter.

The following table summarizes HDD and CDD variances from the 10-year average HDD/CDD ("Normal") for the three months ended March 31, 2018 and 2017.

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HDD and CDD Information

	Three Months Ended
	March 31,
	2018		2017		Variance
Delmarva
Actual HDD	2,295		1,958		337
10-Year Average HDD ("Delmarva Normal")	2,354		2,403		(49	)
Variance from Delmarva Normal	(59	)	(445	)
Florida
Actual HDD	490		285		205
10-Year Average HDD ("Florida Normal")	517		536		(19	)
Variance from Florida Normal	(27	)	(251	)
Ohio
Actual HDD	2,991		2,484		507
10-Year Average HDD ("Ohio Normal")	3,069		3,137		(68	)
Variance from Ohio Normal	(78	)	(653	)
Florida
Actual CDD	139		145		(6	)
10-Year Average CDD ("Florida CDD Normal")	89		82		7
Variance from Florida CDD Normal	50		63

Natural Gas Distribution Customer Growth

Customer growth for our Delmarva Peninsula natural gas distribution operations generated $500,000 in additional gross margin for the quarter ended March 31, 2018, compared to the same period in 2017. The additional margin was generated from a 3.7 percent increase in average number of residential customers as well as growth in commercial and industrial customers on the Delmarva Peninsula in the first quarter of 2018 compared to the first quarter of 2017.

Our Florida natural gas distribution operations generated $302,000 in additional gross margin for the quarter ended March 31, 2018, compared to the same period in 2017, with approximately half of the margin growth generated from residential customers and the other half from commercial and industrial customers.

Propane Operations

Our Florida and Delmarva Peninsula propane distribution operations continue to pursue a multi-pronged growth plan, which includes: targeting retail and wholesale customer growth in existing markets, both organically as well as through acquisitions; incremental growth from recent and planned start-ups in new markets, targeting new community gas systems in high growth areas; further build-out of our propane vehicular platform through AutoGas fueling stations; and optimization of our supply portfolio to generate incremental margin opportunities. Over the years, we have focused on meeting customer energy demand, and we have created a portfolio of offerings regardless of whether the customer is served via a pipeline or through an individual tank. AutoGas is our most recent offering that meets customers’ varying demands. As a member of AutoGas, our Delmarva Peninsula propane distribution operations and AutoGas install and support propane vehicle conversion systems for vehicle fleets. Our Delmarva Peninsula propane distribution operations continues to convert fleets to bi-fuel propane-powered engines and provides onsite fueling infrastructure.

These operations generated $4.0 million in incremental margin for the three months ended March 31, 2018, compared to the same period 2017. In addition, successful marketing initiatives led to increased volumes sold and revenues from service contracts. Supply management initiatives, including favorable hedging of propane purchases, have increased retail propane margins as well as opportunities to generate incremental margin from wholesale sales.

PESCO

PESCO markets and sells natural gas to wholesale, industrial and commercial customers and manages natural gas storage and transportation assets in several market areas. PESCO also provides management of storage and transportation assets for natural gas producers and regulated utilities. These management transactions typically involve the release of storage and/or transportation capacity in combination with an obligation to purchase and/or deliver natural gas. In April 2017, PESCO entered into 3-year asset

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management agreements with our Delmarva Peninsula natural gas distribution operations whereby PESCO manages a portion of their natural gas transportation and storage capacity.

In conjunction with the active management of these contracts, PESCO generates financial margin by identifying market opportunities and simultaneously entering into natural gas purchase/sale, storage or transportation contracts and/or financial derivatives contracts. The financial derivatives contracts consist primarily of exchange-traded futures that are used to manage volatility in natural gas market prices. Volatility in PESCO’s recorded gross margin and operating income can occur over periods of time due to changes in the value of financial derivatives contracts prior to the time of the settlement of the financial derivatives and the purchase or sale of the underlying physical commodity. Derivatives accounting has no impact on economic gains or losses of the purchase or sale contracts. PESCO’s results may also fluctuate based on the actual demand of its customers relative to its initial estimates of their demand, and PESCO's ability to manage its supply portfolio, considering weather and other factors, including pipeline constraints.

For the three months ended March 31, 2018, PESCO's gross margin decreased by $2.3 million compared to the same period in 2017. The decrease in gross margin was primarily due to higher gas supply costs of $2.0 million with retail customers in the Mid-Atlantic region and the absence of $2.1 million revenues from a supplier agreement with a customer in Ohio, which expired on March 31, 2017, offset by a favorable $2.2 million increase in margin from PESCO's asset management supply services. Unrealized fair value MTM losses of $300,000 related to financial derivative contracts also contributed to the decrease.

Xeron

Xeron's operations were wound down during the second quarter of 2017. Operating income for the quarter ended March 31, 2018, improved by $697,000 due to the absence of pre-tax losses generated by Xeron in the first quarter of 2017.

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Regulated Energy Segment

For the quarter ended March 31, 2018 compared to the quarter ended March 31, 2017

	Three Months Ended
	March 31,				Increase
	2018		2017		(decrease)
(in thousands)
Revenue	$	109,393	$	97,654	$	11,739
Cost of sales	48,231		40,244		7,987
Gross margin	61,162		57,410		3,752
Operations & maintenance	23,147		23,580		(433		)
Depreciation & amortization	7,516		6,885		631
Other taxes	3,788		3,550		238
Other operating expenses	34,451		34,015		436
Operating income	$	26,711	$	23,395	$	3,316

Operating income for the Regulated Energy segment for the three months ended March 31, 2018 was $26.7 million, an increase of $3.3 million compared to the same period in 2017. The increased operating income resulted from increased gross margin of $3.8 million and an increase in operating expenses of $436,000.

Excluding the impact of the estimated reserve for lower income taxes due to the TCJA of approximately $3.2 million, gross margin and operating income increased by $6.9 million and $6.5 million, respectively.

Gross Margin

Items contributing to the quarter-over-quarter increase in gross margin are listed in the following table:

(in thousands)	Margin Impact
Implementation of Eastern Shore settled rates	$	2,843
Return to more normal weather	1,017
Customer consumption (non-weather)	949
Natural gas growth (excluding service expansions)	802
Service expansions	565
Florida electric reliability/modernization program	372
Florida GRIP	298
Sandpiper's margin from an industrial customer and natural gas conversions	257
Other	(196		)
Total	6,907
TCJA impact - estimated refunds to ratepayers*	(3,155		)
Quarter over quarter increase in gross margin	$	3,752

^*As a result of the TCJA, a preliminary reserve of $3.2 million was established during the first quarter of 2018 to reflect the impact of lower tax rates on the Company's regulated businesses, based on internal guidance, until final agreements are approved and permanent changes are made to customer rates. The reserves and lower customer rates are equal to the anticipated reduction in federal income taxes due to the TCJA and have no material impact on after-tax earnings from the Regulated Energy segment.

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

Implementation of Eastern Shore Settled Rates

Eastern Shore generated additional gross margin of $2.8 million from the implementation of new rates as a result of its rate case filing. See Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.

Return to More Normal Weather

Closer to normal temperatures during the first quarter of 2018, as compared to significantly warmer than normal weather during the first quarter of 2017, generated $1.0 million in additional margin for the current period.

Increased Customer Consumption (non-weather)

Gross margin increased by $949,000 from higher non-weather consumption of natural gas on the Delmarva Peninsula.

Natural Gas Growth (excluding service expansions)

Increased gross margin of $802,000 from other growth in natural gas (excluding service expansions) was generated primarily from the following:

• $500,000 from a 3.7 percent increase in the average number of residential customers in the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers; and

• $302,000 from Florida natural gas customer growth, due primarily to an increase in residential and commercial customers.

Service Expansions

We generated additional gross margin of $565,000 primarily from natural gas service expansions from the following:

• $1.0 million from Eastern Shore's services including those provided, on an interim basis, to industrial customers in Delaware in conjunction with Eastern Shore's 2017 Expansion Project being placed in service in December 2017; partially offset by the absence of short-term contracts totaling $874,000 that were replaced by long-term service agreements; and

• $352,000 generated by Peninsula Pipeline from the New Smyrna Beach Expansion Project.

Florida Electric Reliability/Modernization Program

Gross margin increased by $372,000, due primarily to the limited proceedings rates that went into effect in January 2018. See Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.

GRIP

Increased investment in GRIP generated additional gross margin of $298,000for the three months ended March 31, 2018, compared to the same period in 2017.

Sandpiper DSR and SIR

Gross margin increased by $257,000, due primarily to a higher system improvement rate resulting from the continuing conversion of the Sandpiper system from propane service to natural gas service and an increase in a negotiated rate charged to a large industrial customer in the Maryland natural gas division. This increase was slightly offset by a decrease in delivery service rates for Sandpiper as a result of a settlement in its last rate case.

Impact of the TCJA on customer rates

The adjustment to customer rates, because of the implementation of the TCJA, decreased gross margin by $3.2 million due to the establishment of a reserve for the estimated refund to customers.

Other Operating Expenses

Other operating expenses decreased by $436,000. The significant factors contributing to the increase in other operating expenses included:

• $966,000 in higher depreciation, asset removal and property tax costs associated with recent capital investments;

• $589,000 in higher staffing costs for additional personnel to support growth; offset by

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• $667,000 in lower costs related to outside services and facilities and maintenance costs, due primarily to lower consulting and service contractor costs, as temporary resources were replaced with permanent resources and certain consulting services were finalized/concluded in first quarter of 2017; and

• $413,000 in lower benefits and employee-related costs (since we are self-insured for healthcare, benefits costs fluctuate depending upon filed claims).

Unregulated Energy Segment

For the quarter ended March 31, 2018 compared to the quarter ended March 31, 2017

	Three Months Ended
	March 31,				Increase
	2018		2017		(decrease)
(in thousands)
Revenue	$	145,367	$	92,725	$	52,642
Cost of sales	115,066		65,906		49,160
Gross margin	30,301		26,819		3,482
Operations & maintenance	13,359		12,380		979
Depreciation & amortization	2,167		1,903		264
Other taxes	1,091		961		130
Total operating expenses	16,617		15,244		1,373
Operating income	$	13,684	$	11,575	$	2,109

Operating income for the Unregulated Energy segment for the three months ended March 31, 2018 was $13.7 million, compared to operating income of $11.6 million for same period in 2017. The increase in operating income of $2.1 million was due to an increase in gross margin of $3.5 million, which was offset by a $1.4 million increase in operating expenses.

Gross Margin

Items contributing to the quarter-over-quarter increase in gross margin are listed in the following table:

(in thousands)	Margin Impact
PESCO	$	(2,292	)
Propane delivery operations - additional customer consumption - weather	1,956
Propane delivery operations - increased margin driven by growth and other factors	1,392
Aspire Energy - customer consumption - weather	941
Growth in wholesale propane margins and sales	379
Aspire Energy - increased margin driven by growth and other factors	319
Other	787
Quarter over quarter increase in gross margin	$	3,482

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

PESCO

For the three months ended March 31, 2018, PESCO's gross margin decreased by $2.3 million compared to the same period in 2017. Lower first quarter 2018 margin from PESCO resulted from the following:

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(in thousands)	Margin Impact
PESCO First Quarter 2017 Margin	$	3,467
Reversal of fourth quarter 2017 unrealized MTM loss	5,713
Margin from 2017 customer Supply Agreement that was not renewed	(2,124		)
Net impact for the Mid-Atlantic wholesale portfolio from extraordinary costs associated with 2018 Bomb Cyclone	(3,284		)
Loss for the Mid-Atlantic retail portfolio caused by capacity constraints in January and warm weather in February	(2,261		)
Other	(336		)
PESCO First Quarter 2018 Margin	$	1,175

• Reversal of MTM loss recorded during the fourth quarter of 2017 as contracts settled, as well as $300,000 of unrealized gains at the end of March 31, 2018;

• Absence of revenues from a supplier agreement in the first quarter of 2017, which was not renewed; and

• Extraordinary costs of meeting demand requirements in the Mid-Atlantic region due to pipeline capacity constraints experienced due to the 2018 Bomb Cyclone, followed by unseasonably warm weather in February.

The 2018 Bomb Cyclone refers to the early January high intensity winter storms that impacted our Mid-Atlantic service territory and which had a residual impact on our businesses through the month.  The early days of January experienced higher levels of wintry precipitation (snow and wind) and an extended period of anomalously cold weather. The extraordinary weather conditions created by the 2018 Bomb Cyclone generated incremental margin for our natural gas transmission and natural gas and propane distribution businesses. However, the exceedingly high demand and associated pipeline capacity and gas supply in the Delmarva Peninsula region created significant, unusual costs for PESCO. While these circumstances will recur infrequently, our management has taken various steps to mitigate PESCO’s exposure going forward. These mitigation steps resulted in improved results in February and March of 2018.

Propane delivery operations - additional customer consumption - weather

Gross margin increased by $2.0 million, due primarily to increased deliveries of propane as a result of colder temperatures in the three months ended March 31, 2018, compared to the same period in 2017.

Propane delivery operations - increased margin driven by growth and other factors

Gross margin increased by $1.4 million, due primarily to increased sales of propane as a result of growth in customers and other factors.

Aspire Energy - customer consumption - weather

Gross margin increased by $941,000, as a result of increased deliveries of natural gas, due primarily to colder temperatures during the three months ended March 31, 2018, compared to the same period in 2017.

Wholesale Propane Margins

Gross margin increased by $379,000, due to a higher margin per gallon and an increase in volume delivered for the Delmarva Peninsula propane distribution operations.

Aspire Energy - increased margin driven by growth and other factors

Gross margin increased by $319,000, due to customer growth and upgrade of pipeline pressure, which resulted in an increase in deliveries of natural gas.

Other Operating Expenses

Other operating expenses increased by $1.4 million, due primarily to $969,000 in higher staffing and associated costs for additional personnel to support growth and increased deliveries driven by the significantly colder weather in the first quarter of 2018, compared to the same period in 2017.

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OTHER EXPENSE, NET

For the quarter ended March 31, 2018 compared to the quarter ended March 31, 2017

Other expense, net, which includes non-operating investment income (expense), interest income, late fees charged to customers, gains or losses from the sale of assets and pension and other benefits expense, increased by $768,000 in the first quarter of 2018, compared to the same period in 2017.

INTEREST CHARGES

For the quarter ended March 31, 2018 compared to the quarter ended March 31, 2017

Interest charges for the three months ended March 31, 2018 increased by $925,000, compared to the same period in 2017, attributable primarily to an increase of $531,000 in interest on long-term debt, largely as a result of the issuance of the Prudential Shelf Notes in April 2017, and an increase of $556,000 in interest on higher short-term borrowings.

INCOME TAXES

For the quarter ended March 31, 2018 compared to the quarter ended March 31, 2017

Income tax expense was $10.0 million for the three months ended March 31, 2018, compared to $12.5 million in the same period in 2017. The decrease in income tax expense was due primarily to the impact of the TCJA in the first quarter of 2018. Our effective income tax rate was 27.0 percent and 39.5 percent, for the three months ended March 31, 2018 and 2017, respectively.

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FINANCIAL POSITION, LIQUIDITYAND CAPITAL RESOURCES

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

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 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.

Capital expenditures for investments in new or acquired plant and equipment are our largest capital requirements. Our capital expenditures were $61.2 million for the three months ended March 31, 2018.

We budgeted $181.6 million for capital expenditures in 2018. The following table shows the 2018 capital expenditure budget by segment and by business line:

	2018
(dollars in thousands)
Regulated Energy:
Natural gas distribution	$	53,899
Natural gas transmission	92,562
Electric distribution	7,972
Total Regulated Energy	154,433
Unregulated Energy:
Propane distribution	11,235
Other unregulated energy	5,827
Total Unregulated Energy	17,062
Other:
Corporate and other businesses	10,097
Total Other	10,097
Total 2018 Budgeted Capital Expenditures	$	181,592

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

The timing of capital expenditures can vary based on delays in regulatory approvals, securing environmental approvals and other permits. The regulatory application and approval process has lengthened in the past few years, and we expect this trend to continue.

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Capital Structure

We are committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access capital markets when required. This commitment, along with adequate and timely rate relief for our regulated energy 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, 2018 and December 31, 2017:

	March 31, 2018				December 31, 2017
(in thousands)
Long-term debt, net of current maturities	$	222,014	31	%	$	197,395	29	%
Stockholders’ equity	505,241		69	%	486,294		71	%
Total capitalization, excluding short-term debt	$	727,255	100	%	$	683,689	100	%
	March 31, 2018				December 31, 2017
(in thousands)
Short-term debt	$	229,108	24	%	$	250,969	26	%
Long-term debt, including current maturities	231,403		24	%	206,816		22	%
Stockholders’ equity	505,241		52	%	486,294		52	%
Total capitalization, including short-term debt	$	965,752	100	%	$	944,079	100	%

Included in the long-term debt balances at March 31, 2018 and December 31, 2017, was a capital lease obligation associated with Sandpiper's capacity, supply and operating agreement (at March 31, 2018, $249,000 excluding current maturities and $1.7 million including current maturities and, at December 31, 2017, $620,000 excluding current maturities and $2.1 million including current maturities). At the closing of the ESG acquisition in May 2013, Sandpiper entered into this agreement, which has a six-year term. The capacity portion of this agreement is accounted for as a capital lease.

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 50 percent and 59 percent during the past three years.

We will seek to align, as much as feasible, any 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.

Shelf Agreements

In October 2015, we entered into the $150.0 million Prudential Shelf Agreement, under which we may request that Prudential purchase up to $150.0 million of our unsecured senior debt. As of March 31, 2018, we have issued $70.0 million of 3.25% Prudential Shelf Notes.

