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, 2017~~March 31, 2018



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

For the transition period from to

Commission File Number: 001-11590




CHESAPEAKE UTILITIES CORPORATION (Exact name of registrant as specified in its charter)



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

909 Silver Lake Boulevard, Dover, Delaware 19904

(Address of principal executive offices, including Zip Code)

(302) 734-6799

(Registrant’s telephone number, including area code)

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

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

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



Large accelerated filer	x	Accelerated filer	¨

Non-accelerated filer	¨	Smaller reporting company	¨

		Emerging growth company	¨

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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 — ~~16,344,442~~16,363,792 shares outstanding as of ~~October 31, 2017~~.April 30, 2018.

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PART I—FINANCIAL INFORMATION		1

ITEM 1.	FINANCIAL STATEMENTS	1

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	2831

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	5048

ITEM 4.	CONTROLS AND PROCEDURES	5149

PART II—OTHER INFORMATION		5250

ITEM 1.	LEGAL PROCEEDINGS	5250

ITEM 1A.	RISK FACTORS	5250

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	5250

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	5250

ITEM 5.	OTHER INFORMATION	5250

ITEM 6.	EXHIBITS	5351

SIGNATURES		5452

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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

~~ASU:~~ ~~Accounting Standards Update~~ issued by the FASB

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

ASU: Accounting Standards Update issued by the FASB

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

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

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

CGC: Consumer Gas Cooperative, an Ohio natural gas cooperative

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

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

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

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

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

CHP: Combined heat and power plant

CIAC: Contributions from customers that are used to construct facilities

~~CGC: Consumer Gas Cooperative, an Ohio natural gas cooperative~~

~~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

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

DNREC: Delaware Department of Natural Resources and Environmental Control

DSR: Delivery Service Rate

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

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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

~~Table of Contents~~

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

~~FDEP:~~ ~~Florida Department of Environmental Protection~~

FGT: Florida Gas Transmission Company

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

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

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

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

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

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

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

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

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

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

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

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

MDE: Maryland Department of Environment

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

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

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

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

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

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

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

NYL Shelf Agreement: An agreement entered into by Chesapeake Utilities and NYL ~~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

~~Table of Contents~~
NYL Shelf Notes:

Unsecured senior promissory notes issuable under the NYL Shelf Agreement

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

OTC: Over-the-counter

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

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

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

Prudential: Prudential Investment Management Inc., an institutional investment management firm, with which we have entered into the Prudential Shelf Agreement

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

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

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

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

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

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

Revolver: Our unsecured revolving credit facility with the Lenders

~~Rights Plan:~~ ~~A plan designed to protect against abusive or coercive takeover attempts or tactics that are contrary to the best interests of Chesapeake Utilities' stockholders~~

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

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

SEC: Securities and Exchange Commission

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

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

SICP: 2013 Stock and Incentive Compensation Plan

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

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

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

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

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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						Three Months Ended
	September 30,					September 30,						March 31,
	2017		2016			2017			2016			2018		2017
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	69,703	$	70,019		$	238,353		$	226,630		$	109,393	$	97,654
Unregulated Energy and other	57,233		38,329			198,827			130,356			129,963		87,506
Total Operating Revenues	126,936		108,348			437,180			356,986			239,356		185,160
Operating Expenses
Regulated Energy cost of sales	22,794		24,644			87,206			81,184			48,231		40,244
Unregulated Energy and other cost of sales	44,066		28,183			145,325			85,142			99,826		60,754
Operations	29,667		30,126			92,990			85,370			32,702		32,490
Maintenance	2,737		3,542			9,370			8,925			3,593		3,231
Gain from a settlement	—		—			(130		)	(130		)
Depreciation and amortization	9,362		8,209			27,267			23,493			9,704		8,812
Other taxes	4,071		3,488			12,572			10,725			4,894		4,530
Total Operating Expenses	112,697		98,192			374,600			294,709			198,950		150,061
Operating Income	14,239		10,156			62,580			62,277			40,406		35,099
Other income (expense), net	239		(28		)	(643		)	(68		)	68		(700		)
Interest charges	3,321		2,722			9,133			7,996			3,664		2,739
Income Before Income Taxes	11,157		7,406			52,804			54,213			36,810		31,660
Income taxes	4,324		2,990			20,781			21,401			9,955		12,516
Net Income	$	6,833	$	4,416		$	32,023		$	32,812		$	26,855	$	19,144
Weighted Average Common Shares Outstanding:
Basic	16,344,442		15,372,413			16,334,210			15,324,932			16,351,338		16,317,224
Diluted	16,389,635		15,412,783			16,378,633			15,365,955			16,402,985		16,363,796
Earnings Per Share of Common Stock:
Basic	$	0.42	$	0.29		$	1.96		$	2.14		$	1.64	$	1.17
Diluted	$	0.42	$	0.29		$	1.96		$	2.14		$	1.64	$	1.17
Cash Dividends Declared Per Share of Common Stock	$	0.3250	$	0.3050		$	0.9550		$	0.8975		$	0.3250	$	0.3050

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2017			2016			2017			2016			2018			2017
(in thousands)
Net Income	$	6,833		$	4,416		$	32,023		$	32,812		$	26,855		$	19,144
Other Comprehensive (Loss) Income, net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(8), $(8), $(23) and $(23), respectively	(11		)	(12		)	(35		)	(37		)
Net gain, net of tax of $69, $66, $212 and $200, respectively	102			100			297			300
Amortization of prior service cost, net of tax of $(5) and $(8), respectively													(14		)	(11		)
Net gain, net of tax of $41 and $77, respectively													108			93
Cash Flow Hedges, net of tax:
Unrealized (loss)/gain on commodity contract cash flow hedges, net of tax of $(15), $38, $(376) and $360, respectively	(104		)	51			(643		)	548
Total Other Comprehensive (Loss) Income	(13		)	139			(381		)	811
Unrealized (loss)/gain on commodity contract cash flow hedges, net of tax of ($756) and $192, respectively													(1,788		)	338
Total Other Comprehensive (Loss) Income, net of tax													(1,694		)	420
Comprehensive Income	$	6,820		$	4,555		$	31,642		$	33,623		$	25,161		$	19,564

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)


Assets	September 30, 2017			December 31, 2016			March 31, 2018			December 31, 2017
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	1,050,332		$	957,681		$	1,083,004		$	1,073,736
Unregulated Energy	207,331			196,800			213,803			210,682
Other businesses and eliminations	26,061			21,114			27,892			27,699
Total property, plant and equipment	1,283,724			1,175,595			1,324,699			1,312,117
Less: Accumulated depreciation and amortization	(267,138		)	(245,207		)	(279,802		)	(270,599		)
Plus: Construction work in progress	69,053			56,276			131,640			84,509
Net property, plant and equipment	1,085,639			986,664			1,176,537			1,126,027
Current Assets
Cash and cash equivalents	3,386			4,178			5,996			5,614
Accounts receivable (less allowance for uncollectible accounts of $912 and $909, respectively)	52,775			62,803
Trade and other receivables (less allowance for uncollectible accounts of $901 and $936, respectively)							69,447			77,223
Accrued revenue	14,307			16,986			18,907			22,279
Propane inventory, at average cost	5,226			6,457			7,345			8,324
Other inventory, at average cost	12,711			4,576			4,607			12,022
Regulatory assets	9,761			7,694			10,833			10,930
Storage gas prepayments	6,876			5,484			1,197			5,250
Income taxes receivable	26,741			22,888			4,378			14,778
Prepaid expenses	10,899			6,792			8,199			13,621
Derivative assets, at fair value	1,526			823			208			1,286
Other current assets	4,797			2,470			6,717			7,260
Total current assets	149,005			141,151			137,834			178,587
Deferred Charges and Other Assets
Goodwill	21,944			15,070			22,104			22,104
Other intangible assets, net	4,608			1,843			4,482			4,686
Investments, at fair value	6,380			4,902			6,641			6,756
Regulatory assets	75,793			76,803			75,536			75,575
Receivables and other deferred charges	3,381			2,786
Other assets							4,316			3,699
Total deferred charges and other assets	112,106			101,404			113,079			112,820
Total Assets	$	1,346,750		$	1,229,219		$	1,427,450		$	1,417,434

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)


Capitalization and Liabilities	September 30, 2017			December 31, 2016			March 31, 2018			December 31, 2017
(in thousands, except shares and per share data)
Capitalization
Stockholders’ equity
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding	$	—		$	—		$	—		$	—
Common stock, par value $0.4867 per share (authorized 25,000,000 shares)	7,955			7,935
Common stock, par value $0.4867 per share (authorized 50,000,000 shares)							7,964			7,955
Additional paid-in capital	252,722			250,967			254,126			253,470
Retained earnings	208,402			192,062			250,024			229,141
Accumulated other comprehensive loss	(5,259		)	(4,878		)	(6,873		)	(4,272		)
Deferred compensation obligation	3,366			2,416			3,573			3,395
Treasury stock	(3,366		)	(2,416		)	(3,573		)	(3,395		)
Total stockholders’ equity	463,820			446,086			505,241			486,294
Long-term debt, net of current maturities	201,248			136,954			222,014			197,395
Total capitalization	665,068			583,040			727,255			683,689
Current Liabilities
Current portion of long-term debt	12,136			12,099			9,389			9,421
Short-term borrowing	203,098			209,871			229,108			250,969
Accounts payable	53,284			56,935			57,457			74,688
Customer deposits and refunds	32,493			29,238			34,795			34,751
Accrued interest	3,361			1,312			3,256			1,742
Dividends payable	5,312			4,973			5,318			5,312
Accrued compensation	8,544			10,496			5,444			13,112
Regulatory liabilities	5,338			1,291			18,503			6,485
Derivative liabilities, at fair value	1,732			773			2,359			6,247
Other accrued liabilities	13,972			7,063			8,694			10,273
Total current liabilities	339,270			334,051			374,323			413,000
Deferred Credits and Other Liabilities
Deferred income taxes	252,273			222,894			141,484			135,850
Regulatory liabilities	42,915			43,064			141,346			140,978
Environmental liabilities	8,382			8,592			8,215			8,263
Other pension and benefit costs	32,059			32,828			28,981			29,699
Deferred investment tax credits and other liabilities	6,783			4,750			5,846			5,955
Total deferred credits and other liabilities	342,412			312,128			325,872			320,745
Environmental and other commitments and contingencies (Note 4 and 5)
Environmental and other commitments and contingencies (Note 5 and 6)
Total Capitalization and Liabilities	$	1,346,750		$	1,229,219		$	1,427,450		$	1,417,434

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)


	Nine Months Ended						Three Months Ended
	September 30,						March 31,
	2017			2016			2018			2017
(in thousands)
Operating Activities
Net income	$	32,023		$	32,812		$	26,855		$	19,144
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	27,267			23,493			9,704			8,812
Depreciation and accretion included in other costs	5,989			5,357			2,276			1,939
Deferred income taxes	29,520			12,004			6,469			7,849
Realized gain on commodity contracts/sale of assets/investments	(2,817		)	(405		)	3,416			1,330
Unrealized gain on investments/commodity contracts	(695		)	(243		)
Unrealized loss on investments/commodity contracts							44			132
Employee benefits and compensation	1,212			1,217			228			423
Share-based compensation	1,608			1,887			1,520			639
Other, net	(39		)	42			(12		)	(4		)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	12,912			(3,835		)	9,649			5,095
Propane inventory, storage gas and other inventory	(8,256		)	(2,179		)	12,448			6,688
Regulatory assets/liabilities, net	927			(3,326		)	11,511			6,103
Prepaid expenses and other current assets	(2,860		)	485			8,095			1,136
Accounts payable and other accrued liabilities	4,515			7,187			(26,932		)	(5,897		)
Income taxes (payable) receivable	(3,810		)	14,897
Income taxes receivable							8,741			9,500
Customer deposits and refunds	3,255			(314		)	44			400
Accrued compensation	(2,030		)	(2,293		)	(7,731		)	(4,966		)
Other assets and liabilities, net	(349		)	(1,053		)	347			1,631
Net cash provided by operating activities	98,372			85,733			66,672			59,954
Investing Activities
Property, plant and equipment expenditures	(130,137		)	(109,589		)	(63,116		)	(42,172		)
Proceeds from sales of assets	601			119			193			36
Acquisitions, net of cash acquired	(11,707		)	—
Environmental expenditures	(210		)	(260		)	(48		)	(57		)
Net cash used in investing activities	(141,453		)	(109,730		)	(62,971		)	(42,193		)
Financing Activities
Common stock dividends	(14,780		)	(12,964		)	(5,147		)	(4,815		)
Issuance of stock for Dividend Reinvestment Plan	254			600
Stock issuance	(10		)	57,306
(Purchase) issuance of stock under the Dividend Reinvestment Plan							(164		)	222
Tax withholding payments related to net settled stock compensation	(692		)	(770		)	(719		)	(692		)
Change in cash overdrafts due to outstanding checks	(3,013		)	2,466			2,352			587
Net repayment under line of credit agreements	(3,760		)	(21,379		)
Proceeds from issuance of long-term debt	69,800			—
Repayment of long-term debt and capital lease obligation	(5,510		)	(2,581		)
Net cash provided by financing activities	42,289			22,678
Net Decrease in Cash and Cash Equivalents	(792		)	(1,319		)
Net repayment under line of credit agreements and short-term borrowing under the Revolver							(24,213		)	(11,125		)
Proceeds from long-term debt under the Revolver							25,000			—
Repayment of long term debt and capital lease obligation							(428		)	(416		)
Net cash used in financing activities							(3,319		)	(16,239		)
Net Increase in Cash and Cash Equivalents							382			1,522
Cash and Cash Equivalents—Beginning of Period	4,178			2,855			5,614			4,178
Cash and Cash Equivalents—End of Period	$	3,386		$	1,536		$	5,996		$	5,700

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

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)


	Common Stock ⁽¹⁾																				Common Stock ⁽¹⁾
(in thousands, except shares and per share data)	Number of Shares⁽²⁾	Par Value		Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Loss			Deferred Compensation		Treasury Stock			Total ⁽²⁾			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, 2015	15,270,659	$	7,432	$	190,311		$	166,235		$	(5,840	)	$	1,883	$	(1,883	)	$	358,138
Balance at December 31, 2016																					16,303,499	$	7,935	$	250,967		$	192,062		$	(4,878	)	$	2,416	$	(2,416	)	$	446,086
Net income	—	—		—			44,675			—			—		—			44,675			—	—		—			58,124			—			—		—			58,124
Other comprehensive income	—	—		—			—			962			—		—			962			—	—		—			—			606			—		—			606
Dividend declared ($1.2025 per share)	—	—		—			(18,848		)	—			—		—			(18,848		)
Retirement savings plan and dividend reinvestment plan	36,253	17		2,225			—			—			—		—			2,242
Dividend declared ($1.28 per share)																					—	—		—			(21,045		)	—			—		—			(21,045		)
Dividend reinvestment plan																					10,771	5		730			—			—			—		—			735
Stock issuance ⁽³⁾	960,488	467		56,893			—			—			—		—			57,360			—	—		(10		)	—			—			—		—			(10		)
Share-based compensation and tax benefit ^{(4) (5)}	36,099	19		1,538			—			—			—		—			1,557
Share-based compensation and tax benefit ⁽³⁾⁽⁴⁾																					30,172	15		1,783			—			—			—		—			1,798
Treasury stock activities	—	—		—			—			—			533		(533		)	—			—	—		—			—			—			979		(979		)	—
Balance at December 31, 2016	16,303,499	7,935		250,967			192,062			(4,878		)	2,416		(2,416		)	446,086
Balance at December 31, 2017																					16,344,442	7,955		253,470			229,141			(4,272		)	3,395		(3,395		)	486,294
Net income	—	—		—			32,023			—			—		—			32,023			—	—		—			26,855			—			—		—			26,855
Cumulative effect of the adoption of ASU 2014-09																					—	—		—			(1,498		)	—			—		—			(1,498		)
Reclassification upon the adoption of ASU 2018-02																					—	—		—			907			(907		)	—		—			—
Other comprehensive loss	—	—		—			—			(381		)	—		—			(381		)	—	—		—			—			(1,694		)	—		—			(1,694		)
Dividend declared ($0.9550 per share)	—	—		—			(15,683		)	—			—		—			(15,683		)
Dividend declared ($0.3250 per share)																					—	—		—			(5,381		)	—			—		—			(5,381		)
Dividend reinvestment plan	10,771	5		731			—			—			—		—			736			—	—		(1		)	—			—			—		—			(1		)
Stock issuance	—	—		(10		)	—			—			—		—			(10		)
Share-based compensation and tax benefit ⁽⁴⁾ ⁽⁵⁾	30,172	15		1,034			—			—			—		—			1,049
Share-based compensation and tax benefit ⁽³⁾ ⁽⁴⁾																					19,350	9		657			—			—			—		—			666
Treasury stock activities	—	—		—			—			—			950		(950		)	—			—	—		—			—			—			178		(178		)	—
Balance at September 30, 2017	16,344,442	$	7,955	$	252,722		$	208,402		$	(5,259	)	$	3,366	$	(3,366	)	$	463,820
Balance at March 31, 2018																					16,363,792	$	7,964	$	254,126		$	250,024		$	(6,873	)	$	3,573	$	(3,573	)	$	505,241


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


⁽²⁾	Includes ~~90,588~~93,422 and ~~76,745~~90,961 shares at ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.


