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: September 30, 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 every Interactive Data File required to be submitted 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 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.

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 — 16,378,545 shares outstanding as of October 31, 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	35
ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	58
ITEM 4.	CONTROLS AND PROCEDURES	59
PART II—OTHER INFORMATION		61
ITEM 1.	LEGAL PROCEEDINGS	61
ITEM 1A.	RISK FACTORS	61
ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	61
ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	61
ITEM 5.	OTHER INFORMATION	61
ITEM 6.	EXHIBITS	62
SIGNATURES		63

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

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

CGS: Community Gas Systems

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

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

Del-Mar Energy Pathway Project - A project for the construction of pipeline looping in Kent County, Delaware, and additional mainline extension in Sussex County, Delaware. The project also upgrades an existing pressure control facility, which includes a portion of mainline extension in Sussex County, Delaware, as well as in Somerset County, Maryland.

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

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

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

NOPR: Notice of Proposed Rulemaking

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 in March 2017 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: PGIM, Inc., formerly known as 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 in October 2015 pursuant to which Chesapeake Utilities could 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, as subsequently amended in September 2018, pursuant to which we may request that Prudential purchase up to $150.0 million of our unsecured debt over a three-year period, expiring in August 2021

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

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: A qualified 401(k) retirement savings plan sponsored by Chesapeake Utilities

Revolver: Our unsecured revolving credit facility with the Lenders

ROU: Right of use

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: U.S. 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: Chesapeake Utilities' 2013 Stock and Incentive Compensation Plan

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						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	72,770		$	69,703		$	252,667		$	238,353
Unregulated Energy and other	67,509			57,233			263,632			198,827
Total Operating Revenues	140,279			126,936			516,299			437,180
Operating Expenses
Regulated Energy cost of sales	21,501			22,794			89,741			87,206
Unregulated Energy and other cost of sales	55,660			44,066			204,880			145,325
Operations	32,821			29,274			101,804			91,778
Maintenance	3,208			2,737			10,419			9,370
Gain from a settlement	—			—			(130		)	(130		)
Depreciation and amortization	10,633			9,362			30,176			27,267
Other taxes	4,420			4,071			13,719			12,572
Total Operating Expenses	128,243			112,304			450,609			373,388
Operating Income	12,036			14,632			65,690			63,792
Other expense, net	(11		)	(154		)	(204		)	(1,855		)
Interest charges	4,430			3,321			11,976			9,133
Income Before Income Taxes	7,595			11,157			53,510			52,804
Income taxes	2,057			4,324			14,731			20,781
Net Income	$	5,538		$	6,833		$	38,779		$	32,023
Weighted Average Common Shares Outstanding:
Basic	16,378,545			16,344,442			16,366,608			16,334,210
Diluted	16,428,439			16,389,635			16,416,255			16,378,633
Earnings Per Share of Common Stock:
Basic	$	0.34		$	0.42		$	2.37		$	1.96
Diluted	$	0.34		$	0.42		$	2.36		$	1.96
Cash Dividends Declared Per Share of Common Stock	$	0.3700		$	0.3250		$	1.0650		$	0.9550

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

- 1

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
(in thousands)
Net Income	$	5,538		$	6,833		$	38,779		$	32,023
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(5), $(8), $(16) and $(23), respectively	(14		)	(11		)	(42		)	(35		)
Net gain, net of tax of $38, $69, $118 and $212, respectively	100			102			317			297
Cash Flow Hedges, net of tax:
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $257, $(15), $(70) and $(376), respectively	644			(104		)	(83		)	(643		)
Total Other Comprehensive Income (Loss), net of tax	730			(13		)	192			(381		)
Comprehensive Income	$	6,268		$	6,820		$	38,971		$	31,642

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

- 2

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Assets	September 30, 2018			December 31, 2017
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	1,242,840		$	1,073,736
Unregulated Energy	220,721			210,682
Other businesses and eliminations	34,975			27,699
Total property, plant and equipment	1,498,536			1,312,117
Less: Accumulated depreciation and amortization	(295,449		)	(270,599		)
Plus: Construction work in progress	60,243			84,509
Net property, plant and equipment	1,263,330			1,126,027
Current Assets
Cash and cash equivalents	6,215			5,614
Trade and other receivables (less allowance for uncollectible accounts of $987 and $936, respectively)	52,660			77,223
Accrued revenue	12,352			22,279
Propane inventory, at average cost	7,444			8,324
Other inventory, at average cost	4,786			12,022
Regulatory assets	6,891			10,930
Storage gas prepayments	6,989			5,250
Income taxes receivable	8,725			14,778
Prepaid expenses	9,775			13,621
Derivative assets, at fair value	10,568			1,286
Other current assets	2,557			7,260
Total current assets	128,962			178,587
Deferred Charges and Other Assets
Goodwill	19,604			19,604
Other intangible assets, net	4,073			4,686
Investments, at fair value	7,951			6,756
Regulatory assets	76,343			75,575
Other assets	5,293			3,699
Total deferred charges and other assets	113,264			110,320
Total Assets	$	1,505,556		$	1,414,934

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

- 3

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)

Capitalization and Liabilities	September 30, 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)	7,971			7,955
Additional paid-in capital	255,509			253,470
Retained earnings	249,805			229,141
Accumulated other comprehensive loss	(4,987		)	(4,272		)
Deferred compensation obligation	3,818			3,395
Treasury stock	(3,818		)	(3,395		)
Total stockholders’ equity	508,298			486,294
Long-term debt, net of current maturities	241,597			197,395
Total capitalization	749,895			683,689
Current Liabilities
Current portion of long-term debt	9,613			9,421
Short-term borrowing	268,293			250,969
Accounts payable	60,228			74,688
Customer deposits and refunds	34,887			34,751
Accrued interest	3,969			1,742
Dividends payable	6,060			5,312
Accrued compensation	10,396			13,112
Regulatory liabilities	9,099			6,485
Derivative liabilities, at fair value	9,774			6,247
Other accrued liabilities	14,819			10,273
Total current liabilities	427,138			413,000
Deferred Credits and Other Liabilities
Deferred income taxes	146,814			135,850
Regulatory liabilities	141,840			140,978
Environmental liabilities	7,941			8,263
Other pension and benefit costs	28,839			29,699
Deferred investment tax credits and other liabilities	3,089			3,455
Total deferred credits and other liabilities	328,523			318,245
Environmental and other commitments and contingencies (Notes 5 and 6)
Total Capitalization and Liabilities	$	1,505,556		$	1,414,934

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

- 4

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)

	Nine Months Ended
	September 30,
	2018			2017
(in thousands)
Operating Activities
Net income	$	38,779		$	32,023
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	30,176			27,267
Depreciation and accretion included in other costs	6,464			5,989
Deferred income taxes	11,047			29,520
Realized loss (gain) on commodity contracts/sale of assets/investments	4,015			(2,817		)
Unrealized gain on investments/commodity contracts	(427		)	(695		)
Employee benefits and compensation	456			1,212
Share-based compensation	2,535			1,608
Other, net	(35		)	(39		)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	32,988			12,912
Propane inventory, storage gas and other inventory	6,379			(8,256		)
Regulatory assets/liabilities, net	3,899			927
Prepaid expenses and other current assets	(1,533		)	(2,860		)
Accounts payable and other accrued liabilities	(9,590		)	4,515
Income taxes receivable	6,053			(3,810		)
Customer deposits and refunds	136			3,255
Accrued compensation	(2,804		)	(2,030		)
Other assets and liabilities, net	(542		)	(349		)
Net cash provided by operating activities	127,996			98,372
Investing Activities
Property, plant and equipment expenditures	(171,410		)	(130,137		)
Proceeds from sales of assets	565			601
Acquisitions, net of cash acquired	—			(11,707		)
Environmental expenditures	(322		)	(210		)
Net cash used in investing activities	(171,167		)	(141,453		)
Financing Activities
Common stock dividends	(16,171		)	(14,780		)
(Purchase) issuance of stock under the Dividend Reinvestment Plan	(518		)	254
Stock issuance	—			(10		)
Tax withholding payments related to net settled stock compensation	(1,210		)	(692		)
Change in cash overdrafts due to outstanding checks	712			(3,013		)
Net borrowing (repayment) under line of credit agreements and short-term borrowing under the Revolver	16,612			(3,760		)
Proceeds from long-term debt and long-term borrowing under the Revolver	74,901			69,800
Repayment of long-term debt, long-term borrowing under the Revolver and capital lease obligation	(30,554		)	(5,510		)
Net cash provided in financing activities	43,772			42,289
Net Increase (Decrease) in Cash and Cash Equivalents	601			(792		)
Cash and Cash Equivalents—Beginning of Period	5,614			4,178
Cash and Cash Equivalents—End of Period	$	6,215		$	3,386

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	—	—		—			38,779			—			—		—			38,779
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 income	—	—		—			—			192			—		—			192
Dividend declared ($1.065 per share)	—	—		—			(17,524		)	—			—		—			(17,524		)
Dividend reinvestment plan	—	—		(2		)	—			—			—		—			(2		)
Share-based compensation and tax benefit (3)(4)	34,103	16		2,041			—			—			—		—			2,057
Treasury stock activities	—	—		—			—			—			423		(423		)	—
Balance at September 30, 2018	16,378,545	$	7,971	$	255,509		$	249,805		$	(4,987	)	$	3,818	$	(3,818	)	$	508,298

⁽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 96,622 and 90,961 shares at September 30, 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 nine months ended September 30, 2018, and for the year ended December 31, 2017, we withheld 16,918 and 10,269 shares, respectively, for taxes.

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

- 6

NOTESTO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1.    Summary of Accounting Policies

Basis of Presentation

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 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. The acquired assets complemented PESCO’s existing asset portfolio and expanded our regional footprint and retail demand in a market where we had existing pipeline capacity and wholesale liquidity.  We accounted for the purchase of these assets as a business combination and initially recorded goodwill of $6.8 million within our Unregulated Energy segment. In connection with the acquisition, we initially recorded a contingent consideration liability of $2.5 million, based on our preliminary analysis projecting that the acquired business would achieve at least a certain gross margin target in 2018. During the second quarter of 2018, we identified certain known information as of the acquisition date that was not considered in our original analysis and would have resulted in no contingent consideration liability being initially recorded. Therefore, we reversed the originally-recorded contingent liability and reduced goodwill by $2.5 million. We similarly revised the condensed consolidated balance sheet as of December 31, 2017. These revisions are considered immaterial to our condensed consolidated financial statements. The need for a contingent consideration liability will be re-evaluated in the final reporting period in 2018. However, our current assessment is that no contingent consideration will be paid.

In August 2017, Flo-gas acquired certain operating assets of Chipola, which provided 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, which were included in our condensed consolidated statements of income for the three and nine months ended September 30, 2018, were not material. The acquisition accounting amounts recorded in conjunction with the ARM and Chipola acquisitions are now final although the amounts associated with the Central Gas acquisition 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. The impact of adoption of the new revenue standard was immaterial to our net income.

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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 that 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 statements for the three and nine months endedSeptember 30, 2018 and condensed consolidated balance sheet as of September 30, 2018:

	Three Months Ended   September 30, 2018							Nine Months Ended   September 30, 2018
Income statement	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)			As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Regulated Energy operating revenues	$	72,770	$	72,879	$	(109	)	$	252,667	$	253,659	$	(992	)
Regulated Energy cost of sales	21,501		21,512		(11		)	89,741		90,454		(713		)
Depreciation and amortization	10,633		10,629		4			30,176		30,150		26
Income before income taxes	7,595		7,697		(102		)	53,510		53,815		(305		)
Income taxes	2,057		2,086		(29		)	14,731		14,819		(88		)
Net income	5,538		5,611		(73		)	38,779		38,996		(217		)

	As of September 30, 2018
Balance sheet	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Assets
Accrued revenues	$	12,352	$	13,658	$	(1,306	)
Other assets	$	5,293	$	5,702	$	(409	)
Capitalization
Retained earnings	$	249,805	$	251,520	$	(1,715	)

The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $305,000 in revenue in the first nine months of 2018 to future years and a cumulative adjustment that decreased retained earnings and other assets by $1.7 million at September 30, 2018, 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 should not be included operating expenses. 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, 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. 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) change because of a change in the terms or conditions of the award. We adopted

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ASU 2017-09, prospectively, on January 1, 2018. 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 adopted 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 contract cash flows hedges. 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.

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. 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 that is 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. ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges and 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 adopted ASU 2017-12 effective July 1, 2018, with no material impact on our financial statements. See Note 12, Derivative Instruments, for additional information with respect to the disclosures required by ASU 2017-12.

Recent Accounting Standards Yet to be Adopted

Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which requires lessees to recognize leases on the balance sheet and disclose key information about leasing arrangements. The standard establishes a ROU model that requires a lessee to recognize a ROU asset and lease liability for all leases with a term greater than 12 months. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASC 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. ASU 2016-02 will be effective for our annual and interim financial statements, beginning January 1, 2019, although early adoption is permitted. We expect to adopt ASU 2016-02 effective January 1, 2019 and use the modified retrospective transition approach to all existing leases.

The new standard permits companies to elect several practical expedients. We expect to elect: (1) the ‘package of practical expedients,’ pursuant to which we do not need to reassess our prior conclusions about lease identification, lease classification and initial direct costs and (2) the ‘use-of-hindsight’ practical expedient, which allows us to use hindsight in assessing impairment of our existing land easements. We also intend to aggregate all non-lease components with the lease components to which they relate.

The most significant effect of ASC 842 will be recognition of ROU assets and lease liabilities on our balance sheet for our operating leases and providing significant new disclosures about our leasing activities. We currently expect that upon adoption, we will recognize lease liabilities ranging from $4.0 million to $5.0 million, with corresponding ROU of the same amount based on the present value of the remaining minimum rental payments for existing operating leases.

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 implementation of this new standard will not have a material impact on our financial position or results of operations.

Compensation - Stock Compensation (ASC 718) - In June 2018, the FASB issued ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting, which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. ASU 2018-07 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We believe that implementation of this new standard will not have a material impact on our financial position or results of operations.

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Fair Value Measurement (ASC 820) - In August 2018, the FASB issued ASU 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement, which removes, modifies and adds certain disclosure requirements on fair value measurements in ASC 820. ASU 2018-13 will be effective for our annual and interim financial statements beginning January 1, 2020 and, since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.

Compensation - Retirement Benefits - Defined Benefit Plans - General (ASC 715-20) - In August 2018, the FASB issued ASU 2018-14, Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans, which removes, clarifies and adds certain disclosure requirements in ASC 715-20 related to defined benefit pension and other postretirement plans. ASU 2018-14 will be effective for our annual and interim financial statements, on a retrospective basis, beginning January 1, 2021 and, since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.

2. Calculation of Earnings Per Share

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	5,538	$	6,833	$	38,779	$	32,023
Weighted average shares outstanding	16,378,545		16,344,442		16,366,608		16,334,210
Basic Earnings Per Share	$	0.34	$	0.42	$	2.37	$	1.96
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	5,538	$	6,833	$	38,779	$	32,023
Reconciliation of Denominator:
Weighted shares outstanding—Basic	16,378,545		16,344,442		16,366,608		16,334,210
Effect of dilutive securities—Share-based compensation	49,894		45,193		49,647		44,423
Adjusted denominator—Diluted	16,428,439		16,389,635		16,416,255		16,378,633
Diluted Earnings Per Share	$	0.34	$	0.42	$	2.36	$	1.96

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 month following the satisfaction of our performance obligation.

The following table displays our revenue by major source based on product and service type for the three months ended September 30, 2018:

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(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Florida natural gas division	$	6,282		$	—		$	—		$	6,282
Delaware natural gas division	7,010			—			—			7,010
FPU electric distribution	23,830			—			—			23,830
FPU natural gas distribution	17,390			—			—			17,390
Maryland natural gas division	2,463			—			—			2,463
Sandpiper	3,561			—			—			3,561
Total energy distribution	60,536			—			—			60,536
Energy transmission
Aspire Energy	—			5,750			—			5,750
Eastern Shore	16,189			—			—			16,189
Peninsula Pipeline	3,404			—			—			3,404
Total energy transmission	19,593			5,750			—			25,343
Energy generation
Eight Flags	—			4,044			—			4,044
Propane delivery
Delmarva Peninsula propane delivery	—			13,172			—			13,172
Florida propane delivery	—			4,166			—			4,166
Total propane delivery	—			17,338			—			17,338
Energy services
PESCO	—			51,619			—			51,619
Other and eliminations
Eliminations	(7,359		)	(3,185		)	(8,668		)	(19,212		)
Other	—			476			135			611
Total other and eliminations	(7,359		)	(2,709		)	(8,533		)	(18,601		)
Total operating revenues (1)	$	72,770		$	76,042		$	(8,533	)	$	140,279

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $546,000 and $91,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.

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The following table displays our revenue by major source based on product and service type for the nine months ended September 30, 2018:

(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Florida natural gas division	$	18,462		$	—		$	—		$	18,462
Delaware natural gas division	50,963			—			—			50,963
FPU electric distribution	60,933			—			—			60,933
FPU natural gas distribution	58,885			—			—			58,885
Maryland natural gas division	17,136			—			—			17,136
Sandpiper	16,892			—			—			16,892
Total energy distribution	223,271			—			—			223,271
Energy transmission
Aspire Energy	—			23,682			—			23,682
Eastern Shore	46,289			—			—			46,289
Peninsula Pipeline	8,469			—			—			8,469
Total energy transmission	54,758			23,682			—			78,440
Energy generation
Eight Flags	—			12,652			—			12,652
Propane delivery
Delmarva Peninsula propane delivery	—			73,907			—			73,907
Florida propane delivery	—			15,741			—			15,741
Total propane delivery	—			89,648			—			89,648
Energy services
PESCO	—			181,976			—			181,976
Other and eliminations
Eliminations	(25,362		)	(11,679		)	(34,643		)	(71,684		)
Other	—			1,475			521			1,996
Total other and eliminations	(25,362		)	(10,204		)	(34,122		)	(69,688		)
Total operating revenues (1)	$	252,667		$	297,754		$	(34,122	)	$	516,299

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $(399,000) and $246,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.

Regulated Energy segment

The businesses within our Regulated Energy segment are regulated utilities whose operations and customer contracts are subject to rates approved by the respective state PSC 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 provide delivery service only). 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

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meter readings, which are based on the 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 the FERC-approved maximum 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 receive service only 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 capacity used or reserved and the fixed monthly charge.

Peninsula Pipeline is engaged in natural gas intrastate 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. We accrue unbilled revenues for transportation services provided and not yet billed at the end of an accounting period.

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 established monthly index price 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 affiliates of Chesapeake Utilities) 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 balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2017 and September 30, 2018 were as follows:

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	Trade Receivables			Contract Assets (Non-current)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2017	$	74,962		$	1,270	$	407
Balance at 9/30/2018	50,937			2,331		583
Increase (decrease)	$	(24,025	)	$	1,061	$	176

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 incurred by Eight Flags 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 September 30, 2018 and December 31, 2017, we had a contract liability of $583,000 and $407,000, respectively, which was included in other accrued liabilities in the condensed consolidated balance sheet, 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 and nine months ended September 30, 2018, we recognized revenue of $48,000 and $384,000, respectively.

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 customers: 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. Subsequently, the Delaware Division filed an updated report reflecting the impact of the TCJA on May 31, 2018. If, after reviewing the required filing, 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.

In addition, on February 1, 2018, the Delaware PSC issued an order requiring Delaware rate-regulated public utilities to accrue regulatory liabilities reflecting the impacts of changes in the federal corporate income tax laws. In compliance with the Delaware PSC order, we have established a regulatory liability to reflect the estimated impacts of the changes in the federal corporate income tax rate. We believe that the reduction in rates charged by our Delaware Division because of the lower federal income taxes resulting from the TCJA will not have a material effect on our financial position or results of operations, because the reduction will be offset by an equal reduction in income tax expense.

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Underserved Area Rates: In December 2017, we filed an application requesting authorization to utilize existing expansion area tariff rates to serve customers located outside of the current Sussex County, Delaware expansion area boundaries that cannot be economically served under the regular tariff rates. In June 2018, we reached a settlement agreement with the relevant parties, which allows us to utilize higher rates for areas outside of our existing expansion area. The Delaware PSC unanimously approved the settlement at its public meeting on July 10, 2018. The new rate schedule became effective on August 1, 2018.

CGS: In June 2018, we filed with the Delaware PSC an application requesting approval of the acquisition and subsequent conversion of propane to natural gas for certain CGS located within our territory. We requested the establishment of regulatory accounting treatment and valuation of the acquisition of certain CGS, approval of a methodology to set new distribution rates for CGS customers and approval of a new system-wide tariff rate that will recover CGS conversion costs. The Delaware PSC has not reached a decision as of the date of this filing.

Maryland Division and Sandpiper

Effect of the TCJA on customers: The Maryland PSC issued an order requiring all Maryland public utilities with rates 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 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 impacts of the changes in the federal corporate income tax rate in compliance with the Maryland PSC’s order and made compliance filings that included preliminary estimates of the annual impact of the change in the statutory federal income tax rate. In April 2018, the Maryland PSC ordered both the Maryland Division and Sandpiper to implement reduced rates effective May 1, 2018, reflecting the impact of the TCJA. We implemented a one-time bill credit for the regulatory liability established for the refunds and issued the refunds to customers in July 2018. We submitted an informational filing to the Maryland PSC within the requisite 60 days of completing the refund payments. Additionally, if in the future the Maryland Division or Sandpiper identify any additional tax savings, we must submit an additional filing to the Maryland PSC in order to return those savings to customers as soon as possible. We believe that the reduction in rates charged by our Maryland Division and Sandpiper because of the lower federal income taxes resulting from the TCJA will not have a material effect on our financial position or results of operations, because the reduction is offset by an equal reduction in income tax expense.

Florida

Florida Electric Reliability/Modernization Pilot Program: In July 2017, our Florida electric operations 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 our electrical grid. An interconnection project with FPL, which enables us to mitigate fuel costs for our 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, our Florida electric operations 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 storm reserve to its pre-storm level of $1.5 million. As a result of these hurricanes and tropical storms, our Florida electric operation’s storm reserve was depleted and is currently at a deficit of $779,000. We have requested approval of a surcharge of $1.82 per kilowatt per hour for two years to recover and replenish storm-related costs. This matter is scheduled for review at the Florida PSC’s meeting in the fourth quarter of 2018.

Effect of the TCJA on customers: 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. Hearings for Florida’s electric utilities are tentatively scheduled for the first quarter of 2019, and hearings for the natural gas utilities are tentatively scheduled for the fourth quarter of 2018.

In December 2017, the Florida PSC issued an order regarding the limited proceeding for our Florida electric operations, which prescribes the applicability, timing and treatment of the impacts of the TCJA, as discussed above. In June, our

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Florida natural gas operations filed petitions and testimony in support of the disposition of the impacts created by the TCJA. We believe that the reduction in rates charged by our Florida electric and natural gas operations because of the lower federal income taxes resulting from the TCJA will not have a material effect on our financial position or results of operations, because the reduction is offset by an equal reduction in income tax expense.

In October 18, 2018, our electric distribution operation reached a settlement agreement with the Office of Public Counsel. This settlement agreement was filed for approval with the Florida PSC on October 19, 2018 and hearing in this action is expected to be held in December 2018. This agreement proposes that our electric distribution operation will flow benefit associated with the TCJA back to its customers through a combination of reductions to the fuel cost recovery rate, base rates, as well as application to the storm reserve over the next several years.

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 October 2017, the FERC issued a CP authorizing Eastern Shore to construct the expansion facilities. 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. In June 2018, the Fair Hill Loop in Chester County, Pennsylvania and Cecil County, Maryland was placed into service. With the exception of some minor facilities, the remaining segments of the 2017 Expansion Project are expected to be placed into service in various phases during the fourth quarter 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 based its proposed rates on the mainline cost of service of approximately $60.0 million resulting in an overall requested annual 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 on 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 pending FERC approval of the settlement and refunds to customers according to the terms of the settlement agreement. The FERC approved the settlement agreement in February 2018, and it became final in March 2018. Exclusive of the TCJA impact, base rates would have increased, on an annual basis, by approximately $9.8 million.