In March 2017, we entered into the MetLife Shelf Agreement and the NYL Shelf Agreement, under which we may request that MetLife and NYL, through March 2, 2020, purchase up to $150.0 million and $100.0 million, respectively, of our unsecured senior debt. The unsecured senior debt would have a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance. MetLife and NYL are under no obligation to purchase any unsecured senior debt. The interest rate and terms of payment of any series of unsecured senior debt will be determined at the time of purchase.

In November 2017, NYL agreed to purchase $50.0 million of 3.48% Series A notes and $50.0 million of 3.58% Series B notes. The Series A notes and Series B notes will be issued on or before May 21, 2018 and November 20, 2018, respectively. The proceeds received from the issuances of these NYL Shelf Notes will be used to reduce long and short-term borrowings under the Revolver and/or lines of credit and/or to fund capital expenditures. The NYL Shelf Agreement has been fully utilized.

As of March 31, 2018, we have $230.0 million of additional potential borrowing capacity under the Prudential and MetLife Shelf Agreements. The Prudential Shelf Agreement and the NYL Shelf Agreement set forth certain business covenants to which we are subject when any note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.

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Short-term Borrowings

Our outstanding short-term borrowings at March 31, 2018 and December 31, 2017 were $229.1 million and $251.0 million at weighted average interest rates of 2.71 percent and 2.42 percent, respectively. Our current short-term borrowing limit, authorized by our Board of Directors, is $350.0 million.

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, 2018, we had five unsecured bank credit facilities with four financial institutions totaling $220.0 million in available credit. In addition, since October 2015, we have $150.0 million of additional short-term debt capacity available under the Revolver. The terms of the Revolver are described in further detail below. None of the unsecured bank lines of credit requires compensating balances.

The $150.0 million Revolver is available through October 8, 2020 and is subject to the terms and conditions set forth in 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% or less. Interest is payable quarterly, and the Revolver is subject to a commitment fee on the unused portion of the facility. We have the right, under certain circumstances, to 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.

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the three months ended March 31, 2018 and 2017:

	Three Months Ended
	March 31,
	2018			2017
(in thousands)
Net cash provided by (used in):
Operating activities	$	66,672		$	59,954
Investing activities	(62,971		)	(42,193		)
Financing activities	(3,319		)	(16,239		)
Net increase in cash and cash equivalents	382			1,522
Cash and cash equivalents—beginning of period	5,614			4,178
Cash and cash equivalents—end of period	$	5,996		$	5,700

Cash Flows Provided By Operating Activities

Changes in our cash flows from operating activities are attributable primarily to changes in net income, adjusted for non-cash items such as depreciation and changes in 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, 2018 and 2017, net cash provided by operating activities was $66.7 million and $60.0 million, respectively, resulting in an increase in cash flows of $6.7 million. Significant operating activities generating the cash flows change were as follows:

• Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities decreased cash flows by $16.5 million, due primarily to the timing of the receipt of customer payments as well as the timing of payments to vendors.

• Net income, adjusted for reconciling activities, increased cash flows by $10.2 million, due primarily to the higher performance during the quarter, non-cash adjustments related to realized losses on sale of assets/investments, higher depreciation and amortization expenses related to increased investing activities, offset by a decrease in deferred income taxes of $1.4 million due to tax reform.

• Net cash flows from changes in propane inventories increased by approximately $5.8 million, as a result of higher use of propane, which decreased the levels of our inventory.

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• Changes in net regulatory assets and liabilities increased cash flows by $5.4 million, due primarily to the change in fuel costs collected through the various cost recovery mechanisms.

• Changes in net prepaid expenses and other current assets, customer deposits and refunds increased cash flows by $6.6 million.

• Changes in accrued compensation, other assets and liabilities and income tax receivables decreased cash flow by $4.8 million.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $63.0 million and $42.2 million during the three months ended March 31, 2018 and 2017, respectively, resulting in a decrease in cash flows of $20.8 million. Cash paid for capital expenditures increased by $20.9 million to $63.1 million for the first three months of 2018, compared to $42.2 million for the same period in 2017, which was slightly offset by an increase in proceeds from the sales of assets.

Cash Flows Used in Financing Activities

Net cash used in financing activities totaled $3.3 million and $16.2 million during the three months ended March 31, 2018 and 2017, respectively. The decrease in net cash used in financing activities for the three months ended March 31, 2018 resulted primarily from the following:

• We received $25.0 million in net cash proceeds from the Revolver, which was advanced on a long-term basis, partially offset by an increased repayment of short-term borrowing of $13.1 million under our line of credit arrangements. Our additional financing needs are a result of the additional capital expenditures during the quarter.

• We paid $5.1 million in cash dividends for the three months ended March 31, 2018, compared to $4.8 million for the three months ended March 31, 2017.

Off-Balance Sheet Arrangements

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. These subsidiaries have never defaulted on their obligations to pay their suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at March 31, 2018 was $72.7 million, with the guarantees expiring on various dates through March 2019.

We have issued letters of credit totaling $5.0 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 carrier. These letters of credit have varying expiration dates through December 2019. There have been no draws on these letters of credit as of March 31, 2018. 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 inNote 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 2017 Annual Report on Form 10-K, except for commodity purchase obligations and forward contracts entered into in the ordinary course of our business. The following table summarizes the commodity purchase and forward contract obligations at March 31, 2018:

	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)	$	70,476	$	55,912	$	—	$	—	$	126,388
Total	$	70,476	$	55,912	$	—	$	—	$	126,388

⁽¹⁾  In addition to the obligations noted above, we 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.

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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, 2018, 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 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 condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

INTEREST RATE RISK

Long-term debt is subject to potential losses based on changes in interest rates. Our long-term debt at March 31, 2018, consists of fixed-rate Senior Notes and $8.0 million of fixed-rate secured debt. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowings based in part on the fluctuation in interest rates. Additional information about our long-term debt is disclosed in Note 14, Long-term Debt, in the condensed consolidated financial statements.

COMMODITY PRICE RISK

Regulated Energy Segment

We have entered into agreements with various wholesale suppliers to purchase natural gas and electricity for resale to our customers. Our regulated energy distribution businesses that sell natural gas or electricity to end-use customers have fuel cost recovery mechanisms authorized by the PSCs that allow us to periodically adjust fuel rates to reflect changes in the wholesale cost of natural gas and electricity and to ensure that we recover all of the costs prudently incurred in purchasing natural gas and electricity for our customers. Therefore, our regulated energy distribution operations have limited commodity price risk exposure.

Unregulated Energy Segment

Sharp and Flo-gas are exposed to commodity price risk as a result of the competitive nature of retail pricing offered to our customers. In order to mitigate this risk, we utilize propane storage activities and forward contracts for supply.

We can store up to approximately 6.8 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, particularly if we utilize fixed price forward contracts for supply. To mitigate the risk of propane commodity price fluctuations on the inventory valuation, we have adopted a Risk Management Policy that allows our propane distribution operation to enter into fair value hedges, cash flows hedges or other economic hedges of our inventory.

Aspire Energy is exposed to commodity price risk, primarily during the winter season, to the extent we are not successful in balancing our natural gas purchases and sales and have to secure natural gas from alternative sources at higher spot prices. In order to mitigate this risk, we procure firm capacity that meets our estimated volume requirements and we continue to seek out new producers with which to contract in order to fulfill our natural gas purchase requirements.

PESCO is a party to natural gas swap and futures contracts. These contracts provide PESCO with the right to purchase natural gas at a fixed price at future dates. Upon expiration, the contracts can be settled financially without taking delivery of natural gas, or PESCO can procure natural gas for its customers.

PESCO is subject to commodity price risk on its open positions to the extent that market prices for natural gas liquids and natural gas 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, 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.

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The following table reflects the changes in the fair market value of financial derivatives contracts related to natural gas and propane purchases and sales from December 31, 2017 to March 31, 2018:

(in thousands)	Balance at December 31, 2017			Increase (Decrease) in Fair Market Value			Less Amounts Settled			Balance at March 31, 2018
PESCO	$	(6,153	)	$	12,274		$	(8,464	)	$	(2,343	)
Sharp	1,192			(1,469		)	469			192
Total	$	(4,961	)	$	10,805		$	(7,995	)	$	(2,151	)

There were no changes in methods of valuations during the three months ended March 31, 2018.

The following is a summary of fair market value of financial derivatives as of March 31, 2018, by method of valuation and by maturity for each fiscal year period.

(in thousands)	2018			2019			2020		2021			2022		Total Fair Value
Price based on ICE - PESCO	$	(2,315	)	$	(295	)	$	335	$	(69	)	$	1	$	(2,343	)
Price based on Mont Belvieu - Sharp	208			(16		)	—		—			—		192
Total	$	(2,107	)	$	(311	)	$	335	$	(69	)	$	1	$	(2,151	)

WHOLESALE CREDIT RISK

The Risk Management Committee reviews credit risks associated with counterparties to commodity derivative contracts prior to such contracts being approved.

Additional information about our derivative instruments is disclosed in Note 12, Derivative Instruments, in the condensed consolidated financial statements.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of Chesapeake Utilities, 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, 2018. 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, 2018.

Changes in Internal Control over Financial Reporting

Beginning January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers. The impacts of the adoption are discussed in detail in Note 1, Summary of Accounting Policies, and Note 3, Revenue Recognition, in the notes to the condensed consolidated financial statements within this Form 10-Q. In conjunction with this adoption, we implemented changes to our controls related to revenue which were not material to our internal controls over financial reporting. These included the development of new policies based on the five-step model provided in the new revenue standard, enhanced contract review requirements, and other ongoing monitoring activities. These controls were designed to provide assurance, at a reasonable level, of the fair presentation of our condensed consolidated financial statements and related disclosures. During the quarter ended March 31, 2018, there was no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

As disclosed in Note 6, Other Commitments and Contingencies, of the 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, 2017, 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 Chesapeake Utilities, 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 Chesapeake Utilities. 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, 2018 through January 31, 2018 (1)	388	$	76.00	—	—
February 1, 2018 through February 28, 2018	—	$	—	—	—
March 1, 2018 through March 31, 2018	—	$	—	—	—
Total	388	$	76.00	—	—

⁽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, 2017. During the quarter ended March 31, 2018, 388 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

Departure of named executive officer

On May 2, 2018, Elaine B. Bittner ceased serving as the Senior Vice President of Chesapeake Utilities Corporation and her employment terminated.

- 50

Item 6. Exhibits

10.1	Form of Performance Share Agreement, effective February 26, 2018 for the period 2018 to 2020, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Michael P. McMasters, Beth W. Cooper, Stephen C. Thompson, Jeffry M. Householder and James F. Moriarty is filed herewith.
31.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
31.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
32.1	Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350.
32.2	Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350.
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.

- 51

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 8, 2018

- 52

EX-10.1

PERFORMANCE STOCK AWARD AGREEMENT

pursuant to the

CHESAPEAKE UTILITIES CORPORATION

2013 STOCK AND INCENTIVE COMPENSATION PLAN

On _______________, (the “Grant Date”), Chesapeake Utilities Corporation, a Delaware corporation (the “Company”), has granted to _______________ (the “Grantee”), who resides at ___________________________________, a Performance Stock Award on the terms and subject to the conditions of this Performance Stock Award Agreement.

Recitals

WHEREAS, the Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan (the “Plan”) has been duly adopted by action of the Company's Board of Directors (the “Board”) on March 6, 2013 and approved by the Shareholders of the Company at a meeting held on May 2, 2013; and

WHEREAS, the Committee of the Board of Directors of the Company referred to in the Plan (the “Committee”) has determined that it is in the best interests of the Company to grant the Performance Stock Award described herein pursuant to the Plan; and

WHEREAS, the shares of the Common Stock of the Company (“Shares”) that are subject to this Agreement, when added to the other shares of Common Stock that are subject to awards granted under the Plan, do not exceed the total number of shares of Common Stock with respect to which awards are authorized to be granted under the Plan or the total number of shares of Common Stock that may be granted to an individual in a single calendar year.

Agreement

It is hereby covenanted and agreed by and between the Company and the Grantee as follows:

Section 1.Performance Stock Award and Performance Period

The Company hereby grants to the Grantee a Performance Stock Award as of the Grant Date. As more fully described herein, the Grantee may earn up to _________ Shares upon the Company's achievement of the performance criteria set forth in Section 2 (the “Performance Shares”) over the performance period from January 1, 2018 to December 31, 2020 (the “Performance Period”). This Award has been granted pursuant to the Plan; capitalized terms used in this agreement which are not specifically defined herein shall have the meanings ascribed to such terms in the Plan.

Section 2.Performance Criteria and Terms of Stock Award

(a)The Committee selected and established in writing performance criteria for the Performance Period, which, if met, may entitle the Grantee to some or all of the Performance Shares under this Award. As soon as practicable after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period, the Committee shall determine for purposes of this Agreement the Company’s (1) total shareholder return, defined as the cumulative total return to shareholders (“Shareholder Value”), (2) growth in long-term earnings, defined as the growth in total capital expenditures as a percentage of total capitalization (“Growth”), and (3) earnings performance, defined as average return on equity (“RoE”), in accordance with procedures established by the Committee. The Shareholder Value, Growth and RoE (each a “Performance Metric” and collectively, the “Performance Metrics”) shall be determined

by the Committee in accordance with the terms of the Plan and this Agreement based on financial results reported to shareholders in the Company’s annual reports and may be subject to adjustment by the Committee for extraordinary events during the Performance Period, as applicable. Both the Shareholder Value and the Growth Performance Metrics will be compared to the performance of the 2018-2020 Performance Peer Group, Attachment A hereto and to the 2018-2020 Long-Term Award Resolution (collectively referred to as the “Peer Group”), for the Performance Period and Awards will be determined according to the schedule in subsection (b) below. For Shareholder Value, the calculation of total shareholder return will utilize the average closing stock price from November 1 through December 31 immediately preceding the beginning and at the end of the performance period. For the average RoE Performance Metric, the Company’s performance will be compared to pre-determined RoE thresholds established by the Committee. At the end of the Performance Period, the Committee shall certify the extent to which the Performance Goals were met during the Performance Period. If the Performance Goals for the Performance Period are met, the Grantee shall be entitled to the Award, subject to the Committee’s exercise of discretion to adjust any Award to a grantee based on business objectives established for that grantee or other factors as determined by the Committee in its sole discretion. The Committee shall promptly notify the Grantee of its determination.

(b)The Grantee may earn 50% percent or more of the target award of _____ Performance Shares (the “Target Award”) up to a maximum number of Performance Shares set forth in Section 1 above (the “Maximum Award”) based upon achievement of threshold and target levels of performance against the Performance Metrics established for the Performance Period . The Committee shall confirm the level of Award attained for the Performance Period after the Company’s independent auditors have certified the Company’s financial statements for each fiscal year of the Company in the Performance Period.

(c)Once established, the performance criteria identified above normally shall not be changed during the Performance Period. However, if any of the companies in the Peer Group cease to be publically traded, they will automatically be deleted from the Peer Group. In addition, if the Committee determines that external changes or other unanticipated business conditions have materially affected the fairness of the goals, or that a change in the business, operations, corporate structure or capital structure of the Company, or the manner in which it conducts its business, or acquisitions or divestitures of subsidiaries or business units, or other events or circumstances materially affect the performance criteria or render the performance criteria unsuitable, then the Committee may approve appropriate adjustments to the performance criteria (either up or down) during the Performance Period, in its discretion.

(d)Performance Shares that are earned by the Grantee pursuant to this Section 2 shall be issued promptly, without payment of consideration by the Grantee, within 2 ½ months of the end of the Performance Period. The Grantee shall have the right to vote the Performance Shares and to receive the dividends distributable with respect to such Shares on and after, but not before, the date on which the Grantee is recorded on the Company's ledger as holder of record of the Performance Shares (the “Issue Date”). If, however, the Grantee receives Shares as part of any dividend or other distribution with respect to the Performance Shares, such Shares shall be treated as if they are Performance Shares, and such Shares shall be subject to all of the terms and conditions imposed by this Section 2. Notwithstanding the foregoing, the Grantee shall be entitled to receive an amount in cash, equivalent to the dividends that would have been paid on the awarded Performance Shares from the Grant Date to the Issue Date for those Performance Shares actually earned by the Grantee during the applicable Performance Period. Such dividend equivalents shall be payable at the time such Performance Shares are issued.

(e)The Performance Shares will not be registered for resale under the Securities Act of 1933 or the laws of any state except when and to the extent determined by the Board pursuant to a resolution. Until a registration statement is filed and becomes effective, however, transfer of the Performance Shares shall require the availability of an exemption from such registration, and prior to the issuance of new certificates, the Company shall be entitled to take such measures as it deems appropriate (including but

not limited to obtaining from the Grantee an investment representation letter and/or further legending the new certificates) to ensure that the Performance Shares are not transferred in the absence of such exemption.

(f) In the event of a Change in Control, as defined in the Plan, during the Performance Period, the Grantee shall earn the Target Award of Performance Shares set forth in this Section 2, as if all performance criteria were satisfied, without any pro ration based on the portion of the Performance Period that has expired as of the date of such Change in Control.

(g)If, during the Performance Period, the Grantee has a Termination of Employment, Performance Shares shall be deemed earned or forfeited as follows:

(1)Except as provided in Section (2), below, upon voluntary Termination of Employment by the Grantee or termination by the Company for any reason, all unearned Performance Shares shall be forfeited immediately; and

(2) If the Grantee has a Termination of Employment by reason of death or Disability or Retirement (as such terms are defined in the Plan), the number of Performance Shares that would otherwise have been earned at the end of the Performance Period shall be reduced by pro rating such Performance Shares based on the proportion of the Performance Period during which the Grantee was employed by the Company (based upon the full months of the Performance Period elapsed as of the end of the month in which the Termination of Employment occurred over the total number of months in the Performance Period), unless the Committee determines that the Performance Shares shall not be so reduced.