⁽³⁾	~~On September 22, 2016, we completed a public offering of 960,488~~Includes amounts for shares ~~of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million.~~issued for directors’ compensation.


⁽⁴⁾	~~Includes amounts for shares issued for Directors’ compensation.~~


⁽⁵⁾	The shares issued under the SICP are net of shares withheld for employee taxes. For the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2018, and for the year ended December 31, ~~2016~~,2017, we withheld ~~10,269~~10,436 and ~~12,031~~10,269 shares, respectively, for taxes.

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

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NOTES TO 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, ~~2016.~~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.

We reclassified certain amounts in the condensed consolidated statement of cash flows for the nine months ended September 30, 2016 to conform to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

ARM, Chipola and Central Gas Asset Acquisitions

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

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

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

The revenue and net income from these acquisitions that wewere included in our condensed consolidated statements of income for the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2018, were not material. The amounts recorded in conjunction with our acquisitions are preliminary and subject to adjustment based on additional valuations performed during the measurement period.

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

~~Inventory (ASC 330) - In July 2015, the FASB issued ASU 2015-11,~~ ~~Simplifying the Measurement of Inventory.~~ Under this guidance, inventories are required to be measured at the lower of cost or net realizable value. Net realizable value represents the estimated selling price less costs associated with completion, disposal and transportation. We adopted ASU 2015-11 on January 1, 2017, on a prospective basis. Adoption of this standard did not have a material impact on our financial position or results of operations.

~~Table of Contents~~

~~Recent Accounting Standards Yet to be Adopted~~

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

This standard ~~provides a single comprehensive revenue recognition model for all contracts with customers~~requires entities to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. The underlying principle is that an entity will recognize revenue ~~to depict~~when control of the ~~transfer of~~promised goods or services is transferred to customers at an amount that reflects the consideration to which the entity expects to ~~be entitled 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. ~~In March 2016, FASB issued ASU 2016-08,~~See Note 3, ~~Principal versus Agent Considerations (Reporting~~ Revenue ~~Gross versus Net)~~Recognition, ~~, to clarify the implementation guidance on principal versus agent considerations. For public entities, this standard is effective~~ for ~~interim and annual financial statements issued beginning January 1, 2018.~~additional information.

~~We have completed our evaluation~~

Table of ~~our revenue sources and will continue assessing~~Contents

The following highlights the impact ~~on our financial position, results~~ of operations and cash flows during the fourth quarter of 2017. In tandem, we have developed and documented accounting policies and position papers, which are intended to meet the requirements of this new revenue recognition standard. We have also completed our plan to update our internal controls. In the third quarter of 2017, we began providing additional training to our employees and implementing system and process changes that are associated with the adoption of ASC 606 on our condensed consolidated income statement and condensed consolidated balance sheet for the ~~standard. We plan to utilize~~three months ended March 31, 2018:



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



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

Capitalization
Retained earnings	$	250,024	$	251,522	$	(1,498	)

The primary impact of the ~~modified retrospective transition method upon~~ adoption of ~~this standard.~~

~~Based~~ASC 606 on our ~~current assessment, we believe that~~income statement was the ~~implementation of this new standard will not have a material impact on the amount and timing of revenue~~delayed recognition ~~except for one long-term contract for which we will delay the recognition of revenue~~ of approximately $407,000 in ~~2018. Since we have not yet finalized our assessment, we will continue~~annual revenue from 2018 to ~~monitor and subsequently disclose~~ future identified material impacts, if any, in our annual report on Form 10-K for the year ended December 31, 2017. In addition, the AICPA Power and Utilities Industry Task Force is addressing issues specific to our industry, including CIAC, and has concluded that CIAC is outside of the scope of this standard; accordingly, our Regulated Energy segment accounting for CIAC will not change as a result of ASC 606.

~~Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02,~~ ~~Leases,~~ ~~which provides updated guidance regarding accounting for leases. This update requires a lessee to recognize a lease liability~~years and a ~~lease asset for all leases, including operating leases,~~cumulative adjustment that decreased retained earnings and other assets by $1.5 million, associated with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted.

We have assessed all of our leases and have concluded that a majority of our operating leases would continue to fall within the category of operating leases; however, we may have some leases that qualify for the short-term lease exception. We will record the right to use of assets and the lease liability related to the operating leases, but we do not believe that this will have a material impact on our financial position, results of operations and cash flows. During the fourth quarter of 2017, we intend to quantify the overall impact that may result from early adoption of the standard and implementation of the overall process. This guidance will be applied using the modified retrospective transition method for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements.

~~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. ASU 2016-15 will be effective for our annual and interim financial statements beginning January 1, 2018, although early adoption is permitted. We believe that the implementation of this new standard will not have a material impact on our statement of cash flows.

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

Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update allows for capitalization of the service cost component when applicable. We adopted ASU 2017-07 ~~will be effective for our annual and interim financial statements beginning~~on January 1, 2018 ~~although early adoption is permitted. The~~and applied the changes in the presentation of the service cost and other components ~~in this update are to be applied retrospectively, and the~~

~~Table~~ of ~~Contents~~

~~capitalization of the service cost is to be applied prospectively on or after the effective date.~~net benefit costs, retrospectively. Aside from changes in presentation, ~~we believe that~~ the implementation of this ~~new~~ standard ~~will~~did not have a material impact on our financial position or results of operations.

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

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

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

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

Recent Accounting Standards Yet to be Adopted

Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which provides updated guidance isregarding accounting for leases. This update requires a lessee to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted.

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

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

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

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

Other practical expedients that can be elected individually are:

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

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

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

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

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

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

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2.	Calculation of Earnings Per Share


	Three Months Ended				Nine Months Ended				Three Months Ended
	September 30,				September 30,				March 31,
	2017		2016		2017		2016		2018		2017
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:

Net Income	$	6,833	$	4,416	$	32,023	$	32,812	$	26,855	$	19,144
Weighted average shares outstanding	16,344,442		15,372,413		16,334,210		15,324,932		16,351,338		16,317,224
Basic Earnings Per Share	$	0.42	$	0.29	$	1.96	$	2.14	$	1.64	$	1.17

Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	6,833	$	4,416	$	32,023	$	32,812	$	26,855	$	19,144
Reconciliation of Denominator:
Weighted shares outstanding—Basic	16,344,442		15,372,413		16,334,210		15,324,932		16,351,338		16,317,224
Effect of dilutive securities—Share-based compensation	45,193		40,370		44,423		41,023		51,647		46,572
Adjusted denominator—Diluted	16,389,635		15,412,783		16,378,633		15,365,955		16,402,985		16,363,796
Diluted Earnings Per Share	$	0.42	$	0.29	$	1.96	$	2.14	$	1.64	$	1.17

3. Revenue Recognition

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

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

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	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Florida natural gas division	$	5,864		$	—		$	—		$	5,864
Delaware natural gas division	32,072			—			—			32,072
FPU electric distribution	18,741			—			—			18,741
FPU natural gas distribution	23,213			—			—			23,213
Maryland natural gas division	10,672			—			—			10,672
Sandpiper	8,964			—			—			8,964
Total energy distribution	99,526			—			—			99,526

Energy transmission
Aspire Energy	—			12,077			—			12,077
Eastern Shore	15,597			—			—			15,597
Peninsula Pipeline	2,098			—			—			2,098
Total energy transmission	17,695			12,077			—			29,772

Energy generation
Eight Flags	—			4,378			—			4,378

Propane delivery
Delmarva Peninsula propane delivery	—			45,470			—			45,470
Florida propane delivery	—			6,634			—			6,634
Total propane delivery	—			52,104			—			52,104

Energy services
PESCO	—			81,559			—			81,559

Other and eliminations
Eliminations	(7,828		)	(5,245		)	(15,598		)	(28,671		)
Other	—			494			194			688
Total other and eliminations	(7,828		)	(4,751		)	(15,404		)	(27,983		)

Total operating revenues⁽¹⁾	$	109,393		$	145,367		$	(15,404	)	$	239,356

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

Regulated Energy segment

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

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

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

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

Unregulated Energy segment

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

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

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

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

Contract balances

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




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

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

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

Practical expedients

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

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


3.4.	Rates and Other Regulatory Activities

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

Delaware

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

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

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~~Delaware~~Maryland Division and Sandpiper

~~Rate Case Filing:~~Effect of the TCJA on ratepayers: ~~In December 2015, our Delaware Division filed~~The Maryland PSC issued an ~~application~~order requiring all Maryland public utilities whose rates are explicitly grossed-up for income taxes to track the impacts of the TCJA beginning January 1, 2018. The order required utilities to: (a) apply regulatory accounting treatment, which includes the use of regulatory assets and liabilities for all impacts of the TCJA; (b) file, on or before February 15, 2018, an explanation of the expected effects of the TCJA on their expenses and revenues; and (c) explain when and how they expect to pass on to their customers the net results of those effects. We established a regulatory liability to reflect the estimated impacts of the changes in the federal corporate income tax rate in compliance with the ~~Delaware PSC for a base rate increase~~Maryland PSC’s order. In addition, on February 15, 2018, our Maryland natural gas division and ~~certain other changes to its tariff. The Delaware Division, Delaware PSC Staff, the Division~~Sandpiper filed preliminary estimates of the ~~Public Advocate and other intervenors met and reached a settlement agreement in November 2016. The terms~~annual impact of the ~~settlement agreement included~~change in the statutory federal income tax rate from 35 percent to 21 percent and requested that the Maryland PSC grant us additional time to finalize our calculations. In March 2018, our Maryland natural gas division and Sandpiper supplemented their initial filings to include, among other items, an ~~annual increase~~explanation of ~~$2.3 million in base rates. The order became final in December 2016,~~when and how they propose to pass the ~~new rates became effective January 1, 2017. Amounts collected through interim rates in excess~~tax impacts on to their customers. In April 2018, the Maryland PSC issued orders directing our Maryland natural gas division and Sandpiper to: (1) file tariff pages reflective of the ~~respective portion~~Maryland PSC's recommended rates with an effective date of May 1, 2018; (2) implement a one-time bill credit for the regulatory liability established for refunds; and, (3) make an informational filing within 60 days after the distribution of the ~~$2.3 million increase through December 31, 2016 were accrued as of~~one-time refunds. The orders further directed that, ~~date. In January 2017,~~if any additional tax savings are later identified by either our natural gas divisions, we ~~filed our proposed refund plan~~make a filing with the ~~Delaware~~Maryland PSC ~~and subsequently issued refunds~~to return those savings to customers ~~in March 2017.~~as soon as possible.

~~Maryland~~

~~There were no material rates and other regulatory activities for our Maryland division during the period.~~

~~Sandpiper~~

~~There were no material rates and other regulatory activities for Sandpiper during the period.~~

Florida

~~Cost Recovery for the~~Florida Electric ~~Interconnect Project:~~ In September 2015, FPU’s electric division filed to recover the cost of the proposed Florida Power & Light Company interconnect project through FPU's annual Fuel and Purchased Power Cost Recovery Clause filing. The interconnect project would enable FPU's electric division to negotiate a new power purchase agreement to mitigate fuel costs for its Northeast division. FPU's proposal was approved by the Florida PSC at its Agenda Conference held in December 2015. In January 2016, however, the Office of Public Counsel filed an appeal of the Florida PSC's decision with the Florida Supreme Court. The Florida Supreme Court reversed the Florida PSC decision in March 2017, after consideration of the parties' legal briefs and oral arguments. As a result, FPU excluded the recovery of these costs from its 2018 Fuel and Purchased Power Cost Recovery Clause and included the costs for recovery in the limited proceeding filing described below.

~~Surcharge Associated with~~ Reliability/Modernization ~~of Electric Distribution System Project:~~ In February 2017, FPU’s electric division filed a petition with the Florida PSC requesting a temporary surcharge mechanism to recover costs and generate an appropriate return on investment associated with an essential reliability and modernization project for its electric distribution system. We requested approval to invest approximately $59.8 million, over a five-year period, associated with the modernization project. In February 2017, the Office of Public Counsel intervened in this petition. The Florida PSC requested that FPU file a limited proceeding to include these investments in base rates instead of seeking approval of a temporary surcharge. In April 2017, FPU voluntarily withdrew its petition and subsequently filed the limited proceeding described in the next paragraph.

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

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

Effect of the TCJA on ratepayers: The Office of Public Counsel filed a petition requesting that the Florida PSC establish a general docket to investigate and adjust rates for all investor-owned utilities related to the passage of the TCJA. The Florida PSC issued a Memorandum with a recommendation that, if utilities do not agree to a January 1, 2018 effective date, then the effective date should be February 6, 2018. On January 30, 2018, the Florida PSC scheduled informal meetings between its staff and interested persons to discuss the impact of the TCJA. Meetings to discuss the impact for natural gas utilities, electric utilities and water and wastewater utilities were held in mid-February 2018. In December 2017, ~~Agenda.~~

~~Northwest~~the Florida ~~Expansion Project: Peninsula Pipeline~~PSC issued an order regarding the limited proceeding for FPU's electric division, which prescribes the applicability, timing and ~~FPU's natural gas division are constructing~~treatment of the implications of the TCJA. We established a ~~pipeline~~regulatory liability to reflect the impacts of the changes in ~~Escambia County, Florida~~the federal corporate income tax rate in compliance with the settlement agreement. We believe that the ultimate resolution of this matter will ~~interconnect with FGT's pipeline. The project consists~~not have a material impact on our financial position or results of 33 miles of 12-inch transmission line from the FGT interconnect that will be operated by Peninsula Pipeline and 8 miles of 8-inch lateral distribution lines that will be operated by Chesapeake Utilities' Florida natural gas division. We have entered into agreements to serve two large customers and are marketing to other customers close to the facilities.

~~New Smyrna Beach, Florida Project:~~ Peninsula Pipeline is constructing a pipeline in Volusia County, Florida that will interconnect with FGT's pipeline. The project consists of 14 miles of transmission line from the FGT interconnect that will be operated by Peninsula Pipeline and will serve FPU natural gas distribution customers.operations.