Effect of the TCJA on customers: 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 in incremental margin, 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 to 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 the TCJA.

In March 2018, the FERC issued a NOPR that proposed a process to determine which 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 NOPR 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 in accordance with the settlement agreement in its 2017 rate case approved by the FERC. In July 2018, the FERC issued a final rule, which largely adopted the process proposed in the NOPR, requiring all interstate natural gas companies to file an informational filing for the purpose of evaluating the impact of the TCJA and the United

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Airlines, Inc. v. FERC decision on interstate natural gas pipelines’ revenue requirements. The final rule provides that an individual pipeline has the option to request a waiver if the pre-March 2018 settlement justifies not adjusting its rates at this time. In September 2018, Eastern Shore requested that the FERC grant it a waiver of the requirement. In October 2018, the FERC issued an order granting the waiver.

Del-Mar Energy Pathway Project: In September 2018, Eastern Shore filed a Certificate Application for the Del-Mar Energy Pathway project with the FERC. The proposed project would provide an additional 14,300 Dts/d of capacity to four customers. Facilities to be constructed include six miles of pipeline looping in Delaware, 13 miles of new mainline extension in Sussex County, Delaware and Somerset County, Maryland as well as new pressure control and delivery stations in these counties. The benefits of this project include (i) further natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware and (ii) first extension of Eastern Shore’s pipeline system into Somerset County, Maryland.

5. Environmental Commitments and Contingencies

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

MGP Sites

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

As of September 30, 2018, we had approximately $9.4 million in environmental liabilities related to FPU’s MGP sites in Key West, Pensacola, Sanford and West Palm Beach. 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. As of September 30, 2018 we have recovered approximately $11.4 million, leaving approximately $2.6 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:

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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. We expect to implement similar remedial actions on other remaining portions, including the anticipated demolition of buildings on the site's west parcel in 2018.	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. Site assessment is ongoing.	Between $273,000 and $465,000.	Yes
Maryland	Cambridge	Currently in discussions with the MDE.	Unable to estimate.	N/A

6. Other Commitments and Contingencies

Natural Gas, Electric and Propane Supply

We have entered into contractual commitments, with various expiration dates, to purchase natural gas, electricity and propane from various suppliers. 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 1.8 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 1.8 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.

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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 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 FPU fails to meet this ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric 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 September 30, 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 our 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 September 30, 2018 was approximately $73.9 million, with the guarantees expiring on various dates through September 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 September 30, 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 September 30, 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

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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						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	69,697		$	67,257		$	243,382		$	232,519
Unregulated Energy segment and other businesses	70,582			59,679			272,917			204,661
Total operating revenues, unaffiliated customers	$	140,279		$	126,936		$	516,299		$	437,180
Intersegment Revenues (1)
Regulated Energy segment	$	3,073		$	2,446		$	9,285		$	5,834
Unregulated Energy segment	5,460			5,009			24,837			15,801
Other businesses	135			194			521			581
Total intersegment revenues	$	8,668		$	7,649		$	34,643		$	22,216
Operating Income
Regulated Energy segment	$	15,915		$	15,523		$	56,930		$	53,004
Unregulated Energy segment	(3,933		)	(951		)	10,241			10,626
Other businesses and eliminations	54			60			(1,481		)	162
Total operating income	12,036			14,632			65,690			63,792
Other expense, net	(11		)	(154		)	(204		)	(1,855		)
Interest charges	4,430			3,321			11,976			9,133
Income before Income Taxes	7,595			11,157			53,510			52,804
Income taxes	2,057			4,324			14,731			20,781
Net Income	$	5,538		$	6,833		$	38,779		$	32,023

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

(in thousands)	September 30, 2018		December 31, 2017
Identifiable Assets
Regulated Energy segment	$	1,223,537	$	1,121,673
Unregulated Energy segment	244,390		259,041
Other businesses and eliminations	37,629		34,220
Total identifiable assets	$	1,505,556	$	1,414,934

Our operations are entirely domestic.

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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 September 30, 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 early adoption of 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 flow hedges.

The following tables present the changes in the balance of accumulated other comprehensive (loss)/income as of September 30, 2018 and 2017. All amounts except the stranded tax reclassification are presented net of tax.

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)
Other comprehensive loss before reclassifications	—			(1,126		)	(1,126		)
Amounts reclassified from accumulated other comprehensive income	275			1,043			1,318
Net current-period other comprehensive income/(loss)	275			(83		)	192
Stranded tax reclassification to retained earnings	(1,022		)	115			(907		)
As of September 30, 2018	$	(5,490	)	$	503		$	(4,987	)

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	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)
Other comprehensive (loss)/income before reclassifications	(9		)	322			313
Amounts reclassified from accumulated other comprehensive income/(loss)	271			(965		)	(694		)
Net prior-period other comprehensive income/(loss)	262			(643		)	(381		)
As of September 30, 2017	$	(5,098	)	$	(161	)	$	(5,259	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months endedSeptember 30, 2018 and 2017. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit (1)	$	19		$	19		$	58		$	58
Net loss(1)	(138		)	(171		)	(435		)	(509		)
Total before income taxes	(119		)	(152		)	(377		)	(451		)
Income tax benefit	33			61			102			180
Net of tax	$	(86	)	$	(91	)	$	(275	)	$	(271	)
Gains and losses on commodity contracts cash flow hedges:
Propane swap agreements (2)	$	(276	)	$	198		$	(921	)	$	663
Natural gas swaps (2)	123			1			(358		)	1
Natural gas futures (2)	(308		)	(852		)	(171		)	929
Total before income taxes	(461		)	(653		)	(1,450		)	1,593
Income tax benefit (expense)	129			248			407			(628		)
Net of tax	(332		)	(405		)	(1,043		)	965
Total reclassifications for the period	$	(418	)	$	(496	)	$	(1,318	)	$	694

⁽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 and nine months endedSeptember 30, 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 September 30,	2018			2017			2018			2017			2018		2017		2018			2017			2018		2017
(in thousands)
Interest cost	$	94		$	103		$	570		$	623		$	21	$	22	$	10		$	11		$	12	$	13
Expected return on plan assets	(131		)	(127		)	(770		)	(699		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(19		)	(19		)	—		—
Amortization of net loss	82			107			86			131			25		22		15			17			—		—
Net periodic cost (benefit) (1)	45			83			(114		)	55			46		44		6			9			12		13
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	45		$	83		$	77		$	246		$	46	$	44	$	6		$	9		$	14	$	15

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Nine Months Ended September 30,	2018			2017			2018			2017			2018		2017		2018			2017			2018		2017
(in thousands)
Interest cost	$	288		$	309		$	1,754		$	1,870		$	63	$	66	$	29		$	31		$	38	$	38
Expected return on plan assets	(406		)	(381		)	(2,318		)	(2,098		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(58		)	(58		)	—		—
Amortization of net loss	258			319			302			392			75		65		45			50			—		—
Net periodic cost (benefit) (1)	140			247			(262		)	164			138		131		16			23			38		38
Amortization of pre-merger regulatory asset	—			—			571			571			—		—		—			—			6		6
Total periodic cost	$	140		$	247		$	309		$	735		$	138	$	131	$	16		$	23		$	44	$	44

⁽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 $856,000 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 $749,000 and approximately $1.3 million at September 30, 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.

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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 September 30, 2018 and 2017:

For the Three Months Ended September 30, 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	82		86		25		15			—		208
Total recognized in net periodic benefit cost	82		86		25		(4		)	—		189
Recognized from accumulated other comprehensive loss (1)	82		16		25		(4		)	—		119
Recognized from regulatory asset	—		70		—		—			—		70
Total	$	82	$	86	$	25	$	(4	)	$	—	$	189

For the Three Months Ended September 30, 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		17			—		277
Total recognized in net periodic benefit cost	107		131		22		(2		)	—		258
Recognized from accumulated other comprehensive loss (1)	107		25		22		(2		)	—		152
Recognized from regulatory asset	—		106		—		—			—		106
Total	$	107	$	131	$	22	$	(2	)	$	—	$	258

For the Nine Months Ended September 30, 2018	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(58	)	$	—	$	(58	)
Net loss	258		302		75		45			—		680
Total recognized in net periodic benefit cost	258		302		75		(13		)	—		622
Recognized from accumulated other comprehensive loss (1)	258		57		75		(13		)	—		377
Recognized from regulatory asset	—		245		—		—			—		245
Total	$	258	$	302	$	75	$	(13	)	$	—	$	622

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For the Nine Months Ended September 30, 2017	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(58	)	$	—	$	(58	)
Net loss	319		392		65		50			—		826
Total recognized in net periodic benefit cost	319		392		65		(8		)	—		768
Recognized from accumulated other comprehensive loss (1)	319		75		65		(8		)	—		451
Recognized from regulatory asset	—		317		—		—			—		317
Total	$	319	$	392	$	65	$	(8	)	$	—	$	768

⁽¹⁾ See Note 8, Stockholder's Equity.

During the three and nine months ended September 30, 2018, we contributed approximately $235,000 and $433,000, respectively, to the Chesapeake Pension Plan and approximately $123,000 and $971,000, respectively, 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 and nine months endedSeptember 30, 2018, were approximately $38,000 and $113,000, respectively. 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 nine months ended September 30, 2018, were approximately $15,000 and no cash benefits were paid for medical claims during the third quarter of 2018. 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 and nine months ended September 30, 2018, were approximately $9,000 and $33,000, respectively. 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 September 30, 2018 and December 31, 2017, consisted of the following:

(in thousands)	September 30, 2018		December 31, 2017
Rabbi trust (associated with the Deferred Compensation Plan)	$	7,929	$	6,734
Investments in equity securities	22		22
Total	$	7,951	6,756

We classify these investments as trading securities and report them at their fair value. For the three months ended September 30,2018 and 2017, we recorded a net unrealized gain of approximately $313,000 and $261,000, respectively, in other expense, net in the condensed consolidated statements of income related to these investments. For the nine months ended September 30, 2018 and 2017, we recorded a net unrealized gain of approximately $426,000 and $694,000, 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.

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The table below presents the amounts included in net income related to share-based compensation expense for the three and nine months endedSeptember 30, 2018 and 2017:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
(in thousands)
Awards to non-employee directors	$	135		$	134		$	404		$	406
Awards to key employees	153			662			2,728			1,202
Total compensation expense	288			796			3,132			1,608
Less: tax benefit	(79		)	(320		)	(858		)	(647		)
Share-based compensation amounts included in net income	$	209		$	476		$	2,274		$	961

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 2018, each of our non-employee directors received an annual retainer of 792 shares of common stock under the SICP for service as a director through the 2019 Annual Meeting of Stockholders. The table below presents the summary of the stock activity for awards to non-employee directors for the nine months endedSeptember 30, 2018:

	Number of Shares		Weighted Average Fair Value
Outstanding—December 31, 2017	—		$	—
Granted	7,128		$	75.70
Vested	(7,128	)	$	75.70
Outstanding—September 30, 2018	—		$	—

At September 30, 2018, there was approximately $315,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2019. See Note 1, Summary of Accounting Policies, for additional information regarding ASU 2018-07 and its impact on the accounting for non-employee share-based payments.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the nine months endedSeptember 30, 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
Vested - Accelerated pursuant to separation agreement (1)	(16,676	)	$	75.78
Expired	(3,933	)	$	49.66
Outstanding—September 30, 2018	131,741		$	67.43

⁽¹⁾Includes 2,569 shares that were forfeited.

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 financial results, which comprise market-based and performance-based conditions or targets. The fair value of each performance-

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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.

In June 2018, the Company and a former executive officer entered into a separation agreement and release (the "Separation Agreement"). Pursuant to the Separation Agreement, three awards, representing a total of 14,107 shares of common stock previously granted to the executive officer under the SICP, immediately vested at the time of separation, and an additional 2,569 shares were forfeited. We settled the awards that vested in cash and recognized $1.1 million as share-based compensation expense.

At September 30, 2018, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $11.1 million. At September 30, 2018, there was approximately $2.6 million of unrecognized compensation cost related to these awards, which is expected to be recognized as expense from 2018 through 2020.

Stock Options

We did not have any stock options outstanding at September 30, 2018 or 2017, nor were any stock options issued during these periods.

12. Derivative Instruments

We use derivative and non-derivative contracts to 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 September 30, 2018, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

We adopted ASU 2017-12 as of July 1, 2018. See Note 1, Summary of Accounting Policies, under the heading "FASB Statements and Other Authoritative Pronouncements" for additional details.

Volume of Derivative Activity

As of September 30, 2018, the volume of our open commodity derivative contracts were as follows:

Business unit	Commodity	Quantity hedged (in millions)	Designation	Longest Expiration date of hedge
PESCO	Natural gas (Dts)	22.1	Cash flows hedges	March 2022
PESCO	Natural gas (Dts)	1.1	Not designated	January 2020
Sharp	Propane (gallons)	4.4	Cash flows hedges	June 2021
Sharp	Propane (gallons)	0.3	Fair value hedges	March 2019

PESCO entered into natural gas futures contracts associated with the purchase and sale of natural gas to specific customers. We designated and accounted for them as cash flow hedges. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $570,000 from accumulated other comprehensive loss to earnings during the next 12-month period ending September 30, 2019.

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Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes expected to be purchased during the heating season. Under the futures and swap agreements, Sharp will receive the difference between (i) the index prices (Mont Belvieu prices in August 2018 through June 2021) and (ii) the per gallon propane swap prices, to the extent the index prices exceed the contracted prices. If the index prices are lower than the swap prices, Sharp will pay the difference. We designated and accounted for propane swaps as cash flows hedges. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $392,000 from accumulated other comprehensive income to earnings during the next 12-month period ending September 30, 2019.

Sharp paid a total of $28,000 to purchase a put option to protect against a decline in propane prices and related potential inventory losses associated volumes of propane for its propane price cap program during the upcoming heating season. We will exercise the put option if propane prices fall below specified strike price(s) per gallon in December 2018 to March 2019. If exercised, we will receive the difference between the market price and the strike price during those months. We accounted for the put option as a fair value hedge. The premium paid by Sharp is amortized and recorded in earnings over the duration of the put option and recorded in the same line item as the hedged item. The change in the fair value of the put option is recorded in derivative assets and or derivative liability and later recognized in cost of sales.

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 payable on a gross and net basis at September 30, 2018 and December 31, 2017:

	At September 30, 2018
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	7,042	$	1,158	$	5,884
Accounts payable	$	11,264	$	1,158	$	10,106

	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

Broker Margin

Futures exchanges have contract specific margin requirements that require the posting of cash or cash equivalents relating to traded contracts. Margin requirements consist of initial margin that is posted upon the initiation of a position, maintenance margin that is usually expressed as a percent of initial margin, and variation margin that fluctuates based on the daily MTM relative to maintenance margin requirements. We maintain separate broker margin accounts for Sharp and PESCO. The balances are as follows:

(in thousands)	Balance Sheet Location	At September 30, 2018		At December 31, 2017
Sharp	Other Current Liabilities	$	18	$	—
PESCO	Other Current Assets	$	2,060	$	6,300

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Financial Statements Presentation

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 September 30, 2018 and December 31, 2017, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	September 30, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	—	$	13
Natural gas futures contracts	Derivative assets, at fair value	1,841		—
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	19		—
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative assets, at fair value	8,114		92
Propane swap agreements	Derivative assets, at fair value	594		1,181
Total asset derivatives		$	10,568	$	1,286

	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	September 30, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative liabilities, at fair value	$	1,602	$	5,776
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative liabilities, at fair value	8,168		469
Natural gas swap contracts	Derivative liabilities, at fair value	—		2
Propane swap agreements	Derivative liabilities, at fair value	4		—
Total liability derivatives		$	9,774	$	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 September 30,						For the Nine Months Ended September 30,
(in thousands)	(Loss) on Derivatives	2018			2017			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	197			286			(2,766		)	907
Propane swap agreements	Cost of sales	—			15			(13		)	11
Natural gas swap contracts	Cost of sales	—			1			—			1
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	(276		)	198			(921		)	663
Propane swap agreements	Other comprehensive income (loss)	296			1,590			(590		)	814
Natural gas futures contracts	Cost of sales	(308		)	(852		)	(171		)	929
Natural gas swap contracts	Cost of sales	123			1			(358		)	1
Natural gas swap contracts	Other comprehensive income (loss)	(25		)	(413		)	563			(413		)
Natural gas futures contracts	Other comprehensive income (loss)	630			(1,296		)	(241		)	(1,420		)
Total		$	637		$	(470	)	$	(4,497	)	$	1,596

⁽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.

As of September 30, 2018, the following amounts were recorded in the condensed consolidated balance sheets related to fair value hedges:

(in thousands)	Carrying Amount of Hedged Item				Cumulative Adjustment Included in Carrying Amount of Hedged Item
Balance Sheet Location of Hedged Items	At September 30, 2018		At December 31, 2017		At September 30, 2018		At December 31, 2017
Inventory	$	290	$	—	$	—	$	—

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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 September 30, 2018 and December 31, 2017:

			Fair Value Measurements Using:
As of September 30, 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	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	679		—		—		679
Investments—mutual funds and other	7,250		7,250		—		—
Total investments	7,951		7,272		—		679
Derivative assets	10,568		—		10,568		—
Total assets	$	18,519	$	7,272	$	10,568	$	679
Liabilities:
Derivative liabilities	$	9,774	$	—	$	9,774	$	—

			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:

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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 nine months ended September 30, 2018 and 2017:

	Nine Months Ended   September 30,
	2018			2017
(in thousands)
Beginning Balance	$	648		$	561
Purchases and adjustments	64			76
Transfers	(29		)	—
Distribution	(12		)	(2		)
Investment income	8			7
Ending Balance	$	679		$	642

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

At September 30, 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 September 30, 2018, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of approximately $250.7 million. This compares to a fair value of approximately $248.9 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:

	September 30,			December 31,
(in thousands)	2018			2017
FPU secured first mortgage bonds (1) :
9.08% bond, due June 1, 2022	$	7,985		$	7,982
Uncollateralized senior notes:
5.50% note, due October 12, 2020	6,000			6,000
5.93% note, due October 31, 2023	16,500			18,000
5.68% note, due June 30, 2026	23,200			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
3.48% note, due May 31, 2038	50,000			—
Promissory notes	26			97
Capital lease obligation	987			2,070
Less: debt issuance costs	(488		)	(433		)
Total long-term debt	251,210			206,816
Less: current maturities	(9,613		)	(9,421		)
Total long-term debt, net of current maturities	$	241,597		$	197,395

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

In January 2018, we borrowed an additional $25.0 million under the Revolver, which we classified as long-term debt due to the stated maturity date of October 8, 2020. In May 2018, we utilized a portion of the proceeds from the issuance of $50.0 million of 3.48% Series A notes to repay the $25.0 million of long-term debt borrowed under the Revolver. For additional information regarding the issuance of the Series A notes, see "Shelf Agreements" below.

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. Prudential is under no obligation to purchase any unsecured senior debt. As of September 30, 2018, we had issued $70.0 million of 3.25% Prudential Shelf Notes. In September 2018, we amended the Prudential Shelf Agreement, pursuant to which we may request that Prudential purchase up to $150.0 million of our unsecured debt over a three-year period which expires in August 2021. Following this amendment, in September 2018, Prudential accepted our request to purchase $100 million of Shelf Notes on or before August 20, 2019. The new Prudential Shelf Notes will bear interest at the rate of 3.98% and have a maturity date not to exceed 20 years from the date of issuance. The proceeds received from the issuance of these Prudential Shelf Notes will be used to reduce short-term borrowings under the Revolver, lines of credit and/or to fund capital expenditures.

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 of Met Life Shelf Notes and $100.0 million NYL Shelf Notes, respectively. 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 were issued in May 2018 and the Series B notes will be issued on or before November 20, 2018. The proceeds received from the issuances of these NYL Shelf Notes will be used to reduce 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 September 30, 2018, we have $200.0 million of additional potential borrowing capacity (after excluding existing unfunded commitments) under the Prudential Shelf Agreement ($50.0 million) and MetLife Shelf Agreement ($150.0 million). 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

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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 and Nine Months endedSeptember 30, 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 September 30, 2018 was $5.5 million, or $0.34 per share. This represents a decrease of $1.3 million, or $0.08 per share, compared to net income of $6.8 million, or $0.42 per share, reported for the same quarter in 2017. Operating income decreased by $2.6 million for the three months ended September 30, 2018, compared to the same period in the prior year, as margin increased by $3.0 million, or 5.1 percent, and was offset by a $1.5 million increase in depreciation, amortization and property taxes and a $4.1 million increase in other operating expenses. During the third quarter, we refunded $2.0 million in margin, which represents a pass-through to regulated energy customers of the $2.0 million benefit from lower federal income taxes during the quarter. Excluding the estimated customer refunds during the third quarter of 2018 associated with the TCJA, gross margin increased by $5.0 million, or 8.4 percent, and operating income decreased by $603,000, or 4.1 percent, compared to the same period in the prior year. The decrease in the federal income tax rate positively impacted earnings in our unregulated energy businesses.

	Three Months Ended
	September 30,						Increase
	2018			2017			(decrease)
(in thousands except per share)
Business Segment:
Regulated Energy segment	$	15,915		$	15,523		$	392
Unregulated Energy segment	(3,933		)	(951		)	(2,982		)
Other businesses and eliminations	54			60			(6		)
Operating Income	$	12,036		$	14,632		$	(2,596	)
Other expense, net	(11		)	(154		)	143
Interest charges	4,430			3,321			1,109
Pre-tax Income	7,595			11,157			(3,562		)
Income taxes	2,057			4,324			(2,267		)
Net Income	$	5,538		$	6,833		$	(1,295	)
Earnings Per Share of Common Stock
Basic	$	0.34		$	0.42		$	(0.08	)
Diluted	$	0.34		$	0.42		$	(0.08	)

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

(in thousands, except per share data)	Pre-tax Income			Net Income			Earnings Per Share
Third Quarter of 2017 Reported Results	$	11,157		$	6,833		$	0.42
Increased (Decreased) Gross Margins:
Eastern Shore and Peninsula Pipeline service expansions*	3,616			2,636			0.16
Pass-through of lower taxes to regulated energy customers(1)	(1,993		)	(1,454		)	(0.09		)
Implementation of Eastern Shore settled rates* (2)	1,161			847			0.05
Natural gas growth (including customer and consumption growth, but excluding service expansions)	734			535			0.03
PESCO results (decrease primarily due to imbalance adjustments)	(629		)	(459		)	(0.03		)
Retail margins per gallon	(469		)	(342		)	(0.02		)
Florida electric reliability/modernization program*	464			339			0.02
Unregulated energy customer consumption	(374		)	(273		)	(0.02		)
GRIP*	329			240			0.01
	2,839			2,069			0.11
Decreased (Increased) Other Operating Expenses:
Outside services and facilities maintenance costs (3)	(1,532		)	(1,117		)	(0.07		)
Depreciation, asset removal and property tax costs due to new capital investments (3)	(1,447		)	(1,055		)	(0.06		)
Benefits and other employee-related expenses (3)	(758		)	(553		)	(0.03		)
Payroll expense (increased staffing and annual salary increases) (3)	(754		)	(550		)	(0.03		)
Operating expenses to increase staffing, infrastructure and risk management systems necessary to support growth for PESCO	(452		)	(330		)	(0.02		)
Early termination of facility lease due to consolidation of operations facilities(3)	(423		)	(309		)	(0.02		)
	(5,366		)	(3,914		)	(0.23		)
Interest charges	(1,109		)	(809		)	(0.04		)
Income taxes - including TCJA impact - decreased effective tax rate for regulated energy	—			1,454			0.09
Income taxes - including TCJA impact - change in effective tax rate for unregulated energy and other operations	—			(151		)	(0.01		)
Net other changes	74			56			—
	(1,035		)	550			0.04
Third Quarter of 2018 Reported Results	$	7,595		$	5,538		$	0.34

⁽¹⁾"Pass-through of lower taxes to regulated customers" represents the amounts that have already been refunded to customers or reserves established for future refunds and/or reduced rates to customers in the third quarter of 2018 as a result of lower taxes due to the TCJA. Refunds made to customers are offset by the corresponding decrease in federal income taxes and are expected to have no net impact on net income.