(a)The Grantee shall be solely responsible for any federal, state and local taxes of any kind imposed in connection with the vesting or delivery of the Performance Shares. Prior to the transfer of any Performance Shares to the Grantee, the Grantee shall remit to the Company an amount sufficient to satisfy any federal, state, local and other withholding tax requirements. The Grantee may elect to have all or part of any withholding tax obligation satisfied by having the Company withhold Shares otherwise deliverable to the Grantee as Performance Shares, unless the Committee determines otherwise by resolution. If the Grantee fails to make such payments or election, the Company and its subsidiaries shall, to the extent permitted by law, have the right to deduct from any payments of any kind otherwise due to the Grantee any taxes required by law to be withheld with respect to the Performance Shares. In the case of any amounts withheld for taxes pursuant to this provision in the form of Shares, the amount withheld shall not exceed the maximum required by applicable law and regulations.

(i)Notwithstanding any other provision of this Agreement, if any payment or distribution (a "Payment") by the Company or any other person or entity to or for the benefit of the Grantee is determined to be an "excess parachute payment" (within the meaning of Code Section 280G(b)(1) or any successor provision of similar effect), whether paid or payable or distributed or distributable pursuant to this Agreement or otherwise, then the Grantee’s benefits under this Agreement may, unless the Grantee elects otherwise pursuant to his employment agreement, be reduced by the amount necessary so that the Grantee’s total "parachute payment" as defined in Code Section 280G(b)(2)(A) under this and all other agreements will be $1.00 less than the amount that would be a "parachute payment". The payment of any “excess parachute payment” pursuant to this paragraph shall also comply with the terms of the Grantee’s employment agreement, if any.

Section 3.Additional Conditions to Issuance of Shares

Each transfer of Performance Shares shall be subject to the condition that if at any time the Committee shall determine, in its sole discretion, that it is necessary or desirable as a condition of, or in connection with, the transfer of Performance Shares (i) to satisfy withholding tax or other withholding liabilities, (ii) to

effect the listing, registration or qualification on any securities exchange or under any state or federal law of any Shares deliverable in connection with such exercise, or (iii) to obtain the consent or approval of any regulatory body, then in any such event such transfer shall not be effective unless such withholding, listing, registration, qualification, consent or approval shall have been effected or obtained free of any conditions not acceptable to the Company.

Section 4.Adjustment of Shares

(a)If the Company shall become involved in a merger, consolidation or other reorganization, whether or not the Company is the surviving corporation, any right to earn Performance Shares shall be deemed a right to earn or to elect to receive the consideration into which the Shares represented by the Performance Shares would have been converted under the terms of the merger, consolidation or other reorganization. If the Company is not the surviving corporation, the surviving corporation (the “Successor”) shall succeed to the rights and obligations of the Company under this Agreement.

(b)If any subdivision or combination of Shares or any stock dividend, capital reorganization or recapitalization occurs after the adoption of the Plan, the Committee shall make such proportionate adjustments as are appropriate to the number of Performance Shares to be earned in order to prevent the dilution or enlargement of the rights of the Grantee.

Section 5.No Right to Employment

Nothing contained in this Agreement shall be deemed by implication or otherwise to confer upon the Grantee any right to continued employment by the Company or any affiliate of the Company or to limit the right of the Company to terminate the Grantee’s employment for any reason or for no reason.

Section 6.Notice

Any notice to be given hereunder by the Grantee shall be sent by mail addressed to Chesapeake Utilities Corporation, 909 Silver Lake Boulevard, Dover, Delaware 19904, for the attention of the Committee, c/o the Corporate Secretary, and any notice by the Company to the Grantee shall be sent by mail addressed to the Grantee at the address of the Grantee shown on the first page hereof. Either party may, by notice given to the other in accordance with the provisions of this Section, change the address to which subsequent notices shall be sent.

Section 7.Beneficiary Designation

Grantee may designate a beneficiary to receive any Performance Shares to which Grantee is entitled which vest as a result of Grantee’s death. Grantee acknowledges that the Company may exercise all rights under this Agreement and the Plan against Grantee and Grantee’s estate, heirs, lineal descendants and personal representatives and shall not be limited to exercising its rights against Grantee’s beneficiary.

Section 8.Assumption of Risk

It is expressly understood and agreed that the Grantee assumes all risks incident to any change hereafter in the applicable laws or regulations or incident to any change in the market value of the Performance Shares.

Section 9.Terms of Plan and Employment Agreement

This Agreement is entered into pursuant to the Plan (a summary of which has been delivered to the Grantee). This Agreement is subject to all of the terms and provisions of the Plan, which are incorporated into this Agreement by reference, and the actions taken by the Committee pursuant to the Plan. In the event of a conflict between this Agreement and the Plan, the provisions of the Plan shall govern. In addition, this Award

is subject to applicable provisions of the Grantee’s employment agreement, including provisions requiring the Company to recover some or all of the Performance Shares awarded hereunder in the circumstances described in such agreement or as otherwise required by applicable law. All determinations by the Committee shall be in its sole discretion and shall be binding on the Company and the Grantee.

Section 10.Governing Law; Amendment

This Agreement shall be governed by, and shall be construed and administered in accordance with, the laws of the State of Delaware (without regard to its choice of law rules) and the requirements of any applicable federal law. This Agreement may be modified or amended only by a writing signed by the parties hereto.

Section 11.Action by the Committee

The parties agree that the interpretation of this Agreement shall rest exclusively and completely within the sole discretion of the Committee. The parties agree to be bound by the decisions of the Committee with regard to the interpretation of this Agreement and with regard to any and all matters set forth in this Agreement. The Committee may delegate its functions under this Agreement to an officer of the Company designated by the Committee (hereinafter the “Designee”). In fulfilling its responsibilities hereunder, the Committee or its Designee may rely upon documents, written statements of the parties or such other material as the Committee or its Designee deems appropriate. The parties agree that there is no right to be heard or to appear before the Committee or its Designee and that any decision of the Committee or its Designee relating to this Agreement shall be final and binding unless such decision is arbitrary and capricious.

Section 12.Terms of Agreement

This Agreement shall remain in full force and effect and shall be binding on the parties hereto for so long as any Performance Shares issued to the Grantee under this Agreement continue to be held by the Grantee.

IN WITNESS WHEREOF, the Company has caused this Agreement to be executed in its corporate name, and the Grantee has executed the same in evidence of the Grantee'sacceptance hereof, upon the terms and conditions herein set forth, as of the day and year first above written.

CHESAPEAKE UTILITIES CORPORATION

By:

Its:

Grantee:

Printed Name:

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, 2018 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 8, 2018

/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, 2018 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 8, 2018

/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, 2018, 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 8, 2018

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, 2018, 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 8, 2018

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, 2018	Apr. 30, 2018
Document Document And Entity Information [Abstract]
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, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q1
Amendment Flag	false
Entity Common Stock, Shares Outstanding		16,363,792

XML

Condensed Consolidated Statements of Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating Revenues
Regulated Energy	$ 109,393	$ 97,654
Unregulated Energy and other	129,963	87,506
Total Operating Revenues	239,356	185,160
Operating Expenses
Regulated Energy cost of sales	48,231	40,244
Unregulated Energy and other cost of sales	99,826	60,754
Operations	32,702	32,490
Maintenance	3,593	3,231
Depreciation and amortization	9,704	8,812
Other taxes	4,894	4,530
Total Operating Expenses	198,950	150,061
Operating Income	40,406	35,099
Other income (expense), net	68	(700)
Interest charges	3,664	2,739
Income Before Income Taxes	36,810	31,660
Income taxes	9,955	12,516
Net Income	$ 26,855	$ 19,144
Weighted Average Common Shares Outstanding:
Basic (shares)	16,351,338	16,317,224
Diluted (shares)	16,402,985	16,363,796
Earnings Per Share of Common Stock:
Basic (in dollars per share)	$ 1.64	$ 1.17
Diluted (in dollars per share)	1.64	1.17
Cash Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.3250	$ 0.305

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Statement of Comprehensive Income [Abstract]
Net Income	$ 26,855	$ 19,144
Other Comprehensive (Loss) Income, net of tax:
Amortization of prior service cost, net of tax of $(5) and $(8), respectively	(14)	(11)
Net gain, net of tax of $41 and $77, respectively	108	93
Cash Flow Hedges, net of tax:
Unrealized (loss)/gain on commodity contract cash flow hedges, net of tax of ($756) and $192, respectively	(1,788)	338
Total Other Comprehensive (Loss) Income, net of tax	(1,694)	420
Comprehensive Income	$ 25,161	$ 19,564

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Statement of Comprehensive Income [Abstract]
Amortization of prior service cost, tax	$ (5)	$ (8)
Net gain, tax	41	77
Unrealized (loss)/gain on commodity contract cash flow hedges, tax	$ (756)	$ 192

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Mar. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment
Regulated Energy		$ 1,083,004	$ 1,073,736
Unregulated Energy		213,803	210,682
Other businesses and eliminations		27,892	27,699
Total property, plant and equipment		1,324,699	1,312,117
Less: Accumulated depreciation and amortization		(279,802)	(270,599)
Plus: Construction work in progress		131,640	84,509
Net property, plant and equipment		1,176,537	1,126,027
Current Assets
Cash and cash equivalents		5,996	5,614
Trade and other receivables (less allowance for uncollectible accounts of $901 and $936, respectively)		69,447	77,223
Accrued revenue		18,907	22,279
Propane inventory, at average cost		7,345	8,324
Other inventory, at average cost		4,607	12,022
Regulatory assets		10,833	10,930
Storage gas prepayments		1,197	5,250
Income taxes receivable		4,378	14,778
Prepaid expenses		8,199	13,621
Derivative assets, at fair value		208	1,286
Other current assets		6,717	7,260
Total current assets		137,834	178,587
Deferred Charges and Other Assets
Goodwill		22,104	22,104
Other intangible assets, net		4,482	4,686
Investments, at fair value		6,641	6,756
Regulatory assets		75,536	75,575
Other assets		4,316	3,699
Total deferred charges and other assets		113,079	112,820
Total Assets		1,427,450	1,417,434
Stockholders’ equity
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding		0	0
Common stock, par value $0.4867 per share (authorized 50,000,000 shares)		7,964	7,955
Additional paid-in capital		254,126	253,470
Retained earnings		250,024	229,141
Accumulated other comprehensive loss		(6,873)	(4,272)
Deferred compensation obligation		3,573	3,395
Treasury stock		(3,573)	(3,395)
Total stockholders’ equity	[1]	505,241	486,294
Long-term debt, net of current maturities		222,014	197,395
Total capitalization		727,255	683,689
Current Liabilities
Current portion of long-term debt		9,389	9,421
Short-term borrowing		229,108	250,969
Accounts payable		57,457	74,688
Customer deposits and refunds		34,795	34,751
Accrued interest		3,256	1,742
Dividends payable		5,318	5,312
Accrued compensation		5,444	13,112
Regulatory liabilities		18,503	6,485
Derivative liabilities, at fair value		2,359	6,247
Other accrued liabilities		8,694	10,273
Total current liabilities		374,323	413,000
Deferred Credits and Other Liabilities
Deferred income taxes		141,484	135,850
Regulatory liabilities		141,346	140,978
Environmental liabilities		8,215	8,263
Other pension and benefit costs		28,981	29,699
Deferred investment tax credits and other liabilities		5,846	5,955
Total deferred credits and other liabilities		325,872	320,745
Environmental and other commitments and contingencies (Note 5 and 6)
Total Capitalization and Liabilities		$ 1,427,450	$ 1,417,434

[1] Includes 93,422 and 90,961 shares at March 31, 2018 and December 31, 2017, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.

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Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 901	$ 936
Common stock, par value (in dollars per share)	$ 0.4867	$ 0.4867
Common stock, shares authorized (shares)	50,000,000	50,000,000
Preferred Stock, Shares Authorized	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Preferred Stock, Shares Issued	0	0

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Condensed Consolidated Statements of Cash Flows (Unaudited) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Operating Activities
Net Income	$ 26,855	$ 19,144
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	9,704	8,812
Depreciation and accretion included in other costs	2,276	1,939
Deferred income taxes	6,469	7,849
Realized gain on commodity contracts/sale of assets/investments	3,416	1,330
Unrealized loss on investments/commodity contracts	44	132
Employee benefits and compensation	228	423
Share-based compensation	1,520	639
Other, net	(12)	(4)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	9,649	5,095
Propane inventory, storage gas and other inventory	12,448	6,688
Regulatory assets/liabilities, net	11,511	6,103
Prepaid expenses and other current assets	8,095	1,136
Accounts payable and other accrued liabilities	(26,932)	(5,897)
Income taxes receivable	8,741	9,500
Customer deposits and refunds	44	400
Accrued compensation	(7,731)	(4,966)
Other assets and liabilities, net	347	1,631
Net cash provided by operating activities	66,672	59,954
Investing Activities
Property, plant and equipment expenditures	(63,116)	(42,172)
Proceeds from sales of assets	193	36
Environmental expenditures	(48)	(57)
Net cash used in investing activities	(62,971)	(42,193)
Financing Activities
Common stock dividends	(5,147)	(4,815)
(Purchase) issuance of stock under the Dividend Reinvestment Plan	(164)	222
Tax Withholding payments related to net settled stock compensation	(719)	(692)
Change in cash overdrafts due to outstanding checks	2,352	587
Net repayment under line of credit agreements and short-term borrowing under the Revolver	(24,213)	(11,125)
Proceeds from issuance of long-term debt	25,000	0
Repayment of long term debt and capital lease obligation	(428)	(416)
Net cash used in financing activities	(3,319)	(16,239)
Net Increase in Cash and Cash Equivalents	382	1,522
Cash and Cash Equivalents—Beginning of Period	5,614	4,178
Cash and Cash Equivalents—End of Period	$ 5,996	$ 5,700

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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, 2016	[1]			16,303,499
Beginning Balances at Dec. 31, 2016		$ 446,086	[1]	$ 7,935	$ 250,967	$ 192,062	$ (4,878)	$ 2,416	$ (2,416)
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		58,124				58,124
Other comprehensive income (loss)		606					606
Dividend declared		(21,045)				(21,045)
Retirement savings plan and dividend reinvestment plan (shares)				10,771
Dividend reinvestment plan		735		$ 5	730
Stock issuance, shares				0
Stock issuance		(10)		$ 0	(10)
Share-based compensation (shares)	[2],[3]			30,172
Share-based compensation and tax benefit	[2],[3]	1,798		$ 15	1,783
Treasury stock activities		0						979	(979)
Ending Balances (shares) at Dec. 31, 2017	[1],[4]			16,344,442
Ending Balances at Dec. 31, 2017		$ 486,294	[4]	$ 7,955	253,470	229,141	(4,272)	3,395	(3,395)
Preferred Stock, Shares Authorized		2,000,000
Preferred Stock, Par or Stated Value Per Share		$ 0.01
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		$ 26,855				26,855
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect		(907)				907	(907)
Other comprehensive income (loss)		(1,694)					(1,694)
Dividend declared		(5,381)				(5,381)
Stock Issued During Period, Shares, Dividend Reinvestment Plan				0
Stock Issued During Period, Value, Dividend Reinvestment Plan		(1)		$ 0	(1)
Share-based compensation (shares)	[2],[3]			19,350
Share-based compensation and tax benefit	[2],[3]	666		$ 9	657
Treasury stock activities		0						178	(178)
Ending Balances (shares) at Mar. 31, 2018	[1],[4]			16,363,792
Ending Balances at Mar. 31, 2018		$ 505,241	[4]	$ 7,964	$ 254,126	250,024	$ (6,873)	$ 3,573	$ (3,573)
Preferred Stock, Shares Authorized		2,000,000
Preferred Stock, Par or Stated Value Per Share		$ 0.01
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Cumulative Effect of New Accounting Principle in Period of Adoption		$ (1,498)				$ (1,498)

[1] 2,000,000 shares of preferred stock at $0.01 par value have been authorized. None has been issued or is outstanding; accordingly, no information has been included in the statements of stockholders’ equity.

[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, 2018, and for the year ended December 31, 2017, we withheld 10,436 and 10,269 shares, respectively, for taxes.

[4] Includes 93,422 and 90,961 shares at March 31, 2018 and December 31, 2017, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.

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Condensed Consolidated Statements of Stockholders' Equity (Parenthetical) (Unaudited) - USD ($) $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]
Dividend declared (in dollars per share)	$ 0.3250	$ 1.2800
Deferred compensation plan held Rabbi Trust (shares)	93,422	90,961
Preferred Stock, Shares Authorized	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Proceeds from Issuance of Common Stock		$ (10)
Shares issued under the performance incentive plan withheld for employee taxes (shares)	10,436	10,269

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Summary of Accounting Policies

3 Months Ended

Mar. 31, 2018

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, 2017. 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.

ARM, Chipola and Central Gas Asset Acquisitions

In August 2017, PESCO acquired certain natural gas marketing assets of ARM. We have accounted for the purchase of these assets as a business combination and recorded goodwill of $6.8 million, which is included in the Unregulated Energy segment. The acquired assets complement PESCO’s current asset portfolio and expanded our regional footprint and retail demand in a market where we had existing pipeline capacity and wholesale liquidity. In connection with the acquisition, we recorded a contingent liability of $2.5 million, which represents the expected future payment of additional consideration to ARM based on the achievement of certain performance targets. The payment, which is expected to be paid in 2019, is contingent upon the achievement of certain gross margin targets during the 2018 calendar year. The recorded liability is based upon our most recent gross margin projections for the acquired assets and is subject to change based on actual performance or changes in our gross margin projections.