Eastern Shore

~~White Oak Mainline Expansion Project:~~ In July 2016, Eastern Shore received FERC authorization to construct, own and operate certain expansion facilities designed to provide 45,000 Dts/d of firm transportation service to an electric power generator in Kent County, Delaware ("White Oak Mainline Project"). Eastern Shore constructed approximately 5.4 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and increased compression capability at Eastern Shore’s existing Delaware City compressor station in New Castle County, Delaware. At the end of March 2017, the entire project was placed into service. The total cost to complete the project was approximately $42.0 million.

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~~System Reliability Project:~~ In September 2016, the FERC approved Eastern Shore's application to construct, own and operate approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware, and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposed to reinforce critical points on its pipeline system. Previously, in July 2016, the FERC granted Eastern Shore’s pre-determination of rolled-in rate treatment absent any significant change in circumstances.

As of June 2017, the entire project was placed into service. The total cost to complete the project was approximately $38.0 million. We began to recover the project's costs in August 2017, coinciding with the proposed effectiveness of new rates, subject to refund, pending final resolution of the base rate case described below.

2017 Expansion Project: In May 2016, ~~Eastern Shore submitted a request to~~ the FERC approved Eastern Shore's request to initiate the pre-filing review ~~procedures~~process for ~~Eastern Shore's~~its 2017 ~~expansion project (the “2017~~ Expansion ~~Project”).~~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. ~~In May 2016, the FERC approved Eastern Shore’s request to commence the pre-filing review process.~~ Eastern Shore entered into ~~Precedent Agreements~~precedent agreements with seven existing customers, including three affiliates of Chesapeake Utilities, for a total of 61,162 Dts/d of additional firm natural gas transportation service on Eastern Shore’s pipeline system with an additional 52,500 Dts/d of firm transportation service at certain Eastern Shore receipt facilities.

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In December 2016, Eastern Shore submitted an application for a CP ~~seeking authorization to construct~~authorizing construction of the expansion ~~facilities. Six of Eastern Shore's existing customers timely intervened to become parties. In February and March 2017, Eastern Shore submitted responses to~~facilities, which the FERC ~~staff's data requests.~~

Inissued in October ~~2017, FERC issued a CP authorizing Eastern Shore to construct and operate the proposed 2017 Expansion Project.~~2017. The estimated cost of the 2017 Expansion Project is approximately ~~$115.0 million~~

$117.0 million. Eastern Shore ~~is preparing~~submitted its ~~implementation plan, which will be filed with the FERC,~~Implementation Plan in October 2017 addressing the actions Eastern Shore will undertake to meet the ~~Environmental Conditions~~environmental conditions set forth in the FERC's order.

In December 2017, the TETLP interconnect upgrade was placed into service, as Eastern Shore ~~anticipates placing certain facilities~~requested. The remaining segments of the 2017 Expansion Project are expected to be placed into service byin various phases during the ~~end~~remainder of ~~the year and completing the entire project in~~ 2018.

2017 Rate Case Filing: In January 2017, Eastern Shore filed a base rate proceeding with the FERC, as required by the terms of its 2012 rate case settlement agreement. Eastern Shore's proposed rates were based on the mainline cost of service of approximately $60.0 million resulting in an overall requested revenue increase of approximately $18.9 million and a requested rate of return on common equity of 13.75 percent. The filing includes incremental rates for the White Oak Lateral Project and White Oak Mainline Expansion Project, which benefits a single customer. Eastern Shore also proposed to revise its depreciation rates and negative salvage rate based on the results of independent, third-party depreciation and negative salvage value studies. In March 2017, the FERC issued an order suspending the tariff rates for the usual five-month period.

OnIn August 1, 2017, Eastern Shore implemented new rates, subject to refund, based upon the outcome of the rate proceeding. Eastern Shore recorded incremental revenue of approximately ~~$1.0~~$3.7 million for the ~~three and nine months~~year ended ~~September 30,~~December 31, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates until the rate case settlement is ~~resolved. Settlement discussions continue among~~approved by the ~~other parties~~FERC and customers receive refunds according to the ~~case.~~terms of the settlement agreement. Eastern Shore filed an uncontested settlement agreement and a motion to place interim settlement rates into effect beginning on January 1, 2018, which interim settlement rates were approved by the FERC in December 2017. The settlement agreement was approved by the FERC in February 2018, and became final in March 2018. Eastern Shore will recover the costs of its 2016 System Reliability Project, along with the cost of investments and expenses associated with various expansion, reliability and safety initiatives. Not considering the effects of the TCJA, base rates will increase, on an annual basis, by approximately $9.8 million.

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

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

4.5. Environmental Commitments and Contingencies

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

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MGP Sites

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

As of ~~September 30, 2017,~~March 31, 2018, we had approximately ~~$9.7~~$9.6 million in environmental liabilities related to FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites. FPU has approval to recover, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to its MGP sites. Approximately ~~$10.9~~$11.1 million has been recovered as of ~~September 30, 2017,~~March 31, 2018, leaving approximately ~~$3.1~~$2.9 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

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

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



Jurisdiction	MGP Site	Status	Cost to Clean up	Recovery through Rates
Florida	West Palm Beach	Remedial actions approved by the FDEP have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions.	Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the ~~properties~~properties.	Yes
Florida	Sanford	In ~~January 2007, FPU and~~March 2018, the ~~Sanford group signed~~EPA approved a ~~Third Participation Agreement. FPU's share of remediation costs under~~"site-wide ready for anticipated use" status, which is the ~~Third Participation Agreement is set at five percent of~~final step before delisting a ~~maximum of $13.0 million, or $650,000, which~~site. Construction has been ~~paid to an escrow account.~~ ~~The EPA issued a preliminary close-out report~~completed and restrictive covenants are in ~~December 2014. Groundwater monitoring and statutory five-year reviews~~place to ensure ~~performance~~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 ~~approved remedy will continue on this~~ site.	FPU's remaining remediation expenses, including attorneys' fees and costs, are ~~estimated~~anticipated to be ~~approximately $24,000~~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~~site.	Yes
Delaware	Seaford	Proposed plan for implementation approved by the DNREC in July 2017.	~~$273,000 to $465,000~~Between $273,000 and $465,000.	Yes
Maryland	Cambridge	Currently in discussions with ~~MDE~~the MDE.	Unable to ~~estimate~~estimate.	N/A

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5.6.	Other Commitments and Contingencies

Natural Gas, Electric and Propane Supply

We have entered into contractual commitments to purchase natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. In 2017, our Delmarva Peninsula natural gas distribution operations entered into asset management agreements with PESCO to manage ~~a portion of~~ 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.~~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 ~~estimated at~~ approximately ~~2.8~~2.5 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.

Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a six-year term ending in May 2019. Sharp's current annual commitment is ~~estimated at~~ approximately ~~2.8~~2.5 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement.

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

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with ~~JEA~~FPL requires FPU to ~~comply with the following ratios~~meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 ~~months: (a) total liabilities to tangible net worth less than 3.75 times and (b) a fixed charge coverage ratio greater than 1.5 times.~~months. If ~~either~~this ratio is not met by FPU, it ~~has 30 days to cure the default or~~must provide an irrevocable letter of credit ifor pay all amounts outstanding under the ~~default is not cured.~~agreement within five business days. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times) and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of ~~September 30, 2017,~~March 31, 2018, FPU was in compliance with all of the requirements of its fuel supply contracts.

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

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Corporate Guarantees

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 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, 2017~~March 31, 2018 was approximately ~~$71.9~~$72.7 million, with the guarantees expiring on various dates through ~~September 2018.~~March 2019.

Chesapeake Utilities also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under this guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 1314, Long-Term Debt, for further details).

Letters of Credit

As of ~~September 30, 2017,~~March 31, 2018, we have issued letters of credit totaling approximately ~~$5.8~~$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 ~~June 2018.~~December 2019. There have been

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no draws on these letters of credit as of ~~September 30, 2017.~~March 31, 2018. We do not anticipate that the counterparties will draw upon these letters of credit, ~~will be drawn upon by the counterparties,~~ and we expect that the letters of credit will be renewed to the extent necessary in the future.

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.


6.7.	Segment Information

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

Our operations are comprised of two reportable segments:

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

Unregulated Energy. ~~The Unregulated Energy segment includes~~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.~~supply). These operations are unregulated as to their rates and services. ~~Effective June 2016, this segment includes electricity and steam generation through Eight Flags' CHP plant.~~ Through March 2017, this segment also included the operations of Xeron, our propane and crude oil trading subsidiary that ~~began winding~~wound down its operations ~~at the end of~~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.

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

~~Our operations are entirely domestic.~~

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The following table presents financial information about our reportable segments:


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2017			2016			2017			2016			2018		2017
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	67,257		$	68,899		$	232,519		$	224,382		$	105,954	$	96,446
Unregulated Energy segment and other businesses	59,679			39,449			204,661			132,604			133,402		88,714
Total operating revenues, unaffiliated customers	$	126,936		$	108,348		$	437,180		$	356,986		$	239,356	$	185,160
Intersegment Revenues ⁽¹⁾
Regulated Energy segment	$	2,446		$	1,120		$	5,834		$	2,248		$	3,439	$	1,208
Unregulated Energy segment	5,009			2,593			15,801			3,759			11,965		4,011
Other businesses	194			240			581			705			194		228
Total intersegment revenues	$	7,649		$	3,953		$	22,216		$	6,712		$	15,598	$	5,447
Operating Income
Regulated Energy segment	$	15,168		$	13,115		$	51,915		$	52,660		$	26,711	$	23,395
Unregulated Energy segment	(989		)	(3,080		)	10,504			9,267			13,684		11,575
Other businesses and eliminations	60			121			161			350			11		129
Total operating income	14,239			10,156			62,580			62,277			40,406		35,099
Other income (expense), net	239			(28		)	(643		)	(68		)	68		(700		)
Interest charges	3,321			2,722			9,133			7,996			3,664		2,739
Income before Income Taxes	11,157			7,406			52,804			54,213			36,810		31,660
Income taxes	4,324			2,990			20,781			21,401			9,955		12,516
Net Income	$	6,833		$	4,416		$	32,023		$	32,812		$	26,855	$	19,144


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


(in thousands)	September 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
Identifiable Assets
Regulated Energy segment	$	1,084,961	$	986,752	$	1,148,635	$	1,121,673
Unregulated Energy segment	233,785		226,368		246,230		261,541
Other businesses and eliminations	28,004		16,099		32,585		34,220
Total identifiable assets	$	1,346,750	$	1,229,219	$	1,427,450	$	1,417,434

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Our operations are entirely domestic.


7.8.	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, 2017~~March 31, 2018 and December 31, ~~2016.~~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.

~~Common Stock Public Offering~~

~~In September 2016, we completed a public offering of 960,488 shares of our common stock at a public offering price~~per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million, which were added to our general funds and used primarily to repay a portion of our short-term debt under unsecured lines of credit.

~~Stockholders' Rights~~

Pursuant to authority granted under Delaware law and our Certificate of Incorporation, our Board of Directors previously declared a dividend of one preferred stock purchase right (each, a "Right," and, collectively, the "Rights") for each outstanding share of our common stock held of record on September 3, 1999, as adjusted for our stock split in September of 2014, and for additional shares of common stock issued since that time. The description and terms of the Rights are set forth in the Rights Plan. Unless exercised, the Rights trade with our common stock and are evidenced by the common stock certificate. In general, each Right will become exercisable and trade independently from our common stock upon a person or entity acquiring a beneficial ownership of 15 percent or more of our outstanding common stock.

Each Right, if it becomes exercisable, initially entitles the holder to purchase one fiftieth of a share of our Series A Participating Cumulative Preferred Stock, par value $0.01 per share, at a price of $70 per unit, subject to anti-dilution adjustments. Upon a person or entity becoming an "acquiring person," each Right (other than the Rights held by the acquiring person) will become exercisable to purchase a number of shares of our common stock having a market value equal to two times the exercise price of the Right. The Rights expire on August 20, 2019, unless they are redeemed earlier by us at the redemption price of $0.01 per Right. We may redeem the Rights at any time before they become exercisable and thereafter only in limited circumstances.

Accumulated Other Comprehensive Loss

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements, call options and natural gas futures contracts, designated as commodity contracts cash flow hedges, are the components of our accumulated other comprehensive loss. During the first quarter of 2018, we elected to early adopt ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. Accordingly, we reclassified

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

The following tables present the changes in the balance of accumulated other comprehensive ~~loss~~(loss)/income for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 and ~~2016.~~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, 2016 $ (5,360 ) $ 482
$ (4,878 )
Other comprehensive income/(loss) before reclassifications (9 ) 322
313
Amounts reclassified from accumulated other comprehensive income/(loss) 271
(965 ) (694 )
Net current-period other comprehensive income/(loss) 262
(643 ) (381 )
As of September 30, 2017 $ (5,098 ) $ (161 ) $ (5,259 )



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

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	Defined Benefit			Commodity						Defined Benefit			Commodity
	Pension and			Contracts						Pension and			Contracts
	Postretirement			Cash Flow						Postretirement			Cash Flows
	Plan Items			Hedges			Total			Plan Items			Hedges			Total
(in thousands)
As of December 31, 2015	$	(5,580	)	$	(260	)	$	(5,840	)
Other comprehensive income before reclassifications	—			641			641
As of December 31, 2016										$	(5,360	)	$	482		$	(4,878	)
Other comprehensive income/(loss) before reclassifications										(9		)	1,278			1,269
Amounts reclassified from accumulated other comprehensive income/(loss)	263			(93		)	170			91			(940		)	(849		)
Net prior-period other comprehensive income	263			548			811			82			338			420
As of September 30, 2016	$	(5,317	)	$	288		$	(5,029	)
As of March 31, 2017										$	(5,278	)	$	820		$	(4,458	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2018 and ~~2016.~~2017. Deferred gains or losses for our commodity contracts cash ~~flow~~flows hedges are recognized in earnings upon settlement.


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2017			2016			2017			2016			2018			2017
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit ⁽¹⁾	$	19		$	20		$	58		$	60		$	19		$	19
Net loss⁽¹⁾	(171		)	(166		)	(509		)	(500		)	(149		)	(170		)
Total before income taxes	(152		)	(146		)	(451		)	(440		)	(130		)	(151		)
Income tax benefit	61			58			180			177			36			60
Net of tax	$	(91	)	$	(88	)	$	(271	)	$	(263	)	$	(94	)	$	(91	)

Gains and losses on commodity contracts cash flow hedges
Gains and losses on commodity contracts cash flow hedges:
Propane swap agreements ⁽²⁾	$	198		$	—		$	663		$	(322	)	$	(464	)	$	388
Natural gas swaps ⁽²⁾	1			—			1			—			(450		)	—
Natural gas futures ⁽²⁾	(852		)	105			929			464			298			1,150
Total before income taxes	(653		)	105			1,593			142			(616		)	1,538
Income tax benefit (expense)	248			(41		)	(628		)	(49		)	172			(598		)
Net of tax	(405		)	64			965			93			(444		)	940
Total reclassifications for the period	$	(496	)	$	(24	)	$	694		$	(170	)	$	(538	)	$	849

⁽¹⁾ These amounts are included in the computation of net periodic costs (benefits). See Note 89, Employee Benefit Plans, for additional details.

⁽²⁾ These amounts are included in the effects of gains and losses from derivative instruments. See Note ~~11,~~12, Derivative Instruments, for additional details.