⁽²⁾ Excluding amounts refunded to customers associated with the TCJA, which are broken out separately and discussed in footnote 1.

⁽³⁾ Excluding incremental operating expenses at PESCO.

*See the Major Projects and Initiatives table.

Our net income for the nine months ended September 30, 2018 was $38.8 million, or $2.36 per share. This represents an increase of $6.8 million, or $0.40 per share, compared to net income of $32.0 million, or $1.96 per share, reported for the same period in 2017. Operating income increased by $1.9 millionfor the nine months ended September 30, 2018, compared to the same

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period in the prior year. This increase was driven by a $17.0 million, or 8.3 percent, increase in gross margin, which was offset by a $3.7 million increase in depreciation, amortization and property taxes and an $11.4 million increase in other operating expenses. Excluding the estimated customer refunds reserved or refunded to regulated customers for the nine months ended September 30, 2018, associated with the TCJA, gross margin and operating income increased by $24.6 million, or 12.0 percent, and $9.4 million, or 14.8 percent, respectively, compared to the same period in the prior year. The decrease in the federal income tax rate positively impacted earnings in our unregulated energy businesses.

	Nine Months Ended
	September 30,						Increase
	2018			2017			(decrease)
(in thousands except per share)
Business Segment:
Regulated Energy segment	$	56,930		$	53,004		$	3,926
Unregulated Energy segment	10,241			10,626			(385		)
Other businesses and eliminations	(1,481		)	162			(1,643		)
Operating Income	$	65,690		$	63,792		$	1,898
Other expense, net	(204		)	(1,855		)	1,651
Interest charges	11,976			9,133			2,843
Pre-tax Income	53,510			52,804			706
Income taxes	14,731			20,781			(6,050		)
Net Income	$	38,779		$	32,023		$	6,756
Earnings Per Share of Common Stock
Basic	$	2.37		$	1.96		$	0.41
Diluted	$	2.36		$	1.96		$	0.40

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Key variances, between the nine months ended2018 and the nine months ended2017, included:

(in thousands, except per share data)	Pre-tax Income			Net Income			Earnings Per Share
Nine Months Ended September 30, 2017 Reported Results	$	52,804		$	32,023		$	1.96
Adjusting for unusual items:
One-time separation expenses associated with a former executive	(1,548		)	(1,421		)	(0.09		)
Absence of Xeron expenses, including 2017 wind-down expenses	829			601			0.04
	(719		)	(820		)	(0.05		)
Increased (Decreased) Gross Margins:
Pass-through of lower taxes to regulated energy customers(1)	(7,530		)	(5,457		)	(0.33		)
Implementation of Eastern Shore settled rates* (2)	6,256			4,534			0.28
Eastern Shore and Peninsula Pipeline service expansions*	5,966			4,323			0.26
Return to normal weather	5,342			3,872			0.24
Natural gas growth (including customer and consumption growth, but excluding service expansions)	4,098			2,970			0.18
Unregulated energy growth excluding PESCO	1,704			1,234			0.08
Florida electric reliability/modernization program*	1,231			892			0.05
GRIP*	931			675			0.04
Non-recurring margin decrease at PESCO	(863		)	(626		)	(0.04		)
Margin from PESCO operations	(373		)	(271		)	(0.02		)
	16,762			12,146			0.74
Decreased (Increased) Other Operating Expenses:
Depreciation, asset removal and property tax costs due to new capital investments (3)	(3,401		)	(2,465		)	(0.15		)
Payroll expense (increased staffing and annual salary increases)(3)	(3,287		)	(2,382		)	(0.15		)
Facilities maintenance costs (3)	(2,275		)	(1,649		)	(0.10		)
Operating expenses to increase staffing, infrastructure and risk management systems necessary to support growth for PESCO	(2,167		)	(1,571		)	(0.10		)
Incentive compensation costs (based on period-over-period results)(3)	(1,046		)	(758		)	(0.05		)
Vehicle, credit collections, other taxes, sales and advertising costs (3)	(1,010		)	(732		)	(0.04		)
Benefits and other employee-related expenses (3)	(749		)	(543		)	(0.03		)
Regulatory costs (3)	536			389			0.02
Early termination of facility lease due to consolidation of operations facilities(3)	(423		)	(306		)	(0.02		)
	(13,822		)	(10,017		)	(0.62		)
Interest charges	(2,843		)	(2,060		)	(0.13		)
Income taxes - including TCJA impact - decreased effective tax rate for regulated energy	—			5,457			0.33
Income taxes - including TCJA impact - decreased effective tax rate for unregulated energy and other operations				1,087			0.07
Net other changes	1,328			963			0.06
	(1,515		)	5,447			0.33
Nine Months Ended September 30, 2018 Reported Results	$	53,510		$	38,779		$	2.36

⁽¹⁾ "Pass-through of lower taxes to regulated customers" represents the amounts that have already been refunded to customers or reserves established for future refunds and/or reduced rates to customers in the third quarter of 2018 as a result of lower taxes due to the TCJA. Refunds made to customers are offset by the corresponding decrease in federal income taxes and are expected to have no net impact on net income.

⁽²⁾ Excluding amounts refunded to regulated customers associated with the TCJA, which are broken out separately and discussed in footnote 1.

⁽³⁾ Excluding incremental operating expenses at PESCO.

*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 recently completed and currently underway. In the future, we will add new projects to this table as such projects are initiated.

	Gross Margin for the Period
	Three Months Ended				Nine Months Ended				Year Ended		Estimate for
	September 30,				September 30,				December 31,		Fiscal
in thousands	2018		2017		2018		2017		2017		2018		2019
Florida GRIP	$	3,722	$	3,393	$	10,933	$	10,002	$	13,454	$	14,287	$	14,370
Eastern Shore Rate Case (1)	2,181		1,020		7,276		1,020		3,693		9,800		9,800
Florida Electric Reliability/Modernization Pilot Program (1)	464		—		1,231		—		94		1,558		1,558
New Smyrna Beach, Florida Project (1)	352		—		1,056		—		235		1,409		1,409
2017 Eastern Shore System Expansion Project - including interim services (1)	2,409		—		4,439		—		433		8,009		15,773
Northwest Florida Expansion Project (1)	1,307		—		2,177		—		—		3,484		6,500
(Palm Beach County) Belvedere, Florida Project (1)	—		—		—		—		—		—		2,023
Total	$	10,435	$	4,413	$	27,112	$	11,022	$	17,909	$	38,547	$	51,433

^{(1 )}Gross margin amount included in this table has not been adjusted to reflect the impact of the TCJA. The refunds and rate reductions implemented were or will 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 mains and services. Since the program's inception in August 2012, we have invested $123.4 million to replace 261 miles of qualifying distribution mains, including $9.5 million during the first nine months of 2018. The increased investments in GRIP generated additional gross margin of $329,000 and $931,000 for the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017.

Regulatory Proceedings

Eastern Shore Rate Case

Eastern Shore's rate case settlement agreement became final on April 1, 2018, with settlement rates effective January 1, 2018. The final agreement increases Eastern Shore's operating income by $6.6 million, representing $9.8 million in additional margin from base rates offset by $3.2 million in lower federal income tax expense for Eastern Shore resulting from the TCJA. For the three and nine months ended September 30, 2018, Eastern Shore recognized incremental gross margin of approximately $1.2 million and $6.3 million, respectively. As of September 30, 2018, Eastern Shore has provided rate reductions to its customers totaling approximately $2.5 million related to the decrease in federal income taxes as a result of the TCJA.

Florida Electric Reliability/Modernization Pilot Program

In December 2017, the Florida PSC approved 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 our Florida electric distribution system. This increase will continue through at least the last billing cycle of December 2019. For the three and nine months ended September 30, 2018, additional margin of $464,000 and $1.2 million, respectively, was generated.

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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 natural gas transmission pipeline to serve current and planned customer growth in the 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 during the fourth quarter of 2018. For the three and nine months ended September 30, 2018, the project generated incremental gross margin of approximately $352,000 and $1.1 million, respectively, and is expected to generate $1.4 million of annual gross margin beginning in fiscal year 2019.

2017 Eastern Shore System Expansion Project

In November 2017, Eastern Shore began construction of a $117.0 million system expansion that will increase its capacity by 26 percent once completed. We have invested $103.3 million through September 30, 2018 and expect to substantially complete the project during the remainder of 2018. The first phase of the project was placed into service in December 2017. Additional segments of the project were placed into service over the first nine months of 2018. The project generated $2.4 million and $4.4 million in incremental gross margin, including margin from interim services, during the three and nine months ended September 30, 2018, respectively. The project is expected to produce approximately $15.8 million annually in gross margin through 2022 and $13.2 million annually in gross margin thereafter.

Northwest Florida Expansion Project

In our first expansion of natural gas service into Northwest Florida, Peninsula Pipeline has completed construction of transmission lines and the Florida natural gas division has completed construction of lateral distribution lines to serve several customers. The project was placed into service in May 2018 and generated incremental gross margin of $1.3 million and $2.2 million for the three and nine months ended September 30, 2018, respectively. The estimated annual gross margin from this project is $6.5 million.

(Palm Beach County) Belvedere, Florida Project

Peninsula Pipeline is constructing a transmission line to bring natural gas to our natural gas distribution system in West Palm Beach, Florida. We expect to complete this project by mid-2019 and estimate that the annual gross margin associated with this project will be approximately $2.0 million.

Impact of Hurricane Michael

In October 2018, Hurricane Michael passed through our electric distribution operation's service territory in Northwest Florida. The hurricane caused widespread and severe damage to our infrastructure resulting in 100% of our customers losing electrical service. We have restored power to those customers who are able to accept power following Hurricane Michael. Efforts to restore the severely damaged infrastructure will continue into the foreseeable future and we estimates that we will spend over $50.0 million towards these restoration and reliability efforts. Consistent with past practices, at the appropriate time, FPU will seek a recovery of the associated storm related costs. We have developed a preliminary range of the negative earnings impact on 2018’s results, which is estimated at $0.01-$0.03 per share.

Future Projects Not Included in the Table Above

Del-Mar Energy Pathway Project

In September 2018, Eastern Shore filed with the FERC a CP to construct the Del-Mar Energy Pathway project. The proposed project will provide an additional 14,300 Dts/d of capacity to four customers. The benefits of this project include additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and the initial extension of Eastern Shore’s pipeline system into Somerset County, Maryland. The estimated annual gross margin from this project is $5.1 million.

Other major factors influencing gross margin

Weather and Consumption

Weather did not have a material impact on results for the three months ended September 30, 2018. For the nine months ended September 30, 2018, colder temperatures compared to the prior year contributed $5.3 million in incremental gross margin. While temperatures during the first nine months of 2018 were colder than the first nine months of 2017, they were still warmer than normal, as shown in the table below. We estimate that we would have generated an additional $2.2 million in gross margin if temperatures for the nine months ended September 30, 2018 had been normal. The following table summarizes HDD and CDD variances from the 10-year average HDD/CDD ("Normal") for the three and nine months ended September 30, 2018 and 2017.

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HDD and CDD Information

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018		2017		Variance		2018		2017		Variance
Delmarva
Actual HDD	10		16		(6	)	2,729		2,262		467
10-Year Average HDD ("Delmarva Normal")	61		61		—		2,846		2,850		(4	)
Variance from Delmarva Normal	(51	)	(45	)			(117	)	(588	)
Florida
Actual HDD	—		—		—		507		298		209
10-Year Average HDD ("Florida Normal")	—		—		—		533		555		(22	)
Variance from Florida Normal	—		—				(26	)	(257	)
Ohio
Actual HDD	55		80		(25	)	3,707		3,070		637
10-Year Average HDD ("Ohio Normal")	91		92		(1	)	3,774		3,866		(92	)
Variance from Ohio Normal	(36	)	(12	)			(67	)	(796	)
Florida
Actual CDD	1,613		1,526		87		2,704		2,606		98
10-Year Average CDD ("Florida CDD Normal")	1,535		1,542		(7	)	2,593		2,579		14
Variance from Florida CDD Normal	78		(16	)			111		27

Natural Gas Distribution Customer and Consumption Growth

The Company's natural gas distribution operations generated $734,000 and $4.1 million of additional margin for the three and nine months endedSeptember 30, 2018, respectively. The breakdown of the increased margin is as follows:

	Three Months Ended			Nine Months Ended
(in thousands)	September 30, 2018			September 30, 2018
Customer growth:
Residential	$	309		$	1,171
Commercial and industrial, excluding new service in Northwest Florida	283			927
New service in Northwest Florida	305			652
Total customer growth	897			2,750
Volume growth:
Residential	(239		)	613
Commercial and industrial	57			1,030
Other - including unbilled revenue	19			(295		)
Total volume growth	(163		)	1,348
Total natural gas distribution growth	$	734		$	4,098

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Customer growth for our Delmarva Peninsula and Florida natural gas distribution operations generated $897,000 and $2.8 million in additional gross margin for the three and nine months endedSeptember 30, 2018, respectively, compared to the same periods in 2017.The additional margin was generated from an approximately 3.9 percent and 3.8 percent increase in the average number of residential customers for the three and nine months endedSeptember 30, 2018, respectively, as well as growth in commercial and industrial customers on the Delmarva Peninsula in the third quarter and first nine months of 2018, compared to the corresponding periods in 2017. Residential customer growth on the Delmarva Peninsula has averaged 3.0 percent over the past five years. Our Florida natural gas distribution operations generated additional gross margin for the three and nine months endedSeptember 30, 2018, due to growth in all customer classes and new service to customers in Northwest Florida.

Lower consumption by natural gas distribution customers reduced gross margin by $163,000 during the third quarter of 2018 compared to the same period in 2017. The lower consumption was primarily due to a decline in residential consumption in Florida, as compared to the increased customer consumption due to Hurricane Irma in the prior year period. These businesses generated $1.3 million in additional gross margin for the nine months ended September 30, 2018, compared to the same period in 2017, from higher consumption by residential and commercial customers.

Propane Operations

Gross margin generated by our propane operations decreased by $834,000 during the three months ended September 30, 2018, compared to the same period in 2017, as a result of lower retail margins per gallon and the timing of propane deliveries to customers. Customer consumption for our Florida propane operations was higher during the third quarter of 2017 due to the impact of Hurricane Irma.

For the nine months ended September 30, 2018, propane operations generated $4.9 million in incremental margin compared to the same period in 2017. More normal temperatures accounted for $2.9 million of the margin increase during the nine months endedSeptember 30, 2018. The balance of the increase reflected increased customer growth, continued expansion of AutoGas through the addition of new customers and other factors, higher sales and revenues from service contracts and increased wholesale sales activities.

PESCO

PESCO's gross margin for the three and nine months ended September 30, 2018 was lower by $629,000 and $1.2 million, compared to the same periods in 2017, respectively. The following table summarizes the changes in PESCO’S year-over-year margin for the three and nine months ended September 30, 2018:

	Three Months Ended			Nine Months Ended
	September 30, 2018			September 30, 2018
(in thousands)
2017 Gross margin	$	1,360		$	5,749
Imbalance positions and true up	(493		)	(493		)
Margin changes from growth and the acquisition of certain assets from ARM in 2017	(136		)	119
Non-recurring margin factors - change in gross margin contribution from various asset management agreements, MTM impact, Bomb Cyclone impact and other adjustments	—			(863		)
2018 Gross Margin	$	731		$	4,512

PESCO generated an operating loss of $1.1 million for the three months ended September 30, 2018, compared to a loss of $63,000 during the prior year period. The quarter-over-quarter decreased results reflect lower gross margin growth accompanied by a $452,000 increase in planned operating expenses as a result of increased staffing, infrastructure and risk management system costs as PESCO executes its growth strategy.

For the nine months ended September 30, 2018, PESCO reported an operating loss of $1.2 million, compared to operating income of $2.2 million during the prior year period. The year-over-year operating loss primarily reflects increased expenses incurred for the reasons discussed in the paragraph above, $596,000 in additional expenses related to the acquisition of certain assets from ARM, as well as the impact of several non-recurring margin adjustments, largely during the first quarter of 2018.

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Xeron

Xeron's operations were wound down during the second quarter of 2017. Operating income for the nine months ended September 30, 2018, improved by $829,000, compared to the prior year period due to the absence of Xeron's 2017 wind-down expenses and operating losses.

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Regulated Energy Segment

For the quarter ended September 30, 2018, compared to the quarter ended September 30, 2017:

	Three Months Ended
	September 30,				Increase
	2018		2017		(decrease)
(in thousands)
Revenue	$	72,770	$	69,703	$	3,067
Cost of sales	21,501		22,794		(1,293		)
Gross margin	51,269		46,909		4,360
Operations & maintenance	23,376		20,794		2,582
Depreciation & amortization	8,405		7,338		1,067
Other taxes	3,573		3,254		319
Other operating expenses	35,354		31,386		3,968
Operating income	$	15,915	$	15,523	$	392

Operating income for the Regulated Energy segment for the three months ended September 30, 2018 was $15.9 million, an increase of $392,000 compared to the same period in 2017. The increased operating income resulted from increased gross margin of $4.4 million, offset by a $4.0 million increase in operating expenses.

Excluding the impact of the customer refunds and reserves for future refunds and/ or rate reductions of approximately $2.0 million for lower income taxes due to the TCJA, gross margin and operating income for the three months ended September 30, 2018 increased by $6.4 million and $2.4 million, or 13.5 percent and 15.4 percent, respectively.

Gross Margin

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

(in thousands)	Margin Impact
Eastern Shore and Peninsula Pipeline service expansions	$	3,616
Implementation of Eastern Shore settled rates	1,161
Natural gas growth (including customer and consumption growth, but excluding service expansions)	734
Florida electric reliability/modernization program	464
Florida GRIP	329
Other	49
Total	6,353
Pass-through to regulated customers of lower taxes as a result of the TCJA*	(1,993		)
Quarter-over-quarter increase in gross margin	$	4,360

*As a result of the TCJA and ensuing directives by federal and state regulatory commissions, we reserved or refunded to customers of our regulated businesses an estimated $2.0 million during the three months ended September 30, 2018. In some jurisdictions, we have paid refunds to customers, while in other jurisdictions, we have established reserves until agreements are approved and changes are made to customer rates. The reserves and lower customer rates are equal to the estimated reduction in federal income taxes due to the TCJA and have no material impact on after-tax earnings from the Regulated Energy segment.

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.

Service Expansions

We generated additional gross margin of $3.6 million primarily from the following natural gas service expansions:

• $2.4 million from Eastern Shore's services, including those provided to customers on an interim basis, in conjunction with portions of Eastern Shore's 2017 Expansion Project that were placed in service in December 2017 and July 2018, partially offset by the absence of short-term contracts totaling $343,000 that were replaced by long-term service agreements; and

• $1.7 million generated by Peninsula Pipeline from the New Smyrna Beach and Northwest Pipeline Expansion Projects.

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Implementation of Eastern Shore Settled Rates

Eastern Shore generated additional gross margin of $1.2 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.

Natural Gas Growth (including customer and consumption growth but excluding service expansions)

Increased gross margin of $734,000 from natural gas growth and consumption (excluding service expansions) was generated primarily from the following:

• $591,000 from Florida natural gas customer growth, due primarily to an increase in residential and commercial customers served as well as expansion to Northwest Florida;

• $307,000 from a 3.9 percent increase in the average number of residential customers served by the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers served; offset by

• $165,000 from lower sales on the Delmarva Peninsula and absence of the positive impact on consumption growth in Florida in the third quarter of 2017.

Florida Electric Reliability/Modernization Program

Gross margin increased by $464,000, due primarily to the 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 $329,000for the three months ended September 30, 2018, compared to the same period in 2017.

Impact of the TCJA on Customer Rates

Adjustments to customer rates, because of the implementation of the TCJA, decreased gross margin by $2.0 million due to refunds paid to customers and the establishment of reserves for future refunds and/or rate reductions to customers. The decrease in gross margin was offset by a $2.0 million reduction in federal income taxes.

Other Operating Expenses

Other operating expenses increased by $4.0 million. The significant factors contributing to the increase in other operating expenses included:

• $1.2 million in higher costs related to outside services to support growth and facilities and maintenance costs to maintain system integrity;

• $1.3 million in higher depreciation, asset removal and property tax costs associated with recent capital investments;

• $530,000 in higher benefits and other employee-related expenses (since we self-insure for health care costs, benefits costs fluctuate depending upon filed claims);

• $446,000 in higher payroll expense for additional personnel to support growth, including Eastern Shore's 2017 System Expansion Project, which is our largest project to date; and

• $323,000 in early lease termination fees for our former service center, which service center moved to our newly constructed “Energy Lane Campus” in Dover, Delaware during the third quarter of 2018.

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For the nine months ended September 30, 2018, compared to the nine months ended September 30, 2017:

	Nine Months Ended
	September 30,				Increase
	2018		2017		(decrease)
(in thousands)
Revenue	$	252,667	$	238,353	$	14,314
Cost of sales	89,741		87,206		2,535
Gross margin	162,926		151,147		11,779
Operations & maintenance	71,546		66,780		4,766
Depreciation & amortization	23,541		21,365		2,176
Other taxes	10,909		9,998		911
Other operating expenses	105,996		98,143		7,853
Operating income	$	56,930	$	53,004	$	3,926

Operating income for the Regulated Energy segment for the nine months ended September 30, 2018 was $56.9 million, an increase of $3.9 million compared to the same period in 2017. The increased operating income resulted from increased gross margin of $11.8 million, offset by an increase in operating expenses of $7.9 million.

Excluding the impact of refunds to customers and reserves for future refunds and/or rate reductions of approximately $7.5 million for lower income taxes due to the TCJA, gross margin and operating income increased by $19.3 million and $11.4 million, or 12.8 percent and 21.6 percent, respectively.

Gross Margin

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

(in thousands)	Margin Impact
Implementation of Eastern Shore settled rates	$	6,256
Eastern Shore and Peninsula Pipeline service expansions	5,966
Natural gas growth (including customer and consumption growth but excluding service expansions)	4,098
Return to more normal weather	1,498
Florida electric reliability/modernization program	1,231
Florida GRIP	931
Other	(671		)
Total	19,309
Pass-through to regulated customers of lower taxes as a result of the TCJA*	(7,530		)
Period-over-Period increase in gross margin	$	11,779

*As a result of the TCJA, and ensuing directives by federal and state regulatory commissions, we reserved or refunded to customers of our regulated businesses an estimated $7.5 million during the first nine months of 2018. In some jurisdictions, we have paid refunds to customers, while in other jurisdictions, we have established reserves until agreements are approved and changes are made to customer rates. The reserves and lower customer rates are equal to the estimated reduction in federal income taxes due to the TCJA and have no material impact on after-tax earnings from the Regulated Energy segment.

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's Settled Rates

Eastern Shore generated additional gross margin of $6.3 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.

Service Expansions

We generated additional gross margin of $6.0 million primarily from the following natural gas service expansions:

• $4.4 million from Eastern Shore's services, including those provided to customers on an interim basis, in conjunction with portions of Eastern Shore's 2017 Expansion Project that were placed in service in December 2017 and July 2018;

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• $446,000 in additional margin as a result of an increase in rates from service provided to an industrial customer, partially offset by the absence of short-term contracts totaling $1.6 million that were replaced by long-term service agreements; and

• $3.2 million generated by Peninsula Pipeline from the New Smyrna Beach and Northwest Pipeline Expansion Projects.