In August 2017, Flo-gas acquired certain operating assets of Chipola, which provides propane distribution service to approximately 800 residential and commercial customers in Bay, Calhoun, Gadsden, Jackson, Liberty, and Washington Counties, Florida.

In December 2017, Flo-gas acquired certain operating assets of Central Gas, which provides propane distribution service to approximately 325 residential and commercial customers in Glades, Highlands, Martin, Okeechobee, and St. Lucie Counties, Florida.

The revenue and net income from these acquisitions that were included in our condensed consolidated statements of income for the three months ended March 31, 2018, were not material. The amounts recorded in conjunction with our acquisitions are preliminary and subject to adjustment based on additional valuations performed during the measurement period.

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

Revenue from Contracts with Customers (ASC 606) - On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and all the related amendments using the modified retrospective method. We recognized the cumulative effect of initially applying the new revenue standard to all of our contracts as an adjustment to the beginning balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. We expect the impact of the adoption of the new revenue standard to be immaterial to our net income on an ongoing basis.

This standard requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to receive in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. See Note 3, Revenue Recognition, for additional information.

The following highlights the impact of the adoption of ASC 606 on our condensed consolidated income statement and condensed consolidated balance sheet for the three months ended March 31, 2018:

	Three months ended March 31, 2018
Income statement	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Regulated Energy operating revenues	$	109,393	$	110,357	$	(964	)
Regulated Energy cost of sales	$	48,231	$	48,803	$	(572	)
Depreciation and amortization	$	9,704	$	9,689	$	15
Income before income taxes	$	36,810	$	37,217	$	(407	)
Income taxes	$	9,955	$	10,077	$	(122	)
Net income	$	26,855	$	27,140	$	(285	)

	As of March 31, 2018
Balance sheet	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Assets
Accrued revenues	$	18,907	$	20,213	$	(1,306	)
Other assets	$	4,316	$	4,508	$	(192	)
Capitalization
Retained earnings	$	250,024	$	251,522	$	(1,498	)

The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $407,000 in annual revenue from 2018 to future years and a cumulative adjustment that decreased retained earnings and other assets by $1.5 million, associated with a long-term firm transmission contract with an industrial customer.

Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update allows for capitalization of the service cost component when applicable. We adopted ASU 2017-07 on January 1, 2018 and applied the changes in the presentation of the service cost and other components of net benefit costs, retrospectively. Aside from changes in presentation, the implementation of this standard did not have a material impact on our financial position or results of operations.

Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain transactions are classified in the statement of cash flows. We adopted ASU 2016-15 on January 1, 2018. The implementation of this new standard did not have a material impact on our condensed consolidated statement of cash flows.

Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scopeof ModificationAccounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) changes because of a change in the terms or conditions of the award. We adopted ASU 2017-09, prospectively, on January 1, 2018. The implementation of this new standard did not have a material impact on our financial position or results of operations.

Income Statement - Reporting Comprehensive Income (ASC 220) - In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. We elected to early adopt ASU 2018-02 on January 1, 2018 and reclassified stranded tax effects from accumulated other comprehensive loss related to our employee benefit plans and commodity contracts cash flows hedges. The implementation of this new standard did not have a material impact on our financial position and results of operations. See Note 8, Stockholders' Equity, for additional information.

Recent Accounting Standards Yet to be Adopted

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.

The FASB allows companies to elect several practical expedients, in order to simplify the transition to the new standard. The following three expedients must all be elected together:

• An entity need not reassess whether any expired or existing contracts are or contain leases.

• An entity need not reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840 will continue to be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will continue to be classified as capital leases).

•An entity need not reassess initial direct costs for any existing leases.

Other practical expedients that can be elected individually are:

• An entity may elect to use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets.

• An entity may elect to apply the provisions of the new lease guidance at the effective date, without adjusting the comparative periods presented.

We expect to use the practical expedients to assist in implementation of this standard. We have assessed all of our leases and have concluded that we may have some operating leases that qualify for the short-term lease exception. Upon adoption, we will record the right-of-use assets and the lease liabilities related to our operating leases with a lease term in excess of one year. We do not believe that this will have a material impact on our financial position, results of operations or cash flows.

In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, which provides a practical expedient under Topic 842 to not evaluate existing or expired land easements that were not previously accounted for as leases. We plan to utilize the provided practical expedient for existing and expired land easements and will assess all new or modified land easements and right-of-way agreements, under the guidance of ASU 2016-02, following its adoption.

Intangibles-Goodwill (ASC 350) - In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. ASU 2017-04 will be effective for our annual and interim financial statements beginning January 1, 2020, although early adoption is permitted. The amendments included in this ASU are to be applied prospectively. We believe that the implementation of this new standard will not have a material impact on our financial position or results of operations.

Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Among other changes to hedge designation, ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument included in the assessment of hedge effectiveness to be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. For disclosures, ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges, and it eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. ASU 2017-12 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We intend to adopt the updated hedge accounting standard in 2018, which we expect will reduce the MTM volatility in PESCO’s results due to better alignment of risk management activities and financial reporting, risk component hedging and certain other simplifications of hedge accounting guidance.

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Calculation of Earnings Per Share

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Calculation of Earnings Per Share

Calculation of Earnings Per Share

	Three Months Ended
	March 31,
	2018		2017
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	26,855	$	19,144
Weighted average shares outstanding	16,351,338		16,317,224
Basic Earnings Per Share	$	1.64	$	1.17
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	26,855	$	19,144
Reconciliation of Denominator:
Weighted shares outstanding—Basic	16,351,338		16,317,224
Effect of dilutive securities—Share-based compensation	51,647		46,572
Adjusted denominator—Diluted	16,402,985		16,363,796
Diluted Earnings Per Share	$	1.64	$	1.17

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Revenue Recognition (Notes)

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Revenue from Contract with Customer [Text Block]

3.     Revenue Recognition

We recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the subsequent month following the satisfaction of our performance obligation.

The following table is a breakdown of our revenue by major source based on product and service type for the three months ended March 31, 2018:

	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Florida natural gas division	$	5,864		$	—		$	—		$	5,864
Delaware natural gas division	32,072			—			—			32,072
FPU electric distribution	18,741			—			—			18,741
FPU natural gas distribution	23,213			—			—			23,213
Maryland natural gas division	10,672			—			—			10,672
Sandpiper	8,964			—			—			8,964
Total energy distribution	99,526			—			—			99,526
Energy transmission
Aspire Energy	—			12,077			—			12,077
Eastern Shore	15,597			—			—			15,597
Peninsula Pipeline	2,098			—			—			2,098
Total energy transmission	17,695			12,077			—			29,772
Energy generation
Eight Flags	—			4,378			—			4,378
Propane delivery
Delmarva Peninsula propane delivery	—			45,470			—			45,470
Florida propane delivery	—			6,634			—			6,634
Total propane delivery	—			52,104			—			52,104
Energy services
PESCO	—			81,559			—			81,559
Other and eliminations
Eliminations	(7,828		)	(5,245		)	(15,598		)	(28,671		)
Other	—			494			194			688
Total other and eliminations	(7,828		)	(4,751		)	(15,404		)	(27,983		)
Total operating revenues (1)	$	109,393		$	145,367		$	(15,404	)	$	239,356

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $(589,000) and $73,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to weather normalization for Maryland division and Sandpiper and late fees.

Regulated Energy segment

Our businesses within the Regulated Energy segment are regulated utilities whose operations and customer contracts are subject to tariff rates approved by the state regulators or the FERC.

Our energy distribution operations deliver natural gas or electricity to customers and we bill the customers for both the delivery of natural gas or electricity and the related commodity, where applicable. In most jurisdictions, our customers are also required to purchase the commodity from us, although certain customers in some jurisdictions may purchase the commodity from a third party retailer (in which case we only provide delivery service). We consider the delivery of natural gas or electricity and/or the related commodity sale as one performance obligation because the commodity and its delivery are highly interrelated with two-way dependency on one another. Our performance obligation is satisfied over time as natural gas or electricity is delivered and consumed by the customer. We recognize revenues based on monthly meter readings, which are based on quantity of natural gas or electricity used and the approved rates. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period to the extent that billing and delivery do not coincide.

Revenues for Eastern Shore are based on rates approved by the FERC. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to negotiated rates. Eastern Shore's services can be firm or interruptible. Firm services are offered on a guaranteed basis and are available at all times unless prevented by force majeure or other permitted curtailments. Interruptible customers only receive service when there is available capacity or supply. Our performance obligation is satisfied over time as we deliver natural gas to the customers' locations. We recognize revenues based on meter readings at the end of the month, which are based on capacity used or reserved and the fixed monthly charge.

Peninsula Pipeline is engaged in natural gas intra-state transmission to third-party customers and certain affiliates in the state of Florida. Our performance obligation is satisfied over time as the natural gas is transported to customers. We recognize revenue based on rates approved by the Florida PSC and the capacity used or reserved. Since we bill customers at the end of each month, we do not have any unbilled revenue.

Unregulated Energy segment

Revenues generated from the Unregulated Energy segment are not subject to any federal, state, or local pricing regulations. Aspire Energy primarily sources gas from hundreds of conventional producers and performs gathering and processing functions to maintain the quality and reliability of its gas for its wholesale customers. Aspire Energy's performance obligation is satisfied over time as natural gas is delivered to its customers. Aspire Energy recognizes revenue based on the deliveries of natural gas at contractually agreed upon rates (which are based upon an index price that is established monthly and a monthly operating fee, as applicable). For natural gas customers, we accrue unbilled revenues for natural gas that has been delivered, but not yet billed, at the end of an accounting period to the extent that billing and delivery do not coincide with the end of the accounting period.

Eight Flags' CHP plant, which is located on land leased from Rayonier, produces three sources of energy: electricity, steam and heated water. Rayonier purchases the steam (unfired and fired) and heated water, which is used in Rayonier’s production facility. Our electric distribution operation purchases the electricity generated by the CHP plant for distribution to its customers. Eight Flags' performance obligation is satisfied over time as deliveries of heated water, steam and electricity occur. Eight Flags recognizes revenues over time based on the amount of heated water, steam and electricity generated and delivered to its customers.

For our propane delivery operations, we recognize revenue based upon customer type and service offered. Generally, for propane bulk delivery customers (customers without meters) and wholesale sales, our performance obligation is satisfied when we deliver propane to the customers' locations (point-in-time basis). We recognize revenue from these customers based on the number of gallons delivered and the price per gallon at the point-in-time of delivery. For our propane delivery customers with meters, we satisfy our performance obligation over time when we deliver propane to customers. We recognize revenue over time based on the amount of propane consumed and the applicable price per unit. For propane delivery metered customers, we accrue unbilled revenues for propane that has been delivered, but not yet billed, at the end of an accounting period to the extent that billing and delivery do not coincide with the end of the accounting period.

PESCO provides natural gas supply and asset management services to customers (including Chesapeake Utilities affiliates) located primarily in Florida, the Delmarva Peninsula, and the Appalachian Basin. PESCO's performance obligation is satisfied over time as natural gas is delivered to its customers. PESCO recognizes revenue over time based on customer meter readings, on a monthly basis. We accrue unbilled revenues for natural gas that has been delivered, but not yet billed, at the end of an accounting period to the extent that billing and delivery do not coincide with the end of the accounting period.

Contract balances

The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our consolidated balance sheets. The opening and closing balances of our trade receivables, contract assets, and contract liability are as follows:

	Trade Receivables			Contract Assets (Non-current)		Contract Liability (Current)
in thousands
Balance at 12/31/2017	$	74,962		$	1,270	$	407
Balance at 3/31/2018	67,828			1,305		244
Increase (decrease)	$	(7,134	)	$	35	$	(163	)

Our trade receivables are included in trade and other receivables in the condensed consolidated balance sheets. Our non-current contract assets are included in other assets in the condensed consolidated balance sheet and relate to operations and maintenance costs that have not yet been recovered through rates for the sale of electricity to our electric distribution operation pursuant to a long-term service agreement.

At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. At March 31, 2018 and December 31, 2017, we had a contract liability, which was included in other accrued liabilities in the condensed consolidated balance sheet, of $244,000 and $407,000, respectively, and which relates to non-refundable prepaid fixed fees for our Delmarva Peninsula propane delivery operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the three months ended March 31, 2018, we recognized revenue of $251,000.

Practical expedients

For our businesses with agreements that contain variable consideration, we use the invoice practical expedient method. We determined that the amounts invoiced to customers correspond directly with the value to our customers and our performance to date.

For our long-term contracts, the revenue we recognize corresponds directly to the amount we have the right to invoice, which corresponds directly to our performance obligation. Our performance obligations under our long-term contracts are satisfied over time. As a practical expedient, we do not disclose information about remaining, or unsatisfied, performance obligations for these long-term contracts since the revenue recognized corresponds to the amount we have the right to invoice.

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Rates and Other Regulatory Activities

3 Months Ended

Mar. 31, 2018

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, as separate entities, by the Florida PSC.

Delaware

Effect of the TCJA on ratepayers: As result of the enactment of the TCJA, the Delaware PSC issued an order requiring all rate-regulated utilities to file estimates of the impact of the TCJA on their cost of service for the most recent test year available (including new rate schedules). The order also required utilities to propose procedures for changing rates to reflect those impacts on or before March 31, 2018. Our Delaware Division filed the requisite reports with the Delaware PSC on March 30, 2018. If, after reviewing our report, the Delaware PSC determines to reduce our rates, it will open a new docket and establish a procedural schedule for conducting an evidentiary hearing regarding the impacts of the TCJA on our operations and existing rates. We believe that the ultimate resolution of this matter will not have a material impact on our financial position or results of operations.

In addition, on February 1, 2018, the Delaware PSC issued an order requiring Delaware rate-regulated public utilities to accrue regulatory liabilities to reflect the impacts of the Delaware jurisdictional revenue requirement in light of the changes to the federal corporate income tax laws. In compliance with this order, we have established a regulatory liability to reflect the estimated impacts of the changes in the federal corporate income tax rate.

Maryland Division and Sandpiper

Effect of the TCJA on ratepayers: The Maryland PSC issued an order requiring all Maryland public utilities whose rates are explicitly grossed-up for income taxes to track the impacts of the TCJA beginning January 1, 2018. The order required utilities to: (a) apply regulatory accounting treatment, which includes the use of regulatory assets and liabilities for all impacts of the TCJA; (b) file, on or before February 15, 2018, an explanation of the expected effects of the TCJA on their expenses and revenues; and (c) explain when and how they expect to pass on to their customers the net results of those effects. We established a regulatory liability to reflect the estimated impacts of the changes in the federal corporate income tax rate in compliance with the Maryland PSC’s order. In addition, on February 15, 2018, our Maryland natural gas division and Sandpiper filed preliminary estimates of the annual impact of the change in the statutory federal income tax rate from 35 percent to 21 percent and requested that the Maryland PSC grant us additional time to finalize our calculations. In March 2018, our Maryland natural gas division and Sandpiper supplemented their initial filings to include, among other items, an explanation of when and how they propose to pass the tax impacts on to their customers. In April 2018, the Maryland PSC issued orders directing our Maryland natural gas division and Sandpiper to: (1) file tariff pages reflective of the Maryland PSC's recommended rates with an effective date of May 1, 2018; (2) implement a one-time bill credit for the regulatory liability established for refunds; and, (3) make an informational filing within 60 days after the distribution of the one-time refunds. The orders further directed that, if any additional tax savings are later identified by either our natural gas divisions, we make a filing with the Maryland PSC to return those savings to customers as soon as possible.

Florida

Florida Electric Reliability/Modernization Pilot Program: In July 2017, FPU’s electric division filed a petition with the Florida PSC, requesting approval to include $15.2 million of certain capital project expenditures in its rate base and to adjust its base rates accordingly. These expenditures are designed to improve the stability and safety of the electric system, while enhancing the capability of FPU’s electrical grid. An interconnection project with FPL, which enables FPU to mitigate fuel costs for its electric customers, was included in the $15.2 million capital project expenditures. In December 2017, the Florida PSC approved this petition, effective January 1, 2018. The settlement agreement prescribed the methodology for adjusting the new rates based on the lower federal income tax rate and the process and methodology regarding the refund of deferred income taxes, reclassified as a regulatory liability, as a result of the TCJA. We have established a regulatory liability to reflect the impacts of the changes in the federal corporate income tax rate in compliance with the settlement agreement.

Electric Limited Proceeding-Storm Recovery: In February 2018, FPU’s electric division filed a petition with the Florida PSC, requesting recovery of incremental storm restoration costs related to several hurricanes and tropical storms, along with the replenishment of FPU’s storm reserve to its pre-storm level of $1.5 million. As a result of these hurricanes and tropical storms, FPU’s storm reserve was depleted and is currently at a deficit of $779,000. FPU is requesting approval of a surcharge of $1.82 per kilowatt per hour for two years to recover and replenish storm-related costs. At this time, no date for approval of this petition has been scheduled by the Florida PSC.