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

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8.9.	Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three ~~and nine~~ months ended ~~September 30,~~March 31, 2018 and 2017 ~~and 2016~~ 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, 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016
(in thousands)
Interest cost $ 103
$ 105
$ 623
$ 635
$ 22
$ 23
$ 11
$ 11
$ 13
$ 14
Expected return on plan assets (127 ) (131 ) (699 ) (625 ) —
—
—
—
—
—
Amortization of prior service credit —
—
—
—
—
—
(19 ) (20 ) —
—
Amortization of net loss 107
103
131
133
22
22
17
16
—
—
Net periodic cost (benefit) 83
77
55
143
44
45
9
7
13
14
Amortization of pre-merger regulatory asset —
—
191
191
—
—
—
—
2
2
Total periodic cost $ 83
$ 77
$ 246
$ 334
$ 44
$ 45
$ 9
$ 7

$ 15
$ 16


	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan				Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Nine Months Ended September 30,	2017			2016			2017			2016			2017		2016		2017			2016			2017		2016
For the Three Months Ended March 31,																											2018			2017			2018			2017			2018		2017		2018			2017			2018		2017
(in thousands)
Interest cost	$	309		$	315		$	1,870		$	1,894		$	66	$	68	$	31		$	32		$	38	$	41	$	97		$	103		$	592		$	623		$	21	$	22	$	10		$	10		$	12	$	13
Expected return on plan assets	(381		)	(392		)	(2,098		)	(2,027		)	—		—		—			—			—		—		(138		)	(127		)	(774		)	(699		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(58		)	(60		)	—		—		—			—			—			—			—		—		(19		)	(19		)	—		—
Amortization of net loss	319			309			392			389			65		66		50			51			—		—		88			107			109			131			25		22		15			16			—		—
Net periodic cost (benefit)(1)	247			232			164			256			131		134		23			23			38		41		47			83			(73		)	55			46		44		6			7			12		13
Amortization of pre-merger regulatory asset	—			—			571			571			—		—		—			—			6		6		—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	247		$	232		$	735		$	827		$	131	$	134	$	23		$	23		$	44	$	47	$	47		$	83		$	118		$	246		$	46	$	44	$	6		$	7		$	14	$	15

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

We expect to record pension and postretirement benefit costs of approximately ~~$1.6 million~~$913,000 for ~~2017.~~2018. Included in these costs is approximately $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations for the changes in funded status that occurred, but were not recognized, as part of net periodic benefit costs prior to the FPU merger in 2009. This was deferred as a regulatory asset by FPU prior to the merger, to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was approximately ~~$1.5~~$1.1 million and approximately ~~$2.1~~$1.3 million at ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016~~,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 ~~and nine~~ months ended ~~September 30, 2017~~March 31, 2018 and ~~2016:~~2017:

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 Three Months Ended September 30, 2016 Chesapeake
Pension
Plan FPU
Pension
Plan Chesapeake SERP Chesapeake
Postretirement
Plan FPU
Medical
Plan Total
(in thousands)
Prior service credit $ —
$ —
$ —
$ (20 ) $ —
$ (20 )
Net loss 103
133
22
16
—
274
Total recognized in net periodic benefit cost 103
133
22
(4 ) —
254
Recognized from accumulated other comprehensive loss ⁽¹⁾
103
25
22
(4 ) —
146
Recognized from regulatory asset —
108
—
—
—
108
Total $ 103
$ 133
$ 22

$ (4 )
$ —

$ 254


For the Nine Months Ended September 30, 2017	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
For the Three Months Ended March 31, 2018															Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(58	)	$	—	$	(58	)	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	319		392		65		50			—		826			88		109		25		15			—		237
Total recognized in net periodic benefit cost	319		392		65		(8		)	—		768			88		109		25		(4		)	—		218
Recognized from accumulated other comprehensive loss ⁽¹⁾	319		75		65		(8		)	—		451			88		21		25		(4		)	—		130
Recognized from regulatory asset	—		317		—		—			—		317			—		88		—		—			—		88
Total	$	319	$	392	$	65	$	(8	)	$	—	$	768		$	88	$	109	$	25	$	(4	)	$	—	$	218

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For the Nine Months Ended September 30, 2016	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
For the Three Months Ended March 31, 2017															Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(60	)	$	—	$	(60	)	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	309		389		66		51			—		815			107		131		22		16			—		276
Total recognized in net periodic benefit cost	309		389		66		(9		)	—		755			107		131		22		(3		)	—		257
Recognized from accumulated other comprehensive loss ⁽¹⁾	309		74		66		(9		)	—		440			107		25		22		(3		)	—		151
Recognized from regulatory asset	—		315		—		—			—		315			—		106		—		—			—		106
Total	$	309	$	389	$	66	$	(9	)	$	—	$	755		$	107	$	131	$	22	$	(3	)	$	—	$	257

⁽¹⁾See Note 78, Stockholder's Equity.

During the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2018, we contributed approximately ~~$67,000 and $234,000, respectively,~~$72,000 to the Chesapeake Pension Plan and approximately ~~$110,000 and $1.6 million, respectively,~~$309,000 to the FPU Pension Plan. We expect to contribute a total of approximately ~~$746,000~~$359,000 and approximately ~~$3.0~~$1.5 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during ~~2017,~~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 ended ~~September 30, 2017,~~March 31, 2018, were approximately ~~$38,000 and $114,000, respectively.~~$38,000. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake SERP in ~~2017.~~2018. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2018, were approximately ~~$30,000 and $94,000, respectively.~~$12,000. We estimate that approximately ~~$83,000~~$97,000 will be paid for such benefits under the Chesapeake Postretirement Plan in ~~2017.~~2018. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three ~~and nine~~ months ended ~~September 30, 2017,~~March 31, 2018, were approximately ~~$13,000 and $48,000, respectively.~~$11,000. We estimate that approximately ~~$129,000~~$88,000 will be paid for such benefits under the FPU Medical Plan in ~~2017.~~2018.


9.10.	Investments

The investment balances at ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, consisted of the following:


(in thousands)	September 30, 2017		December 31, 2016		March 31, 2018		December 31, 2017
Rabbi trust (associated with the Deferred Compensation Plan)	$	6,358	$	4,881	$	6,621	$	6,734
Investments in equity securities	22		21		20		22
Total	$	6,380	4,902		$	6,641	6,756

We classify these investments as trading securities and report them at their fair value. For the three months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ we recorded a net unrealized loss of approximately $44,000 and a net unrealized gain of approximately ~~$261,000 and $193,000,~~$252,000, respectively, in other income (expense), net in the condensed consolidated statements of income related to these investments. For the nine months ended September 30, 2017 and 2016, we recorded an unrealized gain of approximately $694,000 and $246,000, respectively, in other income (expense),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 ~~condensed~~ consolidated balance sheets and is adjusted each ~~month~~period for the gains and losses incurred by the investments in the Rabbi Trust.


~~10.~~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

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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 ended ~~September 30, 2017~~March 31, 2018 and ~~2016:~~2017:

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	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2017			2016			2017			2016			2018			2017
(in thousands)
Awards to non-employee directors	$	134		$	135		$	406		$	445		$	135		$	135
Awards to key employees	662			488			1,202			1,442			1,385			504
Total compensation expense	796			623			1,608			1,887			1,520			639
Less: tax benefit	(320		)	(251		)	(647		)	(760		)	(416		)	(257		)
Share-based compensation amounts included in net income	$	476		$	372		$	961		$	1,127		$	1,104		$	382

Non-employee Directors

Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the grant date. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a ~~service period of~~ one ~~year.~~-year service period. In May 2017, each of our non-employee directors received an annual retainer of 835 shares of common stock under the SICP for service as a director through the 2018 Annual Meeting of Stockholders.

~~A summary of the stock activity for our non-employee directors during the nine months ended September 30, 2017 is presented below:~~

Number of Shares
Weighted Average
Fair Value
Outstanding— December 31, 2016 —
$ —
Granted 7,515
$ 71.80
Vested (7,515 ) $ 71.80
Outstanding— September 30, 2017 —
$ —

At ~~September 30, 2017,~~March 31, 2018, there was approximately ~~$314,000~~$45,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2018.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the ~~nine~~three months ended ~~September 30, 2017:~~

March 31, 2018:


	Number of Shares		Weighted Average Fair Value		Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2016	115,091		$	51.85
Outstanding—December 31, 2017					132,642		$	59.31
Granted	52,355		$	63.42	49,494		$	67.76
Vested	(32,926	)	$	38.88	(29,786	)	$	47.39
Expired	(1,878	)	$	39.97	(3,933	)	$	49.66
Outstanding— September 30, 2017	132,642		$	52.42
Outstanding—March 31, 2018					148,417		$	66.53

In February ~~and May 2017,~~2018, our Board of Directors granted awards of ~~52,355~~49,494 shares of common stock to key employees under the SICP. The shares granted ~~in February and May 2017~~ are multi-year awards that will vest at the end of the three-year service period ending December 31, ~~2019.~~2020. All of these stock awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprise both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the grant date of each award. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

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AtIn March 2018, upon the election of certain of our ~~executives, in March 2017, for shares that were awarded for the performance period ending December 31, 2016,~~executive officers, we withheld shares with a value at least equivalent to each such ~~executive’s~~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.~~executive officer. We withheld ~~10,269~~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 ~~$692,000.~~$719,000.

At ~~September 30, 2017,~~March 31, 2018, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $10.4 million. At ~~September 30, 2017,~~March 31, 2018, there was approximately ~~$2.7~~$4.2 million of unrecognized compensation cost related to these awards, which is expected to be recognized from ~~2017~~2018 through ~~2019.~~2020.

Stock Options

We did not have any stock options outstanding at ~~September 30,~~March 31, 2018 or 2017, ~~or 2016,~~ nor were any stock options issued during these periods.

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~~11.~~12.	Derivative Instruments

We use derivative and non-derivative contracts to engage in trading activities and manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to our customers. Aspire Energy has entered into contracts with producers to secure natural gas to meet its obligations. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and normal sales” and are accounted for on an accrual basis. Our propane distribution and natural gas marketing operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of ~~September 30, 2017,~~March 31, 2018, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Hedging Activities in 2018

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

Hedging Activities in 2017

In 2017, Sharp entered into ~~several~~futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with ~~11.1~~7.7 million gallons of propane expected to be purchased from October 2017 through ~~September~~March 2019, of which positions covering 2.1 million gallons of forecasted future purchases were outstanding as of March 31, 2018. Under the futures and swap agreements, Sharp will receive the difference between the index prices (Mont Belvieu prices in October 2017 through ~~September 2018)~~March 2019) and the swap prices of ~~$0.5900 and $0.6750~~$0.59 per gallon, to the extent the index ~~prices exceed~~price exceeds the ~~swap prices.~~contracted price. If the index prices are lower than the swap ~~price,~~prices, Sharp will pay the difference. ~~We accounted~~Sharp received a total of approximately $464,000, which represented the difference between the index prices and the contracted prices during the first quarter of 2018 related to hedging activities originated in 2017 and received $3,000, which represented the mark-to-market activities for ~~these swap agreements as cash flow hedges,~~the three months ended March 31, 2018. At March 31, 2018, the futures and ~~there is no ineffective portion of these hedges. At September 30, 2017, the~~ swap agreements had a fair value asset of approximately ~~$1.5 million.~~$204,000 and a fair value liability of $16,000. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss).

~~PESCO enters into natural gas futures contracts~~The impact on Sharp's financial instruments that were not designated as hedges in our consolidated financial statements as of March 31, 2018 was $4,000, which was recorded as a decrease in propane costs during the three months ended March 31, 2018 and is associated with ~~the purchase and sale~~18,000 gallons of natural gas to other specific customers. These contracts have a two-year term, and we accounted for them as cash flow hedges. There is no ineffective portion of these hedges. At September 30, 2017, PESCO had a total of 4.0 million Dts hedged under natural gas futures contracts, with a liability fair value of approximately $1.3 million accounted for as a cash flow hedge. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss).propane.

In August 2017, PESCO entered into natural gas swap agreements associated with ~~ARM's~~ financial contracts acquired in the ARM acquisition to mitigate the risk of fluctuations in wholesale natural gas prices associated with ~~12.0 million~~702,000 Dts of natural gas PESCO expects to purchase through January 2020. We accounted for these swap agreements as cash flow hedges, ~~with~~which have a ~~liability~~ fair value liability of approximately ~~$412,000.~~$404,000 at March 31, 2018. The change in fair value of the natural gas swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss).

The impact ofon PESCO's financial instruments that were not designated as hedges in our ~~condensed~~ consolidated financial statements ~~for the nine months ended September 30, 2017~~as of March 31, 2018 was ~~$13,000,~~$300,000, which was recorded as an increase in gas costs during the three months ended March 31, 2018 and is associated with ~~1.4 million~~87,500 Dts of natural gas. ~~This presentation does not reflect~~

Balance sheet offsetting

PESCO has entered into master netting agreements with counterparties that enable it to net the ~~expected gains or losses arising from~~counterparties' outstanding accounts receivable and payable, which are presented on a net basis in the ~~underlying physical transactions associated with these financial instruments.~~consolidated balance sheets. The following table summarizes the accounts receivable and payables on a gross and net basis at March 31, 2018 and December 31, 2017:

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~~Hedging Activities in 2016~~

In 2016, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 4.8 million gallons expected to be purchased through September 2017. Under the swap agreements, Sharp would receive the difference between the index prices (Mont Belvieu prices in October 2016 through September 2017) and the swap prices of $0.5225 and $0.5650 per gallon, to the extent the index prices exceeded the swap prices. If the index prices were lower than the swap price, Sharp would pay the difference. Sharp received a total of approximately $193,000, which represented the difference between the index prices and swap prices during the months of October 2016 through September 2017. We had accounted for these swap agreements as cash flow hedges.



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

In December 2016, Sharp paid a total of $33,000 to purchase a put option to protect against a decline in propane prices and related potential inventory losses associated with 630,000 gallons for its propane price cap program in the 2016-2017 heating season. The put option expired without being exercised because the propane prices did not fall below the strike price of $0.5650 per gallon in December 2016, January 2017, or February 2017. We accounted for the put option as a fair value hedge, and there was no ineffective portion of this hedge.

In January 2016, PESCO entered into a supplier agreement with Columbia Gas to provide natural gas supply for one of its local distribution customer pools. PESCO also assumed the obligation to store natural gas inventory to satisfy its obligations under the supplier agreement, which terminated on March 31, 2017. In conjunction with the supplier agreement, PESCO entered into natural gas futures contracts during the second quarter of 2016 in order to protect its natural gas inventory against market price fluctuations. We had previously accounted for these contracts as fair value hedges, with any ineffective portion being reported directly in earnings and offset by any associated gain (loss) on the inventory value being hedged. During the third quarter of 2016, we discontinued hedge accounting as the hedges were no longer highly effective. As of September 30, 2017, these contracts have all expired and are no longer reported on the balance sheet.



	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

~~Commodity Contracts for Trading Activities~~

Shortly after the first quarter of 2017, Xeron wound down its operations. Xeron was previously engaged in trading activities using forward and futures contracts for propane and crude oil. These contracts were considered derivatives and were accounted for using the mark-to-market method of accounting. As of September 30, 2017, Xeron had no outstanding contracts that were accounted for as derivatives.