Natural Gas Growth (including customer and consumption growth but excluding service expansions)

Increased gross margin of $4.1 million from natural gas growth and consumption (excluding service expansions) was generated primarily from the following:

• $1.5 million from Florida natural gas customer growth, due primarily to an increase in residential and commercial customers served;

• $1.3 million from higher sales on the Delmarva Peninsula and in Florida that were not driven by weather; and

• $1.2 million from a 3.8 percent increase in the average number of residential customers served by the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers served.

Return to More Normal Weather

Temperatures during the first nine months of 2018 were 2.9 percent warmer than normal, compared to 22.6 percent warmer than normal during the first nine months of 2017. Comparatively colder weather during the first nine months of 2018 increased usage and generated $1.5 million in additional margin.

Florida Electric Reliability/Modernization Program

Gross margin increased by $1.2 million, due primarily to the 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 $931,000for the nine months ended September 30, 2018, compared to the same period in 2017.

Impact of the TCJA on Customer Rates

Adjustments to customer rates, because of the implementation of the TCJA, decreased gross margin by $7.5 million due to refunds and reserves for future refunds and/or rate reductions to customers. The decrease in gross margin was offset by a reduction in federal income taxes.

Other Operating Expenses

Other operating expenses increased by $7.9 million. The significant factors contributing to the increase in other operating expenses included:

• $3.0 million in higher depreciation, asset removal and property tax costs associated with recent capital investments;

• $1.9 million in higher payroll expenses for additional personnel to support growth, including Eastern Shore's 2017 System Expansion Project, our largest project to date;

• $1.5 million in higher facilities and maintenance costs to maintain system integrity;

• $401,000 in higher incentive compensation costs as a result of improved period-over-period results;

• $356,000 in higher vehicle, credit collections, other taxes, sales and advertising costs;

• $323,000 in early lease termination fees for our former service center, which service center moved to our newly constructed “Energy Lane Campus” in Dover, Delaware during the third quarter; and

• $307,000 in higher benefit and other employee-related expenses (since we self-insure for health care costs, benefits costs fluctuate depending upon filed claims); offset by

• $536,000 in lower regulatory costs due to the absence of rate case filings in 2018.

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Unregulated Energy Segment

For the quarter ended September 30, 2018, compared to the quarter ended September 30, 2017:

	Three Months Ended
	September 30,						Increase
	2018			2017			(decrease)
(in thousands)
Revenue	$	76,042		$	64,688		$	11,354
Cost of sales	64,109			51,416			12,693
Gross margin	11,933			13,272			(1,339		)
Operations & maintenance	12,832			11,422			1,410
Depreciation & amortization	2,207			2,001			206
Other taxes	827			800			27
Total operating expenses	15,866			14,223			1,643
Operating loss	$	(3,933	)	$	(951	)	$	(2,982	)

The Unregulated Energy segment had an operating loss of $3.9 millionfor the three months ended September 30, 2018 compared to an operating loss of $951,000 for the same period in 2017. The increased operating loss of approximately $3.0 million was due to a decrease in gross margin of $1.3 million, accompanied by a $1.6 million increase in operating expenses.

Gross Margin

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

(in thousands)	Margin Impact
PESCO	$	(629	)
Propane retail operations - decreased margins driven by lower prices per gallon	(469		)
Unregulated Energy customer consumption decrease	(374		)
Other	133
Quarter-over-quarter decrease in gross margin	$	(1,339	)

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 September 30, 2018, PESCO's gross margin decreased by $629,000 compared to the same period in 2017. Reduced third quarter 2018 margin from PESCO primarily resulted from the timing and true-up of various imbalance positions with pipelines.

Propane Retail Operations - Decreased Prices Per Gallon

Gross margin decreased by $469,000for the three months ended September 30, 2018, mainly driven by lower prices per retail gallon as these businesses responded to current market conditions.

Unregulated Energy customer consumption decrease

Gross margin decreased by $374,000, due primarily to decreased sales of propane resulting from timing of propane deliveries to customers. Propane deliveries in Florida during the third quarter of 2017 were positively impacted by Hurricane Irma.

Other Operating Expenses

Other operating expenses increased by $1.6 million in the third quarter of 2018. The significant components of the increase in other operating expenses included:

• $452,000 in higher expenses as a result of increased staffing, infrastructure and risk management system costs to ensure the appropriate infrastructure is in place as PESCO executes its growth strategy;

• $308,000 in higher staffing and associated costs for additional personnel to support growth;

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• $275,000 in higher outside services associated primarily with growth and ongoing compliance activities;

• $228,000 in higher benefits and employee-related costs (since we self-insure for health care costs, benefits costs fluctuate depending upon filed claims);

• $176,000 in higher incentive compensation costs as a result of improved period-over-period results for most of the unregulated energy business; and

• $144,000 in higher depreciation, amortization and property tax expense.

For the nine months ended September 30, 2018, compared to the nine months ended September 30, 2017:

	Nine Months Ended
	September 30,				Increase
	2018		2017		(decrease)
(in thousands)
Revenue	$	297,754	$	220,462	$	77,292
Cost of sales	238,605		166,635		71,970
Gross margin	59,149		53,827		5,322
Operations & maintenance	39,597		34,849		4,748
Depreciation & amortization	6,572		5,833		739
Other taxes	2,739		2,519		220
Total operating expenses	48,908		43,201		5,707
Operating income	$	10,241	$	10,626	$	(385	)

Operating income for the Unregulated Energy segment for the nine months ended September 30, 2018 was $10.2 million, compared to operating income of $10.6 million for same period in 2017. The $385,000 decrease in operating income in the nine months ended September 30, 2018 was due to an increase in gross margin of $5.3 million, offset by a $5.7 million increase in operating expenses.

Gross Margin

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

(in thousands)	Margin Impact
Propane delivery operations - additional customer consumption - (weather)	2,923
Propane delivery operations - increased margin driven by growth and other factors	1,552
PESCO	(1,236		)
Aspire Energy - customer consumption - (weather)	921
Aspire Energy - increased margin driven by growth and other factors	592
Growth in wholesale propane margins and sales	255
Other	315
Period-over-period increase in gross margin	$	5,322

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.

Propane Delivery Operations - Additional Customer Consumption - (Weather)

Gross margin increased by $2.9 million, due primarily to increased propane deliveries in the Mid-Atlantic region as a result of colder temperatures during the nine months endedSeptember 30, 2018, compared to the same period in 2017.

Propane Delivery Operations - Increased Margin Driven by Growth and Other Factors

Gross margin increased by $1.6 million, due primarily to increased propane sales as a result of growth in customers and other factors in Florida and in the Mid-Atlantic region.

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PESCO

For the nine months ended September 30, 2018, PESCO's gross margin decreased by $1.2 million compared to the same period in 2017. Lower gross margin for the nine months ended September 30, 2018 from PESCO resulted from the following:

(in thousands)	Margin Impact
Reversal of unrealized MTM loss recorded in the fourth quarter of 2017	$	5,713
Net impact of extraordinary costs associated with the 2018 Bomb Cyclone for the Mid-Atlantic wholesale portfolio (1)	(3,284		)
Loss for the Mid-Atlantic retail portfolio caused by pipeline capacity constraints in January and warm weather in February 2018 (1)	(2,261		)
Non-recurring margin and annual imbalance settlement from 2017 customer Supply Agreement	(1,673		)
Non-recurring margin increase associated with the Southeast portfolio	642
Other	(373		)
Total Change in Gross Margin for PESCO for the nine months ended September 30, 2018	$	(1,236	)

⁽¹⁾The 2018 Bomb Cyclone refers to the high-intensity winter storms in early January 2018 that impacted the Company's Mid-Atlantic service territory and which had a residual impact on the Company's businesses through the month of February.   The exceedingly high demand and associated impacts on pipeline capacity and gas supply in the Delmarva Peninsula region created significant, unusual costs for PESCO. While such concerted impacts will recur infrequently, the Company's management revisited and refined its risk management strategies and implemented additional controls.

Aspire Energy - Customer Consumption (Weather)

Gross margin increased by $921,000, as a result of increased natural gas deliveries, due primarily to colder temperatures during the nine months endedSeptember 30, 2018, compared to the same period in 2017.

Aspire Energy - Customer Consumption (Growth and Other Factors)

Gross margin increased by $592,000, in the nine months ended September 30, 2018, due primarily to increased sales as a result of customer consumption growth and other factors.

Wholesale Propane Margins

Gross margin increased by $255,000, in the nine months ended September 30, 2018 due to a higher margin per gallon and an increase in volume delivered for the Mid-Atlantic propane distribution operations.

Other Operating Expenses

Other operating expenses increased by $5.7 million in the nine months ended September 30, 2018. The significant components of the increase in other operating expenses included:

• $2.2 million in higher expenses as a result of increased staffing, infrastructure and risk management system costs to ensure the appropriate infrastructure is in place as PESCO executes its growth strategy;

• $1.4 million in higher staffing and associated costs for additional personnel to support growth and increased deliveries driven by the colder weather during the nine months ended September 30, 2018, compared to the same period in 2017;

• $706,000 in higher maintenance costs as a result of ongoing compliance activities;

• $654,000 in higher expenses, including vehicle fuel costs, sales and advertising, taxes other than income taxes and credit collections costs;

• $645,000 in higher incentive compensation costs as a result of improved period-over-period results for many of the unregulated energy businesses;

• $442,000 in higher benefits and employee-related costs (since we self-insure for health care costs, benefits costs fluctuate depending upon filed claims); and

• $410,000 in higher depreciation, amortization and property tax expense due to increased investments; offset by

• the absence of $829,000 in 2017 Xeron wind-down expenses.

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OTHER EXPENSE, NET

For the quarter ended September 30, 2018 compared to the quarter ended September 30, 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, decreased by $143,000 in the third quarter of 2018, compared to the same period in 2017, due to gain from the sale of assets within our unregulated businesses in the third quarter of 2017.

For the nine months endedSeptember 30, 2018 compared to the nine months endedSeptember 30, 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, decreased by $1.7 million for the first three quarters of 2018, compared to the same period in 2017, due partly to the recognition of Xeron lease termination expenses in 2017.

INTEREST CHARGES

For the quarter ended September 30, 2018 compared to the quarter ended September 30, 2017

Interest charges for the three months ended September 30, 2018 increased by $1.1 million, compared to the same period in 2017, attributable primarily to an increase of $953,000 in interest on higher short-term borrowings, and an increase of $277,000 in interest on long-term debt, largely as a result of the issuance of the NYL Shelf Notes (Series A) in May 2018.

For the nine months endedSeptember 30, 2018 compared to the nine months endedSeptember 30, 2017

Interest charges for the nine months ended September 30, 2018 increased by $2.8 million, compared to the same period in 2017, attributable primarily to an increase of $2.3 million in interest on higher short-term borrowings, and an increase of $1.1 million in interest on long-term debt, largely as a result of the issuance of the Prudential Shelf Notes in April 2017 and the issuance of the NYL Shelf Notes (Series A) in May 2018.

INCOME TAXES

For the quarter ended September 30, 2018 compared to the quarter ended September 30, 2017

Income tax expense was $2.1 million for the three months ended September 30, 2018, compared to $4.3 million in the same period in 2017. The decrease in income tax expense was due primarily to the impact of the TCJA in the third quarter of 2018. Our effective income tax rate was 27.1 percent and 39.5 percent, for the three months ended September 30, 2018 and 2017, respectively.

For the nine months endedSeptember 30, 2018 compared to the nine months endedSeptember 30, 2017

Income tax expense was $14.7 million for the nine months ended September 30, 2018, compared to $20.8 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 nine months of 2018. Our effective income tax rate was 27.5 percent and 39.5 percent for the nine months ended September 30, 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 with 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 $176.1 million for the nine months ended September 30, 2018.

We originally budgeted $181.6 million for capital expenditures in 2018, and we currently project capital expenditures of approximately $216.4 million in 2018. Our current capital projection by segment and by business line is shown below:

	2018
(dollars in thousands)
Regulated Energy:
Natural gas distribution	$	65,594
Natural gas transmission	110,813
Electric distribution	8,930
Total Regulated Energy	185,337
Unregulated Energy:
Propane distribution	13,359
Other unregulated energy	7,413
Total Unregulated Energy	20,772
Other:
Corporate and other businesses	10,289
Total Other	10,289
Total 2018 Budgeted Capital Expenditures	$	216,398

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 September 30, 2018 and December 31, 2017:

	September 30, 2018				December 31, 2017
(in thousands)
Long-term debt, net of current maturities	$	241,597	32	%	$	197,395	29	%
Stockholders’ equity	508,298		68	%	486,294		71	%
Total capitalization, excluding short-term debt	$	749,895	100	%	$	683,689	100	%
	September 30, 2018				December 31, 2017
(in thousands)
Short-term debt	$	268,293	26	%	$	250,969	26	%
Long-term debt, including current maturities	251,210		24	%	206,816		22	%
Stockholders’ equity	508,298		50	%	486,294		52	%
Total capitalization, including short-term debt	$	1,027,801	100	%	$	944,079	100	%

Included in the long-term debt balances at September 30, 2018 and December 31, 2017, was a capital lease obligation associated with Sandpiper's capacity, supply and operating agreement (at September 30, 2018, zero excluding current maturities and $1.0 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 ending in May 2019. The capacity portion of this agreement is accounted for as a capital lease.

Our target equity to total capitalization ratio, including short-term borrowings, is between 50 and 60 percent. From time to time, we may go below the lower end of the target range as we 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. Prudential is under no obligation to purchase any unsecured senior debt. As of September 30, 2018, we have issued $70.0 million of 3.25% Prudential Shelf Notes. In September 2018, we amended the Prudential Shelf Agreement, pursuant to which we may request that Prudential purchase up to $150.0 million of our unsecured debt over a three year period which expires in August 2021. Following this amendment, in September 2018, Prudential accepted our request to purchase $100.0 million of Shelf Notes on or before August 20, 2019. The new Prudential Shelf Notes will bear interest at the rate of 3.98% and have a maturity date not to exceed 20 years from the date of issuance. The proceeds received from the issuance of these Prudential Shelf Notes will be used to reduce short-term borrowings under our Revolver, lines of credit and/or to fund capital expenditures.

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 of Met Life Shelf Notes and $100.0 million NYL Shelf Notes, respectively. 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 were issued in May 2018 and the Series B notes will be issued on or before November 20, 2018. The proceeds received from the issuances of these NYL Shelf Notes will be used to reduce 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 September 30, 2018, we have $200.0 million of additional potential borrowing capacity (after excluding existing unfunded commitments) under the Prudential Shelf Agreement ($50.0 million) and MetLife Shelf Agreement ($150.0 million). The Prudential Shelf Agreement and the NYL Shelf Agreement set forth certain business covenants to which we are subject when any note is

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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.

Short-term Borrowings

Our outstanding short-term borrowings at September 30, 2018 and December 31, 2017 were $268.3 million and $251.0 million at weighted average interest rates of 3.12 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 September 30, 2018, we had five unsecured bank credit facilities with four financial institutions totaling $220.0 million in available credit. In addition, 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, which was recently extended by two years 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 nine months ended September 30, 2018 and 2017:

	Nine Months Ended
	September 30,
	2018			2017
(in thousands)
Net cash provided by (used in):
Operating activities	$	127,996		$	98,372
Investing activities	(171,167		)	(141,453		)
Financing activities	43,772			42,289
Net increase (decrease) in cash and cash equivalents	601			(792		)
Cash and cash equivalents—beginning of period	5,614			4,178
Cash and cash equivalents—end of period	$	6,215		$	3,386

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 nine months ended September 30, 2018 and 2017, net cash provided by operating activities was $128.0 million and $98.4 million, respectively, resulting in an increase in cash flows of $29.6 million. Significant operating activities generating the cash flows change were as follows:

• Net cash flows from changes in propane inventory, storage gas and other inventories increased by approximately $14.6 million due primarily to higher levels of our inventory during 2017.

• Changes in net regulatory assets and liabilities increased cash flows by $3.0 million, due primarily to the change in fuel costs collected through the various cost recovery mechanisms.

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• Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities decreased cash flows by $6.0 million, due primarily higher to the timing of the receipt of customer payments from increased revenue as well as the timing of payments to vendors.

• Changes in net prepaid expenses and other current assets, customer deposits and refunds decreased cash flows by $1.8 million.

• Net income, adjusted for reconciling activities, decreased cash flows by $1.1 million, primarily due to the absence of deferred tax assets pertaining to the availability and utilization of bonus depreciation during the first nine months 2018, offset by an increase in net income, higher non-cash adjustments for depreciation and amortization related to increased investing activities and adjustments for realized gains on investments.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $171.2 million and $141.5 million during the nine months ended September 30, 2018 and 2017, respectively, resulting in a decrease in cash flows of $29.7 million. Cash paid for capital expenditures, including acquisitions increased by $41.3 million to $171.4 million for the first nine months of 2018, compared to $130.1 million for the same period in 2017.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities totaled $43.8 million during the nine months ended September 30, 2018 compared to net cash of $42.3 million provided by in financing activities during the prior year period resulting in an increase in cash flows of $1.5 million. The increase in net cash provided by financing activities resulted primarily from the following:

• Increased cash flows from lower repayments of short-term borrowing of $20.4 million under our line of credit arrangements;

• Receipt of $74.9 million in net cash proceeds from the Revolver and the issuance of the NYL Shelf Notes (Series A) in January and May 2018, respectively, which increased cash flow by $5.1 million during the nine months ended September 30, 2018, compared to the same period in 2017. For the nine months ended September 30, 2017, we received $69.8 million in net proceeds from the issuance of the Prudential Shelf Notes; and

• Increased cash flows of $3.7 million as a result of changes in cash overdrafts; partially offset by

• Higher repayment of long-term debt of $25.0 million during the nine months ended September 30, 2018, compared to the same period in 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 September 30, 2018 was $73.9 million, with the guarantees expiring on various dates through September 2019.

We have issued letters of credit totaling $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 varying expiration dates through December 2019. There have been no draws on these letters of credit as of September 30, 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 long-term debt and commodity purchase obligations entered into in the ordinary course of our business. The following table summarizes long-term debt and commodity purchase contract obligations at September 30, 2018:

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	Payments Due by Period
	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
(in thousands)
Long-term debt(1)	$	8,626	$	31,200	$	38,700	$	172,200	$	250,726
Purchase obligations - Commodity (2)	95,964		22,335		28		—		118,327
Total	$	104,590	$	53,535	$	38,728	$	172,200	$	369,053

⁽¹⁾  Excludes capital lease obligation, debt issuance costs and an unamortized discount of $484,000.

⁽²⁾  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.

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 September 30, 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 September 30, 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 7.0 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 flow 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 in order to fulfill our natural gas purchase requirements.

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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 take delivery of 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.

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 September 30, 2018:

(in thousands)	Balance at December 31, 2017			Increase (Decrease) in Fair Market Value			Less Amounts Settled			Balance at September 30, 2018
PESCO	$	(6,153	)	$	15,293		$	(8,954	)	$	186
Sharp	1,192			(1,237		)	654			609
Total	$	(4,961	)	$	14,056		$	(8,300	)	$	795

There were no changes in methods of valuations during the nine months endedSeptember 30, 2018.

The following is a summary of fair market value of financial derivatives as of September 30, 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	$	482	$	(1,285	)	$	1,027	$	(35	)	$	(3	)	$	186
Price based on Mont Belvieu - Sharp	117		346			132		14			—			609
Total	$	599	$	(939	)	$	1,159	$	(21	)	$	(3	)	$	795

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 September 30, 2018. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 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 that 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 September 30, 2018, there

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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)
July 1, 2018 through July 31, 2018 (1)	417	$	85.25	—	—
August 1, 2018 through August 31, 2018	—	$	—	—	—
September 1, 2018 through September 30, 2018	—	$	—	—	—
Total	417	$	85.25	—	—

⁽¹⁾  Chesapeake Utilities purchased shares of common 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 September 30, 2018, 417 shares were purchased through the reinvestment of dividends on deferred stock units.

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

Item 3. Defaults upon Senior Securities

None.

Item 5. Other Information

None.

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Item 6. Exhibits

4.1†	Form of Note Agreement dated September 14, 2018, among Chesapeake Utilities Corporation, as issuer, and certain note holders relating to the private placement of Chesapeake Utilities Corporation’s 3.98% Senior Notes due 2039.
10.1†	First Amendment to Private Shelf Agreement dated September 14, 2018, by and between Chesapeake Utilities Corporation and PGIM, Inc. formerly known as Prudential Investment Management, Inc., and other purchasers that may become a party thereto.
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.

*Filed herewith

†Pursuant to Item 601(b)(4)(v) of Regulation S-K under the Securities Act of 1933, as amended, these exhibits are not being filed herewith and Chesapeake Utilities agrees to furnish a copy to the Securities and Exchange Commission upon request.