Effect of the TCJA on ratepayers: The Office of Public Counsel filed a petition requesting that the Florida PSC establish a general docket to investigate and adjust rates for all investor-owned utilities related to the passage of the TCJA. The Florida PSC issued a Memorandum with a recommendation that, if utilities do not agree to a January 1, 2018 effective date, then the effective date should be February 6, 2018. On January 30, 2018, the Florida PSC scheduled informal meetings between its staff and interested persons to discuss the impact of the TCJA. Meetings to discuss the impact for natural gas utilities, electric utilities and water and wastewater utilities were held in mid-February 2018. In December 2017, the Florida PSC issued an order regarding the limited proceeding for FPU's electric division, which prescribes the applicability, timing and treatment of the implications of the TCJA. We established a regulatory liability to reflect the impacts of the changes in the federal corporate income tax rate in compliance with the settlement agreement. We believe that the ultimate resolution of this matter will not have a material impact on our financial position or results of operations.

Eastern Shore

2017 Expansion Project: In May 2016, the FERC approved Eastern Shore's request to initiate the pre-filing review process for its 2017 Expansion Project. The 2017 Expansion Project's facilities include approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional compressor unit at Eastern Shore’s existing Daleville compressor station in Chester County, Pennsylvania; and approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware. Eastern Shore entered into precedent agreements with seven existing customers, including three affiliates of Chesapeake Utilities, for a total of 61,162 Dts/d of additional firm natural gas transportation service on Eastern Shore’s pipeline system with an additional 52,500 Dts/d of firm transportation service at certain Eastern Shore receipt facilities.

In December 2016, Eastern Shore submitted an application for a CP authorizing construction of the expansion facilities, which the FERC issued in October 2017. The estimated cost of the 2017 Expansion Project is approximately $117.0 million. Eastern Shore submitted its Implementation Plan in October 2017 addressing the actions Eastern Shore will undertake to meet the environmental conditions set forth in the FERC's order.

In December 2017, the TETLP interconnect upgrade was placed into service, as Eastern Shore requested. The remaining segments of the 2017 Expansion Project are expected to be placed into service in various phases during the remainder of 2018.

2017 Rate Case Filing: In January 2017, Eastern Shore filed a base rate proceeding with the FERC, as required by the terms of its 2012 rate case settlement agreement. Eastern Shore's proposed rates were based on the mainline cost of service of approximately $60.0 million resulting in an overall requested revenue increase of approximately $18.9 million and a requested rate of return on common equity of 13.75 percent. In March 2017, the FERC issued an order suspending the tariff rates for the usual five-month period.

In August 2017, Eastern Shore implemented new rates, subject to refund, based upon the outcome of the rate proceeding.  Eastern Shore recorded incremental revenue of approximately $3.7 million for the year ended December 31, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates until the rate case settlement is approved by the FERC and customers receive refunds according to the terms of the settlement agreement. Eastern Shore filed an uncontested settlement agreement and a motion to place interim settlement rates into effect beginning on January 1, 2018, which interim settlement rates were approved by the FERC in December 2017. The settlement agreement was approved by the FERC in February 2018, and became final in March 2018. Eastern Shore will recover the costs of its 2016 System Reliability Project, along with the cost of investments and expenses associated with various expansion, reliability and safety initiatives. Not considering the effects of the TCJA, base rates will increase, on an annual basis, by approximately $9.8 million.

Effect of the TCJA on ratepayers: In March 2018, Eastern Shore filed with the FERC its revised base rates, reflecting the change in its federal corporate income tax rate. These adjusted base rates became effective April 1, 2018 and will generate approximately $6.6 million, on an annual basis. Any excess accumulated deferred income tax balances will flow back to customers over the period determined in the next rate case, absent any transition rule included in the TCJA or other statutes or rules that would govern the flow-back period. In April 2018, Eastern Shore refunded its customers, with interest, the difference between the proposed rates and the settlement rates. The refund to customers also reflected the difference in rates due to the impact of TCJA.

In March 2018, the FERC issued a Notice of Proposed Rulemaking proposing a process that will allow it to determine which jurisdictional natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the TCJA and changes to the FERC’s income tax allowance policies following the United Airlines, Inc. v. FERC decision. The Notice of Proposed Rulemaking proposed requiring interstate natural gas pipelines to provide an informational filing to allow the FERC to evaluate the impact of the TCJA on the pipelines’ revenue requirement. In April 2018, Eastern Shore filed comments in this proceeding requesting confirmation that Eastern Shore is not required to provide an informational filing because it has already implemented lower rates based on the 21 percent tax rate in accordance with the settlement agreement in its 2017 rate case approved by the FERC. We believe that the ultimate resolution of this matter will not have a material impact on our financial position or results of operations.

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Environmental Commitments and Contingencies

3 Months Ended

Mar. 31, 2018

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, 2018, we had approximately $9.6 million in environmental liabilities related to 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 its MGP sites. Approximately $11.1 million has been recovered as of March 31, 2018, leaving approximately $2.9 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

Environmental liabilities for 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.

The following is a summary of our remediation status and estimated costs to implement clean-up of our key MGP sites:

Jurisdiction	MGP Site	Status	Cost to Clean up	Recovery through Rates
Florida	West Palm Beach	Remedial actions approved by the FDEP have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions.	Between $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.	Yes
Florida	Sanford	In March 2018, the EPA approved a "site-wide ready for anticipated use" status, which is the final step before delisting a site. Construction has been completed and restrictive covenants are in place to ensure protection of human health. The only remaining activity is long-term groundwater monitoring. It is unlikely that FPU will incur any significant future costs associated with the site.	FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be less than $10,000.	Yes
Florida	Winter Haven	Remediation is ongoing.	Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site.	Yes
Delaware	Seaford	Proposed plan for implementation approved by the DNREC in July 2017.	Between $273,000 and $465,000.	Yes
Maryland	Cambridge	Currently in discussions with the MDE.	Unable to estimate.	N/A

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Other Commitments and Contingencies

3 Months Ended

Mar. 31, 2018

Commitments and Contingencies Disclosure [Abstract]

Other Commitments and Contingencies

Other Commitments and Contingencies

Natural Gas, Electric and Propane Supply

We have entered into contractual commitments to purchase natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. In 2017, our Delmarva Peninsula natural gas distribution operations entered into asset management agreements with PESCO to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017, and each has a three-year term, expiring on March 31, 2020. Previously, the Delaware PSC approved PESCO to serve as an asset manager with respect to our Delaware Division.

In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term ending in May 2019. Sandpiper's current annual commitment is approximately 2.5 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 ending in May 2019. Sharp's current annual commitment is approximately 2.5 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 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.

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with FPL requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If this ratio is not met by FPU, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times) and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of March 31, 2018, FPU was in compliance with all of the requirements of its fuel supply contracts.

Eight Flags provides electricity and steam generation services through its CHP plant located on Amelia Island, Florida. In June 2016, Eight Flags began selling power generated from the CHP plant to FPU pursuant to a 20-year power purchase agreement for distribution to its retail electric customers. In July 2016, Eight Flags also started selling steam, pursuant to a separate 20-year contract, to Rayonier, the landowner on which the CHP plant is located. The CHP plant is powered by natural gas transported by FPU through its distribution system and Peninsula Pipeline through its intrastate pipeline.

Corporate Guarantees

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily PESCO. These corporate guarantees provide for the payment of natural gas purchases in the event that PESCO defaults. PESCO has never defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at March 31, 2018 was approximately $72.7 million, with the guarantees expiring on various dates through March 2019.

Chesapeake Utilities also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under this 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).

Letters of Credit

As of March 31, 2018, we have issued letters of credit totaling approximately $5.0 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, the payment of natural gas purchases for PESCO, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through December 2019. There have been no draws on these letters of credit as of March 31, 2018. We do not anticipate that the counterparties will draw upon these letters of credit, and we expect that the letters of credit will be renewed to the extent necessary in the future.

Other

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

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Segment Information

3 Months Ended

Mar. 31, 2018

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.

Our operations are comprised of two reportable segments:

• Regulated Energy. Includes energy distribution and transmission services (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. Includes energy transmission, energy generation, propane delivery, and other energy services (propane distribution, the operations of our Eight Flags' CHP plant, as well as natural gas marketing, gathering, processing, transportation and supply). These operations are unregulated as to their rates and services. Through March 2017, this segment also included the operations of Xeron, our propane and crude oil trading subsidiary that wound down its operations shortly after the first quarter of 2017. 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,
	2018		2017
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	105,954	$	96,446
Unregulated Energy segment and other businesses	133,402		88,714
Total operating revenues, unaffiliated customers	$	239,356	$	185,160
Intersegment Revenues (1)
Regulated Energy segment	$	3,439	$	1,208
Unregulated Energy segment	11,965		4,011
Other businesses	194		228
Total intersegment revenues	$	15,598	$	5,447
Operating Income
Regulated Energy segment	$	26,711	$	23,395
Unregulated Energy segment	13,684		11,575
Other businesses and eliminations	11		129
Total operating income	40,406		35,099
Other income (expense), net	68		(700		)
Interest charges	3,664		2,739
Income before Income Taxes	36,810		31,660
Income taxes	9,955		12,516
Net Income	$	26,855	$	19,144

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

(in thousands)	March 31, 2018		December 31, 2017
Identifiable Assets
Regulated Energy segment	$	1,148,635	$	1,121,673
Unregulated Energy segment	246,230		261,541
Other businesses and eliminations	32,585		34,220
Total identifiable assets	$	1,427,450	$	1,417,434

Our operations are entirely domestic.

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Stockholder's Equity - Accumulated Other Comprehensive Income (Loss)

3 Months Ended

Mar. 31, 2018

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

Stockholder's Equity

Preferred Stock

We had 2,000,000 authorized and unissued shares of preferred stock, $0.01 par value per share, as of March 31, 2018 and December 31, 2017. Shares of preferred stock may be issued from time to time, by authorization of our Board of Directors and without the necessity of further action or authorization by stockholders, in one or more series and with such voting powers, designations, preferences and relative, participating, optional or other special rights and qualifications as the Board of Directors may, in its discretion, determine.

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 other comprehensive loss. During the first quarter of 2018, we elected to early adopt ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. Accordingly, we reclassified stranded tax effects resulting from the TCJA from accumulated other comprehensive loss to retained earnings, related to our employee benefit plans and commodity contracts cash flows hedges.

The following tables present the changes in the balance of accumulated other comprehensive (loss)/income for the three months endedMarch 31, 2018 and 2017. All amounts except the stranded tax reclassification are presented net of tax.

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flows
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)
Other comprehensive loss before reclassifications	—			(2,232		)	(2,232		)
Amounts reclassified from accumulated other comprehensive income	94			444			538
Net current-period other comprehensive income/(loss)	94			(1,788		)	(1,694		)
Stranded tax reclassification to retained earnings	(1,022		)	115			(907		)
As of March 31, 2018	$	(5,671	)	$	(1,202	)	$	(6,873	)

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flows
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)
Other comprehensive income/(loss) before reclassifications	(9		)	1,278			1,269
Amounts reclassified from accumulated other comprehensive income/(loss)	91			(940		)	(849		)
Net prior-period other comprehensive income	82			338			420
As of March 31, 2017	$	(5,278	)	$	820		$	(4,458	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three months endedMarch 31, 2018 and 2017. Deferred gains or losses for our commodity contracts cash flows hedges are recognized in earnings upon settlement.

	Three Months Ended
	March 31,
	2018			2017
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit (1)	$	19		$	19
Net loss(1)	(149		)	(170		)
Total before income taxes	(130		)	(151		)
Income tax benefit	36			60
Net of tax	$	(94	)	$	(91	)
Gains and losses on commodity contracts cash flow hedges:
Propane swap agreements (2)	$	(464	)	$	388
Natural gas swaps (2)	(450		)	—
Natural gas futures (2)	298			1,150
Total before income taxes	(616		)	1,538
Income tax benefit (expense)	172			(598		)
Net of tax	(444		)	940
Total reclassifications for the period	$	(538	)	$	849

⁽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, call options and natural gas futures contracts are included in cost of sales in the accompanying consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying consolidated statements of income.

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Employee Benefit Plans

3 Months Ended

Mar. 31, 2018

Retirement Benefits [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, 2018 and 2017 are set forth in the following tables:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended March 31,	2018			2017			2018			2017			2018		2017		2018			2017			2018		2017
(in thousands)
Interest cost	$	97		$	103		$	592		$	623		$	21	$	22	$	10		$	10		$	12	$	13
Expected return on plan assets	(138		)	(127		)	(774		)	(699		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(19		)	(19		)	—		—
Amortization of net loss	88			107			109			131			25		22		15			16			—		—
Net periodic cost (benefit) (1)	47			83			(73		)	55			46		44		6			7			12		13
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	47		$	83		$	118		$	246		$	46	$	44	$	6		$	7		$	14	$	15

⁽¹⁾As a result of our adoption of ASU 2017-07 on January 1, 2018, the "other than service" cost components of net periodic costs have been recorded or reclassified to other income (expense), net in the condensed consolidated statements of income.

We expect to record pension and postretirement benefit costs of approximately $913,000 for 2018. Included in these costs is approximately $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 approximately $1.1 million and approximately $1.3 million at March 31, 2018 and December 31, 2017, respectively.

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 tables present 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, 2018 and 2017:

For the Three Months Ended March 31, 2018	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	88		109		25		15			—		237
Total recognized in net periodic benefit cost	88		109		25		(4		)	—		218
Recognized from accumulated other comprehensive loss (1)	88		21		25		(4		)	—		130
Recognized from regulatory asset	—		88		—		—			—		88
Total	$	88	$	109	$	25	$	(4	)	$	—	$	218

For the Three Months Ended March 31, 2017	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	107		131		22		16			—		276
Total recognized in net periodic benefit cost	107		131		22		(3		)	—		257
Recognized from accumulated other comprehensive loss (1)	107		25		22		(3		)	—		151
Recognized from regulatory asset	—		106		—		—			—		106
Total	$	107	$	131	$	22	$	(3	)	$	—	$	257

⁽¹⁾ See Note 8, Stockholder's Equity.

During the three months ended March 31, 2018, we contributed approximately $72,000 to the Chesapeake Pension Plan and approximately $309,000 to the FPU Pension Plan. We expect to contribute a total of approximately $359,000 and approximately $1.5 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2018, which represents 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 endedMarch 31, 2018, were approximately $38,000. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake SERP in 2018. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three months endedMarch 31, 2018, were approximately $12,000. We estimate that approximately $97,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2018. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three months ended March 31, 2018, were approximately $11,000. We estimate that approximately $88,000 will be paid for such benefits under the FPU Medical Plan in 2018.

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Investments

3 Months Ended

Mar. 31, 2018

Investments, Debt and Equity Securities [Abstract]

Investments

Investments

The investment balances at March 31, 2018 and December 31, 2017, consisted of the following:

(in thousands)	March 31, 2018		December 31, 2017
Rabbi trust (associated with the Deferred Compensation Plan)	$	6,621	$	6,734
Investments in equity securities	20		22
Total	$	6,641	6,756

We classify these investments as trading securities and report them at their fair value. For the three months ended March 31,2018 and 2017, we recorded a net unrealized loss of approximately $44,000 and a net unrealized gain of approximately $252,000, respectively, in other expense, net 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 consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust.

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Share-Based Compensation

3 Months Ended

Mar. 31, 2018

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, 2018 and 2017:

	Three Months Ended
	March 31,
	2018			2017
(in thousands)
Awards to non-employee directors	$	135		$	135
Awards to key employees	1,385			504
Total compensation expense	1,520			639
Less: tax benefit	(416		)	(257		)
Share-based compensation amounts included in net income	$	1,104		$	382

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 one-year service period. In May 2017, each of our non-employee directors received an annual retainer of 835 shares of common stock under the SICP for service as a director through the 2018 Annual Meeting of Stockholders. At March 31, 2018, there was approximately $45,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2018.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the three months endedMarch 31, 2018:

	Number of Shares		Weighted Average Fair Value
Outstanding—December 31, 2017	132,642		$	59.31
Granted	49,494		$	67.76
Vested	(29,786	)	$	47.39
Expired	(3,933	)	$	49.66
Outstanding—March 31, 2018	148,417		$	66.53

In February 2018, our Board of Directors granted awards of 49,494 shares of common stock to key employees under the SICP. The shares granted are multi-year awards that will vest at the end of the three-year service period ending December 31, 2020. 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.

In March 2018, upon the election of certain of our executive officers, we withheld shares with a value at least equivalent to each such executive officer’s minimum statutory obligation for applicable income and other employment taxes related to shares that we awarded for the performance period ended December 31, 2017, remitted the cash to the appropriate taxing authorities, and paid the balance of such awarded shares to each such executive officer. We withheld 10,436 shares, based on the value of the shares on their award date, determined by the average of the high and low prices of our common stock. Total combined payments for the employees’ tax obligations to the taxing authorities were approximately $719,000.

At March 31, 2018, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $10.4 million. At March 31, 2018, there was approximately $4.2 million of unrecognized compensation cost related to these awards, which is expected to be recognized from 2018 through 2020.

Stock Options

We did not have any stock options outstanding at March 31, 2018 or 2017, nor were any stock options issued during these periods.

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Derivative Instruments

3 Months Ended

Mar. 31, 2018

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 our 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 normal 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, 2018, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Hedging Activities in 2018

PESCO enters into natural gas futures contracts associated with the purchase and sale of natural gas to specific customers. These contracts are effective through March 2022, and we designate and account for them as cash flow hedges. There is no ineffective portion of these hedges. At March 31, 2018, PESCO had a total of 22.9 million Dts hedged under natural gas futures contracts, with a liability fair value of approximately $1.6 million. 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 2017

In 2017, Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 7.7 million gallons of propane expected to be purchased from October 2017 through March 2019, of which positions covering 2.1 million gallons of forecasted future purchases were outstanding as of March 31, 2018. Under the futures and swap agreements, Sharp will receive the difference between the index prices (Mont Belvieu prices in October 2017 through March 2019) and the swap prices of $0.59 per gallon, to the extent the index price exceeds the contracted price. If the index prices are lower than the swap prices, Sharp will pay the difference. Sharp received a total of approximately $464,000, which represented the difference between the index prices and the contracted prices during the first quarter of 2018 related to hedging activities originated in 2017 and received $3,000, which represented the mark-to-market activities for the three months ended March 31, 2018. At March 31, 2018, the futures and swap agreements had a fair value asset of approximately $204,000 and a fair value liability of $16,000. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss).