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, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, are as follows:


						Asset Derivatives
		Fair Value As Of					Fair Value As Of
(in thousands)	Balance Sheet Location	September 30, 2017		December 31, 2016		Balance Sheet Location	March 31, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	15	$	8	Derivative assets, at fair value	$	4	$	13
Put options	Derivative assets, at fair value	—		9
Natural gas swap contracts	Derivative assets, at fair value	1		—
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative assets, at fair value	—		113		Derivative assets, at fair value	—		92
Propane swap agreements	Derivative assets, at fair value	1,510		693		Derivative assets, at fair value	204		1,181
Total asset derivatives		$	1,526	$	823		$	208	$	1,286



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

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Liability Derivatives
Fair Value As Of
(in thousands) Balance Sheet Location September 30, 2017 December 31, 2016
Derivatives not designated as hedging instruments
Natural gas futures contracts Derivative liabilities, at fair value $ 13
$773
Derivatives designated as cash flow hedges
Natural gas swap contracts Derivative liabilities, at fair value 412
—
Natural gas futures contracts Derivative liabilities, at fair value 1,307
—
Total liability derivatives $ 1,732
$ 773

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


		Amount of Gain (Loss) on Derivatives:													Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended September 30,						For the Nine Months Ended September 30,						Location of Gain	For the Three Months Ended March 31,
(in thousands)	(Loss) on Derivatives	2017			2016			2017			2016			(Loss) on Derivatives	2018			2017
Derivatives not designated as hedging instruments
Realized gain on forward contracts and options ⁽¹⁾	Revenue	$	—		$	(231	)	$	112		$	44		Revenue	$	—		$	112
Unrealized gain (loss) on forward contracts ⁽¹⁾	Revenue	—			(2		)	—			—
Natural gas futures contracts	Cost of sales	286			205			907			205			Cost of sales	(2,835		)	124
Propane swap agreements	Cost of sales	15			—			11			—			Cost of sales	(9		)	(4		)
Natural gas swap contracts	Cost of sales	1			—			1			—
Derivatives designated as fair value hedges
Put /Call option ⁽²⁾	Cost of sales	—			—			(9		)	73			Cost of sales	—			(9		)
Natural gas futures contracts	Natural gas inventory	—			—			—			(233		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	198			—			663			(364		)	Cost of sales	(464		)	388
Propane swap agreements	Other comprehensive income	1,590			213			814			559			Other comprehensive loss	(992		)	(557		)
Natural gas futures contracts	Cost of sales	(852		)	105			929			464			Cost of sales	298			1,150
Natural gas futures contracts	Other comprehensive income (loss)	(1,296		)	(123		)	(1,420		)	349
Natural gas swap agreements	Cost of sales	1			—			1			—
Natural gas swap contracts														Cost of sales	(450		)	1,087
Natural gas futures agreements														Other comprehensive income	65			—
Natural gas swap agreements	Other comprehensive loss	(413		)	—			(413		)	—			Other comprehensive loss	(1,732		)	—
Total		$	(470	)	$	167		$	1,596		$	1,097			$	(6,119	)	$	2,291


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

⁽²⁾

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


~~12.~~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:

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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, 2017~~March 31, 2018 and December 31, ~~2016:~~2017:

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			Fair Value Measurements Using:								Fair Value Measurements Using:
As of September 30, 2017	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of March 31, 2018									Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	22	$	22	$	—	$	—	$	20	$	20	$	—	$	—
Investments—guaranteed income fund	642		—		—		642		602		—		—		602
Investments—mutual funds and other	5,716		5,716		—		—		6,019		6,019		—		—
Total investments	6,380		5,738		—		642		6,641		6,039		—		602
Derivative assets	1,526		—		1,526		—		208		—		208		—
Total assets	$	7,906	$	5,738	$	1,526	$	642	$	6,849	$	6,039	$	208	$	602
Liabilities:
Derivative liabilities	$	1,732	$	—	$	1,732	$	—	$	2,359	$	—	$	2,359	$	—


			Fair Value Measurements Using:								Fair Value Measurements Using:
As of December 31, 2016	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
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	$	21	$	21	$	—	$	—	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	561		—		—		561		648		—		—		648
Investments—mutual funds and other	4,320		4,320		—		—		6,086		6,086		—		—
Total investments	4,902		4,341		—		561		6,756		6,108		—		648
Derivative assets	823		—		823		—		1,286		—		1,286		—
Total assets	$	5,725	$	4,341	$	823	$	561	$	8,042	$	6,108	$	1,286	$	648
Liabilities:
Derivative liabilities	$	773	$	—	$	773	$	—	$	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.

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Level 2 Fair Value Measurements:

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

Level 3 Fair Value Measurements:

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

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The following table sets forth the summary of the changes in the fair value of Level 3 investments for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 and ~~2016:~~2017:


	Nine Months Ended September 30,						Three Months Ended March 31,
	2017			2016			2018			2017
(in thousands)
Beginning Balance	$	561		$	279		$	648		$	561
Purchases and adjustments	76			120			(48		)	2
Transfers	—			88			—			—
Distribution	(2		)	(8		)	—			—
Investment income	7			6			2			2
Ending Balance	$	642		$	485		$	602		$	565

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

At ~~September 30, 2017,~~March 31, 2018, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its short maturities and because interest rates approximate current market rates (Level 3 measurement). At ~~September 30, 2017~~March 31, 2018, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of approximately ~~$211.4~~$230.1 million. This compares to a fair value of approximately ~~$224.2~~$237.9 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At December 31, ~~2016,~~2017, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of approximately ~~$145.9~~$205.2 million, compared to the estimated fair value of approximately ~~$161.5~~$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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~~13.~~14.	Long-Term Debt

Our outstanding long-term debt is shown below:


	September 30,			December 31,			March 31,			December 31,
(in thousands)	2017			2016			2018			2017
FPU secured first mortgage bonds ⁽¹⁾:
9.08% bond, due June 1, 2022	$	7,981		$	7,978		$	7,983		$	7,982
Uncollateralized senior notes:
6.64% note, due October 31, 2017	2,727			2,727
5.50% note, due October 12, 2020	8,000			8,000			6,000			6,000
5.93% note, due October 31, 2023	19,500			21,000			18,000			18,000
5.68% note, due June 30, 2026	26,100			29,000			26,100			26,100
6.43% note, due May 2, 2028	7,000			7,000			7,000			7,000
3.73% note, due December 16, 2028	20,000			20,000			20,000			20,000
3.88% note, due May 15, 2029	50,000			50,000			50,000			50,000
3.25% note, due April 30, 2032	70,000			—			70,000			70,000
Long-term portion of the Revolver⁽²⁾							25,000			—
Promissory notes	97			168			26			97
Capital lease obligation	2,425			3,471			1,712			2,070
Less: debt issuance costs	(446		)	(291		)	(418		)	(433		)
Total long-term debt	213,384			149,053			231,403			206,816
Less: current maturities	(12,136		)	(12,099		)	(9,389		)	(9,421		)
Total long-term debt, net of current maturities	$	201,248		$	136,954		$	222,014		$	197,395

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

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

Shelf Agreements

In October 2015, we entered into the $150.0 million Prudential Shelf Agreement, under which we may request that Prudential purchase ~~through October 8, 2018,~~ up to $150.0 million of ~~Prudential Shelf Notes. The Prudential Shelf Notes~~our unsecured senior debt. As of March 31, 2018, we have a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance. Prudential is under no obligation to purchase any of the Prudential Shelf Notes. The interest rate and terms of payment of any series of the Prudential Shelf Notes will be determined at the time of purchase.

~~In May 2016, Prudential confirmed and accepted our request that Prudential purchase~~issued $70.0 million of ~~3.25 percent~~3.25% Prudential Shelf Notes, which were issued on April 21, 2017. The proceeds received from this issuance of Prudential Shelf Notes were used to reduce short-term borrowings under the Revolver. The balance under the Revolver had accumulated over time as capital expenditures were temporarily financed.

The Prudential Shelf Agreement sets forth certain business covenants to which we are subject when any Prudential Shelf 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.Notes.

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

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

As of ~~September 30, 2017, no unsecured senior debt has been issued~~March 31, 2018, we have $230.0 million of additional potential borrowing capacity under the Prudential and MetLife Shelf Agreements. The Prudential Shelf Agreement and the NYL Shelf ~~Agreements.~~Agreement set forth certain business covenants to which we are subject when any note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K for the year ended December 31, ~~2016,~~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 ~~event~~events or otherwise. These statements are subject to many risks, uncertainties and ~~uncertainties.~~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 ~~2016~~2017 Annual Report on Form 10-K, ~~the following important~~such factors ~~among others, could cause actual future results to differ materially from those expressed in the forward-looking statements:~~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 ofto which competition ~~entering~~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 ~~certificate~~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;

~~industrial, commercial and residential growth~~long-term global climate change, which could adversely affect customer demand or ~~contraction in our markets or service territories;~~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 effect of competition on our businesses;~~

~~the capital-intensive nature of our regulated~~ 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 ~~ability to construct facilities at or below estimated costs and within projected time frames;~~

~~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,~~plans; regulatory or other limitations imposed as a result of a ~~merger,~~merger; acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture;

the impact on our ~~cost~~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;~~

~~the impact of significant changes to current tax regulations and rates; and~~

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systems.

~~the impact of future rate case proceedings.~~

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.

The following discussions and those ~~elsewhere~~later in ~~this Quarterly Report on Form 10-Q~~the document on operating income and segment results include the use of the term “gross ~~margin",~~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 ~~structure~~structures for ~~non-regulated segments.~~unregulated energy operations. Our management uses gross margin in measuring ~~its~~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.

Table of Contents

Results of Operations for the Three ~~and Nine~~ Months ended ~~September 30, 2017~~March 31, 2018

Overview

Chesapeake Utilities ~~Corporation~~ 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, 2017~~March 31, 2018 was ~~$6.8~~$26.9 million, or ~~$0.42~~$1.64 per share. This represents an increase of ~~$2.4~~$7.7 million, or ~~$0.13~~$0.47 per share, compared to net income of ~~$4.4~~$19.1 million, or ~~$0.29~~$1.17 per share, reported for the same quarter in ~~2016.~~2017. Operating income increased ~~$4.1~~by $5.3 million for the three months ended ~~September 30, 2017.~~March 31, 2018, compared to the same period in the prior year. This increase was driven by a $7.1 million, or 8.5 percent, increase in gross margin, which was partially offset by a $1.2 million increase in depreciation, amortization and property taxes and a $616,000 increase in other operating expenses. Excluding the estimated customer refunds reserved during the first quarter of 2018 associated with the TCJA, gross margin and operating income increased by $10.3 million, or 12.2 percent, and $8.5 million, or 24.1 percent, respectively, compared to the same period in the prior year. A decrease in income taxes, due mainly to the lower effective tax rate, also positively impacted our earnings.


	Three Months Ended									Three Months Ended
	September 30,						Increase			March 31,					Increase
	2017			2016			(decrease)			2018		2017			(decrease)
(in thousands except per share)
Business Segment:
Regulated Energy segment	$	15,168		$	13,115		$	2,053		$	26,711	$	23,395		$	3,316
Unregulated Energy segment	(989		)	(3,080		)	2,091			13,684		11,575			2,109
Other businesses and eliminations	60			121			(61		)	11		129			(118		)
Operating Income	$	14,239		$	10,156		$	4,083		$	40,406	$	35,099		$	5,307
Other income (expense), net	239			(28		)	267			68		(700		)	768
Interest charges	3,321			2,722			599			3,664		2,739			925
Pre-tax Income	11,157			7,406			3,751			36,810		31,660			5,150
Income taxes	4,324			2,990			1,334			9,955		12,516			(2,561		)
Net Income	$	6,833		$	4,416		$	2,417		$	26,855	$	19,144		$	7,711
Earnings Per Share of Common Stock
Basic	$	0.42		$	0.29		$	0.13		$	1.64	$	1.17		$	0.47
Diluted	$	0.42		$	0.29		$	0.13		$	1.64	$	1.17		$	0.47

Table of Contents

Key variances, between the ~~third~~first quarter of ~~2017~~2018 and the ~~third~~first quarter of ~~2016,~~2017, included:

(in thousands, except per share data) Pre-tax
Income Net
Income Earnings
Per Share
Third Quarter of 2016 Reported Results $ 7,406
$ 4,416
$ 0.29

Adjusting for unusual items:
Absence of Xeron's third quarter 2016 loss 545
334
0.02
Weather impact (333 ) (204 ) (0.01 )
212

130

0.01
Increased Gross Margins:
Customer consumption (non-weather) 1,166
714
0.05
Implementation of new rates for Eastern Shore* 1,020
625
0.04
Retail propane margins 440
270
0.02
GRIP* 406
249
0.02
Natural gas growth (excluding service expansions) 347
213
0.01
Eight Flags' CHP plant 304
186
0.01
Pricing amendments to Aspire Energy's long-term agreements 291
178
0.01
Higher wholesale propane volumes and margins 271
166
0.01
4,245

2,601

0.17
Decreased (Increased) Other Operating Expenses:
Higher depreciation, asset removal and property tax costs due to new capital investments (1,710 ) (1,047 ) (0.07 )
Lower outside services and facilities maintenance costs 1,678
1,028
0.07
Higher payroll expense (913 ) (559 ) (0.04 )
Lower benefit and other employee-related expenses 295
181
0.01
Eight Flags' operating expenses 293
179
0.01
(357 )
(218 )
(0.02 )

Net other changes (349 )
(96 ) (0.01 )
(349 ) (96 ) (0.01 )

EPS impact of increase in outstanding shares due to September 2016 offering —
—
(0.02 )
Third Quarter of 2017 Reported Results $ 11,157

$ 6,833

$ 0.42



(in thousands, except per share data)	Pre-tax Income			Net Income			Earnings Per Share
First Quarter of 2017 Reported Results	$	31,660		$	19,144		$	1.17

Increased Gross Margins:
Return to more normal weather	3,914			2,855			0.17
TCJA impact - estimated refunds to ratepayers⁽¹⁾	(3,155		)	(2,302		)	(0.14		)
Implementation of Eastern Shore settled rates* ⁽²⁾	2,843			2,074			0.13
PESCO	(2,292		)	(1,672		)	(0.10		)
Unregulated Energy customer consumption (non-weather)	1,682			1,227			0.07
Regulated Energy customer consumption (non-weather)	949			692			0.04
Natural gas growth (excluding service expansions)	802			585			0.04
Service expansions*	565			412			0.03
Florida electric reliability/modernization program*	372			272			0.02
GRIP*	298			217			0.01
Sandpiper's margin from an industrial customer and natural gas conversions	257			188			0.01
	6,235			4,548			0.28

Decreased (Increased) Other Operating Expenses:
Higher payroll expense	(1,559		)	(1,137		)	(0.07		)
Higher depreciation, asset removal and property tax costs due to new capital investments	(1,216		)	(887		)	(0.05		)
Absence of Xeron expenses, including wind-down expenses	697			508			0.03
Lower outside services and facilities maintenance costs	665			485			0.03
Lower regulatory expenses	242			177			0.01
Lower benefit and other employee-related expenses	240			175			0.01
	(931		)	(679		)	(0.04		)

Interest charges	(926		)	(675		)	(0.04		)
Income taxes - TCJA impact - decreased effective tax rate	—			4,594			0.28
Net other changes	772			(77		)	(0.01		)
	(154		)	3,842			0.23

First Quarter of 2018 Reported Results	$	36,810		$	26,855		$	1.64

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

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

*See the Major Projects and Initiatives ~~table.~~table.

~~Table of Contents~~

Our net income for the nine months ended September 30, 2017 was $32.0 million, or $1.96 per share. This represents a decrease of $789,000, or $0.18 per share, compared to net income of $32.8 million, or $2.14 per share, reported for the same period in 2016. Operating income increased $303,000 for the nine months ended September 30, 2017.