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SIGNATURES

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

CHESAPEAKE UTILITIES CORPORATION

/S/ BETH W. COOPER

Beth W. Cooper

Senior Vice President and Chief Financial Officer

Date: November 9, 2018

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EX-31.1

EXHIBIT 31.1

CERTIFICATE PURSUANT TO RULE 13A-14(A)

UNDER THE SECURITIES EXCHANGE ACT OF 1934

I, Michael P. McMasters, certify that:

1. I have reviewed this quarterly report on Form 10-Q for the quarter ended September 30, 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: November 9, 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 September 30, 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: November 9, 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 September 30, 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

November 9, 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 September 30, 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

November 9, 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	9 Months Ended
	Sep. 30, 2018	Oct. 31, 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	Sep. 30, 2018
Document Fiscal Year Focus	2018
Document Fiscal Period Focus	Q3
Amendment Flag	false
Entity Common Stock, Shares Outstanding		16,378,545

XML

Condensed Consolidated Statements of Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operating Revenues
Regulated Energy	$ 72,770	$ 69,703	$ 252,667	$ 238,353
Unregulated Energy and other	67,509	57,233	263,632	198,827
Total Operating Revenues	140,279	126,936	516,299	437,180
Operating Expenses
Regulated Energy cost of sales	21,501	22,794	89,741	87,206
Unregulated Energy and other cost of sales	55,660	44,066	204,880	145,325
Operations	32,821	29,274	101,804	91,778
Maintenance	3,208	2,737	10,419	9,370
Gain From A Settlement	0	0	(130)	(130)
Depreciation and amortization	10,633	9,362	30,176	27,267
Other taxes	4,420	4,071	13,719	12,572
Total Operating Expenses	128,243	112,304	450,609	373,388
Operating Income	12,036	14,632	65,690	63,792
Other expense, net	(11)	(154)	(204)	(1,855)
Interest charges	4,430	3,321	11,976	9,133
Income Before Income Taxes	7,595	11,157	53,510	52,804
Income taxes	2,057	4,324	14,731	20,781
Net Income	$ 5,538	$ 6,833	$ 38,779	$ 32,023
Weighted Average Common Shares Outstanding:
Basic (shares)	16,378,545	16,344,442	16,366,608	16,334,210
Diluted (shares)	16,428,439	16,389,635	16,416,255	16,378,633
Earnings Per Share of Common Stock:
Basic (in dollars per share)	$ 0.34	$ 0.42	$ 2.37	$ 1.96
Diluted (in dollars per share)	0.34	0.42	2.36	1.96
Cash Dividends Declared Per Share of Common Stock (in dollars per share)	$ 0.370	$ 0.325	$ 1.065	$ 0.955

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net Income	$ 5,538	$ 6,833	$ 38,779	$ 32,023
Other Comprehensive Income (Loss), net of tax:
Amortization of prior service cost, net of tax of $(5), $(8), $(16) and $(23), respectively	(14)	(11)	(42)	(35)
Net gain, net of tax of $38, $69, $118 and $212, respectively	100	102	317	297
Cash Flow Hedges, net of tax:
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $257, $(15), $(70) and $(376), respectively	644	(104)	(83)	(643)
Total Other Comprehensive Income (Loss), net of tax	730	(13)	192	(381)
Comprehensive Income	$ 6,268	$ 6,820	$ 38,971	$ 31,642

XML

Condensed Consolidated Statements of Comprehensive Income (Unaudited) (Parenthetical) - USD ($) $ in Thousands	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Amortization of prior service cost, tax	$ (5)	$ (8)	$ (16)	$ (23)
Net gain, tax	38	69	118	212
Unrealized (loss)/gain on commodity contract cash flow hedges, tax	$ 257	$ (15)	$ (70)	$ (376)

XML

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Thousands		Sep. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment
Regulated Energy		$ 1,242,840	$ 1,073,736
Unregulated Energy		220,721	210,682
Other businesses and eliminations		34,975	27,699
Total property, plant and equipment		1,498,536	1,312,117
Less: Accumulated depreciation and amortization		(295,449)	(270,599)
Plus: Construction work in progress		60,243	84,509
Net property, plant and equipment		1,263,330	1,126,027
Current Assets
Cash and cash equivalents		6,215	5,614
Trade and other receivables (less allowance for uncollectible accounts of $987 and $936, respectively)		52,660	77,223
Accrued revenue		12,352	22,279
Propane inventory, at average cost		7,444	8,324
Other inventory, at average cost		4,786	12,022
Regulatory assets		6,891	10,930
Storage gas prepayments		6,989	5,250
Income taxes receivable		8,725	14,778
Prepaid expenses		9,775	13,621
Derivative assets, at fair value		10,568	1,286
Other current assets		2,557	7,260
Total current assets		128,962	178,587
Deferred Charges and Other Assets
Goodwill		19,604	19,604
Other intangible assets, net		4,073	4,686
Investments, at fair value		7,951	6,756
Regulatory assets		76,343	75,575
Other assets		5,293	3,699
Total deferred charges and other assets		113,264	110,320
Total Assets		1,505,556	1,414,934
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)		7,971	7,955
Additional paid-in capital		255,509	253,470
Retained earnings		249,805	229,141
Accumulated other comprehensive loss		(4,987)	(4,272)
Deferred compensation obligation		3,818	3,395
Treasury stock		(3,818)	(3,395)
Total stockholders’ equity	[1]	508,298	486,294
Long-term debt, net of current maturities		241,597	197,395
Total capitalization		749,895	683,689
Current Liabilities
Less: current maturities		9,613	9,421
Short-term borrowing		268,293	250,969
Accounts payable		60,228	74,688
Customer deposits and refunds		34,887	34,751
Accrued interest		3,969	1,742
Dividends payable		6,060	5,312
Accrued compensation		10,396	13,112
Regulatory liabilities		9,099	6,485
Derivative liabilities, at fair value		9,774	6,247
Other accrued liabilities		14,819	10,273
Total current liabilities		427,138	413,000
Deferred Credits and Other Liabilities
Deferred income taxes		146,814	135,850
Regulatory liabilities		141,840	140,978
Environmental liabilities		7,941	8,263
Other pension and benefit costs		28,839	29,699
Deferred investment tax credits and other liabilities		3,089	3,455
Total deferred credits and other liabilities		328,523	318,245
Environmental and other commitments and contingencies (Notes 5 and 6)
Total Capitalization and Liabilities		$ 1,505,556	$ 1,414,934

[1] Includes 96,622 and 90,961 shares at September 30, 2018 and December 31, 2017, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.

XML

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Statement of Financial Position [Abstract]
Allowance for uncollectible accounts	$ 987	$ 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	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Operating Activities
Net Income	$ 38,779	$ 32,023
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	30,176	27,267
Depreciation and accretion included in other costs	6,464	5,989
Deferred income taxes	11,047	29,520
Realized loss (gain) on commodity contracts/sale of assets/investments	4,015	(2,817)
Unrealized gain on investments/commodity contracts	(427)	(695)
Employee benefits and compensation	456	1,212
Share-based compensation	2,535	1,608
Other, net	(35)	(39)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	32,988	12,912
Propane inventory, storage gas and other inventory	6,379	(8,256)
Regulatory assets/liabilities, net	3,899	927
Prepaid expenses and other current assets	(1,533)	(2,860)
Accounts payable and other accrued liabilities	(9,590)	4,515
Income taxes receivable	6,053	(3,810)
Customer deposits and refunds	136	3,255
Accrued compensation	(2,804)	(2,030)
Other assets and liabilities, net	(542)	(349)
Net cash provided by operating activities	127,996	98,372
Investing Activities
Property, plant and equipment expenditures	(171,410)	(130,137)
Proceeds from sales of assets	565	601
Acquisitions, net of cash received		11,707
Environmental expenditures	(322)	(210)
Net cash used in investing activities	(171,167)	(141,453)
Financing Activities
Common stock dividends	(16,171)	(14,780)
(Purchase) issuance of stock under the Dividend Reinvestment Plan	(518)	254
Stock issuance	0	(10)
Tax Withholding payments related to net settled stock compensation	(1,210)	(692)
Change in cash overdrafts due to outstanding checks	712	(3,013)
Net borrowing (repayment) under line of credit agreements and short-term borrowing under the Revolver	16,612	(3,760)
Proceeds from long-term debt and long-term borrowing under the Revolver	74,901	69,800
Repayment of long-term debt, long-term borrowing under the Revolver and capital lease obligation	(30,554)	(5,510)
Net cash provided in financing activities	43,772	42,289
Net Increase (Decrease) in Cash and Cash Equivalents	601	(792)
Cash and Cash Equivalents—Beginning of Period	5,614	4,178
Cash and Cash Equivalents—End of Period	$ 6,215	$ 3,386

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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		$ 38,779				38,779
New Accounting Pronouncement or Change in Accounting Principle, Effect of Adoption, Quantification		(1,498)				(1,498)
Tax Cuts and Jobs Act, Reclassification from AOCI to Retained Earnings, Tax Effect		(907)				907	(907)
Other comprehensive income (loss)		192					192
Dividend declared		(17,524)				(17,524)
Stock Issued During Period, Shares, Dividend Reinvestment Plan				0
Stock Issued During Period, Value, Dividend Reinvestment Plan		(2)		$ 0	(2)
Stock issuance		0
Share-based compensation (shares)	[2],[3]			34,103
Share-based compensation and tax benefit	[2],[3]	2,057		$ 16	2,041
Treasury stock activities		0						423	(423)
Ending Balances (shares) at Sep. 30, 2018	[1],[4]			16,378,545
Ending Balances at Sep. 30, 2018		$ 508,298	[4]	$ 7,971	$ 255,509	$ 249,805	$ (4,987)	$ 3,818	$ (3,818)
Preferred Stock, Shares Authorized		2,000,000
Preferred Stock, Par or Stated Value Per Share		$ 0.01

[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 nine months ended September 30, 2018, and for the year ended December 31, 2017, we withheld 16,918 and 10,269 shares, respectively, for taxes.

[4] Includes 96,622 and 90,961 shares at September 30, 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	9 Months Ended	12 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]
Dividend declared (in dollars per share)	$ 0.370	$ 1.065	$ 1.2800
Deferred compensation plan held Rabbi Trust (shares)	96,622	96,622	90,961
Preferred Stock, Shares Authorized	2,000,000	2,000,000	2,000,000
Preferred Stock, Par or Stated Value Per Share	$ 0.01	$ 0.01	$ 0.01
Proceeds from Issuance of Common Stock		$ 0	$ (10)
Shares issued under the performance incentive plan withheld for employee taxes (shares)		16,918	10,269

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Summary of Accounting Policies

9 Months Ended

Sep. 30, 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. The acquired assets complemented PESCO’s existing asset portfolio and expanded our regional footprint and retail demand in a market where we had existing pipeline capacity and wholesale liquidity.  We accounted for the purchase of these assets as a business combination and initially recorded goodwill of $6.8 million within our Unregulated Energy segment. In connection with the acquisition, we initially recorded a contingent consideration liability of $2.5 million, based on our preliminary analysis projecting that the acquired business would achieve at least a certain gross margin target in 2018. During the second quarter of 2018, we identified certain known information as of the acquisition date that was not considered in our original analysis and would have resulted in no contingent consideration liability being initially recorded. Therefore, we reversed the originally-recorded contingent liability and reduced goodwill by $2.5 million. We similarly revised the condensed consolidated balance sheet as of December 31, 2017. These revisions are considered immaterial to our condensed consolidated financial statements. The need for a contingent consideration liability will be re-evaluated in the final reporting period in 2018. However, our current assessment is that no contingent consideration will be paid.

In August 2017, Flo-gas acquired certain operating assets of Chipola, which provided 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, which were included in our condensed consolidated statements of income for the three and nine months ended September 30, 2018, were not material. The acquisition accounting amounts recorded in conjunction with the ARM and Chipola acquisitions are now final although the amounts associated with the Central Gas acquisition 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. The impact of adoption of the new revenue standard was immaterial to our net income.

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 that 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 statements for the three and nine months endedSeptember 30, 2018 and condensed consolidated balance sheet as of September 30, 2018:

	Three Months Ended   September 30, 2018							Nine Months Ended   September 30, 2018
Income statement	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)			As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Regulated Energy operating revenues	$	72,770	$	72,879	$	(109	)	$	252,667	$	253,659	$	(992	)
Regulated Energy cost of sales	21,501		21,512		(11		)	89,741		90,454		(713		)
Depreciation and amortization	10,633		10,629		4			30,176		30,150		26
Income before income taxes	7,595		7,697		(102		)	53,510		53,815		(305		)
Income taxes	2,057		2,086		(29		)	14,731		14,819		(88		)
Net income	5,538		5,611		(73		)	38,779		38,996		(217		)

	As of September 30, 2018
Balance sheet	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Assets
Accrued revenues	$	12,352	$	13,658	$	(1,306	)
Other assets	$	5,293	$	5,702	$	(409	)
Capitalization
Retained earnings	$	249,805	$	251,520	$	(1,715	)

The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $305,000 in revenue in the first nine months of 2018 to future years and a cumulative adjustment that decreased retained earnings and other assets by $1.7 million at September 30, 2018, 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 should not be included operating expenses. 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, 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. 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) change because of a change in the terms or conditions of the award. We adopted ASU 2017-09, prospectively, on January 1, 2018. 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 adopted 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 contract cash flows hedges. 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.

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. 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 that is 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. ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges and 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 adopted ASU 2017-12 effective July 1, 2018, with no material impact on our financial statements. See Note 12, Derivative Instruments, for additional information with respect to the disclosures required by ASU 2017-12.

Recent Accounting Standards Yet to be Adopted

Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which requires lessees to recognize leases on the balance sheet and disclose key information about leasing arrangements. The standard establishes a ROU model that requires a lessee to recognize a ROU asset and lease liability for all leases with a term greater than 12 months. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASC 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. ASU 2016-02 will be effective for our annual and interim financial statements, beginning January 1, 2019, although early adoption is permitted. We expect to adopt ASU 2016-02 effective January 1, 2019 and use the modified retrospective transition approach to all existing leases.

The new standard permits companies to elect several practical expedients. We expect to elect: (1) the ‘package of practical expedients,’ pursuant to which we do not need to reassess our prior conclusions about lease identification, lease classification and initial direct costs and (2) the ‘use-of-hindsight’ practical expedient, which allows us to use hindsight in assessing impairment of our existing land easements. We also intend to aggregate all non-lease components with the lease components to which they relate.

The most significant effect of ASC 842 will be recognition of ROU assets and lease liabilities on our balance sheet for our operating leases and providing significant new disclosures about our leasing activities. We currently expect that upon adoption, we will recognize lease liabilities ranging from $4.0 million to $5.0 million, with corresponding ROU of the same amount based on the present value of the remaining minimum rental payments for existing operating leases.

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 implementation of this new standard will not have a material impact on our financial position or results of operations.

Compensation - Stock Compensation (ASC 718) - In June 2018, the FASB issued ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting, which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. ASU 2018-07 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We believe that implementation of this new standard will not have a material impact on our financial position or results of operations.

Fair Value Measurement (ASC 820) - In August 2018, the FASB issued ASU 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement, which removes, modifies and adds certain disclosure requirements on fair value measurements in ASC 820. ASU 2018-13 will be effective for our annual and interim financial statements beginning January 1, 2020 and, since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.

Compensation - Retirement Benefits - Defined Benefit Plans - General (ASC 715-20) - In August 2018, the FASB issued ASU 2018-14, Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans, which removes, clarifies and adds certain disclosure requirements in ASC 715-20 related to defined benefit pension and other postretirement plans. ASU 2018-14 will be effective for our annual and interim financial statements, on a retrospective basis, beginning January 1, 2021 and, since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.

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Calculation of Earnings Per Share

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Calculation of Earnings Per Share

Calculation of Earnings Per Share

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	5,538	$	6,833	$	38,779	$	32,023
Weighted average shares outstanding	16,378,545		16,344,442		16,366,608		16,334,210
Basic Earnings Per Share	$	0.34	$	0.42	$	2.37	$	1.96
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	5,538	$	6,833	$	38,779	$	32,023
Reconciliation of Denominator:
Weighted shares outstanding—Basic	16,378,545		16,344,442		16,366,608		16,334,210
Effect of dilutive securities—Share-based compensation	49,894		45,193		49,647		44,423
Adjusted denominator—Diluted	16,428,439		16,389,635		16,416,255		16,378,633
Diluted Earnings Per Share	$	0.34	$	0.42	$	2.36	$	1.96

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Revenue Recognition (Notes)

9 Months Ended

Sep. 30, 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 month following the satisfaction of our performance obligation.

The following table displays our revenue by major source based on product and service type for the three months ended September 30, 2018:

(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Florida natural gas division	$	6,282		$	—		$	—		$	6,282
Delaware natural gas division	7,010			—			—			7,010
FPU electric distribution	23,830			—			—			23,830
FPU natural gas distribution	17,390			—			—			17,390
Maryland natural gas division	2,463			—			—			2,463
Sandpiper	3,561			—			—			3,561
Total energy distribution	60,536			—			—			60,536
Energy transmission
Aspire Energy	—			5,750			—			5,750
Eastern Shore	16,189			—			—			16,189
Peninsula Pipeline	3,404			—			—			3,404
Total energy transmission	19,593			5,750			—			25,343
Energy generation
Eight Flags	—			4,044			—			4,044
Propane delivery
Delmarva Peninsula propane delivery	—			13,172			—			13,172
Florida propane delivery	—			4,166			—			4,166
Total propane delivery	—			17,338			—			17,338
Energy services
PESCO	—			51,619			—			51,619
Other and eliminations
Eliminations	(7,359		)	(3,185		)	(8,668		)	(19,212		)
Other	—			476			135			611
Total other and eliminations	(7,359		)	(2,709		)	(8,533		)	(18,601		)
Total operating revenues (1)	$	72,770		$	76,042		$	(8,533	)	$	140,279

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $546,000 and $91,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.

The following table displays our revenue by major source based on product and service type for the nine months ended September 30, 2018:

(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Florida natural gas division	$	18,462		$	—		$	—		$	18,462
Delaware natural gas division	50,963			—			—			50,963
FPU electric distribution	60,933			—			—			60,933
FPU natural gas distribution	58,885			—			—			58,885
Maryland natural gas division	17,136			—			—			17,136
Sandpiper	16,892			—			—			16,892
Total energy distribution	223,271			—			—			223,271
Energy transmission
Aspire Energy	—			23,682			—			23,682
Eastern Shore	46,289			—			—			46,289
Peninsula Pipeline	8,469			—			—			8,469
Total energy transmission	54,758			23,682			—			78,440
Energy generation
Eight Flags	—			12,652			—			12,652
Propane delivery
Delmarva Peninsula propane delivery	—			73,907			—			73,907
Florida propane delivery	—			15,741			—			15,741
Total propane delivery	—			89,648			—			89,648
Energy services
PESCO	—			181,976			—			181,976
Other and eliminations
Eliminations	(25,362		)	(11,679		)	(34,643		)	(71,684		)
Other	—			1,475			521			1,996
Total other and eliminations	(25,362		)	(10,204		)	(34,122		)	(69,688		)
Total operating revenues (1)	$	252,667		$	297,754		$	(34,122	)	$	516,299

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $(399,000) and $246,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.

Regulated Energy segment

The businesses within our Regulated Energy segment are regulated utilities whose operations and customer contracts are subject to rates approved by the respective state PSC 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 provide delivery service only). 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 the 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 the FERC-approved maximum 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 receive service only 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 capacity used or reserved and the fixed monthly charge.

Peninsula Pipeline is engaged in natural gas intrastate 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. We accrue unbilled revenues for transportation services provided and not yet billed at the end of an accounting period.

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 established monthly index price 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 affiliates of Chesapeake Utilities) 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 balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2017 and September 30, 2018 were as follows:

	Trade Receivables			Contract Assets (Non-current)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2017	$	74,962		$	1,270	$	407
Balance at 9/30/2018	50,937			2,331		583
Increase (decrease)	$	(24,025	)	$	1,061	$	176

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 incurred by Eight Flags 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 September 30, 2018 and December 31, 2017, we had a contract liability of $583,000 and $407,000, respectively, which was included in other accrued liabilities in the condensed consolidated balance sheet, 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 and nine months ended September 30, 2018, we recognized revenue of $48,000 and $384,000, respectively.

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

9 Months Ended

Sep. 30, 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 customers: 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. Subsequently, the Delaware Division filed an updated report reflecting the impact of the TCJA on May 31, 2018. If, after reviewing the required filing, 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.

In addition, on February 1, 2018, the Delaware PSC issued an order requiring Delaware rate-regulated public utilities to accrue regulatory liabilities reflecting the impacts of changes in the federal corporate income tax laws. In compliance with the Delaware PSC order, we have established a regulatory liability to reflect the estimated impacts of the changes in the federal corporate income tax rate. We believe that the reduction in rates charged by our Delaware Division because of the lower federal income taxes resulting from the TCJA will not have a material effect on our financial position or results of operations, because the reduction will be offset by an equal reduction in income tax expense.

Underserved Area Rates: In December 2017, we filed an application requesting authorization to utilize existing expansion area tariff rates to serve customers located outside of the current Sussex County, Delaware expansion area boundaries that cannot be economically served under the regular tariff rates. In June 2018, we reached a settlement agreement with the relevant parties, which allows us to utilize higher rates for areas outside of our existing expansion area. The Delaware PSC unanimously approved the settlement at its public meeting on July 10, 2018. The new rate schedule became effective on August 1, 2018.

CGS: In June 2018, we filed with the Delaware PSC an application requesting approval of the acquisition and subsequent conversion of propane to natural gas for certain CGS located within our territory. We requested the establishment of regulatory accounting treatment and valuation of the acquisition of certain CGS, approval of a methodology to set new distribution rates for CGS customers and approval of a new system-wide tariff rate that will recover CGS conversion costs. The Delaware PSC has not reached a decision as of the date of this filing.

Maryland Division and Sandpiper

Effect of the TCJA on customers: The Maryland PSC issued an order requiring all Maryland public utilities with rates 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 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 impacts of the changes in the federal corporate income tax rate in compliance with the Maryland PSC’s order and made compliance filings that included preliminary estimates of the annual impact of the change in the statutory federal income tax rate. In April 2018, the Maryland PSC ordered both the Maryland Division and Sandpiper to implement reduced rates effective May 1, 2018, reflecting the impact of the TCJA. We implemented a one-time bill credit for the regulatory liability established for the refunds and issued the refunds to customers in July 2018. We submitted an informational filing to the Maryland PSC within the requisite 60 days of completing the refund payments. Additionally, if in the future the Maryland Division or Sandpiper identify any additional tax savings, we must submit an additional filing to the Maryland PSC in order to return those savings to customers as soon as possible. We believe that the reduction in rates charged by our Maryland Division and Sandpiper because of the lower federal income taxes resulting from the TCJA will not have a material effect on our financial position or results of operations, because the reduction is offset by an equal reduction in income tax expense.

Florida

Florida Electric Reliability/Modernization Pilot Program: In July 2017, our Florida electric operations 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 our electrical grid. An interconnection project with FPL, which enables us to mitigate fuel costs for our 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, our Florida electric operations 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 storm reserve to its pre-storm level of $1.5 million. As a result of these hurricanes and tropical storms, our Florida electric operation’s storm reserve was depleted and is currently at a deficit of $779,000. We have requested approval of a surcharge of $1.82 per kilowatt per hour for two years to recover and replenish storm-related costs. This matter is scheduled for review at the Florida PSC’s meeting in the fourth quarter of 2018.

Effect of the TCJA on customers: 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. Hearings for Florida’s electric utilities are tentatively scheduled for the first quarter of 2019, and hearings for the natural gas utilities are tentatively scheduled for the fourth quarter of 2018.

In December 2017, the Florida PSC issued an order regarding the limited proceeding for our Florida electric operations, which prescribes the applicability, timing and treatment of the impacts of the TCJA, as discussed above. In June, our Florida natural gas operations filed petitions and testimony in support of the disposition of the impacts created by the TCJA. We believe that the reduction in rates charged by our Florida electric and natural gas operations because of the lower federal income taxes resulting from the TCJA will not have a material effect on our financial position or results of operations, because the reduction is offset by an equal reduction in income tax expense.

In October 18, 2018, our electric distribution operation reached a settlement agreement with the Office of Public Counsel. This settlement agreement was filed for approval with the Florida PSC on October 19, 2018 and hearing in this action is expected to be held in December 2018. This agreement proposes that our electric distribution operation will flow benefit associated with the TCJA back to its customers through a combination of reductions to the fuel cost recovery rate, base rates, as well as application to the storm reserve over the next several years.

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 October 2017, the FERC issued a CP authorizing Eastern Shore to construct the expansion facilities. 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. In June 2018, the Fair Hill Loop in Chester County, Pennsylvania and Cecil County, Maryland was placed into service. With the exception of some minor facilities, the remaining segments of the 2017 Expansion Project are expected to be placed into service in various phases during the fourth quarter 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 based its proposed rates on the mainline cost of service of approximately $60.0 million resulting in an overall requested annual 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 on 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 pending FERC approval of the settlement and refunds to customers according to the terms of the settlement agreement. The FERC approved the settlement agreement in February 2018, and it became final in March 2018. Exclusive of the TCJA impact, base rates would have increased, on an annual basis, by approximately $9.8 million.

Effect of the TCJA on customers: 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 in incremental margin, 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 to 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 the TCJA.

In March 2018, the FERC issued a NOPR that proposed a process to determine which 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 NOPR 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 in accordance with the settlement agreement in its 2017 rate case approved by the FERC. In July 2018, the FERC issued a final rule, which largely adopted the process proposed in the NOPR, requiring all interstate natural gas companies to file an informational filing for the purpose of evaluating the impact of the TCJA and the United Airlines, Inc. v. FERC decision on interstate natural gas pipelines’ revenue requirements. The final rule provides that an individual pipeline has the option to request a waiver if the pre-March 2018 settlement justifies not adjusting its rates at this time. In September 2018, Eastern Shore requested that the FERC grant it a waiver of the requirement. In October 2018, the FERC issued an order granting the waiver.

Del-Mar Energy Pathway Project: In September 2018, Eastern Shore filed a Certificate Application for the Del-Mar Energy Pathway project with the FERC. The proposed project would provide an additional 14,300 Dts/d of capacity to four customers. Facilities to be constructed include six miles of pipeline looping in Delaware, 13 miles of new mainline extension in Sussex County, Delaware and Somerset County, Maryland as well as new pressure control and delivery stations in these counties. The benefits of this project include (i) further natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware and (ii) first extension of Eastern Shore’s pipeline system into Somerset County, Maryland.

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Environmental Commitments and Contingencies

9 Months Ended

Sep. 30, 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 are also in discussions with the MDE regarding another former MGP site located in Cambridge, Maryland.