The impact on Sharp's financial instruments that were not designated as hedges in our consolidated financial statements as of March 31, 2018 was $4,000, which was recorded as a decrease in propane costs during the three months ended March 31, 2018 and is associated with 18,000 gallons of propane.

In August 2017, PESCO entered into natural gas swap agreements associated with financial contracts acquired in the ARM acquisition to mitigate the risk of fluctuations in wholesale natural gas prices associated with 702,000 Dts of natural gas PESCO expects to purchase through January 2020. We accounted for these swap agreements as cash flow hedges, which have a fair value liability of approximately $404,000 at March 31, 2018. The change in fair value of the natural gas swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss).

The impact on PESCO's financial instruments that were not designated as hedges in our consolidated financial statements as of March 31, 2018 was $300,000, which was recorded as an increase in gas costs during the three months ended March 31, 2018 and is associated with 87,500 Dts of natural gas.

Balance sheet offsetting

PESCO has entered into master netting agreements with counterparties that enable it to net the counterparties' outstanding accounts receivable and payable, which are presented on a net basis in the consolidated balance sheets. The following table summarizes the accounts receivable and payables on a gross and net basis at March 31, 2018 and December 31, 2017:

	At March 31, 2018
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	6,555	$	2,092	$	4,463
Accounts payable	$	13,912	$	2,092	$	11,820

	At December 31, 2017
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	8,283	$	2,391	$	5,892
Accounts payable	$	16,643	$	2,391	$	14,252

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, 2018 and December 31, 2017, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	4	$	13
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative assets, at fair value	—		92
Propane swap agreements	Derivative assets, at fair value	204		1,181
Total asset derivatives		$	208	$	1,286

	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative liabilities, at fair value	$	300	$5,776
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative liabilities, at fair value	1,639		469
Natural gas swap contracts	Derivative liabilities, at fair value	404		2
Propane swap agreements	Derivative liabilities, at fair value	16		—
Total liability derivatives		$	2,359	$	6,247

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	2018			2017
Derivatives not designated as hedging instruments
Realized gain on forward contracts and options (1)	Revenue	$	—		$	112
Natural gas futures contracts	Cost of sales	(2,835		)	124
Propane swap agreements	Cost of sales	(9		)	(4		)
Derivatives designated as fair value hedges
Put /Call option (2)	Cost of sales	—			(9		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	(464		)	388
Propane swap agreements	Other comprehensive loss	(992		)	(557		)
Natural gas futures contracts	Cost of sales	298			1,150
Natural gas swap contracts	Cost of sales	(450		)	1,087
Natural gas futures agreements	Other comprehensive income	65			—
Natural gas swap agreements	Other comprehensive loss	(1,732		)	—
Total		$	(6,119	)	$	2,291

⁽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 on the condensed consolidated balance sheets.

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Fair Value of Financial Instruments

3 Months Ended

Mar. 31, 2018

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, 2018 and December 31, 2017:

			Fair Value Measurements Using:
As of March 31, 2018	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	602		—		—		602
Investments—mutual funds and other	6,019		6,019		—		—
Total investments	6,641		6,039		—		602
Derivative assets	208		—		208		—
Total assets	$	6,849	$	6,039	$	208	$	602
Liabilities:
Derivative liabilities	$	2,359	$	—	$	2,359	$	—

			Fair Value Measurements Using:
As of December 31, 2017	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	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	648		—		—		648
Investments—mutual funds and other	6,086		6,086		—		—
Total investments	6,756		6,108		—		648
Derivative assets	1,286		—		1,286		—
Total assets	$	8,042	$	6,108	$	1,286	$	648
Liabilities:
Derivative liabilities	$	6,247	$	—	$	6,247	$	—

The following valuation techniques were used to measure the fair value of assets and liabilities in the tables above:

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:

Derivative assets and liabilities — The fair values of forward contracts are measured using market transactions in either the listed or OTC markets. 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, 2018 and 2017:

	Three Months Ended   March 31,
	2018			2017
(in thousands)
Beginning Balance	$	648		$	561
Purchases and adjustments	(48		)	2
Transfers	—			—
Distribution	—			—
Investment income	2			2
Ending Balance	$	602		$	565

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

At March 31, 2018, 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, 2018, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of approximately $230.1 million. This compares to a fair value of approximately $237.9 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At December 31, 2017, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of approximately $205.2 million, compared to the estimated fair value of approximately $215.4 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

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Long-Term Debt

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Our outstanding long-term debt is shown below:

	March 31,			December 31,
(in thousands)	2018			2017
FPU secured first mortgage bonds (1) :
9.08% bond, due June 1, 2022	$	7,983		$	7,982
Uncollateralized senior notes:
5.50% note, due October 12, 2020	6,000			6,000
5.93% note, due October 31, 2023	18,000			18,000
5.68% note, due June 30, 2026	26,100			26,100
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
3.25% note, due April 30, 2032	70,000			70,000
Long-term portion of the Revolver(2)	25,000			—
Promissory notes	26			97
Capital lease obligation	1,712			2,070
Less: debt issuance costs	(418		)	(433		)
Total long-term debt	231,403			206,816
Less: current maturities	(9,389		)	(9,421		)
Total long-term debt, net of current maturities	$	222,014		$	197,395

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

⁽²⁾ In January 2018, we borrowed an additional $25.0 million under the Revolver, which we classified as long-term debt. The maturity date of the Revolver is October 8, 2020. The interest rate on the Revolver is a variable interest rate that is dependent on various factors and resets every thirty days. As of March 31, 2018, the interest rate on the Revolver was LIBOR + 1.00% or 2.88%.

Shelf Agreements

In October 2015, we entered into the $150.0 million Prudential Shelf Agreement, under which we may request that Prudential purchase up to $150.0 million of our unsecured senior debt. As of March 31, 2018, we have issued $70.0 million of 3.25% Prudential Shelf Notes.

In March 2017, we entered into the MetLife Shelf Agreement and the NYL Shelf Agreement, under which we may request that MetLife and NYL, through March 2, 2020, purchase up to $150.0 million and $100.0 million, respectively, of our unsecured senior debt. The unsecured senior debt would have a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance. MetLife and NYL are under no obligation to purchase any unsecured senior debt. The interest rate and terms of payment of any series of unsecured senior debt will be determined at the time of purchase.

In November 2017, NYL agreed to purchase $50.0 million of 3.48% Series A notes and $50.0 million of 3.58% Series B notes. The Series A notes and Series B notes will be issued on or before May 21, 2018 and November 20, 2018, respectively. The proceeds received from the issuances of these NYL Shelf Notes will be used to reduce long and short-term borrowings under the Revolver and/or lines of credit and/or to fund capital expenditures. The NYL Shelf Agreement has been fully utilized.

As of March 31, 2018, we have $230.0 million of additional potential borrowing capacity under the Prudential and MetLife Shelf Agreements. The Prudential Shelf Agreement and the NYL Shelf Agreement set forth certain business covenants to which we are subject when any note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.

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Summary of Accounting Policies (Policies)

3 Months Ended

Mar. 31, 2018

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, 2017. 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.

FASB Statements and Other Authoritative Pronouncements

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

Revenue from Contracts with Customers (ASC 606) - On January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers, and all the related amendments using the modified retrospective method. We recognized the cumulative effect of initially applying the new revenue standard to all of our contracts as an adjustment to the beginning balance of retained earnings. The comparative information has not been restated and continues to be reported under the accounting standards in effect for those periods. We expect the impact of the adoption of the new revenue standard to be immaterial to our net income on an ongoing basis.

This standard requires entities to recognize revenue when control of the promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to receive in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. See Note 3, Revenue Recognition, for additional information.

The following highlights the impact of the adoption of ASC 606 on our condensed consolidated income statement and condensed consolidated balance sheet for the three months ended March 31, 2018:

	Three months ended March 31, 2018
Income statement	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Regulated Energy operating revenues	$	109,393	$	110,357	$	(964	)
Regulated Energy cost of sales	$	48,231	$	48,803	$	(572	)
Depreciation and amortization	$	9,704	$	9,689	$	15
Income before income taxes	$	36,810	$	37,217	$	(407	)
Income taxes	$	9,955	$	10,077	$	(122	)
Net income	$	26,855	$	27,140	$	(285	)

	As of March 31, 2018
Balance sheet	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Assets
Accrued revenues	$	18,907	$	20,213	$	(1,306	)
Other assets	$	4,316	$	4,508	$	(192	)
Capitalization
Retained earnings	$	250,024	$	251,522	$	(1,498	)

The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $407,000 in annual revenue from 2018 to future years and a cumulative adjustment that decreased retained earnings and other assets by $1.5 million, associated with a long-term firm transmission contract with an industrial customer.

Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update allows for capitalization of the service cost component when applicable. We adopted ASU 2017-07 on January 1, 2018 and applied the changes in the presentation of the service cost and other components of net benefit costs, retrospectively. Aside from changes in presentation, the implementation of this standard did not have a material impact on our financial position or results of operations.

Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain transactions are classified in the statement of cash flows. We adopted ASU 2016-15 on January 1, 2018. The implementation of this new standard did not have a material impact on our condensed consolidated statement of cash flows.

Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scopeof ModificationAccounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) changes because of a change in the terms or conditions of the award. We adopted ASU 2017-09, prospectively, on January 1, 2018. The implementation of this new standard did not have a material impact on our financial position or results of operations.

Income Statement - Reporting Comprehensive Income (ASC 220) - In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. We elected to early adopt ASU 2018-02 on January 1, 2018 and reclassified stranded tax effects from accumulated other comprehensive loss related to our employee benefit plans and commodity contracts cash flows hedges. The implementation of this new standard did not have a material impact on our financial position and results of operations. See Note 8, Stockholders' Equity, for additional information.

Recent Accounting Standards Yet to be Adopted

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.

The FASB allows companies to elect several practical expedients, in order to simplify the transition to the new standard. The following three expedients must all be elected together:

• An entity need not reassess whether any expired or existing contracts are or contain leases.

• An entity need not reassess the lease classification for any expired or existing leases (that is, all existing leases that were classified as operating leases in accordance with Topic 840 will continue to be classified as operating leases, and all existing leases that were classified as capital leases in accordance with Topic 840 will continue to be classified as capital leases).

•An entity need not reassess initial direct costs for any existing leases.

Other practical expedients that can be elected individually are:

• An entity may elect to use hindsight in determining the lease term and in assessing impairment of the entity’s right-of-use assets.

• An entity may elect to apply the provisions of the new lease guidance at the effective date, without adjusting the comparative periods presented.

We expect to use the practical expedients to assist in implementation of this standard. We have assessed all of our leases and have concluded that we may have some operating leases that qualify for the short-term lease exception. Upon adoption, we will record the right-of-use assets and the lease liabilities related to our operating leases with a lease term in excess of one year. We do not believe that this will have a material impact on our financial position, results of operations or cash flows.

In January 2018, the FASB issued ASU 2018-01, Land Easement Practical Expedient for Transition to Topic 842, which provides a practical expedient under Topic 842 to not evaluate existing or expired land easements that were not previously accounted for as leases. We plan to utilize the provided practical expedient for existing and expired land easements and will assess all new or modified land easements and right-of-way agreements, under the guidance of ASU 2016-02, following its adoption.

Intangibles-Goodwill (ASC 350) - In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. ASU 2017-04 will be effective for our annual and interim financial statements beginning January 1, 2020, although early adoption is permitted. The amendments included in this ASU are to be applied prospectively. We believe that the implementation of this new standard will not have a material impact on our financial position or results of operations.

Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Among other changes to hedge designation, ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument included in the assessment of hedge effectiveness to be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. For disclosures, ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges, and it eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. ASU 2017-12 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We intend to adopt the updated hedge accounting standard in 2018, which we expect will reduce the MTM volatility in PESCO’s results due to better alignment of risk management activities and financial reporting, risk component hedging and certain other simplifications of hedge accounting guidance.

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Summary of Accounting Policies Impact of Adoption of ASC 606 (Tables)

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Schedule of Prospective Adoption of New Accounting Pronouncements [Table Text Block]

The following highlights the impact of the adoption of ASC 606 on our condensed consolidated income statement and condensed consolidated balance sheet for the three months ended March 31, 2018:

	Three months ended March 31, 2018
Income statement	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Regulated Energy operating revenues	$	109,393	$	110,357	$	(964	)
Regulated Energy cost of sales	$	48,231	$	48,803	$	(572	)
Depreciation and amortization	$	9,704	$	9,689	$	15
Income before income taxes	$	36,810	$	37,217	$	(407	)
Income taxes	$	9,955	$	10,077	$	(122	)
Net income	$	26,855	$	27,140	$	(285	)

	As of March 31, 2018
Balance sheet	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Assets
Accrued revenues	$	18,907	$	20,213	$	(1,306	)
Other assets	$	4,316	$	4,508	$	(192	)
Capitalization
Retained earnings	$	250,024	$	251,522	$	(1,498	)

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Calculation of Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2018

Earnings Per Share [Abstract]

Calculation of Basic and Diluted Earnings Per Share

	Three Months Ended
	March 31,
	2018		2017
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	26,855	$	19,144
Weighted average shares outstanding	16,351,338		16,317,224
Basic Earnings Per Share	$	1.64	$	1.17
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	26,855	$	19,144
Reconciliation of Denominator:
Weighted shares outstanding—Basic	16,351,338		16,317,224
Effect of dilutive securities—Share-based compensation	51,647		46,572
Adjusted denominator—Diluted	16,402,985		16,363,796
Diluted Earnings Per Share	$	1.64	$	1.17

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Revenue Recognition (Tables)

3 Months Ended

Mar. 31, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

The following table is a breakdown of our revenue by major source based on product and service type for the three months ended March 31, 2018:

	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Florida natural gas division	$	5,864		$	—		$	—		$	5,864
Delaware natural gas division	32,072			—			—			32,072
FPU electric distribution	18,741			—			—			18,741
FPU natural gas distribution	23,213			—			—			23,213
Maryland natural gas division	10,672			—			—			10,672
Sandpiper	8,964			—			—			8,964
Total energy distribution	99,526			—			—			99,526
Energy transmission
Aspire Energy	—			12,077			—			12,077
Eastern Shore	15,597			—			—			15,597
Peninsula Pipeline	2,098			—			—			2,098
Total energy transmission	17,695			12,077			—			29,772
Energy generation
Eight Flags	—			4,378			—			4,378
Propane delivery
Delmarva Peninsula propane delivery	—			45,470			—			45,470
Florida propane delivery	—			6,634			—			6,634
Total propane delivery	—			52,104			—			52,104
Energy services
PESCO	—			81,559			—			81,559
Other and eliminations
Eliminations	(7,828		)	(5,245		)	(15,598		)	(28,671		)
Other	—			494			194			688
Total other and eliminations	(7,828		)	(4,751		)	(15,404		)	(27,983		)
Total operating revenues (1)	$	109,393		$	145,367		$	(15,404	)	$	239,356

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $(589,000) and $73,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to weather normalization for Maryland division and Sandpiper and late fees.

Contract with Customer, Asset and Liability [Table Text Block]

The opening and closing balances of our trade receivables, contract assets, and contract liability are as follows:

	Trade Receivables			Contract Assets (Non-current)		Contract Liability (Current)
in thousands
Balance at 12/31/2017	$	74,962		$	1,270	$	407
Balance at 3/31/2018	67,828			1,305		244
Increase (decrease)	$	(7,134	)	$	35	$	(163	)

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Environmental Commitments and Contingencies Summary of Environmental Liabilities (Tables)

3 Months Ended

Mar. 31, 2018

Environmental Commitments and Contingencies [Abstract]

Environmental Remedies [Table Text Block]

Jurisdiction	MGP Site	Status	Cost to Clean up	Recovery through Rates
Florida	West Palm Beach	Remedial actions approved by the FDEP have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions.	Between $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.	Yes
Florida	Sanford	In March 2018, the EPA approved a "site-wide ready for anticipated use" status, which is the final step before delisting a site. Construction has been completed and restrictive covenants are in place to ensure protection of human health. The only remaining activity is long-term groundwater monitoring. It is unlikely that FPU will incur any significant future costs associated with the site.	FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be less than $10,000.	Yes
Florida	Winter Haven	Remediation is ongoing.	Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site.	Yes
Delaware	Seaford	Proposed plan for implementation approved by the DNREC in July 2017.	Between $273,000 and $465,000.	Yes
Maryland	Cambridge	Currently in discussions with the MDE.	Unable to estimate.	N/A

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2018

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,
	2018		2017
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	105,954	$	96,446
Unregulated Energy segment and other businesses	133,402		88,714
Total operating revenues, unaffiliated customers	$	239,356	$	185,160
Intersegment Revenues (1)
Regulated Energy segment	$	3,439	$	1,208
Unregulated Energy segment	11,965		4,011
Other businesses	194		228
Total intersegment revenues	$	15,598	$	5,447
Operating Income
Regulated Energy segment	$	26,711	$	23,395
Unregulated Energy segment	13,684		11,575
Other businesses and eliminations	11		129
Total operating income	40,406		35,099
Other income (expense), net	68		(700		)
Interest charges	3,664		2,739
Income before Income Taxes	36,810		31,660
Income taxes	9,955		12,516
Net Income	$	26,855	$	19,144

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

(in thousands)	March 31, 2018		December 31, 2017
Identifiable Assets
Regulated Energy segment	$	1,148,635	$	1,121,673
Unregulated Energy segment	246,230		261,541
Other businesses and eliminations	32,585		34,220
Total identifiable assets	$	1,427,450	$	1,417,434

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Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) (Tables)

3 Months Ended

Mar. 31, 2018

Equity [Abstract]

Changes in Accumulated Other Comprehensive Loss

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flows
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)
Other comprehensive loss before reclassifications	—			(2,232		)	(2,232		)
Amounts reclassified from accumulated other comprehensive income	94			444			538
Net current-period other comprehensive income/(loss)	94			(1,788		)	(1,694		)
Stranded tax reclassification to retained earnings	(1,022		)	115			(907		)
As of March 31, 2018	$	(5,671	)	$	(1,202	)	$	(6,873	)

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flows
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)
Other comprehensive income/(loss) before reclassifications	(9		)	1,278			1,269
Amounts reclassified from accumulated other comprehensive income/(loss)	91			(940		)	(849		)
Net prior-period other comprehensive income	82			338			420
As of March 31, 2017	$	(5,278	)	$	820		$	(4,458	)

Reclassifications out of Accumulated Other Comprehensive Income (Loss)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three months endedMarch 31, 2018 and 2017. Deferred gains or losses for our commodity contracts cash flows hedges are recognized in earnings upon settlement.