Nine Months Ended
September 30, Increase
2017 2016 (decrease)
(in thousands except per share)
Business Segment:
Regulated Energy segment $ 51,915
$ 52,660
$ (745 )
Unregulated Energy segment 10,504
9,267
1,237
Other businesses and eliminations 161
350
(189 )
Operating Income $ 62,580
$ 62,277
$ 303
Other expense, net (643 ) (68 ) (575 )
Interest charges 9,133
7,996
1,137
Pre-tax Income 52,804
54,213
(1,409 )
Income taxes 20,781
21,401
(620 )
Net Income $ 32,023
$ 32,812
$ (789 )
Earnings Per Share of Common Stock
Basic $ 1.96
$ 2.14
$ (0.18 )
Diluted $ 1.96
$ 2.14
$ (0.18 )

~~Table of Contents~~

~~Key variances, between the nine months ended 2017 and the nine months ended 2016, included:~~

(in thousands, except per share data) Pre-tax
Income Net
Income Earnings
Per Share
Nine Months Ended September 30, 2016 Reported Results $ 54,213
$ 32,812
$ 2.14

Adjusting for unusual items:
Weather impact (1,782 ) (1,081 ) (0.07 )
Wind-down and absence of loss from Xeron operations (341 ) (207 ) (0.01 )
(2,123 ) (1,288 ) (0.08 )
Increased Gross Margins:
Eight Flags' CHP plant 4,721
2,863
0.19
Natural gas marketing 1,760
1,067
0.07
GRIP* 1,619
982
0.06
Natural gas growth (excluding service expansions) 1,574
955
0.06
Service expansions* 1,371
831
0.05
Pricing amendments to Aspire Energy's long-term agreements 1,143
693
0.04
Implementation of new rates for Eastern Shore* 1,020
619
0.04
Wholesale propane margins 728
441
0.03
Customer consumption (non-weather) 700
425
0.03
Implementation of Delaware Division settled rates 249
151
0.01
14,885
9,027
0.58
Increased Other Operating Expenses:
Higher depreciation, asset removal and property tax costs due to new capital investments (4,251 ) (2,578 ) (0.17 )
Higher payroll expense (3,074 ) (1,864 ) (0.12 )
Eight Flags' operating expenses (2,821 ) (1,711 ) (0.11 )
Higher benefit and other employee-related expenses (1,669 ) (1,012 ) (0.07 )
Higher regulatory expenses associated with rate filings (855 ) (519 ) (0.03 )
Higher outside services and facilities maintenance costs (318 ) (193 ) (0.01 )
(12,988 ) (7,877 ) (0.51 )

Interest charges (1,136 ) (689 ) (0.04 )
Net other changes (47 ) 38
(0.01 )
(1,183 ) (651 ) (0.05 )

EPS impact of increase in outstanding shares due to September 2016 offering —
—
(0.12 )
Nine Months Ended September 30, 2017 Reported Results $ 52,804

$ 32,023

$ 1.96

*~~See the Major Projects and Initiatives table.~~

Table of Contents

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 ~~summarizes gross margin for our~~represents the major projects ~~and initiatives recently completed and initiatives~~ currently ~~underway, but which~~underway. In the future, we will ~~be completed in the future. Gross margin reflects operating revenue less cost of sales, excluding depreciation, amortization and accretion (dollars in thousands):~~add new projects to this table as projects are initiated.

Gross Margin for the Period
Three Months Ended Nine Months Ended Year Ended
September 30, September 30, December 31, Estimate for
2017 2016 Variance 2017 2016 Variance 2016 2017 2018 2019
Major Projects and Initiatives Recently Completed
Capital Investment Projects $ 9,807
$ 8,963
$ 844
$ 29,533
$ 21,822
$ 7,711
$ 29,819
$ 35,346
$ 31,814
$ 32,724
Eastern Shore Rate Case ⁽¹⁾
1,020
—
1,020
1,020
—
1,020
—
TBD
TBD
TBD
Settled Delaware Division Rate Case 431
469
(38 ) 1,596
1,347
249
1,487
2,250
2,250
2,250
Total Major Projects and Initiatives Recently Completed 11,258
9,432
1,826
32,149
23,169
8,980
31,306
37,596
34,064
34,974
Future Major Projects and Initiatives
Capital Investment Projects
2017 Eastern Shore System Expansion —
—
—
—
—
—
— 126
9,313
15,799
Northwest Florida Expansion —
—
—
—
—
—
— —
3,484
5,127
Other Florida Pipeline Expansions —
—
—
—
—
—
— —
2,044
2,542
Total Future Major Projects and Initiatives —
—
—
—
—
—
— 126
14,841
23,468
Total $ 11,258
$ 9,432
$ 1,826
$ 32,149
$ 23,169
$ 8,980
$ 31,306
$ 37,722
$ 48,905
$ 58,442



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

^{(1)(1 )} ~~In January 2017, Eastern Shore filed a rate case with~~Gross margin amount included in this table has not been adjusted to reflect the ~~FERC~~impact of TCJA. Any reductions implemented would be offset by lower federal income taxes due to ~~recover~~ the costs of the 2016 System Reliability Project and other investments and expenses associated with the expansion, reliability and safety initiatives completed by ESNG since its last rate settlement in 2012. Settlement discussions among Eastern Shore, intervenors and the FERC Staff are ongoing and future margin contributions will be provided once a settlement is finalized. For the third quarter of 2017, a portion of the increase in rates, implemented subject to refund in August 2017, has been recorded as revenue and the remainder has been reserved pending the settlement. See Note 3, ~~Rates and Other Regulatory Activities,~~ ~~for additional information.~~TCJA.

~~Major Projects and~~Ongoing Growth Initiatives ~~Recently Completed~~

~~The following table summarizes gross margin generated by our major projects and initiatives recently completed (dollars in thousands):~~

Gross Margin for the Period
Three Months Ended Nine Months Ended Year Ended
September 30, September 30, December 31, Estimate for
2017 2016 Variance 2017 2016 Variance 2016 2017 2018 2019
Capital Investment Projects:
Service Expansions:
Short-term contracts (Delaware) $ 1,283
$ 3,080
$ (1,797 ) $ 5,140
$ 8,271
$ (3,131 ) $ 11,454
$ 5,642
$ 1,096
$ 1,096
Long-term contracts (Delaware) 2,793
862
1,931
7,089
2,587
4,502
1,815
7,611
7,605
7,583
Total Service Expansions 4,076
3,942
134
12,229
10,858
1,371
13,269
13,253
8,701
8,679
Florida GRIP 3,393
2,987
406
10,002
8,383
1,619
11,552
13,727
14,407
15,085
Eight Flags' CHP Plant 2,338
2,034
304
7,302
2,581
4,721
4,998
8,366
8,706
8,960
Total Capital Investment Projects 9,807
8,963
844
29,533
21,822

7,711
29,819
35,346
31,814
32,724
Eastern Shore Rate Case ⁽¹⁾
1,020
—
1,020
1,020
—
1,020
—
TBD TBD TBD
Settled Delaware Division Rate Case 431
469
(38 ) 1,596
1,347
249
1,487
2,250
2,250
2,250
Total Major Projects and Initiatives Recently Completed $ 11,258
$ 9,432
$ 1,826
$ 32,149
$ 23,169
$ 8,980
$ 31,306
$ 37,596
$ 34,064
$ 34,974

~~Table of Contents~~

⁽¹⁾ In January 2017, Eastern Shore filed a rate case with the FERC to recover the costs of the 2016 System Reliability Project and other investments and expenses associated with the expansion, reliability and safety initiatives completed by ESNG since its last rate settlement in 2012. Settlement discussions among Eastern Shore, intervenors and the FERC Staff are ongoing and future margin contributions will be provided once a settlement is finalized. For the third quarter of 2017, a portion of the increase in rates, implemented subject to refund in August 2017, has been recorded as revenue and the remainder has been reserved pending the settlement. See Note 3, ~~Rates and Other Regulatory Activities,~~ ~~for additional information.~~

~~Service Expansions~~

In August 2014, Eastern Shore entered into a precedent agreement with an electric power generator in Kent County, Delaware, to provide a 20-year OPT 90 ≤ natural gas transmission service for 45,000 Dts/d deliverable to the lateral serving the customer's facility. In July 2016, the FERC authorized Eastern Shore to construct and operate the project, which consists of 5.4 miles of 16-inch pipeline looping and new compression capability in Delaware. Eastern Shore provided interim services to this customer pending construction of facilities. Construction of the project was completed, and long-term service commenced in March 2017. This service generated an additional gross margin of $106,000 during the nine months ended September 30, 2017 compared to the same period in 2016. There was no incremental margin change during the third quarter as the margin generated from the permanent services equated to the margin generated from providing interim services during the third quarter of 2016. This service is expected to generate gross margin of $7.0 million for 2017 and between $5.8 million and $7.8 million annually through the remaining term of the agreement.

In December 2015, the FERC approved Eastern Shore's application to make certain meter tube and control valve replacements and related improvements at its TETLP interconnect facilities to increase natural gas receipts from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. The project was completed and placed in service in March 2016. Approximately 35 percent of the increased capacity has been subscribed on a short-term firm service basis through October 2017. This service generated additional gross margin of $80,000 and $1.3 million for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. The remaining capacity is available for firm or interruptible service.

GRIP

GRIP is a natural gas pipe replacement program approved by the Florida PSC designed to expedite the replacement of qualifying distribution mains and services (any material other than coated steel or plastic) to enhance the reliability and integrity of the Florida natural gas distribution systems. This programthat allows automatic recovery, through regulated rates, of capital and other program-related costs, inclusive of a return on investment, associated with the replacement of the mains and services. Since the program's inception in August 2012, we have invested ~~$110.5~~$117.0 million to replace ~~240~~250 miles of qualifying distribution mains, including ~~$7.6~~$3.2 million during the first ~~nine~~three months of ~~2017.~~2018. The increased ~~investment~~investments in GRIP generated additional gross margin of ~~$406,000 and $1.6 million~~$298,000 for the three ~~and nine~~ months ended ~~September 30, 2017, respectively,~~March 31, 2018 compared to the same ~~periods~~period in ~~2016.~~2017.

~~Eight Flags' CHP plant~~Regulatory Proceedings

Eastern Shore Rate Case

In ~~June~~February 2018, the FERC approved Eastern Shore's rate case settlement agreement. The settlement became final on April 1, 2018, upon the expiration of the right to a rehearing. Under the terms of the settlement agreement, Eastern Shore will recover costs of its 2016 ~~Eight Flags completed construction~~System Reliability Project, along with the cost of ~~a CHP plant on Amelia Island, Florida. This CHP plant, which consists of a natural-gas-fired turbine~~investments and expenses associated ~~electric generator, produces~~with various expansion, reliability and safety initiatives. Pursuant to the settlement agreement, Eastern Shore's annual base rates will increase by approximately 20 MWH of base load power and includes a heat recovery steam generator capable of providing approximately 75,000 pounds per hour of residual steam. In June 2016, Eight Flags began selling power generated$9.8 million, prior to any impact from the ~~CHP plant to FPU, pursuant to a 20-year power purchase agreement for distribution to~~TCJA, and will recognize approximately $6.6 million, on an annual basis, after reflecting the impact of the change in its retail electric customers. In July 2016, it also started selling steam to the industrial customer that owns the property on which Eight Flags' CHP plant is located, pursuant to a separate 20-year contract.

~~The CHP plant is powered by natural gas transported by FPU through its distribution system and by Peninsula Pipeline.~~federal corporate income tax rate. For the three ~~and nine~~ months ended ~~September~~March 31, 2018, Eastern Shore recognized incremental gross margin of approximately $2.8 million, a portion of which was reserved as a regulatory liability to be refunded to customers. Eastern Shore refunded to its customers, with interest, the difference between the proposed rates and the settlement rates on April 30, 2018. The settlement rates were effective January 1, 2018.

Florida Electric Reliability/Modernization Pilot Program

In December 2017, ~~Eight Flags~~the Florida PSC approved a settlement agreement related to FPU’s electric limited proceeding filing, which included a $1.6 million annualized rate increase, effective January 2018, for the recovery of a limited number of investments and ~~other affiliates~~costs related to reliability, safety and modernization for FPU's electric distribution system. This increase will continue through at least the last billing cycle of ~~Chesapeake Utilities generated $304,000 and $4.7 million, in~~December 2019. For the three months ended March 31, 2018, additional ~~gross~~ margin of $372,000 was generated. The settlement agreement prescribes the methodology for adjusting the new rates as a result of ~~these services that began in June 2016. This amount includes gross margin of $7,000 and $534,000, for~~ the three and nine months ended September 30, 2017, respectively, attributable to natural gas distribution and transportation services provided to the CHP plant by Chesapeake Utilities' regulated affiliates.TCJA.

~~System Reliability Project~~

In July 2016, the FERC authorized Eastern Shore to construct and operate the System Reliability Project, which consisted of approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware, and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. A 2.5 mile looping segment was completed and placed into service in December 2016. The remaining looping and the new compressor were completed and placed into service in the second quarter of 2017. This project was included in Eastern Shore's January 2017 base rate case filing with the FERC. We began to recover the project's costs in August 2017, coinciding with the proposed effectiveness of new rates, subject to refund pending final resolution of the base rate case.

Table of Contents

Major Projects and Initiatives Currently Underway

~~Northwest Florida Expansion Project~~

Peninsula Pipeline and FPU's natural gas division are constructing a pipeline in Escambia County, Florida that will interconnect with FGT's pipeline. The project consists of 33 miles of 12-inch transmission line from the FGT interconnect that will be operated by Peninsula Pipeline and 8 miles of 8-inch lateral distribution lines that will be operated by Chesapeake Utilities' Florida natural gas division. We entered into agreements to serve two industrial customers and are currently marketing to other potential customers located close to the facilities. The estimated annual gross margin associated with this project, once in service, is approximately $5.1 million.

New Smyrna Beach, Florida Project

~~Peninsula Pipeline is constructing~~In the fourth quarter of 2017, we commenced construction of a 14-mile transmission pipeline ~~in Volusia County, Florida~~ that ~~will interconnect~~interconnects with FGT's ~~pipeline.~~pipeline to provide additional capacity to serve current and planned growth in Florida natural gas customers in our current New Smyrna Beach service area. The project ~~consists~~was partially placed into service at the end of ~~14 miles of transmission line from~~2017 and is expected to be fully in service in September 2018. For the ~~FGT interconnect that will be operated by Peninsula Pipeline and will serve FPU natural gas distribution customers. The estimated annual~~three months ended March 31, 2018, we recognized incremental gross margin ~~associated with~~of approximately $352,000 from this ~~project, once in service, is approximately $1.4 million.~~project.

2017 ~~Expansion Project~~

~~In May 2016,~~ Eastern Shore ~~submitted a request to the FERC to initiate the FERC's pre-filing process for its proposed 2017~~Pipeline Expansion Project. This project, which will expand Eastern Shore's firm service capacity by 26 percent, will provide 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 pursuant to precedent agreements Eastern Shore entered into with existing customers. Project

We expect to invest approximately ~~$115.0~~$117.0 million in 2018 to increase Eastern Shore's capacity by 26 percent. The new transportation services contracted for this ~~expansion project, and for the project to~~capacity will generate approximately $15.8 million of gross margin in the first full year ~~after the new transportation services go into effect. On October 4,~~of service. In December 2017, the ~~FERC issued~~first phase of the project was placed into service, with the remaining segments expected to be placed into service over the remainder of 2018. For the three months ended March 31, 2018, we recognized incremental gross margin of $1.0 million.