As of September 30, 2018, we had approximately $9.4 million in environmental liabilities related to FPU’s MGP sites in Key West, Pensacola, Sanford and West Palm Beach. 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. As of September 30, 2018 we have recovered approximately $11.4 million, leaving approximately $2.6 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. We expect to implement similar remedial actions on other remaining portions, including the anticipated demolition of buildings on the site's west parcel in 2018.	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. Site assessment is ongoing.	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

9 Months Ended

Sep. 30, 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, with various expiration dates, to purchase natural gas, electricity and propane from various suppliers. 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 1.8 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 1.8 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 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 FPU fails to meet this ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric 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 September 30, 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 our 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 September 30, 2018 was approximately $73.9 million, with the guarantees expiring on various dates through September 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 September 30, 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 September 30, 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

9 Months Ended

Sep. 30, 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						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	69,697		$	67,257		$	243,382		$	232,519
Unregulated Energy segment and other businesses	70,582			59,679			272,917			204,661
Total operating revenues, unaffiliated customers	$	140,279		$	126,936		$	516,299		$	437,180
Intersegment Revenues (1)
Regulated Energy segment	$	3,073		$	2,446		$	9,285		$	5,834
Unregulated Energy segment	5,460			5,009			24,837			15,801
Other businesses	135			194			521			581
Total intersegment revenues	$	8,668		$	7,649		$	34,643		$	22,216
Operating Income
Regulated Energy segment	$	15,915		$	15,523		$	56,930		$	53,004
Unregulated Energy segment	(3,933		)	(951		)	10,241			10,626
Other businesses and eliminations	54			60			(1,481		)	162
Total operating income	12,036			14,632			65,690			63,792
Other expense, net	(11		)	(154		)	(204		)	(1,855		)
Interest charges	4,430			3,321			11,976			9,133
Income before Income Taxes	7,595			11,157			53,510			52,804
Income taxes	2,057			4,324			14,731			20,781
Net Income	$	5,538		$	6,833		$	38,779		$	32,023

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

(in thousands)	September 30, 2018		December 31, 2017
Identifiable Assets
Regulated Energy segment	$	1,223,537	$	1,121,673
Unregulated Energy segment	244,390		259,041
Other businesses and eliminations	37,629		34,220
Total identifiable assets	$	1,505,556	$	1,414,934

Our operations are entirely domestic.

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

9 Months Ended

Sep. 30, 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 September 30, 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 early adoption of 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 flow hedges.

The following tables present the changes in the balance of accumulated other comprehensive (loss)/income as of September 30, 2018 and 2017. All amounts except the stranded tax reclassification are presented net of tax.

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)
Other comprehensive loss before reclassifications	—			(1,126		)	(1,126		)
Amounts reclassified from accumulated other comprehensive income	275			1,043			1,318
Net current-period other comprehensive income/(loss)	275			(83		)	192
Stranded tax reclassification to retained earnings	(1,022		)	115			(907		)
As of September 30, 2018	$	(5,490	)	$	503		$	(4,987	)

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)
Other comprehensive (loss)/income before reclassifications	(9		)	322			313
Amounts reclassified from accumulated other comprehensive income/(loss)	271			(965		)	(694		)
Net prior-period other comprehensive income/(loss)	262			(643		)	(381		)
As of September 30, 2017	$	(5,098	)	$	(161	)	$	(5,259	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months endedSeptember 30, 2018 and 2017. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit (1)	$	19		$	19		$	58		$	58
Net loss(1)	(138		)	(171		)	(435		)	(509		)
Total before income taxes	(119		)	(152		)	(377		)	(451		)
Income tax benefit	33			61			102			180
Net of tax	$	(86	)	$	(91	)	$	(275	)	$	(271	)
Gains and losses on commodity contracts cash flow hedges:
Propane swap agreements (2)	$	(276	)	$	198		$	(921	)	$	663
Natural gas swaps (2)	123			1			(358		)	1
Natural gas futures (2)	(308		)	(852		)	(171		)	929
Total before income taxes	(461		)	(653		)	(1,450		)	1,593
Income tax benefit (expense)	129			248			407			(628		)
Net of tax	(332		)	(405		)	(1,043		)	965
Total reclassifications for the period	$	(418	)	$	(496	)	$	(1,318	)	$	694

⁽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

9 Months Ended

Sep. 30, 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 and nine months endedSeptember 30, 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 September 30,	2018			2017			2018			2017			2018		2017		2018			2017			2018		2017
(in thousands)
Interest cost	$	94		$	103		$	570		$	623		$	21	$	22	$	10		$	11		$	12	$	13
Expected return on plan assets	(131		)	(127		)	(770		)	(699		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(19		)	(19		)	—		—
Amortization of net loss	82			107			86			131			25		22		15			17			—		—
Net periodic cost (benefit) (1)	45			83			(114		)	55			46		44		6			9			12		13
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	45		$	83		$	77		$	246		$	46	$	44	$	6		$	9		$	14	$	15

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Nine Months Ended September 30,	2018			2017			2018			2017			2018		2017		2018			2017			2018		2017
(in thousands)
Interest cost	$	288		$	309		$	1,754		$	1,870		$	63	$	66	$	29		$	31		$	38	$	38
Expected return on plan assets	(406		)	(381		)	(2,318		)	(2,098		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(58		)	(58		)	—		—
Amortization of net loss	258			319			302			392			75		65		45			50			—		—
Net periodic cost (benefit) (1)	140			247			(262		)	164			138		131		16			23			38		38
Amortization of pre-merger regulatory asset	—			—			571			571			—		—		—			—			6		6
Total periodic cost	$	140		$	247		$	309		$	735		$	138	$	131	$	16		$	23		$	44	$	44

⁽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 $856,000 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 $749,000 and approximately $1.3 million at September 30, 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 September 30, 2018 and 2017:

For the Three Months Ended September 30, 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	82		86		25		15			—		208
Total recognized in net periodic benefit cost	82		86		25		(4		)	—		189
Recognized from accumulated other comprehensive loss (1)	82		16		25		(4		)	—		119
Recognized from regulatory asset	—		70		—		—			—		70
Total	$	82	$	86	$	25	$	(4	)	$	—	$	189

For the Three Months Ended September 30, 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		17			—		277
Total recognized in net periodic benefit cost	107		131		22		(2		)	—		258
Recognized from accumulated other comprehensive loss (1)	107		25		22		(2		)	—		152
Recognized from regulatory asset	—		106		—		—			—		106
Total	$	107	$	131	$	22	$	(2	)	$	—	$	258

For the Nine Months Ended September 30, 2018	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(58	)	$	—	$	(58	)
Net loss	258		302		75		45			—		680
Total recognized in net periodic benefit cost	258		302		75		(13		)	—		622
Recognized from accumulated other comprehensive loss (1)	258		57		75		(13		)	—		377
Recognized from regulatory asset	—		245		—		—			—		245
Total	$	258	$	302	$	75	$	(13	)	$	—	$	622

For the Nine Months Ended September 30, 2017	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(58	)	$	—	$	(58	)
Net loss	319		392		65		50			—		826
Total recognized in net periodic benefit cost	319		392		65		(8		)	—		768
Recognized from accumulated other comprehensive loss (1)	319		75		65		(8		)	—		451
Recognized from regulatory asset	—		317		—		—			—		317
Total	$	319	$	392	$	65	$	(8	)	$	—	$	768

⁽¹⁾ See Note 8, Stockholder's Equity.

During the three and nine months ended September 30, 2018, we contributed approximately $235,000 and $433,000, respectively, to the Chesapeake Pension Plan and approximately $123,000 and $971,000, respectively, 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 and nine months endedSeptember 30, 2018, were approximately $38,000 and $113,000, respectively. 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 nine months ended September 30, 2018, were approximately $15,000 and no cash benefits were paid for medical claims during the third quarter of 2018. 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 and nine months ended September 30, 2018, were approximately $9,000 and $33,000, respectively. We estimate that approximately $88,000 will be paid for such benefits under the FPU Medical Plan in 2018.

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Investments

9 Months Ended

Sep. 30, 2018

Investments, Debt and Equity Securities [Abstract]

Investments

Investments

The investment balances at September 30, 2018 and December 31, 2017, consisted of the following:

(in thousands)	September 30, 2018		December 31, 2017
Rabbi trust (associated with the Deferred Compensation Plan)	$	7,929	$	6,734
Investments in equity securities	22		22
Total	$	7,951	6,756

We classify these investments as trading securities and report them at their fair value. For the three months ended September 30,2018 and 2017, we recorded a net unrealized gain of approximately $313,000 and $261,000, respectively, in other expense, net in the condensed consolidated statements of income related to these investments. For the nine months ended September 30, 2018 and 2017, we recorded a net unrealized gain of approximately $426,000 and $694,000, 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

9 Months Ended

Sep. 30, 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 and nine months endedSeptember 30, 2018 and 2017:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
(in thousands)
Awards to non-employee directors	$	135		$	134		$	404		$	406
Awards to key employees	153			662			2,728			1,202
Total compensation expense	288			796			3,132			1,608
Less: tax benefit	(79		)	(320		)	(858		)	(647		)
Share-based compensation amounts included in net income	$	209		$	476		$	2,274		$	961

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 2018, each of our non-employee directors received an annual retainer of 792 shares of common stock under the SICP for service as a director through the 2019 Annual Meeting of Stockholders. The table below presents the summary of the stock activity for awards to non-employee directors for the nine months endedSeptember 30, 2018:

	Number of Shares		Weighted Average Fair Value
Outstanding—December 31, 2017	—		$	—
Granted	7,128		$	75.70
Vested	(7,128	)	$	75.70
Outstanding—September 30, 2018	—		$	—

At September 30, 2018, there was approximately $315,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2019. See Note 1, Summary of Accounting Policies, for additional information regarding ASU 2018-07 and its impact on the accounting for non-employee share-based payments.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the nine months endedSeptember 30, 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
Vested - Accelerated pursuant to separation agreement (1)	(16,676	)	$	75.78
Expired	(3,933	)	$	49.66
Outstanding—September 30, 2018	131,741		$	67.43

⁽¹⁾Includes 2,569 shares that were forfeited.

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 financial results, which comprise 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.

In June 2018, the Company and a former executive officer entered into a separation agreement and release (the "Separation Agreement"). Pursuant to the Separation Agreement, three awards, representing a total of 14,107 shares of common stock previously granted to the executive officer under the SICP, immediately vested at the time of separation, and an additional 2,569 shares were forfeited. We settled the awards that vested in cash and recognized $1.1 million as share-based compensation expense.

At September 30, 2018, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $11.1 million. At September 30, 2018, there was approximately $2.6 million of unrecognized compensation cost related to these awards, which is expected to be recognized as expense from 2018 through 2020.

Stock Options

We did not have any stock options outstanding at September 30, 2018 or 2017, nor were any stock options issued during these periods.

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Derivative Instruments

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments

Derivative Instruments

We use derivative and non-derivative contracts to 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 September 30, 2018, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

We adopted ASU 2017-12 as of July 1, 2018. See Note 1, Summary of Accounting Policies, under the heading "FASB Statements and Other Authoritative Pronouncements" for additional details.

Volume of Derivative Activity

As of September 30, 2018, the volume of our open commodity derivative contracts were as follows:

Business unit	Commodity	Quantity hedged (in millions)	Designation	Longest Expiration date of hedge
PESCO	Natural gas (Dts)	22.1	Cash flows hedges	March 2022
PESCO	Natural gas (Dts)	1.1	Not designated	January 2020
Sharp	Propane (gallons)	4.4	Cash flows hedges	June 2021
Sharp	Propane (gallons)	0.3	Fair value hedges	March 2019

PESCO entered into natural gas futures contracts associated with the purchase and sale of natural gas to specific customers. We designated and accounted for them as cash flow hedges. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $570,000 from accumulated other comprehensive loss to earnings during the next 12-month period ending September 30, 2019.

Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes expected to be purchased during the heating season. Under the futures and swap agreements, Sharp will receive the difference between (i) the index prices (Mont Belvieu prices in August 2018 through June 2021) and (ii) the per gallon propane swap prices, to the extent the index prices exceed the contracted prices. If the index prices are lower than the swap prices, Sharp will pay the difference. We designated and accounted for propane swaps as cash flows hedges. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $392,000 from accumulated other comprehensive income to earnings during the next 12-month period ending September 30, 2019.

Sharp paid a total of $28,000 to purchase a put option to protect against a decline in propane prices and related potential inventory losses associated volumes of propane for its propane price cap program during the upcoming heating season. We will exercise the put option if propane prices fall below specified strike price(s) per gallon in December 2018 to March 2019. If exercised, we will receive the difference between the market price and the strike price during those months. We accounted for the put option as a fair value hedge. The premium paid by Sharp is amortized and recorded in earnings over the duration of the put option and recorded in the same line item as the hedged item. The change in the fair value of the put option is recorded in derivative assets and or derivative liability and later recognized in cost of sales.

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 payable on a gross and net basis at September 30, 2018 and December 31, 2017:

	At September 30, 2018
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	7,042	$	1,158	$	5,884
Accounts payable	$	11,264	$	1,158	$	10,106

	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

Broker Margin

Futures exchanges have contract specific margin requirements that require the posting of cash or cash equivalents relating to traded contracts. Margin requirements consist of initial margin that is posted upon the initiation of a position, maintenance margin that is usually expressed as a percent of initial margin, and variation margin that fluctuates based on the daily MTM relative to maintenance margin requirements. We maintain separate broker margin accounts for Sharp and PESCO. The balances are as follows:

(in thousands)	Balance Sheet Location	At September 30, 2018		At December 31, 2017
Sharp	Other Current Liabilities	$	18	$	—
PESCO	Other Current Assets	$	2,060	$	6,300

Financial Statements Presentation

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 September 30, 2018 and December 31, 2017, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	September 30, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	—	$	13
Natural gas futures contracts	Derivative assets, at fair value	1,841		—
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	19		—
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative assets, at fair value	8,114		92
Propane swap agreements	Derivative assets, at fair value	594		1,181
Total asset derivatives		$	10,568	$	1,286

	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	September 30, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative liabilities, at fair value	$	1,602	$	5,776
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative liabilities, at fair value	8,168		469
Natural gas swap contracts	Derivative liabilities, at fair value	—		2
Propane swap agreements	Derivative liabilities, at fair value	4		—
Total liability derivatives		$	9,774	$	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 September 30,						For the Nine Months Ended September 30,
(in thousands)	(Loss) on Derivatives	2018			2017			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	197			286			(2,766		)	907
Propane swap agreements	Cost of sales	—			15			(13		)	11
Natural gas swap contracts	Cost of sales	—			1			—			1
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	(276		)	198			(921		)	663
Propane swap agreements	Other comprehensive income (loss)	296			1,590			(590		)	814
Natural gas futures contracts	Cost of sales	(308		)	(852		)	(171		)	929
Natural gas swap contracts	Cost of sales	123			1			(358		)	1
Natural gas swap contracts	Other comprehensive income (loss)	(25		)	(413		)	563			(413		)
Natural gas futures contracts	Other comprehensive income (loss)	630			(1,296		)	(241		)	(1,420		)
Total		$	637		$	(470	)	$	(4,497	)	$	1,596

⁽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.

As of September 30, 2018, the following amounts were recorded in the condensed consolidated balance sheets related to fair value hedges:

(in thousands)	Carrying Amount of Hedged Item				Cumulative Adjustment Included in Carrying Amount of Hedged Item
Balance Sheet Location of Hedged Items	At September 30, 2018		At December 31, 2017		At September 30, 2018		At December 31, 2017
Inventory	$	290	$	—	$	—	$	—

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Fair Value of Financial Instruments

9 Months Ended

Sep. 30, 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 September 30, 2018 and December 31, 2017:

			Fair Value Measurements Using:
As of September 30, 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	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	679		—		—		679
Investments—mutual funds and other	7,250		7,250		—		—
Total investments	7,951		7,272		—		679
Derivative assets	10,568		—		10,568		—
Total assets	$	18,519	$	7,272	$	10,568	$	679
Liabilities:
Derivative liabilities	$	9,774	$	—	$	9,774	$	—

			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 nine months ended September 30, 2018 and 2017:

	Nine Months Ended   September 30,
	2018			2017
(in thousands)
Beginning Balance	$	648		$	561
Purchases and adjustments	64			76
Transfers	(29		)	—
Distribution	(12		)	(2		)
Investment income	8			7
Ending Balance	$	679		$	642

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

At September 30, 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 September 30, 2018, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of approximately $250.7 million. This compares to a fair value of approximately $248.9 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

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Long-Term Debt

Long-Term Debt

Our outstanding long-term debt is shown below:

	September 30,			December 31,
(in thousands)	2018			2017
FPU secured first mortgage bonds (1) :
9.08% bond, due June 1, 2022	$	7,985		$	7,982
Uncollateralized senior notes:
5.50% note, due October 12, 2020	6,000			6,000
5.93% note, due October 31, 2023	16,500			18,000
5.68% note, due June 30, 2026	23,200			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
3.48% note, due May 31, 2038	50,000			—
Promissory notes	26			97
Capital lease obligation	987			2,070
Less: debt issuance costs	(488		)	(433		)
Total long-term debt	251,210			206,816
Less: current maturities	(9,613		)	(9,421		)
Total long-term debt, net of current maturities	$	241,597		$	197,395

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

In January 2018, we borrowed an additional $25.0 million under the Revolver, which we classified as long-term debt due to the stated maturity date of October 8, 2020. In May 2018, we utilized a portion of the proceeds from the issuance of $50.0 million of 3.48% Series A notes to repay the $25.0 million of long-term debt borrowed under the Revolver. For additional information regarding the issuance of the Series A notes, see "Shelf Agreements" below.

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. Prudential is under no obligation to purchase any unsecured senior debt. As of September 30, 2018, we had issued $70.0 million of 3.25% Prudential Shelf Notes. In September 2018, we amended the Prudential Shelf Agreement, pursuant to which we may request that Prudential purchase up to $150.0 million of our unsecured debt over a three-year period which expires in August 2021. Following this amendment, in September 2018, Prudential accepted our request to purchase $100 million of Shelf Notes on or before August 20, 2019. The new Prudential Shelf Notes will bear interest at the rate of 3.98% and have a maturity date not to exceed 20 years from the date of issuance. The proceeds received from the issuance of these Prudential Shelf Notes will be used to reduce short-term borrowings under the Revolver, lines of credit and/or to fund capital expenditures.

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 of Met Life Shelf Notes and $100.0 million NYL Shelf Notes, respectively. 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 were issued in May 2018 and the Series B notes will be issued on or before November 20, 2018. The proceeds received from the issuances of these NYL Shelf Notes will be used to reduce 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 September 30, 2018, we have $200.0 million of additional potential borrowing capacity (after excluding existing unfunded commitments) under the Prudential Shelf Agreement ($50.0 million) and MetLife Shelf Agreement ($150.0 million). 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)

9 Months Ended

Sep. 30, 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.

Business Acquisition [Line Items]

Schedule of Business Acquisitions, by Acquisition [Table Text Block]

ARM, Chipola and Central Gas Asset Acquisitions

In August 2017, PESCO acquired certain natural gas marketing assets of ARM. The acquired assets complemented PESCO’s existing asset portfolio and expanded our regional footprint and retail demand in a market where we had existing pipeline capacity and wholesale liquidity.  We accounted for the purchase of these assets as a business combination and initially recorded goodwill of $6.8 million within our Unregulated Energy segment. In connection with the acquisition, we initially recorded a contingent consideration liability of $2.5 million, based on our preliminary analysis projecting that the acquired business would achieve at least a certain gross margin target in 2018. During the second quarter of 2018, we identified certain known information as of the acquisition date that was not considered in our original analysis and would have resulted in no contingent consideration liability being initially recorded. Therefore, we reversed the originally-recorded contingent liability and reduced goodwill by $2.5 million. We similarly revised the condensed consolidated balance sheet as of December 31, 2017. These revisions are considered immaterial to our condensed consolidated financial statements. The need for a contingent consideration liability will be re-evaluated in the final reporting period in 2018. However, our current assessment is that no contingent consideration will be paid.

In August 2017, Flo-gas acquired certain operating assets of Chipola, which provided 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, which were included in our condensed consolidated statements of income for the three and nine months ended September 30, 2018, were not material. The acquisition accounting amounts recorded in conjunction with the ARM and Chipola acquisitions are now final although the amounts associated with the Central Gas acquisition are preliminary and subject to adjustment based on additional valuations performed during the measurement period.

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. The impact of adoption of the new revenue standard was immaterial to our net income.

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 that 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 statements for the three and nine months endedSeptember 30, 2018 and condensed consolidated balance sheet as of September 30, 2018:

	Three Months Ended   September 30, 2018							Nine Months Ended   September 30, 2018
Income statement	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)			As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Regulated Energy operating revenues	$	72,770	$	72,879	$	(109	)	$	252,667	$	253,659	$	(992	)
Regulated Energy cost of sales	21,501		21,512		(11		)	89,741		90,454		(713		)
Depreciation and amortization	10,633		10,629		4			30,176		30,150		26
Income before income taxes	7,595		7,697		(102		)	53,510		53,815		(305		)
Income taxes	2,057		2,086		(29		)	14,731		14,819		(88		)
Net income	5,538		5,611		(73		)	38,779		38,996		(217		)

	As of September 30, 2018
Balance sheet	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Assets
Accrued revenues	$	12,352	$	13,658	$	(1,306	)
Other assets	$	5,293	$	5,702	$	(409	)
Capitalization
Retained earnings	$	249,805	$	251,520	$	(1,715	)

The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $305,000 in revenue in the first nine months of 2018 to future years and a cumulative adjustment that decreased retained earnings and other assets by $1.7 million at September 30, 2018, 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 should not be included operating expenses. 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, 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. 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) change because of a change in the terms or conditions of the award. We adopted ASU 2017-09, prospectively, on January 1, 2018. 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 adopted 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 contract cash flows hedges. 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.

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. 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 that is 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. ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges and 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 adopted ASU 2017-12 effective July 1, 2018, with no material impact on our financial statements. See Note 12, Derivative Instruments, for additional information with respect to the disclosures required by ASU 2017-12.

Recent Accounting Standards Yet to be Adopted

Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which requires lessees to recognize leases on the balance sheet and disclose key information about leasing arrangements. The standard establishes a ROU model that requires a lessee to recognize a ROU asset and lease liability for all leases with a term greater than 12 months. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASC 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements. ASU 2016-02 will be effective for our annual and interim financial statements, beginning January 1, 2019, although early adoption is permitted. We expect to adopt ASU 2016-02 effective January 1, 2019 and use the modified retrospective transition approach to all existing leases.

The new standard permits companies to elect several practical expedients. We expect to elect: (1) the ‘package of practical expedients,’ pursuant to which we do not need to reassess our prior conclusions about lease identification, lease classification and initial direct costs and (2) the ‘use-of-hindsight’ practical expedient, which allows us to use hindsight in assessing impairment of our existing land easements. We also intend to aggregate all non-lease components with the lease components to which they relate.

The most significant effect of ASC 842 will be recognition of ROU assets and lease liabilities on our balance sheet for our operating leases and providing significant new disclosures about our leasing activities. We currently expect that upon adoption, we will recognize lease liabilities ranging from $4.0 million to $5.0 million, with corresponding ROU of the same amount based on the present value of the remaining minimum rental payments for existing operating leases.

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 implementation of this new standard will not have a material impact on our financial position or results of operations.

Compensation - Stock Compensation (ASC 718) - In June 2018, the FASB issued ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting, which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. ASU 2018-07 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We believe that implementation of this new standard will not have a material impact on our financial position or results of operations.

Fair Value Measurement (ASC 820) - In August 2018, the FASB issued ASU 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement, which removes, modifies and adds certain disclosure requirements on fair value measurements in ASC 820. ASU 2018-13 will be effective for our annual and interim financial statements beginning January 1, 2020 and, since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.