	Three Months Ended
	March 31,
	2018			2017
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit (1)	$	19		$	19
Net loss(1)	(149		)	(170		)
Total before income taxes	(130		)	(151		)
Income tax benefit	36			60
Net of tax	$	(94	)	$	(91	)
Gains and losses on commodity contracts cash flow hedges:
Propane swap agreements (2)	$	(464	)	$	388
Natural gas swaps (2)	(450		)	—
Natural gas futures (2)	298			1,150
Total before income taxes	(616		)	1,538
Income tax benefit (expense)	172			(598		)
Net of tax	(444		)	940
Total reclassifications for the period	$	(538	)	$	849

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Employee Benefit Plans (Tables)

3 Months Ended

Mar. 31, 2018

Retirement Benefits [Abstract]

Schedule of Net Benefit Costs [Table Text Block]

Net periodic benefit costs for our pension and post-retirement benefits plans for the three months endedMarch 31, 2018 and 2017 are set forth in the following tables:

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended March 31,	2018			2017			2018			2017			2018		2017		2018			2017			2018		2017
(in thousands)
Interest cost	$	97		$	103		$	592		$	623		$	21	$	22	$	10		$	10		$	12	$	13
Expected return on plan assets	(138		)	(127		)	(774		)	(699		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(19		)	(19		)	—		—
Amortization of net loss	88			107			109			131			25		22		15			16			—		—
Net periodic cost (benefit) (1)	47			83			(73		)	55			46		44		6			7			12		13
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	47		$	83		$	118		$	246		$	46	$	44	$	6		$	7		$	14	$	15

Amounts Included in Regulatory asset and AOCI [Table Text Block]

The following tables present 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, 2018 and 2017:

For the Three Months Ended March 31, 2018	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	88		109		25		15			—		237
Total recognized in net periodic benefit cost	88		109		25		(4		)	—		218
Recognized from accumulated other comprehensive loss (1)	88		21		25		(4		)	—		130
Recognized from regulatory asset	—		88		—		—			—		88
Total	$	88	$	109	$	25	$	(4	)	$	—	$	218

For the Three Months Ended March 31, 2017	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	107		131		22		16			—		276
Total recognized in net periodic benefit cost	107		131		22		(3		)	—		257
Recognized from accumulated other comprehensive loss (1)	107		25		22		(3		)	—		151
Recognized from regulatory asset	—		106		—		—			—		106
Total	$	107	$	131	$	22	$	(3	)	$	—	$	257

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Investments (Tables)

3 Months Ended

Mar. 31, 2018

Investments, Debt and Equity Securities [Abstract]

Investments schedule [Table Text Block]

The investment balances at March 31, 2018 and December 31, 2017, consisted of the following:

(in thousands)	March 31, 2018		December 31, 2017
Rabbi trust (associated with the Deferred Compensation Plan)	$	6,621	$	6,734
Investments in equity securities	20		22
Total	$	6,641	6,756

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Share-Based Compensation (Tables)

3 Months Ended

Mar. 31, 2018

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, 2018 and 2017:

	Three Months Ended
	March 31,
	2018			2017
(in thousands)
Awards to non-employee directors	$	135		$	135
Awards to key employees	1,385			504
Total compensation expense	1,520			639
Less: tax benefit	(416		)	(257		)
Share-based compensation amounts included in net income	$	1,104		$	382

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, 2018:

	Number of Shares		Weighted Average Fair Value
Outstanding—December 31, 2017	132,642		$	59.31
Granted	49,494		$	67.76
Vested	(29,786	)	$	47.39
Expired	(3,933	)	$	49.66
Outstanding—March 31, 2018	148,417		$	66.53

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Derivative Instruments (Tables)

3 Months Ended

Mar. 31, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Offsetting Assets and Liabilities [Table Text Block]

Balance sheet offsetting

PESCO has entered into master netting agreements with counterparties that enable it to net the counterparties' outstanding accounts receivable and payable, which are presented on a net basis in the consolidated balance sheets. The following table summarizes the accounts receivable and payables on a gross and net basis at March 31, 2018 and December 31, 2017:

	At March 31, 2018
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	6,555	$	2,092	$	4,463
Accounts payable	$	13,912	$	2,092	$	11,820

	At December 31, 2017
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	8,283	$	2,391	$	5,892
Accounts payable	$	16,643	$	2,391	$	14,252

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit risk-related contingency.

Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet

The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of March 31, 2018 and December 31, 2017, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	4	$	13
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative assets, at fair value	—		92
Propane swap agreements	Derivative assets, at fair value	204		1,181
Total asset derivatives		$	208	$	1,286

	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	March 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative liabilities, at fair value	$	300	$5,776
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative liabilities, at fair value	1,639		469
Natural gas swap contracts	Derivative liabilities, at fair value	404		2
Propane swap agreements	Derivative liabilities, at fair value	16		—
Total liability derivatives		$	2,359	$	6,247

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	2018			2017
Derivatives not designated as hedging instruments
Realized gain on forward contracts and options (1)	Revenue	$	—		$	112
Natural gas futures contracts	Cost of sales	(2,835		)	124
Propane swap agreements	Cost of sales	(9		)	(4		)
Derivatives designated as fair value hedges
Put /Call option (2)	Cost of sales	—			(9		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	(464		)	388
Propane swap agreements	Other comprehensive loss	(992		)	(557		)
Natural gas futures contracts	Cost of sales	298			1,150
Natural gas swap contracts	Cost of sales	(450		)	1,087
Natural gas futures agreements	Other comprehensive income	65			—
Natural gas swap agreements	Other comprehensive loss	(1,732		)	—
Total		$	(6,119	)	$	2,291

⁽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 on the condensed consolidated balance sheets.

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Fair Value of Financial Instruments (Tables)

3 Months Ended

Mar. 31, 2018

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, 2018 and December 31, 2017:

			Fair Value Measurements Using:
As of March 31, 2018	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	602		—		—		602
Investments—mutual funds and other	6,019		6,019		—		—
Total investments	6,641		6,039		—		602
Derivative assets	208		—		208		—
Total assets	$	6,849	$	6,039	$	208	$	602
Liabilities:
Derivative liabilities	$	2,359	$	—	$	2,359	$	—

			Fair Value Measurements Using:
As of December 31, 2017	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	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	648		—		—		648
Investments—mutual funds and other	6,086		6,086		—		—
Total investments	6,756		6,108		—		648
Derivative assets	1,286		—		1,286		—
Total assets	$	8,042	$	6,108	$	1,286	$	648
Liabilities:
Derivative liabilities	$	6,247	$	—	$	6,247	$	—

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, 2018 and 2017:

	Three Months Ended   March 31,
	2018			2017
(in thousands)
Beginning Balance	$	648		$	561
Purchases and adjustments	(48		)	2
Transfers	—			—
Distribution	—			—
Investment income	2			2
Ending Balance	$	602		$	565

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Long-Term Debt (Tables)

3 Months Ended

Mar. 31, 2018

Debt Disclosure [Abstract]

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below:

	March 31,			December 31,
(in thousands)	2018			2017
FPU secured first mortgage bonds (1) :
9.08% bond, due June 1, 2022	$	7,983		$	7,982
Uncollateralized senior notes:
5.50% note, due October 12, 2020	6,000			6,000
5.93% note, due October 31, 2023	18,000			18,000
5.68% note, due June 30, 2026	26,100			26,100
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
3.25% note, due April 30, 2032	70,000			70,000
Long-term portion of the Revolver(2)	25,000			—
Promissory notes	26			97
Capital lease obligation	1,712			2,070
Less: debt issuance costs	(418		)	(433		)
Total long-term debt	231,403			206,816
Less: current maturities	(9,389		)	(9,421		)
Total long-term debt, net of current maturities	$	222,014		$	197,395

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

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Summary of Accounting policies - Additional Information (Details)	3 Months Ended
	Mar. 31, 2018 USD ($)
Summary of Accounting Policies [Abstract]
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 1,498,000
Delay of Revenue Recognition Due To Implementation of New Standard	$ 407,000

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Summary of Accounting Policies Acquisitions Additional information (Details)	12 Months Ended
	Dec. 31, 2017 USD ($)
Business Acquisition [Line Items]
Number of customers acquired through acquisition	800
ARM Energy [Member]
Business Acquisition [Line Items]
Business Combination, Liabilities Arising from Contingencies, Amount Recognized	$ 2,500,000.0
Central Gas [Member]
Business Acquisition [Line Items]
Number of customers acquired through acquisition	325
Unregulated Energy [Member] | ARM [Member]
Business Acquisition [Line Items]
Goodwill, Acquired During Period	$ 6,800,000

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Summary of Accounting Policies Summary of Effect of Adoption on Consolidated Financial Statements (Details) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Item Effected [Line Items]
Accrued revenue	$ 18,907		$ 22,279
Regulated Energy Operating Revenue	109,393	$ 97,654
Regulated Energy cost of sales	48,231	40,244
Depreciation and amortization	9,704	8,812
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	36,810	31,660
Income taxes	9,955	12,516
Net Income	26,855	$ 19,144	58,124
Other assets	4,316		3,699
Retained earnings	250,024		$ 229,141
Calculated under Revenue Guidance in Effect before Topic 606 [Member]
Item Effected [Line Items]
Accrued revenue	20,213
Regulated Energy Operating Revenue	110,357
Regulated Energy cost of sales	48,803
Depreciation and amortization	9,689
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	37,217
Income taxes	10,077
Net Income	27,140
Other assets	4,508
Retained earnings	251,522
Difference between Revenue Guidance in Effect before and after Topic 606 [Member]
Item Effected [Line Items]
Accrued revenue	(1,306)
Deferred Revenue, Period Increase (Decrease)	(964)
Regulated Energy cost of sales	(572)
Depreciation and amortization	15
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	(407)
Income taxes	(122)
Net Income	(285)
Other assets	(192)
Retained earnings	$ (1,498)

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Calculation of Earnings Per Share - Calculation of Basic and Diluted Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Calculation of Basic Earnings Per Share:
Net Income	$ 26,855	$ 19,144	$ 58,124
Weighted shares outstanding (shares)	16,351,338	16,317,224
Basic Earnings Per Share (in dollars per share)	$ 1.64	$ 1.17
Reconciliation of Numerator:
Net Income	$ 26,855	$ 19,144	$ 58,124
Reconciliation of Denominator:
Weighted shares outstanding - Basic (shares)	16,351,338	16,317,224
Effect of dilutive securities:
Share-based compensation (shares)	51,647	46,572
Adjusted denominator-Diluted (shares)	16,402,985	16,363,796
Diluted Earnings Per Share (in dollars per share)	$ 1.64	$ 1.17

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Revenue Recognition Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Revenues	$ 239,356,000	$ 185,160,000
Contract with Customer, Liability, Current	244,000		$ 407,000
Contract with Customer, Liability, Revenue Recognized	251,000
Regulated Energy [Member] | Other [Member]
Revenues	(589,000)
Unregulated Energy [Member] | Other [Member]
Revenues	$ 73,000

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Revenue Recognition Disegragation of Revenue (Details) $ in Thousands	3 Months Ended
	Mar. 31, 2018 USD ($)
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 239,356	[1]
Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(27,983)
Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	109,393	[1]
Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	145,367	[1]
Other Segments And Intersegments Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(15,404)
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(15,404)	[1]
Other [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(4,751)
Eliminations [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(7,828)
Energy Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	99,526
Energy Distribution [Member] | Florida Natural Gas Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	5,864
Energy Distribution [Member] | Florida Public Utilities Company [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	23,213
Energy Distribution [Member] | Maryland Natural Gas [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	10,672
Energy Distribution [Member] | Delaware natural gas division [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	32,072
Energy Distribution [Member] | FPU Electric Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	18,741
Energy Distribution [Member] | Sandpiper [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	8,964
Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	29,772
Energy Transmission [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	17,695
Energy Transmission [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	12,077
Energy Transmission [Member] | Aspire [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	12,077
Energy Transmission [Member] | Eastern Shore Gas Company [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	15,597
Energy Transmission [Member] | Peninsula Pipeline [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	2,098
Energy Generation [Member] | Eight Flags [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	4,378
Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	52,104
Propane Delivery [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	52,104
Propane Delivery [Member] | Delmarva Peninsula Propane Delivery [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	45,470
Propane Delivery [Member] | Florida Propane [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	6,634
Energy Services [Member] | PESCO [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	81,559
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(28,671)
Eliminations [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(7,828)
Eliminations [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(5,245)
Eliminations [Member] | Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	(15,598)
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	688
Other [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	494
Other [Member] | Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	$ 194

[1] (1) Includes other revenue (revenues from sources other than contracts with customers) of $(589,000) and $73,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to weather normalization for Maryland division and Sandpiper and late fees.

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Revenue Recognition Contract Balances with Customers (Details) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Receivables from Customers	$ 67,828	$ 74,962
Contract with Customer, Asset, Net, Noncurrent	1,305	1,270
Contract with Customer, Liability, Current	244	$ 407
Increase (Decrease) in Receivables	(7,134)
Increase (Decrease) in Other Noncurrent Assets	35
Increase (Decrease) in Other Current Liabilities	$ (163)

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Rates and Other Regulatory Activities - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2018 USD ($) dekatherm / d unit mi	Dec. 31, 2017 USD ($)
Electric Distribution [Member]
Rates and Other Regulatory Activities [Line Items]
Amount of Regulatory Costs Not yet Approved	$ 15,200,000
Electric Limited Proceedings [Member]
Rates and Other Regulatory Activities [Line Items]
Asset Recovery Damaged Property Costs, Noncurrent	1,500,000
Deferred Storm and Property Reserve Deficiency, Noncurrent	800,000
Public Utilities, Requested Rate Increase (Decrease), Amount	1.82
Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	9,800,000
Cost of Services	60,000,000
Public Utilities, Requested Rate Increase (Decrease), Amount	$ 18,900,000
Public Utilities, Requested Return on Equity, Percentage	13.75%
Number of Months Rates Suspended	5 months
Increase in Revenue Recognized Due to Motion Rate in Effect		$ 3,700,000
2017 Expansion Project [Member] | Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Estimated Capital Cost	$ 117,000,000
Number of pipeline miles requested | mi	23
Revised Miles Of Natural Gas Pipeline | mi	17
Pressure Control Stations	2
Firm natural gas transportation deliverability | dekatherm / d	61,162
Additional Firm Natural Gas Transportation Deliverability | dekatherm / d	52,500
Subscribers [Member] | 2017 Expansion Project [Member] | Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Number of customers	7
Number of affiliates | unit	3

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Environmental Commitments and Contingencies - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2018 USD ($) site	Dec. 31, 2017 USD ($)
Environmental Commitments And Contingencies [Line Items]
Company's exposure in number of former Manufactured Gas Plant Sites | site	7
Environmental liabilities	$ 8,215,000	$ 8,263,000
West Palm Beach Florida [Member] | Minimum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	4,500,000
West Palm Beach Florida [Member] | Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	15,400,000
Sanford Florida [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental remediation expense	10,000
Winter Haven Florida [Member] | Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental remediation expense	425,000
Seaford [Member] | Minimum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	273,000
Seaford [Member] | Maximum [Member]
Environmental Commitments And Contingencies [Line Items]
Estimated costs of remediation range, minimum	465,000
FPU [Member]
Environmental Commitments And Contingencies [Line Items]
Environmental liabilities	9,600,000
Approval of recovery of environmental costs	14,000,000
Environmental costs recovered	11,100,000
FPU [Member] | Manufactured Gas Plant [Member]
Environmental Commitments And Contingencies [Line Items]
Regulatory Assets for future recovery of environmental costs	$ 2,900,000

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Other Commitments and Contingencies - Additional Information (Detail) gal in Millions, $ in Millions	3 Months Ended
	Mar. 31, 2018 USD ($) gal
Commitments and Contingencies Disclosure [Abstract]
Number of Years for Asset Management Agreement	3 years
Number of years to purchase propane under contract	6 years
Estimated current annual commitment | gal	2.5
Debt Service Coverage Ratio	1.25
Ratio based on average number of prior quarters	6
Number of Propane Price Indices	2
Ratios based on average of the prior quarters	1 year 6 months
Funds from operations interest coverage ratio minimum times	2
Total debt to capital maximum	0.65
Number Of Years For Power Purchase Agreement	20 years
Contract Duration	20 years
Aggregate guaranteed amount	$ 72.7
Draws on letters of credit	$ 5.0