Northwest Florida Expansion Project

Peninsula Pipeline and our Florida natural gas division are constructing a ~~CP authorizing Eastern Shore~~pipeline that will interconnect with the FGT interstate pipeline. The project consists of transmission lines that will be operated by Peninsula Pipeline, and lateral distribution lines that will be operated by the Florida natural gas division. We have signed agreements to ~~construct~~serve two large customers and ~~operate~~continue to market to other customers close to the ~~proposed 2017 expansion project.~~facilities. The estimated annual gross margin from this project is $6.0 million, and the project is currently expected to be in service by the end of the second quarter of 2018.

(Palm Beach County) Belvedere, Florida Project

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

Other major factors influencing gross margin

Weather and Consumption

~~Temperature variation~~Gross margin increased by $3.9 million in ~~2017 negatively impacted our earnings. Compared~~the first quarter of 2018, primarily as a result of colder temperatures, as compared to the extremely warm temperatures experienced during the first quarter of 2017. Despite colder temperatures in the first quarter of 2018, as compared to the prior year ~~cooler~~period, the temperatures experienced in the first quarter of 2018 were still warmer than normal. We estimate that an additional $1.7 million of gross margin would have been generated if the temperatures in ~~Florida during~~ the ~~third~~first quarter of ~~2017, reduced gross margin by $333,000, and warmer~~2018 were consistent with temperatures in ~~all of our service territories during the~~a normal first nine months of 2017, reduced gross margin by $1.8 million, respectively. Warmer than normal temperatures for the quarter and nine months ended September 30, 2017 reduced gross margin by $193,000 and $4.3 million, respectively. quarter.

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, 2017~~March 31, 2018 and ~~2016.~~2017.

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HDD and CDD Information


	Three Months Ended						Nine Months Ended						Three Months Ended
	September 30,						September 30,						March 31,
	2017		2016		Variance		2017		2016		Variance		2018		2017		Variance
Delmarva
Actual HDD	16		11		5		2,262		2,590		(328	)	2,295		1,958		337
10-Year Average HDD ("Delmarva Normal")	62		65		(3	)	2,845		2,919		(74	)	2,354		2,403		(49	)
Variance from Delmarva Normal	(46	)	(54	)			(583	)	(329	)			(59	)	(445	)
Florida
Actual HDD	—		—		—		298		514		(216	)	490		285		205
10-Year Average HDD ("Florida Normal")	—		—		—		602		553		49		517		536		(19	)
Variance from Florida Normal	—		—				(304	)	(39	)			(27	)	(251	)
Ohio
Actual HDD	80		39		41		3,072		3,596		(524	)	2,991		2,484		507
10-Year Average HDD ("Ohio Normal")	92		103		(11	)	3,866		3,865		1		3,069		3,137		(68	)
Variance from Ohio Normal	(12	)	(64	)			(794	)	(269	)			(78	)	(653	)
Florida
Actual CDD	1,526		1,679		(153	)	2,606		2,792		(186	)	139		145		(6	)
10-Year Average CDD ("Florida CDD Normal")	1,542		1,523		19		2,579		2,548		31		89		82		7
Variance from Florida CDD Normal	(16	)	156				27		244				50		63

Natural Gas Distribution Customer Growth

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

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

Propane Operations

Our Florida and Delmarva Peninsula propane distribution operations ~~added $2.0 million~~continue to pursue a multi-pronged growth plan, which includes: targeting retail and ~~$1.4 million,~~wholesale customer growth in existing markets, both organically as well as through acquisitions; incremental growth from recent and planned start-ups in new markets, targeting new community gas systems in high growth areas; further build-out of our propane vehicular platform through AutoGas fueling stations; and optimization of our supply portfolio to generate incremental margin opportunities. Over the years, we have focused on meeting customer energy demand, and we have created a portfolio of offerings regardless of whether the customer is served via a pipeline or through an individual tank. AutoGas is our most recent offering that meets customers’ varying demands. As a member of AutoGas, our Delmarva Peninsula propane distribution operations and AutoGas install and support propane vehicle conversion systems for ~~the three~~vehicle fleets. Our Delmarva Peninsula propane distribution operations continues to convert fleets to bi-fuel propane-powered engines and ~~nine months ended September 30, 2017, respectively, compared to the same periods in 2016. Higher volumes sold to retail customers and improved margins due to effective supply management activities~~provides onsite fueling infrastructure.

These operations generated ~~$905,000 and $440,000,~~$4.0 million in incremental margin for the three months ended ~~September 30, 2017, respectively,~~March 31, 2018, compared to the same period ~~in 2016 and higher service revenue added $187,000 in additional margin, during the quarter.~~

~~For the nine months ended September 2017, higher volumes sold~~2017. In addition, successful marketing initiatives led to retail customers and improved margins due to effective supply management activities generated $142,000 and $121,000, in incremental margin, respectively, compared to the same period in 2016 and higher service revenue added $244,000, in additional margin during the period.

~~Wholesale propane margins~~ increased ~~generating additional gross margin of $271,000 and $728,000 for the three and nine months ended September 30, 2017, respectively, due primarily to higher~~ volumes sold and ~~improved~~revenues from service contracts. Supply management initiatives, including favorable hedging of propane purchases, have increased retail propane margins ~~resulting~~as well as opportunities to generate incremental margin from ~~supply management activities.~~wholesale sales.

PESCO

PESCO ~~provides~~markets and sells natural gas ~~supply and supply management services~~ to ~~residential, commercial,~~wholesale, industrial and ~~wholesale customers. PESCO operates primarily in Florida, on the Delmarva Peninsula, in Ohio,~~commercial customers and ~~as a result of the recent acquisition of certain operating assets of ARM, in western Pennsylvania. PESCO competes with regulated utilities and other unregulated third-party marketers to sell~~manages natural gas ~~supplies directly to residential, commercial~~storage and ~~industrial customers through competitively-priced contracts.~~transportation assets in several market areas. PESCO ~~does not currently own or operate any~~also provides management of storage and transportation assets for natural gas ~~transmission~~ producers and regulated utilities. These management transactions typically involve the release of storage and/or ~~distribution assets but sells gas that is delivered~~transportation capacity in combination with an obligation to ~~retail, commercial~~ purchase and/or ~~wholesale customers through affiliated and non-affiliated local distribution company systems and transmission pipelines.~~deliver natural gas. In April 2017, PESCO entered into 3-year asset

~~In 2017,~~

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management agreements with our Delmarva Peninsula natural gas distribution operations ~~entered into asset management agreements with~~whereby PESCO ~~to manage~~manages a portion of their natural gas transportation and storage capacity. ~~The asset~~

In conjunction with the active management ~~agreements were effective April 1, 2017, and each has a three-year term, expiring on March 31, 2020. As a result~~ of these ~~agreements,~~contracts, PESCO ~~manages capacity on regional pipelines as well as third-party storage contracts for our Delmarva~~generates financial margin by identifying market opportunities and simultaneously entering into natural gas ~~distribution operations~~purchase/sale, storage or transportation contracts and/or financial derivatives contracts. The financial derivatives contracts consist primarily of exchange-traded futures that are used to manage volatility in ~~conjunction with~~natural gas market prices. Volatility in PESCO’s recorded gross margin and operating income can occur over periods of time due to changes in the value of financial derivatives contracts prior to the time of the settlement of the financial derivatives and the purchase or sale of the underlying physical commodity. Derivatives accounting has no impact on economic gains or losses of the purchase or sale contracts. PESCO’s results may also fluctuate based on the actual demand of its customers relative to its initial estimates of their demand, and PESCO's ~~asset management services.~~ability to manage its supply portfolio, considering weather and other factors, including pipeline constraints.

For the three months ended ~~September 30, 2017,~~March 31, 2018, PESCO's gross margin ~~increased~~decreased by ~~$56,000. For the nine months ended September 30, 2017, PESCO generated additional gross margin of $1.8~~$2.3 million compared to the same period in ~~2016, as a result~~

~~Table~~2017. The decrease in gross margin was primarily due to higher gas supply costs of ~~Contents~~

$2.0 million with retail customers in the Mid-Atlantic region and the absence of $2.1 million revenues from a supplier agreement with a customer in Ohio, which expired on March 31, 2017, ~~as well as additional customers in Florida, partially~~ offset by ~~lower~~a favorable $2.2 million increase in margin infrom PESCO's asset management supply services. Unrealized fair value MTM losses of $300,000 related to financial derivative contracts also contributed to the ~~Mid-Atlantic region, primarily during the first quarter of 2017.~~decrease.

Xeron

~~As disclosed previously,~~ Xeron's operations were wound down during the second quarter of 2017. ~~As a result,~~Operating income for the quarter ended March 31, 2018, improved by $697,000 due to the absence of pre-tax losses generated by Xeron ~~did not generate an operating loss during~~in the ~~third~~first quarter of 2017 and will not report operating results during the fourth quarter of 2017 or subsequent years. During the third quarter of 2016, Xeron generated a pre-tax loss of $486,000. On a year-to-date basis, Xeron's pre-tax operating loss increased by $375,000, compared to the same period in 2016, driven primarily by non-recurring employee severance costs and costs associated with the termination of leased office space in Houston, Texas. The Company does not anticipate incurring any additional costs that will have a material impact associated with winding down Xeron's operations.

~~Other Natural Gas Growth - Distribution Operations~~

In addition to service expansions, the natural gas distribution operations on the Delmarva Peninsula generated $379,000 and $1.0 million in additional gross margin for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016, due to an increase in residential, commercial and industrial customers served. The average number of residential customers on the Delmarva Peninsula increased by 3.7 percent and 3.8 percent during the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. The natural gas distribution operations in Florida generated $187,000 and $1.2 million in additional gross margin for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016, due primarily to an increase in commercial and industrial customers in Florida.

~~Regulatory Proceedings~~

~~Delaware Division Rate Case~~

In December 2016, the Delaware PSC approved a settlement agreement, which, among other things, provided for an increase in our Delaware division revenue requirement of $2.25 million and a rate of return on common equity of 9.75 percent. The new authorized rates went into effect on January 1, 2017. For the three months ended September 30, 2017, compared to the same period in 2016, revenue decreased by $38,000, reflecting the variance between settled and interim rates. For the nine months ended September 30, 2017 compared to the same period in 2016, we recorded incremental revenue of approximately $249,000 related to the rate case. Any amounts collected through 2016 interim rates in excess of the respective portion of the $2.25 million were refunded to the ratepayers in March 2017.

~~Eastern Shore Rate Case~~

In January 2017, Eastern Shore filed a base rate proceeding with the FERC, as required by the terms of its 2012 rate case settlement agreement. Eastern Shore's proposed rates were based on the mainline cost of service of approximately $60.0 million, resulting in an overall requested revenue increase of approximately $18.9 million and a requested rate of return on common equity of 13.75 percent. The filing includes incremental rates for the White Oak Lateral Project and White Oak Mainline Expansion Project, which benefits a single customer. Eastern Shore also proposed to revise its depreciation rates and negative salvage rate based on the results of independent, third-party depreciation and negative salvage value studies. In March 2017, the FERC issued an order suspending the tariff rates for the usual five-month period.

On August 1, 2017, Eastern Shore implemented new rates, subject to refund based upon the outcome of the rate proceeding. Eastern Shore recorded incremental revenue of approximately $1.0 million for the three and nine months ended September 30, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates until resolution of the rate case. Settlement discussions continue with other parties to the case.

~~Investing for Future Growth~~

To support and continue our growth, we have expanded, and will continue to expand, our resources and capabilities. Eastern Shore previously expanded, and continues to significantly expand, its transmission system, which require additional staffing. We requested recovery of most of Eastern Shore's increased staffing costs in its 2017 rate case.Growth in non-regulated energy businesses, including Aspire Energy, PESCO and Eight Flags, also requires additional staff as well as corporate resources to support the increased level of business operations. Finally, to allow us to continue to identify and move growth initiatives forward and to assist in developing additional initiatives, staffing and resources have been added in our corporate shared services departments. For the three and nine months ended September 30, 2017, our staffing and associated costs increased by $617,000 and $4.7 million, respectively, or three percent and nine percent, respectively, compared to the same periods in 2016. We are prudently managing the pace and magnitude of the investments being made, while ensuring that we appropriately expand our human resources and systems capabilities to capitalize on future growth opportunities.

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Regulated Energy Segment

For the quarter ended ~~September 30, 2017~~March 31, 2018 compared to the quarter ended ~~September 30, 2016~~March 31, 2017


	Three Months Ended							Three Months Ended
	September 30,				Increase			March 31,				Increase
	2017		2016		(decrease)			2018		2017		(decrease)
(in thousands)
Revenue	$	69,703	$	70,019	$	(316	)	$	109,393	$	97,654	$	11,739
Cost of sales	22,794		24,644		(1,850		)	48,231		40,244		7,987
Gross margin	46,909		45,375		1,534			61,162		57,410		3,752
Operations & maintenance	21,149		22,912		(1,763		)	23,147		23,580		(433		)
Depreciation & amortization	7,338		6,346		992			7,516		6,885		631
Other taxes	3,254		3,002		252			3,788		3,550		238
Other operating expenses	31,741		32,260		(519		)	34,451		34,015		436
Operating income	$	15,168	$	13,115	$	2,053		$	26,711	$	23,395	$	3,316

Operating income for the Regulated Energy segment for the three months ended ~~September 30, 2017~~March 31, 2018 was ~~$15.2~~$26.7 million, an increase of ~~$2.1~~$3.3 million compared to the same period in ~~2016.~~2017. The increased operating income resulted from increased gross margin of ~~$1.5~~$3.8 million and ~~a decrease~~an increase in operating expenses of ~~$519,000.~~$436,000.

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

Gross Margin

Items contributing to the quarter-over-quarter increase ~~of $1.5 million, or 3.4 percent,~~ in gross margin are listed in the following table:

(in thousands)
Gross margin for the three months ended September 30, 2016 $ 45,375
Factors contributing to the gross margin increase for the three months ended September 30, 2017:
Implementation of Eastern Shore rates 1,020
Additional Revenue from GRIP in Florida 406
Natural gas growth (excluding service expansions) 347
Other (239 )
Gross margin for the three months ended September 30, 2017 $ 46,909

~~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 Rates~~



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

~~Eastern Shore generated additional gross margin of $1.0 million from the implementation of new rates as~~^*As a result of ~~its rate case filing. See~~ ~~Note 3, Rates~~the TCJA, a preliminary reserve of $3.2 million was established during the first quarter of 2018 to reflect the impact of lower tax rates on the Company's regulated businesses, based on internal guidance, until final agreements are approved and ~~Other Regulatory Activities~~,permanent changes are made to customer rates. The reserves and lower customer rates are equal to the ~~condensed consolidated financial statements for additional details.~~

~~Additional Revenue from GRIP~~anticipated reduction in ~~Florida~~

~~Increased investment in GRIP generated additional gross margin of $406,000 for the three months ended September 30, 2017, compared~~federal income taxes due to the ~~same period in 2016.~~

~~Natural Gas Growth (excluding service expansions)~~

~~Increased gross margin of $347,000 from other growth in natural gas (excluding service expansions) was generated primarily~~TCJA and have no material impact on after-tax earnings from the ~~following:~~Regulated Energy segment.