Compensation - Retirement Benefits - Defined Benefit Plans - General (ASC 715-20) - In August 2018, the FASB issued ASU 2018-14, Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans, which removes, clarifies and adds certain disclosure requirements in ASC 715-20 related to defined benefit pension and other postretirement plans. ASU 2018-14 will be effective for our annual and interim financial statements, on a retrospective basis, beginning January 1, 2021 and, since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.

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

9 Months Ended

Sep. 30, 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 statements for the three and nine months endedSeptember 30, 2018 and condensed consolidated balance sheet as of September 30, 2018:

	Three Months Ended   September 30, 2018							Nine Months Ended   September 30, 2018
Income statement	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)			As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Regulated Energy operating revenues	$	72,770	$	72,879	$	(109	)	$	252,667	$	253,659	$	(992	)
Regulated Energy cost of sales	21,501		21,512		(11		)	89,741		90,454		(713		)
Depreciation and amortization	10,633		10,629		4			30,176		30,150		26
Income before income taxes	7,595		7,697		(102		)	53,510		53,815		(305		)
Income taxes	2,057		2,086		(29		)	14,731		14,819		(88		)
Net income	5,538		5,611		(73		)	38,779		38,996		(217		)

	As of September 30, 2018
Balance sheet	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Assets
Accrued revenues	$	12,352	$	13,658	$	(1,306	)
Other assets	$	5,293	$	5,702	$	(409	)
Capitalization
Retained earnings	$	249,805	$	251,520	$	(1,715	)

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Calculation of Earnings Per Share (Tables)

9 Months Ended

Sep. 30, 2018

Earnings Per Share [Abstract]

Calculation of Basic and Diluted Earnings Per Share

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2018		2017		2018		2017
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:
Net Income	$	5,538	$	6,833	$	38,779	$	32,023
Weighted average shares outstanding	16,378,545		16,344,442		16,366,608		16,334,210
Basic Earnings Per Share	$	0.34	$	0.42	$	2.37	$	1.96
Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	5,538	$	6,833	$	38,779	$	32,023
Reconciliation of Denominator:
Weighted shares outstanding—Basic	16,378,545		16,344,442		16,366,608		16,334,210
Effect of dilutive securities—Share-based compensation	49,894		45,193		49,647		44,423
Adjusted denominator—Diluted	16,428,439		16,389,635		16,416,255		16,378,633
Diluted Earnings Per Share	$	0.34	$	0.42	$	2.36	$	1.96

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Revenue Recognition (Tables)

9 Months Ended

Sep. 30, 2018

Revenue from Contract with Customer [Abstract]

Disaggregation of Revenue [Table Text Block]

The following table displays our revenue by major source based on product and service type for the three months ended September 30, 2018:

(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Florida natural gas division	$	6,282		$	—		$	—		$	6,282
Delaware natural gas division	7,010			—			—			7,010
FPU electric distribution	23,830			—			—			23,830
FPU natural gas distribution	17,390			—			—			17,390
Maryland natural gas division	2,463			—			—			2,463
Sandpiper	3,561			—			—			3,561
Total energy distribution	60,536			—			—			60,536
Energy transmission
Aspire Energy	—			5,750			—			5,750
Eastern Shore	16,189			—			—			16,189
Peninsula Pipeline	3,404			—			—			3,404
Total energy transmission	19,593			5,750			—			25,343
Energy generation
Eight Flags	—			4,044			—			4,044
Propane delivery
Delmarva Peninsula propane delivery	—			13,172			—			13,172
Florida propane delivery	—			4,166			—			4,166
Total propane delivery	—			17,338			—			17,338
Energy services
PESCO	—			51,619			—			51,619
Other and eliminations
Eliminations	(7,359		)	(3,185		)	(8,668		)	(19,212		)
Other	—			476			135			611
Total other and eliminations	(7,359		)	(2,709		)	(8,533		)	(18,601		)
Total operating revenues (1)	$	72,770		$	76,042		$	(8,533	)	$	140,279

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $546,000 and $91,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.

The following table displays our revenue by major source based on product and service type for the nine months ended September 30, 2018:

(in thousands)	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Florida natural gas division	$	18,462		$	—		$	—		$	18,462
Delaware natural gas division	50,963			—			—			50,963
FPU electric distribution	60,933			—			—			60,933
FPU natural gas distribution	58,885			—			—			58,885
Maryland natural gas division	17,136			—			—			17,136
Sandpiper	16,892			—			—			16,892
Total energy distribution	223,271			—			—			223,271
Energy transmission
Aspire Energy	—			23,682			—			23,682
Eastern Shore	46,289			—			—			46,289
Peninsula Pipeline	8,469			—			—			8,469
Total energy transmission	54,758			23,682			—			78,440
Energy generation
Eight Flags	—			12,652			—			12,652
Propane delivery
Delmarva Peninsula propane delivery	—			73,907			—			73,907
Florida propane delivery	—			15,741			—			15,741
Total propane delivery	—			89,648			—			89,648
Energy services
PESCO	—			181,976			—			181,976
Other and eliminations
Eliminations	(25,362		)	(11,679		)	(34,643		)	(71,684		)
Other	—			1,475			521			1,996
Total other and eliminations	(25,362		)	(10,204		)	(34,122		)	(69,688		)
Total operating revenues (1)	$	252,667		$	297,754		$	(34,122	)	$	516,299

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $(399,000) and $246,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.

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

The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2017 and September 30, 2018 were as follows:

	Trade Receivables			Contract Assets (Non-current)		Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2017	$	74,962		$	1,270	$	407
Balance at 9/30/2018	50,937			2,331		583
Increase (decrease)	$	(24,025	)	$	1,061	$	176

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Environmental Commitments and Contingencies Summary of Environmental Liabilities (Tables)

9 Months Ended

Sep. 30, 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. We expect to implement similar remedial actions on other remaining portions, including the anticipated demolition of buildings on the site's west parcel in 2018.	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. Site assessment is ongoing.	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)

9 Months Ended

Sep. 30, 2018

Segment Reporting [Abstract]

Schedule of Segment Reporting Information by Segment

The following table presents financial information about our reportable segments:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	69,697		$	67,257		$	243,382		$	232,519
Unregulated Energy segment and other businesses	70,582			59,679			272,917			204,661
Total operating revenues, unaffiliated customers	$	140,279		$	126,936		$	516,299		$	437,180
Intersegment Revenues (1)
Regulated Energy segment	$	3,073		$	2,446		$	9,285		$	5,834
Unregulated Energy segment	5,460			5,009			24,837			15,801
Other businesses	135			194			521			581
Total intersegment revenues	$	8,668		$	7,649		$	34,643		$	22,216
Operating Income
Regulated Energy segment	$	15,915		$	15,523		$	56,930		$	53,004
Unregulated Energy segment	(3,933		)	(951		)	10,241			10,626
Other businesses and eliminations	54			60			(1,481		)	162
Total operating income	12,036			14,632			65,690			63,792
Other expense, net	(11		)	(154		)	(204		)	(1,855		)
Interest charges	4,430			3,321			11,976			9,133
Income before Income Taxes	7,595			11,157			53,510			52,804
Income taxes	2,057			4,324			14,731			20,781
Net Income	$	5,538		$	6,833		$	38,779		$	32,023

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

(in thousands)	September 30, 2018		December 31, 2017
Identifiable Assets
Regulated Energy segment	$	1,223,537	$	1,121,673
Unregulated Energy segment	244,390		259,041
Other businesses and eliminations	37,629		34,220
Total identifiable assets	$	1,505,556	$	1,414,934

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

9 Months Ended

Sep. 30, 2018

Equity [Abstract]

Changes in Accumulated Other Comprehensive Loss

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)
Other comprehensive loss before reclassifications	—			(1,126		)	(1,126		)
Amounts reclassified from accumulated other comprehensive income	275			1,043			1,318
Net current-period other comprehensive income/(loss)	275			(83		)	192
Stranded tax reclassification to retained earnings	(1,022		)	115			(907		)
As of September 30, 2018	$	(5,490	)	$	503		$	(4,987	)

	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)
Other comprehensive (loss)/income before reclassifications	(9		)	322			313
Amounts reclassified from accumulated other comprehensive income/(loss)	271			(965		)	(694		)
Net prior-period other comprehensive income/(loss)	262			(643		)	(381		)
As of September 30, 2017	$	(5,098	)	$	(161	)	$	(5,259	)

Reclassifications out of Accumulated Other Comprehensive Income (Loss)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months endedSeptember 30, 2018 and 2017. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit (1)	$	19		$	19		$	58		$	58
Net loss(1)	(138		)	(171		)	(435		)	(509		)
Total before income taxes	(119		)	(152		)	(377		)	(451		)
Income tax benefit	33			61			102			180
Net of tax	$	(86	)	$	(91	)	$	(275	)	$	(271	)
Gains and losses on commodity contracts cash flow hedges:
Propane swap agreements (2)	$	(276	)	$	198		$	(921	)	$	663
Natural gas swaps (2)	123			1			(358		)	1
Natural gas futures (2)	(308		)	(852		)	(171		)	929
Total before income taxes	(461		)	(653		)	(1,450		)	1,593
Income tax benefit (expense)	129			248			407			(628		)
Net of tax	(332		)	(405		)	(1,043		)	965
Total reclassifications for the period	$	(418	)	$	(496	)	$	(1,318	)	$	694

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Employee Benefit Plans (Tables)

9 Months Ended

Sep. 30, 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 and nine months endedSeptember 30, 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 September 30,	2018			2017			2018			2017			2018		2017		2018			2017			2018		2017
(in thousands)
Interest cost	$	94		$	103		$	570		$	623		$	21	$	22	$	10		$	11		$	12	$	13
Expected return on plan assets	(131		)	(127		)	(770		)	(699		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(19		)	(19		)	—		—
Amortization of net loss	82			107			86			131			25		22		15			17			—		—
Net periodic cost (benefit) (1)	45			83			(114		)	55			46		44		6			9			12		13
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	45		$	83		$	77		$	246		$	46	$	44	$	6		$	9		$	14	$	15

	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Nine Months Ended September 30,	2018			2017			2018			2017			2018		2017		2018			2017			2018		2017
(in thousands)
Interest cost	$	288		$	309		$	1,754		$	1,870		$	63	$	66	$	29		$	31		$	38	$	38
Expected return on plan assets	(406		)	(381		)	(2,318		)	(2,098		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(58		)	(58		)	—		—
Amortization of net loss	258			319			302			392			75		65		45			50			—		—
Net periodic cost (benefit) (1)	140			247			(262		)	164			138		131		16			23			38		38
Amortization of pre-merger regulatory asset	—			—			571			571			—		—		—			—			6		6
Total periodic cost	$	140		$	247		$	309		$	735		$	138	$	131	$	16		$	23		$	44	$	44

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 September 30, 2018 and 2017:

For the Three Months Ended September 30, 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	82		86		25		15			—		208
Total recognized in net periodic benefit cost	82		86		25		(4		)	—		189
Recognized from accumulated other comprehensive loss (1)	82		16		25		(4		)	—		119
Recognized from regulatory asset	—		70		—		—			—		70
Total	$	82	$	86	$	25	$	(4	)	$	—	$	189

For the Three Months Ended September 30, 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		17			—		277
Total recognized in net periodic benefit cost	107		131		22		(2		)	—		258
Recognized from accumulated other comprehensive loss (1)	107		25		22		(2		)	—		152
Recognized from regulatory asset	—		106		—		—			—		106
Total	$	107	$	131	$	22	$	(2	)	$	—	$	258

For the Nine Months Ended September 30, 2018	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(58	)	$	—	$	(58	)
Net loss	258		302		75		45			—		680
Total recognized in net periodic benefit cost	258		302		75		(13		)	—		622
Recognized from accumulated other comprehensive loss (1)	258		57		75		(13		)	—		377
Recognized from regulatory asset	—		245		—		—			—		245
Total	$	258	$	302	$	75	$	(13	)	$	—	$	622

For the Nine Months Ended September 30, 2017	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(58	)	$	—	$	(58	)
Net loss	319		392		65		50			—		826
Total recognized in net periodic benefit cost	319		392		65		(8		)	—		768
Recognized from accumulated other comprehensive loss (1)	319		75		65		(8		)	—		451
Recognized from regulatory asset	—		317		—		—			—		317
Total	$	319	$	392	$	65	$	(8	)	$	—	$	768

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Investments (Tables)

9 Months Ended

Sep. 30, 2018

Investments, Debt and Equity Securities [Abstract]

Investments schedule [Table Text Block]

The investment balances at September 30, 2018 and December 31, 2017, consisted of the following:

(in thousands)	September 30, 2018		December 31, 2017
Rabbi trust (associated with the Deferred Compensation Plan)	$	7,929	$	6,734
Investments in equity securities	22		22
Total	$	7,951	6,756

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Share-Based Compensation (Tables)

9 Months Ended

Sep. 30, 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 and nine months endedSeptember 30, 2018 and 2017:

	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2018			2017			2018			2017
(in thousands)
Awards to non-employee directors	$	135		$	134		$	404		$	406
Awards to key employees	153			662			2,728			1,202
Total compensation expense	288			796			3,132			1,608
Less: tax benefit	(79		)	(320		)	(858		)	(647		)
Share-based compensation amounts included in net income	$	209		$	476		$	2,274		$	961

Awards to non-employee directors [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 non-employee directors for the nine months endedSeptember 30, 2018:

	Number of Shares		Weighted Average Fair Value
Outstanding—December 31, 2017	—		$	—
Granted	7,128		$	75.70
Vested	(7,128	)	$	75.70
Outstanding—September 30, 2018	—		$	—

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 nine months endedSeptember 30, 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
Vested - Accelerated pursuant to separation agreement (1)	(16,676	)	$	75.78
Expired	(3,933	)	$	49.66
Outstanding—September 30, 2018	131,741		$	67.43

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Derivative Instruments (Tables)

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Offsetting Assets and Liabilities [Table Text Block]

The following table summarizes the accounts receivable and payable on a gross and net basis at September 30, 2018 and December 31, 2017:

	At September 30, 2018
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	7,042	$	1,158	$	5,884
Accounts payable	$	11,264	$	1,158	$	10,106

	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

Schedule of Due to (from) Broker-Dealers and Clearing Organizations [Table Text Block]

The balances are as follows:

(in thousands)	Balance Sheet Location	At September 30, 2018		At December 31, 2017
Sharp	Other Current Liabilities	$	18	$	—
PESCO	Other Current Assets	$	2,060	$	6,300

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 September 30, 2018 and December 31, 2017, are as follows:

	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	September 30, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	—	$	13
Natural gas futures contracts	Derivative assets, at fair value	1,841		—
Derivatives designated as fair value hedges
Propane put options	Derivative assets, at fair value	19		—
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative assets, at fair value	8,114		92
Propane swap agreements	Derivative assets, at fair value	594		1,181
Total asset derivatives		$	10,568	$	1,286

	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	September 30, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative liabilities, at fair value	$	1,602	$	5,776
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative liabilities, at fair value	8,168		469
Natural gas swap contracts	Derivative liabilities, at fair value	—		2
Propane swap agreements	Derivative liabilities, at fair value	4		—
Total liability derivatives		$	9,774	$	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 September 30,						For the Nine Months Ended September 30,
(in thousands)	(Loss) on Derivatives	2018			2017			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	197			286			(2,766		)	907
Propane swap agreements	Cost of sales	—			15			(13		)	11
Natural gas swap contracts	Cost of sales	—			1			—			1
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	(276		)	198			(921		)	663
Propane swap agreements	Other comprehensive income (loss)	296			1,590			(590		)	814
Natural gas futures contracts	Cost of sales	(308		)	(852		)	(171		)	929
Natural gas swap contracts	Cost of sales	123			1			(358		)	1
Natural gas swap contracts	Other comprehensive income (loss)	(25		)	(413		)	563			(413		)
Natural gas futures contracts	Other comprehensive income (loss)	630			(1,296		)	(241		)	(1,420		)
Total		$	637		$	(470	)	$	(4,497	)	$	1,596

⁽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.

Schedule of Fair Value Hedging Instruments, Statements of Financial Performance and Financial Position, Location [Table Text Block]

As of September 30, 2018, the following amounts were recorded in the condensed consolidated balance sheets related to fair value hedges:

(in thousands)	Carrying Amount of Hedged Item				Cumulative Adjustment Included in Carrying Amount of Hedged Item
Balance Sheet Location of Hedged Items	At September 30, 2018		At December 31, 2017		At September 30, 2018		At December 31, 2017
Inventory	$	290	$	—	$	—	$	—

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Derivative Instruments Volume of Derivative Activity (Tables)

9 Months Ended

Sep. 30, 2018

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivative Instruments [Table Text Block]

Business unit	Commodity	Quantity hedged (in millions)	Designation	Longest Expiration date of hedge
PESCO	Natural gas (Dts)	22.1	Cash flows hedges	March 2022
PESCO	Natural gas (Dts)	1.1	Not designated	January 2020
Sharp	Propane (gallons)	4.4	Cash flows hedges	June 2021
Sharp	Propane (gallons)	0.3	Fair value hedges	March 2019

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Fair Value of Financial Instruments (Tables)

9 Months Ended

Sep. 30, 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 September 30, 2018 and December 31, 2017:

			Fair Value Measurements Using:
As of September 30, 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	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	679		—		—		679
Investments—mutual funds and other	7,250		7,250		—		—
Total investments	7,951		7,272		—		679
Derivative assets	10,568		—		10,568		—
Total assets	$	18,519	$	7,272	$	10,568	$	679
Liabilities:
Derivative liabilities	$	9,774	$	—	$	9,774	$	—

			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 nine months ended September 30, 2018 and 2017:

	Nine Months Ended   September 30,
	2018			2017
(in thousands)
Beginning Balance	$	648		$	561
Purchases and adjustments	64			76
Transfers	(29		)	—
Distribution	(12		)	(2		)
Investment income	8			7
Ending Balance	$	679		$	642

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Long-Term Debt (Tables)

9 Months Ended

Sep. 30, 2018

Debt Disclosure [Abstract]

Outstanding Long-Term Debt

Our outstanding long-term debt is shown below:

	September 30,			December 31,
(in thousands)	2018			2017
FPU secured first mortgage bonds (1) :
9.08% bond, due June 1, 2022	$	7,985		$	7,982
Uncollateralized senior notes:
5.50% note, due October 12, 2020	6,000			6,000
5.93% note, due October 31, 2023	16,500			18,000
5.68% note, due June 30, 2026	23,200			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
3.48% note, due May 31, 2038	50,000			—
Promissory notes	26			97
Capital lease obligation	987			2,070
Less: debt issuance costs	(488		)	(433		)
Total long-term debt	251,210			206,816
Less: current maturities	(9,613		)	(9,421		)
Total long-term debt, net of current maturities	$	241,597		$	197,395

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

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Summary of Accounting policies - Additional Information (Details) $ in Thousands	9 Months Ended
	Sep. 30, 2018 USD ($)
Summary of Accounting Policies [Abstract]
Cumulative Effect of New Accounting Principle in Period of Adoption	$ 1,700
Delay of Revenue Recognition Due To Implementation of New Standard	$ 305

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Summary of Accounting Policies Acquisitions Additional information (Details)	12 Months Ended
	Dec. 31, 2017 USD ($)	Sep. 30, 2018 USD ($)
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		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Item Effected [Line Items]
Accrued revenue	$ 12,352		$ 12,352		$ 22,279
Regulated Energy Operating Revenue	72,770	$ 69,703	252,667	$ 238,353
Regulated Energy cost of sales	21,501	22,794	89,741	87,206
Depreciation and amortization	10,633	9,362	30,176	27,267
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	7,595	11,157	53,510	52,804
Income taxes	2,057	4,324	14,731	20,781
Net Income	5,538	$ 6,833	38,779	$ 32,023	58,124
Other assets	5,293		5,293		3,699
Retained earnings	249,805		249,805		$ 229,141
Calculated under Revenue Guidance in Effect before Topic 606 [Member]
Item Effected [Line Items]
Accrued revenue	13,658		13,658
Regulated Energy Operating Revenue	72,879		253,659
Regulated Energy cost of sales	21,512		90,454
Depreciation and amortization	10,629		30,150
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	7,697		53,815
Income taxes	2,086		14,819
Net Income	5,611		38,996
Other assets	5,702		5,702
Retained earnings	251,520		251,520
Difference between Revenue Guidance in Effect before and after Topic 606 [Member]
Item Effected [Line Items]
Accrued revenue	(1,306)		(1,306)
Deferred Revenue, Period Increase (Decrease)	(109)		(992)
Regulated Energy cost of sales	(11)		(713)
Depreciation and amortization	4		26
Income (Loss) from Continuing Operations before Equity Method Investments, Income Taxes, Noncontrolling Interest	(102)		(305)
Income taxes	(29)		(88)
Net Income	(73)		(217)
Other assets	(409)		(409)
Retained earnings	$ (1,715)		$ (1,715)

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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		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Calculation of Basic Earnings Per Share:
Net Income	$ 5,538	$ 6,833	$ 38,779	$ 32,023	$ 58,124
Weighted shares outstanding (shares)	16,378,545	16,344,442	16,366,608	16,334,210
Basic Earnings Per Share (in dollars per share)	$ 0.34	$ 0.42	$ 2.37	$ 1.96
Reconciliation of Numerator:
Net Income	$ 5,538	$ 6,833	$ 38,779	$ 32,023	$ 58,124
Reconciliation of Denominator:
Weighted shares outstanding - Basic (shares)	16,378,545	16,344,442	16,366,608	16,334,210
Effect of dilutive securities:
Share-based compensation (shares)	49,894	45,193	49,647	44,423
Adjusted denominator-Diluted (shares)	16,428,439	16,389,635	16,416,255	16,378,633
Diluted Earnings Per Share (in dollars per share)	$ 0.34	$ 0.42	$ 2.36	$ 1.96

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Revenue Recognition Additional Information (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Revenues	$ 140,279,000	$ 126,936,000	$ 516,299,000	$ 437,180,000
Contract with Customer, Liability, Current	583,000		583,000		$ 407,000
Contract with Customer, Liability, Revenue Recognized	48,000		384,000
Regulated Energy [Member] | Other [Member]
Revenues	546,000		(399,000)
Unregulated Energy [Member] | Other [Member]
Revenues	$ 91,000		$ 246,000

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Revenue Recognition Disegragation of Revenue (Details) - USD ($) $ in Thousands		3 Months Ended	9 Months Ended
		Sep. 30, 2018	Sep. 30, 2018
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]	$ 140,279	$ 516,299
Consolidation, Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(18,601)	(69,688)
Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]	72,770	252,667
Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]	76,042	297,754
Other Segments And Intersegments Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(8,533)	(34,122)
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax	[1]	(8,533)	(34,122)
Other [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(2,709)	(10,204)
Eliminations [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(7,359)	(25,362)
Energy Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		60,536	223,271
Energy Distribution [Member] | Florida Natural Gas Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		6,282	18,462
Energy Distribution [Member] | Florida Public Utilities Company [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		17,390	58,885
Energy Distribution [Member] | Maryland Natural Gas [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		2,463	17,136
Energy Distribution [Member] | Delaware natural gas division [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		7,010	50,963
Energy Distribution [Member] | FPU Electric Distribution [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		23,830	60,933
Energy Distribution [Member] | Sandpiper [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3,561	16,892
Energy Transmission [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		25,343	78,440
Energy Transmission [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		19,593	54,758
Energy Transmission [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		5,750	23,682
Energy Transmission [Member] | Aspire [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		5,750	23,682
Energy Transmission [Member] | Eastern Shore Gas Company [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		16,189	46,289
Energy Transmission [Member] | Peninsula Pipeline [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		3,404	8,469
Energy Generation [Member] | Eight Flags [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		4,044	12,652
Propane Delivery [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		17,338	89,648
Propane Delivery [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		17,338	89,648
Propane Delivery [Member] | Delmarva Peninsula Propane Delivery [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		13,172	73,907
Propane Delivery [Member] | Florida Propane [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		4,166	15,741
Energy Services [Member] | PESCO [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		51,619	181,976
Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(19,212)	(71,684)
Eliminations [Member] | Regulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(7,359)	(25,362)
Eliminations [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(3,185)	(11,679)
Eliminations [Member] | Eliminations [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		(8,668)	(34,643)
Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		611	1,996
Other [Member] | Unregulated Energy [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		476	1,475
Other [Member] | Other [Member]
Disaggregation of Revenue [Line Items]
Revenue from Contract with Customer, Excluding Assessed Tax		$ 135	$ 521

[1] (1) Includes other revenue (revenues from sources other than contracts with customers) of $546,000 and $91,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.