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Segment Information - Schedule of Segment Reporting Information by Segment (Detail) $ in Thousands		3 Months Ended		12 Months Ended
		Mar. 31, 2018 USD ($)	Mar. 31, 2017 USD ($)	Dec. 31, 2017 USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments		2
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		$ 239,356	$ 185,160
Intersegment Revenues
Total operating revenues, unaffiliated customers		239,356	185,160
Operating Income
Total operating income		40,406	35,099
Other expense, net		68	(700)
Interest		3,664	2,739
Income Before Income Taxes		36,810	31,660
Income taxes		9,955	12,516
Net Income		26,855	19,144	$ 58,124
Identifiable Assets
Total identifiable assets		1,427,450		1,417,434
Regulated Energy [Member]
Operating Income
Total operating income		26,711	23,395
Identifiable Assets
Total identifiable assets		1,148,635		1,121,673
Unregulated Energy [Member]
Operating Income
Total operating income		13,684	11,575
Identifiable Assets
Total identifiable assets		246,230		261,541
Other [Member]
Identifiable Assets
Total identifiable assets		32,585		$ 34,220
Other and eliminations [Member]
Operating Income
Total operating income		11	129
Operating Revenues, Unaffiliated Customers [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		239,356	185,160
Intersegment Revenues
Total operating revenues, unaffiliated customers		239,356	185,160
Operating Revenues, Unaffiliated Customers [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		105,954	96,446
Intersegment Revenues
Total operating revenues, unaffiliated customers		105,954	96,446
Operating Revenues, Unaffiliated Customers [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		133,402	88,714
Intersegment Revenues
Total operating revenues, unaffiliated customers		133,402	88,714
Intersegment Revenues [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	15,598	5,447
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	15,598	5,447
Intersegment Revenues [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	3,439	1,208
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	3,439	1,208
Intersegment Revenues [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	11,965	4,011
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	11,965	4,011
Intersegment Revenues [Member] | Other [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	194	228
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	$ 194	$ 228

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

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Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) - Changes in Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	$ (4,272)	$ (4,878)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(2,232)	1,269
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	538	(849)
Net current-period other comprehensive income (loss)	(1,694)	420
Ending balance	(6,873)	(4,458)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	(907)
UnrealizedGainsLossesFromDefinedBenefitPensionAndPostretirementPlanItems [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	(4,743)	(5,360)
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	0	(9)
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	94	91
Net current-period other comprehensive income (loss)	94	82
Ending balance	(5,671)	(5,278)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	(1,022)
Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member]
Defined Benefit Plan, Accumulated Other Comprehensive Income (Loss), after Tax [Roll Forward]
Beginning balance	471	482
Other Comprehensive Income (Loss), before Reclassifications, Net of Tax	(2,232)	1,278
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	444	(940)
Net current-period other comprehensive income (loss)	(1,788)	338
Ending balance	(1,202)	$ 820
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect	$ 115

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Stockholder's Equity - Accumulated Other Comprehensive Income (Loss) - Reclassifications of Accumulated Other Comprehensive Loss (Detail) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Amortization of pension and postretirement items:
Tax benefit		$ (9,955)	$ (12,516)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Amortization of pension and postretirement items:
Net of tax		(538)	849
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated Defined Benefit Plans Adjustment [Member]
Amortization of pension and postretirement items:
Prior service cost	[1]	19	19
Net loss	[1]	(149)	(170)
Total before tax		(130)	(151)
Tax benefit		36	60
Net of tax		(94)	(91)
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		(616)	1,538
Tax benefit		172	(598)
Net of tax		(444)	940
Propane Swap Agreement [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 Adjustments AOCI Swap Agreements	[2]	(464)	388
Natural Gas Swaps [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	[2]	(450)
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	[2]	$ 298	$ 1,150

[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.

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Stockholder's Equity Stockholder's Equity Additional Information (Details) - USD ($) $ / shares in Units, $ in Thousands	12 Months Ended
	Dec. 31, 2017	Mar. 31, 2018
Equity [Abstract]
Preferred Stock, Shares Authorized	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01
Proceeds from Issuance of Common Stock	$ (10)

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Employee Benefit Plans (Detail) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Amortization of prior service cost		$ (19)	$ (19)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		(237)	(276)
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		10	10
Amortization of prior service cost		(19)	(19)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		(15)	(16)
Net periodic cost (benefit)	[1]	6	7
Total periodic cost		6	7
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		12	13
Net periodic cost (benefit)	[1]	12	13
Amortization of pre-merger regulatory asset		2	2
Total periodic cost		14	15
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		592	623
Expected return on plan assets		(774)	(699)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		(109)	(131)
Net periodic cost (benefit)	[1]	(73)	55
Amortization of pre-merger regulatory asset		191	191
Total periodic cost		118	246
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		21	22
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		(25)	(22)
Net periodic cost (benefit)	[1]	46	44
Total periodic cost		46	44
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		97	103
Expected return on plan assets		(138)	(127)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		(88)	(107)
Net periodic cost (benefit)	[1]	47	83
Total periodic cost		$ 47	$ 83

[1] See Note 8, Stockholder's Equity.

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Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Expected pension and postretirement benefit costs	$ 900
Expected amortization of pre merger regulatory asset	769
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Unamortized balance of regulatory asset	1,100	$ 1,300
Contribution to pension plan	309
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	1,500
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan	72
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	359
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan	38
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	151
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan	12
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	97
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan	11
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	$ 88

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Employee Benefit Plans - Amounts Included in Regulatory Asset and Accumulated Other Comprehensive Income/Loss Recognized as Net Periodic Benefit Cost (Detail) - USD ($) $ in Thousands		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		$ (19)	$ (19)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		237	276
Recognized from accumulated other comprehensive loss	[1]	130	151
Recognized from regulatory asset		88	106
Total recognized in net periodic benefit cost		218	257
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		88	107
Recognized from accumulated other comprehensive loss	[1]	88	107
Total recognized in net periodic benefit cost		88	107
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		109	131
Recognized from accumulated other comprehensive loss	[1]	21	25
Recognized from regulatory asset		88	106
Total recognized in net periodic benefit cost		109	131
Chesapeake Pension SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		25	22
Recognized from accumulated other comprehensive loss	[1]	25	22
Total recognized in net periodic benefit cost		25	22
Chesapeake Postretirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		(19)	(19)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		15	16
Recognized from accumulated other comprehensive loss	[1]	(4)	(3)
Total recognized in net periodic benefit cost		$ (4)	$ (3)

[1] See Note 8, Stockholder's Equity.

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Investments - Schedule of Investments (Details) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Investments schedule [Line Items]
Investments, at fair value	$ 6,641	$ 6,756
Rabbi Trust Associated With Deferred Compensation Plan [Member]
Investments schedule [Line Items]
Investments, at fair value	6,621	6,734
Equity Securities [Member]
Investments schedule [Line Items]
Investments, at fair value	$ 20	$ 22

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Investments - Additional Information (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Investments, Debt and Equity Securities [Abstract]
Unrealized gain (loss), net of other expenses	$ (44,000)	$ 252,000

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Share-Based Compensation - Share-Based Compensation Amounts Included in Net Income (Detail) - USD ($) $ / shares in Units, $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 1,520	$ 639
Less: tax benefit	(416)	(257)
Share-Based Compensation amounts included in net income	$ 1,104	382
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	835
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 135	135
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Number	148,417		132,642
Total compensation expense	$ 1,385	$ 504
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 66.53		$ 59.31
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period	49,494
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value	$ 47.39
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period	29,786

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Share-Based Compensation - Summary of Stock Activity under the SICP (Detail)	3 Months Ended
	Mar. 31, 2018 $ / shares shares
Number of Shares
Granted awards (shares)	835
Award to key employees [Member]
Number of Shares
Outstanding - December 31, 2017 (shares)	132,642
Granted awards (shares)	49,494
Vested (shares)	(29,786)
Expired (shares)	(3,933)
Outstanding - March 31, 2018 (shares)	148,417
Weighted Average Fair Value
Outstanding - December 31, 2017 (in dollars per share) | $ / shares	$ 59.31
Granted (in dollars per share) | $ / shares	67.76
Vested (in dollars per share) | $ / shares	47.39
Expired (in dollars per share) | $ / shares	49.66
Outstanding - March 31, 2018 (in dollars per share) | $ / shares	$ 66.53

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Share-Based Compensation - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards (shares)	835
Shares Paid for Tax Withholding for Share Based Compensation	10,436		10,269
Payments Related to Tax Withholding for Share-based Compensation	$ 719	$ 692
Unrecognized compensation cost	$ 4,200
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	$ 45
Award to key employees [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards (shares)	49,494
Vesting period	3 years
Payments Related to Tax Withholding for Share-based Compensation	$ 719
Intrinsic value of the SICP awards	$ 10,400

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Derivative Instruments - Additional Information (Detail) gal in Thousands, Mcf in Thousands, $ in Thousands	3 Months Ended	12 Months Ended
	Mar. 31, 2018 USD ($) $ / gal gal Mcf	Dec. 31, 2017 USD ($) gal
Derivative [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	$ 2,092	$ 2,391
Derivative, Nonmonetary Notional Amount, Volume | Mcf	100
Energy Marketing Contracts Assets, Current	$ 208	$ 1,286
Volume settled on hedges | gal		20
Energy Marketing Contract Liabilities, Current	(2,359)	$ (6,247)
Accounts Payable Subject To Master Netting Arrangement	2,092	2,391
Hedging Liability [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	(1,639)	(469)
Hedging Liability [Member] | Natural Gas Swaps [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	(404)	(2)
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	204
Energy Marketing Contract Liabilities, Current	(16)	0
Not Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	4	13
Not Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ (300)	$ (5,776)
PESCO [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | Mcf	22,900
2017 [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal	2,100
2017 [Member] | Natural Gas Swaps [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | Mcf	702
2017 [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal		7,700
Derivative, Cash Received on Hedge	$ 3
2017 [Member] | Strike Price 4 [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Strike Price Per Gallon For The Propane Swap Agreements | $ / gal	0.5900
2018 [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Derivative, Cash Received on Hedge	$ 464
Gross [Member]
Derivative [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	6,555	$ 8,283
Accounts Payable Subject To Master Netting Arrangement	13,912	16,643
Net [Member]
Derivative [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	4,463	5,892
Accounts Payable Subject To Master Netting Arrangement	$ 11,820	$ 14,252

XML

Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 208	$ 1,286
Energy Marketing Contract Liabilities, Current	2,359	6,247
Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member] | Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	4	13
Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	204
Energy Marketing Contract Liabilities, Current	16	0
Hedging Asset [Member] | Natural Gas Futures [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current		92
Hedging Asset [Member] | Propane Swap Agreement [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current		1,181
Mark-to-market energy liabilities [Member] | Natural Gas Futures [Member] | Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	300	5,776
Hedging Liability [Member] | Natural Gas Swaps [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	404	2
Hedging Liability [Member] | Natural Gas Futures [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contract Liabilities, Current	$ 1,639	$ 469

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, 2018	Mar. 31, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		$ (6,119)	$ 2,291
Revenue [Member] | Derivatives not designated as hedging instruments [Member] | Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	[1]		112
Cost of Sales [Member] | Derivatives not designated as hedging instruments [Member] | Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		(2,835)	124
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		(9)	(4)
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net			1,150
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net			388
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Put/Call Option [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	[2]		(9)
Other Comprehensive Income (Loss) [Member] | Derivatives designated as hedging instrument [Member] | Natural Gas Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax		(1,732)	0
Other Comprehensive Income (Loss) [Member] | Derivatives designated as hedging instrument [Member] | Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax		(992)	(557)
Other Comprehensive Income (Loss) [Member] | Derivatives designated as hedging instrument [Member] | Natural Gas Futures [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, before Tax		$ 65	0
Reclassification out of Accumulated Other Comprehensive Income [Member] | Accumulated (Gain) Loss from Commodity Contracts Cash Flows Hedges [Member] | Other Comprehensive Income (Loss) [Member] | Derivatives designated as hedging instrument [Member] | Natural Gas Futures [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net			$ 1,087

[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 on the condensed consolidated balance sheets.

XML

Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Mar. 31, 2018	Dec. 31, 2017
Assets:
Investments	$ 6,641	$ 6,756
Liabilities:
Energy Marketing Contract Liabilities, Current	2,359	6,247
Equity Securities [Member]
Assets:
Investments	20	22
Quoted Prices in Active Markets (Level 1) [Member]
Assets:
Assets, Fair Value Disclosure	6,039	6,108
Quoted Prices in Active Markets (Level 1) [Member] | Equity Securities [Member]
Assets:
Investments	20	22
Quoted Prices in Active Markets (Level 1) [Member] | Investments - other [Member]
Assets:
Investments	6,019	6,086
Quoted Prices in Active Markets (Level 1) [Member] | Total Investments [Member]
Assets:
Investments	6,039	6,108
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Assets, Fair Value Disclosure	208	1,286
Liabilities:
Energy Marketing Contract Liabilities, Current		6,247
Significant Other Observable Inputs (Level 2) [Member] | Mark To Market Energy Assets incl. natural gas and swap agreements[Member]
Assets:
Derivative assets	208	1,286
Significant Unobservable Inputs (Level 3) [Member]
Assets:
Assets, Fair Value Disclosure	602	648
Significant Unobservable Inputs (Level 3) [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	602	648
Significant Unobservable Inputs (Level 3) [Member] | Total Investments [Member]
Assets:
Investments	602	648
Recurring [Member]
Assets:
Assets, Fair Value Disclosure	6,849	8,042
Liabilities:
Energy Marketing Contract Liabilities, Current	2,359	6,247
Recurring [Member] | Equity Securities [Member]
Assets:
Investments	20	22
Recurring [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	602	648
Recurring [Member] | Investments - other [Member]
Assets:
Investments	6,019	6,086
Recurring [Member] | Total Investments [Member]
Assets:
Investments	6,641	6,756
Recurring [Member] | Mark To Market Energy Assets incl. natural gas and swap agreements[Member]
Assets:
Derivative assets	$ 208	$ 1,286

XML

Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 648	$ 561
Purchases and adjustments	(48)	2
Transfers		0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	0	0
Investment Income	2	2
Ending Balance	$ 602	$ 565

XML

Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Long-term debt including current maturities	$ 230.1	$ 205.2
Fair value of long-term debt	$ 237.9	$ 215.4

XML

Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands		Mar. 31, 2018		Dec. 31, 2017
Debt Instrument [Line Items]
Total long-term debt		$ 230,100		$ 205,200
Capital lease obligation		1,712		2,070
Total Long-term debt		231,403		206,816
Less: current maturities		(9,389)		(9,421)
Less: debt issuance costs		(418)		(433)
Total long-term debt, net of current maturities		222,014		197,395
9.08% bond, due June 1, 2022 [Member]
Debt Instrument [Line Items]
Total long-term debt	[1]	7,983		7,982
5.50% note, due October 12, 2020 [Member]
Debt Instrument [Line Items]
Total long-term debt		6,000		6,000
5.93% note, due October 31, 2023 [Member]
Debt Instrument [Line Items]
Total long-term debt		18,000		18,000
5.68% note, due June 30, 2026 [Member]
Debt Instrument [Line Items]
Total long-term debt		26,100		26,100
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
3.25% note, due April 30, 2032 [Member]
Debt Instrument [Line Items]
Total long-term debt		70,000		70,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Total long-term debt		25,000	[2]	0
Promissory note [Member]
Debt Instrument [Line Items]
Total long-term debt		$ 26		$ 97

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

[2] FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities.(2) In January 2018, we borrowed an additional $25.0 million under the Revolver, which we classified as long-term debt. The maturity date of the Revolver is October 8, 2020. The interest rate on the Revolver is a variable interest rate that is dependent on various factors and resets every thirty days. As of March 31, 2018, the interest rate on the Revolver was LIBOR + 1.00% or 2.88%.

XML

Long-Term Debt - Outstanding Long-Term Debt- Supplemental Information (Detail)	3 Months Ended
	Mar. 31, 2018
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
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
Uncollateralized Senior Note Due on Two Thousand Thirty Two [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.25%
Debt instrument, maturity date	Apr. 30, 2032
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	2.88%
Debt instrument, maturity date	Oct. 08, 2020

XML

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017	Nov. 30, 2017
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 230,100	$ 205,200
3.25% note, due April 30, 2032 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 70,000	$ 70,000
Notes Payable, Other Payables [Member] | Shelf Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Prudential [Member]
Debt Instrument [Line Items]
Senior notes	$ 150,000
Prudential [Member] | Notes Payable, Other Payables [Member] | Shelf Notes [Member]
Debt Instrument [Line Items]
Senior notes	150,000
MetLife [Member] | Notes Payable, Other Payables [Member] | Shelf Notes [Member]
Debt Instrument [Line Items]
Senior notes	$ 150,000
Maturity date term	20 years
New York Life [Member] | Notes Payable, Other Payables [Member] | Shelf Notes [Member]
Debt Instrument [Line Items]
Senior notes	$ 100,000
Maturity date term	20 years
Prudential and Metlife [Member]
Debt Instrument [Line Items]
Senior notes	$ 230,000
Series A [Member] | New York Life [Member]
Debt Instrument [Line Items]
Senior notes			$ 50,000
Debt Instrument, Interest Rate, Stated Percentage			3.48%
Series B [Member] | New York Life [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage			3.58%