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Revenue Recognition Contract Balances with Customers (Details) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Dec. 31, 2017
Revenue from Contract with Customer [Abstract]
Receivables from Customers	$ 50,937	$ 74,962
Contract with Customer, Asset, Net, Noncurrent	2,331	1,270
Contract with Customer, Liability, Current	583	$ 407
Increase (Decrease) in Receivables	(24,025)
Increase (Decrease) in Other Noncurrent Assets	1,061
Increase (Decrease) in Other Current Liabilities	$ 176

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Rates and Other Regulatory Activities - Additional Information (Detail)	9 Months Ended
	Sep. 30, 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	779,000
Public Utilities, Requested Rate Increase (Decrease), Amount	1.82
Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
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
Del-Mar Pathway Project [Domain] | Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Firm natural gas transportation deliverability | dekatherm / d	14,300
Del-Mar Pathway Project [Member] | Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Number of pipeline miles requested | mi	13
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
Pre TCJA approved revenue requirements [Member] | Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 9,800,000
Post TCJA approved revenue requirements [Member] | Eastern Shore [Member]
Rates and Other Regulatory Activities [Line Items]
Public Utilities, Approved Rate Increase (Decrease), Amount	$ 6,600,000

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Environmental Commitments and Contingencies - Additional Information (Detail)	9 Months Ended
	Sep. 30, 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	$ 7,941,000	$ 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	9,400,000
Approval of recovery of environmental costs	14,000,000
Environmental costs recovered	11,400,000
FPU [Member] | Manufactured Gas Plant [Member]
Environmental Commitments And Contingencies [Line Items]
Regulatory Assets for future recovery of environmental costs	$ 2,600,000

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Other Commitments and Contingencies - Additional Information (Detail) gal in Millions, $ in Millions	9 Months Ended
	Sep. 30, 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	1.8
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	$ 73.9
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		9 Months Ended		12 Months Ended
		Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Sep. 30, 2018 USD ($)	Sep. 30, 2017 USD ($)	Dec. 31, 2017 USD ($)
Segment Reporting Information [Line Items]
Number of Reportable Segments		2
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		$ 140,279	$ 126,936	$ 516,299	$ 437,180
Intersegment Revenues
Total operating revenues, unaffiliated customers		140,279	126,936	516,299	437,180
Operating Income
Total operating income		12,036	14,632	65,690	63,792
Other expense, net		(11)	(154)	(204)	(1,855)
Interest		4,430	3,321	11,976	9,133
Income Before Income Taxes		7,595	11,157	53,510	52,804
Income taxes		2,057	4,324	14,731	20,781
Net Income		5,538	6,833	38,779	32,023	$ 58,124
Identifiable Assets
Total identifiable assets		1,505,556		1,505,556		1,414,934
Regulated Energy [Member]
Operating Income
Total operating income		15,915	15,523	56,930	53,004
Identifiable Assets
Total identifiable assets		1,223,537		1,223,537		1,121,673
Unregulated Energy [Member]
Operating Income
Total operating income		(3,933)	(951)	10,241	10,626
Identifiable Assets
Total identifiable assets		244,390		244,390		259,041
Other [Member]
Identifiable Assets
Total identifiable assets		37,629		37,629		$ 34,220
Other and eliminations [Member]
Operating Income
Total operating income		54	60	(1,481)	162
Operating Revenues, Unaffiliated Customers [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		140,279	126,936	516,299	437,180
Intersegment Revenues
Total operating revenues, unaffiliated customers		140,279	126,936	516,299	437,180
Operating Revenues, Unaffiliated Customers [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		69,697	67,257	243,382	232,519
Intersegment Revenues
Total operating revenues, unaffiliated customers		69,697	67,257	243,382	232,519
Operating Revenues, Unaffiliated Customers [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers		70,582	59,679	272,917	204,661
Intersegment Revenues
Total operating revenues, unaffiliated customers		70,582	59,679	272,917	204,661
Intersegment Revenues [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	8,668	7,649	34,643	22,216
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	8,668	7,649	34,643	22,216
Intersegment Revenues [Member] | Regulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	3,073	2,446	9,285	5,834
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	3,073	2,446	9,285	5,834
Intersegment Revenues [Member] | Unregulated Energy [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	5,460	5,009	24,837	15,801
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	5,460	5,009	24,837	15,801
Intersegment Revenues [Member] | Other [Member]
Operating Revenues, Unaffiliated Customers
Total operating revenues, unaffiliated customers	[1]	135	194	521	581
Intersegment Revenues
Total operating revenues, unaffiliated customers	[1]	$ 135	$ 194	$ 521	$ 581

[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	9 Months Ended
	Sep. 30, 2018	Sep. 30, 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	(1,126)	313
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	1,318	(694)
Net current-period other comprehensive income (loss)	192	(381)
Ending balance	(4,987)	(5,259)
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	275	271
Net current-period other comprehensive income (loss)	275	262
Ending balance	(5,490)	(5,098)
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	(1,126)	322
Reclassification from Accumulated Other Comprehensive Income, Current Period, Net of Tax	1,043	(965)
Net current-period other comprehensive income (loss)	(83)	(643)
Ending balance	503	$ (161)
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		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Amortization of pension and postretirement items:
Tax benefit		$ (2,057)	$ (4,324)	$ (14,731)	$ (20,781)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Amortization of pension and postretirement items:
Net of tax		(418)	(496)	(1,318)	694
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	58	58
Net loss	[1]	(138)	(171)	(435)	(509)
Total before tax		(119)	(152)	(377)	(451)
Tax benefit		33	61	102	180
Net of tax		(86)	(91)	(275)	(271)
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		(461)	(653)	(1,450)	1,593
Tax benefit		129	248	407	(628)
Net of tax		(332)	(405)	(1,043)	965
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]	(276)	198	(921)	663
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]	123	1	(358)	1
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]	$ (308)	$ (852)	$ (171)	$ 929

[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	9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
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	$ 0	$ (10)	$ (10)

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Employee Benefit Plans (Detail) - USD ($) $ in Thousands		3 Months Ended		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plan Disclosure [Line Items]
Amortization of prior service cost		$ (19)	$ (19)	$ (58)	$ (58)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		208	277	680	826
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		10	11	29	31
Amortization of prior service cost		(19)	(19)	(58)	(58)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		15	17	45	50
Net periodic cost (benefit)	[1]	6	9	16	23
Total periodic cost		6	9	16	23
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		12	13	38	38
Net periodic cost (benefit)	[1]	12	13	38	38
Amortization of pre-merger regulatory asset		2	2	6	6
Total periodic cost		14	15	44	44
Florida Public Utilities Company Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		570	623	1,754	1,870
Expected return on plan assets		(770)	(699)	(2,318)	(2,098)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		86	131	302	392
Net periodic cost (benefit)	[1]	(114)	55	(262)	164
Amortization of pre-merger regulatory asset		191	191	571	571
Total periodic cost		77	246	309	735
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		21	22	63	66
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		25	22	75	65
Net periodic cost (benefit)	[1]	46	44	138	131
Total periodic cost		46	44	138	131
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Interest cost		94	103	288	309
Expected return on plan assets		(131)	(127)	(406)	(381)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		82	107	258	319
Net periodic cost (benefit)	[1]	45	83	140	247
Total periodic cost		$ 45	$ 83	$ 140	$ 247

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

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Employee Benefit Plans - Additional Information (Detail) - USD ($) $ in Thousands	3 Months Ended	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2018	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Expected pension and postretirement benefit costs		$ 856
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	$ 749	749	$ 1,300
Contribution to pension plan	123	971
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	1,500	1,500
Chesapeake Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan	235	433
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	359	359
Chesapeake Pension SERP [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan	38	113
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	151	151
Chesapeake Postretirement Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan		15
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	97	97
Florida Public Utilities Company Medical Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Contribution to pension plan	9	33
Defined Benefit Plan, Expected Future Employer Contributions, Remainder of Fiscal Year	$ 88	$ 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		9 Months Ended
		Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		$ (19)	$ (19)	$ (58)	$ (58)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		208	277	680	826
Recognized from accumulated other comprehensive loss	[1]	119	152	377	451
Recognized from regulatory asset		70	106	245	317
Total recognized in net periodic benefit cost		189	258	622	768
Chesapeake Pension Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		82	107	258	319
Recognized from accumulated other comprehensive loss	[1]	82	107	258	319
Total recognized in net periodic benefit cost		82	107	258	319
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)		86	131	302	392
Recognized from accumulated other comprehensive loss	[1]	16	25	57	75
Recognized from regulatory asset		70	106	245	317
Total recognized in net periodic benefit cost		86	131	302	392
Chesapeake Pension SERP [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		25	22	75	65
Recognized from accumulated other comprehensive loss	[1]	25	22	75	65
Total recognized in net periodic benefit cost		25	22	75	65
Chesapeake Postretirement Plan [Member]
Defined Benefit Plans and Other Postretirement Benefit Plans [Line Items]
Prior service cost (credit)		(19)	(19)	(58)	(58)
Defined Benefit Plan, Benefit Obligation, Actuarial Gain (Loss)		15	17	45	50
Recognized from accumulated other comprehensive loss	[1]	(4)	(2)	(13)	(8)
Total recognized in net periodic benefit cost		$ (4)	$ (2)	$ (13)	$ (8)

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

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Investments - Schedule of Investments (Details) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Investments schedule [Line Items]
Investments, at fair value	$ 7,951	$ 6,756
Rabbi Trust Associated With Deferred Compensation Plan [Member]
Investments schedule [Line Items]
Investments, at fair value	7,929	6,734
Equity Securities [Member]
Investments schedule [Line Items]
Investments, at fair value	$ 22	$ 22

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Investments - Additional Information (Detail) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Investments, Debt and Equity Securities [Abstract]
Unrealized gain (loss), net of other expenses	$ 313,000	$ 261,000	$ 426,000	$ 694,000

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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		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 288	$ 796	$ 3,132	$ 1,608
Less: tax benefit	(79)	(320)	(858)	(647)
Share-Based Compensation amounts included in net income	209	476	$ 2,274	961
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Grants in Period			792
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Total compensation expense	$ 135	134	$ 404	406
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value					$ 0.00
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value			$ 75.70
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period			7,128
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	131,741		131,741		132,642
Total compensation expense	$ 153	$ 662	$ 2,728	$ 1,202
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value	$ 67.43		$ 67.43		$ 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
Accelerated Vested Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost			$ 1,100
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Vested in Period, Weighted Average Grant Date Fair Value			$ 75.78

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Share-Based Compensation - Summary of Stock Activity under the SICP (Detail)	9 Months Ended
	Sep. 30, 2018 $ / shares shares
Number of Shares
Granted awards (shares)	792
Awards to non-employee directors [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Compensation Arrangement by Share-based Payment Award, Non-Option Equity Instruments, Granted	7,128
Number of Shares
Vested (shares)	(7,128)
Weighted Average Fair Value
Outstanding - December 31, 2017 (in dollars per share) | $ / shares	$ 0.00
Vested (in dollars per share) | $ / shares	$ 75.70
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 - September 30, 2018 (shares)	131,741
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 - September 30, 2018 (in dollars per share) | $ / shares	67.43
Accelerated Vested Shares [Member]
Weighted Average Fair Value
Vested (in dollars per share) | $ / shares	$ 75.78
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost	16,676
Accelerated Vested Shares [Member] | Award to key employees [Member]
Number of Shares
Expired (shares)	2,569
Weighted Average Fair Value
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost	14,107

XML

Share-Based Compensation - Additional Information (Detail) $ in Thousands	9 Months Ended		12 Months Ended
	Sep. 30, 2018 USD ($) unit shares	Sep. 30, 2017 USD ($)	Dec. 31, 2017 shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Granted awards (shares)	792
Shares Paid for Tax Withholding for Share Based Compensation	16,918		10,269
Payments Related to Tax Withholding for Share-based Compensation | $	$ 1,210	$ 692
Unrecognized compensation cost | $	$ 2,600
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 | $	$ 315
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, Forfeited in Period	2,569
Granted awards (shares)	49,494
Vesting period	3 years
Payments Related to Tax Withholding for Share-based Compensation | $	$ 719
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expired In Period	3,933
Intrinsic value of the SICP awards | $	$ 11,100
Accelerated Vested Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number Of Multi year Awards | unit	3
Share-based Compensation Arrangement by Share-based Payment Award, Accelerated Vesting, Number	16,676
Share-based Compensation Arrangement by Share-based Payment Award Accelerated Compensation Cost | $	$ 1,100
Accelerated Vested Shares [Member]
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Shares Paid for Tax Withholding for Share Based Compensation	10,436
Accelerated Vested Shares [Member] | 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, Accelerated Vesting, Number	14,107
Share Based Compensation Arrangement By Share Based Payment Award Equity Instruments Other Than Options Expired In Period	(2,569)

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Derivative Instruments - Additional Information (Detail) $ in Thousands, Mcf in Millions	9 Months Ended
	Sep. 30, 2018 USD ($) Mcf	Dec. 31, 2017 USD ($)
Derivative [Line Items]
Derivative, Amount of Hedged Item	$ 290	$ 0
Other Payables to Broker-Dealers and Clearing Organizations	18	0
Other Receivables from Broker-Dealers and Clearing Organizations	2,060	6,300
Accounts Receivable Subject to Master Netting Arrangement	1,158	2,391
Energy Marketing Contracts Assets, Current	10,568	1,286
Energy Marketing Contract Liabilities, Current	(9,774)	(6,247)
Accounts Payable Subject To Master Netting Arrangement	1,158	2,391
Put Option [Member]
Derivative [Line Items]
Derivative, Cost of Hedge	28
Hedging Liability [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	(8,168)	(469)
Hedging Liability [Member] | Natural Gas Swaps [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	0	(2)
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Put Option [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	19	0
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	8,114	92
Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	594	1,181
Designated as Hedging Instrument [Member] | Mark-to-market energy liabilities [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contract Liabilities, Current	$ (4)	0
Not Designated as Hedging Instrument [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | Mcf	1.1
Not Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	$ 1,841
Not Designated as Hedging Instrument [Member] | Mark To Market Energy Assets [Member] | Propane Swap Agreement [Member]
Derivative [Line Items]
Energy Marketing Contracts Assets, Current	0	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	$ (1,602)	(5,776)
PESCO [Member] | Natural Gas Futures [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | Mcf	22.1
Gross [Member]
Derivative [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	$ 7,042	8,283
Accounts Payable Subject To Master Netting Arrangement	11,264	16,643
Net [Member]
Derivative [Line Items]
Accounts Receivable Subject to Master Netting Arrangement	5,884	5,892
Accounts Payable Subject To Master Netting Arrangement	$ 10,106	$ 14,252

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Derivative Instruments - Fair Values of Derivative Contracts Recorded in Condensed Consolidated Balance Sheet (Detail) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	$ 10,568	$ 1,286
Mark To Market Energy Assets [Member] | Natural Gas Futures [Member] | Derivatives not designated as hedging instruments [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	1,841
Mark To Market Energy Assets [Member] | Natural Gas Futures [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	8,114	92
Mark To Market Energy Assets [Member] | Put Option [Member] | Derivatives designated as hedging instrument [Member]
Derivatives, Fair Value [Line Items]
Energy Marketing Contracts Assets, Current	19	0
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	0	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	$ 594	$ 1,181

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Derivative Instruments - Effects of Gains and Losses from Derivative Instruments on Condensed Consolidated Financial Statements (Detail) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018		Sep. 30, 2017
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	$ 637,000	$ (470,000)	$ (4,497,000)		$ 1,596,000
Revenue [Member] | Derivatives not designated as hedging instruments [Member] | Forward Contracts [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net		0	0	[1]	112,000	[1]
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	197,000	286,000	(2,766,000)		907,000
Cost of Sales [Member] | Derivatives not designated as hedging instruments [Member] | Natural Gas Swaps [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	1,000	0		1,000
Cost of Sales [Member] | Derivatives not designated as hedging instruments [Member] | Propane Swap Agreement [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	0	15,000	(13,000)		11,000
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Future [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	(308,000)	(852,000)	(171,000)		929,000
Cost of Sales [Member] | Derivatives designated as hedging instrument [Member] | Swap [Member]
Derivative Instruments, Gain (Loss) [Line Items]
Derivative, Gain (Loss) on Derivative, Net	123,000	1,000	(358,000)		1,000
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	(276,000)	198,000	(921,000)		663,000
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		0	0	[2]	(9,000)	[2]
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	(25,000)	(413,000)	563,000		(413,000)
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	296,000	1,590,000	(590,000)		814,000
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	$ 630,000	$ (1,296,000)	$ (241,000)		$ (1,420,000)

[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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Derivative Instruments Volume of Derivative Activity (Details) $ in Thousands, gal in Millions	9 Months Ended
	Sep. 30, 2018 USD ($) gal
PESCO [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $	$ (570)
Sharp Energy Inc [Member]
Derivative [Line Items]
Cash Flow Hedge Gain (Loss) to be Reclassified within Twelve Months | $	$ 392
Sharp Energy Inc [Member] | Swap [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal	4.4
Sharp Energy Inc [Member] | Put Option [Member]
Derivative [Line Items]
Derivative, Nonmonetary Notional Amount, Volume | gal	0.3

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Fair Value of Financial Instruments - Financial Assets and Liabilities Measured at Fair Value on Recurring Basis (Detail) - USD ($) $ in Thousands	Sep. 30, 2018	Dec. 31, 2017
Assets:
Investments	$ 7,951	$ 6,756
Liabilities:
Energy Marketing Contract Liabilities, Current	9,774	6,247
Equity Securities [Member]
Assets:
Investments	22	22
Quoted Prices in Active Markets (Level 1) [Member]
Assets:
Assets, Fair Value Disclosure	7,272	6,108
Quoted Prices in Active Markets (Level 1) [Member] | Equity Securities [Member]
Assets:
Investments	22	22
Quoted Prices in Active Markets (Level 1) [Member] | Investments - Mutual funds and other [Member]
Assets:
Investments	7,250	6,086
Quoted Prices in Active Markets (Level 1) [Member] | Total Investments [Member]
Assets:
Investments	7,272	6,108
Significant Other Observable Inputs (Level 2) [Member]
Assets:
Assets, Fair Value Disclosure	10,568	1,286
Liabilities:
Energy Marketing Contract Liabilities, Current	9,774	6,247
Significant Other Observable Inputs (Level 2) [Member] | Mark To Market Energy Assets incl. natural gas and swap agreements[Member]
Assets:
Derivative assets	10,568	1,286
Significant Unobservable Inputs (Level 3) [Member]
Assets:
Assets, Fair Value Disclosure	679	648
Significant Unobservable Inputs (Level 3) [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	679	648
Significant Unobservable Inputs (Level 3) [Member] | Total Investments [Member]
Assets:
Investments	679	648
Recurring [Member]
Assets:
Assets, Fair Value Disclosure	18,519	8,042
Liabilities:
Energy Marketing Contract Liabilities, Current	9,774	6,247
Recurring [Member] | Equity Securities [Member]
Assets:
Investments	22	22
Recurring [Member] | Investments in guaranteed income fund [Member]
Assets:
Investments	679	648
Recurring [Member] | Investments - Mutual funds and other [Member]
Assets:
Investments	7,250	6,086
Recurring [Member] | Total Investments [Member]
Assets:
Investments	7,951	6,756
Recurring [Member] | Mark To Market Energy Assets incl. natural gas and swap agreements[Member]
Assets:
Derivative assets	$ 10,568	$ 1,286

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Fair Value of Financial Instruments - Summary of Changes in Fair Value of Investments (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Beginning Balance	$ 648	$ 561
Purchases and adjustments	64	76
Transfers	29	0
Fair Value, Measurement with Unobservable Inputs Reconciliation, Recurring Basis, Asset, Sales	(12)	(2)
Investment Income	8	7
Ending Balance	$ 679	$ 642

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Fair Value of Financial Instruments - Additional Information (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Long-term debt including current maturities	$ 250.7	$ 205.2
Fair value of long-term debt	$ 248.9	$ 215.4

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Long-Term Debt - Outstanding Long-Term Debt (Detail) - USD ($) $ in Thousands		Sep. 30, 2018	Mar. 31, 2018	Dec. 31, 2017
Debt Instrument [Line Items]
Total long-term debt		$ 250,700		$ 205,200
Capital lease obligation		987		2,070
Total Long-term debt		251,210		206,816
Less: current maturities		(9,613)		(9,421)
Less: debt issuance costs		(488)		(433)
Total long-term debt, net of current maturities		241,597		197,395
9.08% bond, due June 1, 2022 [Member]
Debt Instrument [Line Items]
Total long-term debt	[1]	7,985		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		16,500		18,000
5.68% note, due June 30, 2026 [Member]
Debt Instrument [Line Items]
Total long-term debt		23,200		26,100
6.43% note, due May 2, 2028 [Member]
Debt Instrument [Line Items]
Total long-term debt		7,000		7,000
3.73% note, due December 16, 2028 [Member]
Debt Instrument [Line Items]
Total long-term debt		20,000		20,000
3.88% note, due May 15, 2029 [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
3.48% note, due May 31, 2038 [Member]
Debt Instrument [Line Items]
Total long-term debt		50,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Total long-term debt			$ 25,000
Promissory note [Member]
Debt Instrument [Line Items]
Total long-term debt		$ 26		$ 97

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

XML

Long-Term Debt - Outstanding Long-Term Debt- Supplemental Information (Detail)	9 Months Ended
	Sep. 30, 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
6.43% note, due May 2, 2028 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	6.43%
Debt instrument, maturity date	May 02, 2028
3.73% note, due December 16, 2028 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.73%
Debt instrument, maturity date	Dec. 16, 2028
3.88% note, due May 15, 2029 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.88%
Debt instrument, maturity date	May 15, 2029
3.25% due April 30, 2032 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.25%
Debt instrument, maturity date	Apr. 30, 2032
3.48% note, due May 31, 2038 [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage	3.48%
Debt instrument, maturity date	May 31, 2038
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term debt, interest percentage
Debt instrument, maturity date

XML

Long-Term Debt - Additional Information (Detail) - USD ($) $ in Thousands	9 Months Ended
	Sep. 30, 2018	Mar. 31, 2018	Dec. 31, 2017	Nov. 30, 2017
Debt Instrument [Line Items]
Document Period End Date	Sep. 30, 2018
Long-term debt including current maturities	$ 250,700		$ 205,200
Debt Instrument, Unused Borrowing Capacity, Amount	$ 200,000
Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities		$ 25,000
Debt Instrument, Interest Rate, Stated Percentage
3.48% note, due May 31, 2038 [Member]
Debt Instrument [Line Items]
Long-term debt including current maturities	$ 50,000
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] | Senior Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.48%
Shelf Notes [Member]
Debt Instrument [Line Items]
Debt Instrument, Interest Rate, Stated Percentage	3.98%
Prudential [Member]
Debt Instrument [Line Items]
Senior notes	$ 100,000
Debt Instrument, Unused Borrowing Capacity, Amount	50,000
Prudential [Member] | Notes Payable, Other Payables [Member] | Shelf Notes [Member]
Debt Instrument [Line Items]
Senior notes	$ 150,000
Debt Instrument, Interest Rate, Stated Percentage	3.25%
Prudential [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
Debt Instrument, Unused Borrowing Capacity, Amount	$ 150,000
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
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%