$379,000 from a four-percent increase in the average number of residential customers in the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers;

~~$187,000 from Florida natural gas customer growth, due primarily to new services to commercial and industrial customers; and~~

~~which were partially offset by $219,000 in decreased margin from Eastern Shore's interruptible services.~~

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~~Other Operating Expenses~~

~~Other operating expenses decreased by $519,000. The significant factors contributing to the decrease in other operating expenses included:~~

~~$1.6 million in lower costs related to outside services and facilities and maintenance costs, due primarily to lower consulting and service contractor costs;~~

~~$437,000 in lower benefits and employee-related costs (since we are self-insured for healthcare, benefits costs fluctuate depending upon filed claims);~~

~~$1.4 million in higher depreciation, asset removal and property tax costs associated with recent capital investments.~~

~~For the Nine Months Ended September 30, 2017 compared to the nine months ended September 30, 2016~~

Nine Months Ended
September 30, Increase
2017 2016 (decrease)
(in thousands)
Revenue $ 238,353
$ 226,630
$ 11,723
Cost of sales 87,206
81,184
6,022
Gross margin 151,147
145,446
5,701
Operations & maintenance 67,869

64,673
3,196
Depreciation & amortization 21,365
18,909
2,456
Other taxes 9,998
9,204
794
Other operating expenses 99,232
92,786
6,446
Operating income $ 51,915
$ 52,660
$ (745 )

Operating income for the Regulated Energy segment for the nine months ended September 30, 2017 was $51.9 million, a decrease of $745,000 compared to the same period in 2016. The decreased operating income was due to an increase in gross margin of $5.7 million, offset by higher operating expenses of $6.4 million. Of the total $6.4 million increase in operating expenses, $4.7 million is associated with Eastern Shore's recently completed projects as well as initiatives underway.

~~Gross Margin~~

~~Items contributing to the period-over-period increase of $5.7 million, or 3.9 percent, in gross margin are listed in the following table:~~

(in thousands)
Gross margin for the nine months ended September 30, 2016 $ 145,446
Factors contributing to the gross margin increase for the nine months ended September 30, 2017:
Additional revenue from GRIP in Florida 1,619
Natural gas growth (excluding service expansions) 1,574
Service expansions 1,371
Customer consumption - weather and other (1,249 )
Implementation of Eastern Shore rates 1,020
Service to Eight Flags 534
Implementation of Delaware Division Rates 249
Other 583
Gross margin for the nine months ended September 30, 2017 $ 151,147

~~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.~~

~~Additional Revenue from GRIP in Florida~~

~~Increased investment in GRIP generated additional gross margin of $1.6 million for the nine months ended September 30, 2017, compared to the same period in 2016.~~

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~~Natural Gas Growth (Excluding Service Expansions)~~

~~Increased gross margin of $1.6 million from growth (excluding service expansions) was generated primarily from the following:~~

~~$1.2 million from Florida natural gas customer growth, due primarily to new services to commercial and industrial customers; and~~

$1.0 million from a four-percent increase in the average number of residential customers in the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers.

~~Service Expansions~~

Eastern Shore generated increased gross margin of $1.4 million from natural gas service expansions related to short-term firm service that commenced in March 2016. Following certain measurement and related improvements to Eastern Shore's interconnect with TETLP, Eastern Shore's natural gas receipt capacity from TETLP increased by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. The remaining capacity is available for firm or interruptible service.

~~Customer Consumption - Weather and Other~~

Gross margin decreased by $1.2 million from lower customer consumption of electricity and natural gas, due primarily to warmer temperatures in Florida and on the Delmarva Peninsula. Because Maryland and Sandpiper Energy rates include a weather normalization adjustment for residential heating and smaller commercial heating customers, these operations experienced minimal impact from the warmer weather during the first nine months of 2017.

~~Implementation of Eastern Shore Rates~~

~~Eastern Shore generated additional gross margin of $1.0 million from implementation of new rates as a result of its rate case filing. See~~ ~~Note 3, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.~~

~~Service to Eight Flags~~

We generated additional gross margin of $534,000 in the nine months ended September 30, 2017, compared to the same period in 2016, from new natural gas transmission and distribution services provided by our affiliates to Eight Flags' CHP plant.

~~Implementation of Delaware Division Rates~~

~~Our Delaware Division generated additional gross margin of $249,000 as a result of the settlement of the rate case. See~~ ~~Note 3, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.~~

~~Other Operating Expenses~~

~~Other operating expenses increased by $6.4 million. The significant components of the increase in other operating expenses included:~~

~~$3.5 million in higher depreciation, asset removal and property tax costs associated with recent capital investments;~~

~~$1.6 million in higher payroll expenses for addition personnel to support growth;~~

~~$855,000 in increased regulatory expenses, due primarily to costs associated with Eastern Shore’s rate case filing in 2017; and~~

~~$722,000 in higher benefits and employee-related costs in 2017 (since we are self-insured for healthcare, benefits costs fluctuate depending upon claims filed).~~

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~~Unregulated Energy Segment~~

~~For the quarter ended September 30, 2017 compared to the quarter ended September 30, 2016~~

Three Months Ended
September 30, Increase
2017 2016 (decrease)
(in thousands)
Revenue $ 64,688
$ 42,042
$ 22,646
Cost of sales 51,416
31,840
19,576
Gross margin 13,272
10,202
3,070
Operations & maintenance 11,460
10,975
485
Depreciation & amortization 2,001
1,840
161
Other taxes 800
467
333
Total operating expenses 14,261
13,282
979
Operating loss $ (989 ) $ (3,080 ) $ 2,091

Operating loss for the Unregulated Energy segment for the three months ended September 30, 2017 was $989,000, compared to the operating loss of $3.1 million for same period in 2016. The decreased operating loss was due to an increase in gross margin of $3.1 million, which was offset by a $1.0 million increase in operating expenses.

~~Gross Margin~~

~~Items contributing to the quarter-over-quarter increase of $3.1 million in gross margin are listed in the following table:~~

(in thousands)
Gross margin for the three months ended September 30, 2016 $ 10,202
Factors contributing to the gross margin increase for the three months ended September 30, 2017:
Customer Consumption - Weather and Other 1,165
Retail Propane Margins 440
Eight Flags' CHP Plant 297
Pricing Amendments to Aspire Energy's Long-Term Agreements 291
Wholesale Propane Margins 271
Wind-down of Xeron operations 233
Other 373
Gross margin for the three months ended September 30, 2017 $ 13,272

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

Implementation of Eastern Shore Settled Rates

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

Return to More Normal Weather

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

Increased Customer Consumption ~~- Weather and Other~~(non-weather)

Gross margin increased by ~~$1.2 million,~~$949,000 from higher non-weather consumption of natural gas on the Delmarva Peninsula.

Natural Gas Growth (excluding service expansions)

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

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

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

Service Expansions

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

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

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

Florida Electric Reliability/Modernization Program

Gross margin increased ~~sales volumes of propane to wholesale and retail customers on the Delmarva Peninsula and higher retail propane sales volumes in Florida~~by $372,000, due primarily to the ~~timing~~limited proceedings rates that went into effect in January 2018. See Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.

GRIP

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

~~Retail Propane Margins~~Sandpiper DSR and SIR

Gross margin increased by ~~$440,000,~~$257,000, due primarily to ~~favorable supply management activities.~~a higher system improvement rate resulting from the continuing conversion of the Sandpiper system from propane service to natural gas service and an increase in a negotiated rate charged to a large industrial customer in the Maryland natural gas division. This increase was slightly offset by a decrease in delivery service rates for Sandpiper as a result of a settlement in its last rate case.

~~Eight Flags~~Impact of the TCJA on customer rates

~~Eight Flags' CHP plant, which commenced operations in June 2016, generated $297,000 in additional~~The adjustment to customer rates, because of the implementation of the TCJA, decreased gross margin by $3.2 million due ~~primarily~~ to ~~Eight Flags being fully on-line in~~ the ~~third quarter~~establishment of ~~2017.~~a reserve for the estimated refund to customers.

~~Pricing Amendments~~Other Operating Expenses

Other operating expenses decreased by $436,000. The significant factors contributing to ~~Aspire Energy Long-Term Agreements~~

Anthe increase in ~~gross margin of $291,000 was due~~other operating expenses included:

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

$589,000 in higher staffing costs for additional personnel to ~~pricing amendments to long-term sales agreements.~~support growth; offset by

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~~Wholesale Propane Margins~~

~~Gross margin increased by $271,000,~~$667,000 in lower costs related to outside services and facilities and maintenance costs, due primarily to ~~favorable supply management activities for the Delmarva propane distribution operations.~~

~~Xeron~~

~~The absence~~lower consulting and service contractor costs, as temporary resources were replaced with permanent resources and certain consulting services were finalized/concluded in first quarter of ~~the prior year operating loss increased gross margin by $233,000.~~

~~Other Operating Expenses~~

~~Other operating expenses increased by $1.0 million. The significant components of the increase in other operating expenses included:~~2017; and

$~~730,000~~413,000 in ~~higher staffing~~lower benefits and ~~associated~~employee-related costs ~~for additional personnel to support growth~~ (since we are self-insured for healthcare, benefits costs fluctuate depending upon ~~claims filed);~~

~~$347,000 in higher depreciation, amortization and property tax costs due to increased capital investments and amortization of intangible assets acquired through acquisitions in 2017; and~~

~~$293,000 in expenses associated with the incremental margin from Eight Flags~~filed claims).

Unregulated Energy Segment

For the ~~nine months~~quarter ended ~~September 30, 2017~~March 31, 2018 compared to the ~~nine months~~quarter ended ~~September 30, 2016~~

March 31, 2017


	Nine Months Ended						Three Months Ended
	September 30,				Increase		March 31,				Increase
	2017		2016		(decrease)		2018		2017		(decrease)
(in thousands)
Revenue	$	220,462	$	136,361	$	84,101	$	145,367	$	92,725	$	52,642
Cost of sales	166,635		90,981		75,654		115,066		65,906		49,160
Gross margin	53,827		45,380		8,447		30,301		26,819		3,482
Operations & maintenance	34,971		30,136		4,835		13,359		12,380		979
Depreciation & amortization	5,833		4,512		1,321		2,167		1,903		264
Other taxes	2,519		1,465		1,054		1,091		961		130
Total operating expenses	43,323		36,113		7,210		16,617		15,244		1,373
Operating income	$	10,504	$	9,267	$	1,237	$	13,684	$	11,575	$	2,109

Operating income for the Unregulated Energy segment for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 was ~~$10.5 million, an increase of $1.2~~$13.7 million, compared to ~~the~~operating income of $11.6 million for same period in ~~2016.~~2017. The ~~increased~~increase in operating income of $2.1 million was due to an increase in gross margin of ~~$8.4~~$3.5 million, which was ~~partially~~ offset by a ~~$7.2~~$1.4 million increase in operating expenses.

Gross Margin

Items contributing to the ~~period-over-period~~quarter-over-quarter increase ~~of $8.4 million~~ in gross margin are listed in the following table:

(in thousands)
Gross margin for the nine months ended September 30, 2016 $ 45,380
Factors contributing to the gross margin increase for the nine months ended September 30, 2017:
Eight Flags' CHP plant 4,186
Natural Gas Marketing 1,760
Pricing Amendments to Aspire Energy's Long-Term Agreements 1,143
Propane Wholesale Sales 728
Customer consumption - weather and other 168
Other 462
Gross margin for the nine months ended September 30, 2017 $ 53,827



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

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

~~Eight Flags~~PESCO

~~Eight Flags' CHP plant, which commenced operations~~For the three months ended March 31, 2018, PESCO's gross margin decreased by $2.3 million compared to the same period in ~~June 2016, generated $4.2 million in additional gross margin.~~2017. Lower first quarter 2018 margin from PESCO resulted from the following:

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~~Natural Gas Marketing~~

~~PESCO~~



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

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

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

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

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

Propane delivery operations - additional ~~gross~~customer consumption - weather

Gross margin increased by $2.0 million, due primarily to increased deliveries of ~~$1.8 million for~~propane as a result of colder temperatures in the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018, compared to the same period in ~~2016. The increase~~2017.

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

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

Aspire Energy - customer consumption - weather

Gross margin ~~was generated primarily from providing~~increased by $941,000, as a result of increased deliveries of natural gas, due primarily to ~~approximately 40,000 end users within one customer pool pursuant~~colder temperatures during the three months ended March 31, 2018, compared to the ~~supplier agreement with Columbia Gas, which expired on March 31, 2017, as well as an increase~~same period in ~~commercial and industrial customers served in Florida, offset by lower gross margin in the Mid-Atlantic region.~~2017.

~~Pricing Amendments to Aspire Energy's Long-Term Agreements~~

An increase in gross margin of $1.1 million was due to favorable pricing amendments to long-term sales agreements, which generated $1.6 million in gross margin, offset by the absence of a one-time management fee of ~~$560,000 paid to Aspire Energy by CGC in the first quarter of 2016.~~

Wholesale Propane Margins

Gross margin increased by ~~$728,000,~~$379,000, due ~~primarily~~ to ~~favorable supply management activities~~a higher margin per gallon and an increase in volume delivered for the Delmarva Peninsula propane distribution operations.

~~Customer Consumption~~

Aspire Energy - ~~Weather~~increased margin driven by growth and ~~Other~~other factors

Gross margin increased by ~~$168,000, due primarily to higher sales of propane as a result of timing of deliveries for our propane distributions operations, coupled with increased demand for propane in Florida~~$319,000, due to ~~weather conditions~~customer growth and upgrade of pipeline pressure, which resulted in ~~the third quarter~~an increase in deliveries of ~~2017. This was partially offset by the impact of warmer weather primarily during the first three months of 2017.~~natural gas.

Other Operating Expenses

Other operating expenses increased by ~~$7.2 million. The significant components of the increase in other operating expenses included:~~

~~$2.8~~$1.4 million, due primarily to $969,000 in higher ~~operating expenses by Eight Flags' CHP plant in support of the margin generated;~~

~~$1.5 million in higher payroll~~staffing and associated costs for additional personnel to support ~~growth;~~

~~$950,000 in higher benefits and employee-related costs in 2017 (since we are self-insured for healthcare, benefits costs fluctuate depending upon claims filed);~~

~~$800,000 in higher depreciation expense, of which $424,000 relates to a credit adjustment in 2016 recorded in conjunction with the final valuation for Aspire Energy; and~~

~~$350,000 in higher outside services costs associated primarily with~~ growth and ~~ongoing compliance activities.~~increased deliveries driven by the significantly colder weather in the first quarter of 2018, compared to the same period in 2017.

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OTHER ~~INCOME (EXPENSE),~~EXPENSE, NET

For the quarter ended ~~September 30, 2017~~March 31, 2018 compared to the quarter ended ~~September 30, 2016~~March 31, 2017

Other ~~income (expense),~~expense, net, which includes non-operating investment income (expense), interest income, late fees charged to customers, ~~and~~ gains or losses from the sale of assets and pension and other benefits expense, increased by ~~$267,000~~$768,000 in the ~~third~~first quarter of ~~2017,~~2018, compared to the same period in ~~2016, due primarily to the gain from the sale of assets within our unregulated energy businesses.~~

~~For the nine months ended September 30, 2017 compared to the nine months ended September 30, 2017~~

Other income (expense), net, which includes non-operating investment income (expense), interest income, late fees charged to customers and gains or losses from the sale of assets, decreased by $575,000 for the first nine months of 2017, compared to the same period in 2016, due partly to costs associated with the termination of a lease for Xeron partially offset by the gain from the sale of assets within our unregulated energy businesses.2017.

INTEREST CHARGES

For the quarter ended ~~September 30, 2017~~March 31, 2018 compared to the quarter ended ~~September 30, 2016~~March 31, 2017

Interest charges for the three months ended ~~September 30, 2017~~March 31, 2018 increased by ~~$599,000,~~$925,000, compared to the same period in ~~2016,~~2017, attributable primarily to an increase of ~~$410,000~~$531,000 in interest on long-term debt, largely as a result of the issuance of the Prudential Shelf Notes in April 2017, and an increase of ~~$266,000~~$556,000 in interest on higher short-term borrowings.

~~For the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016~~

Interest charges for the nine months ended September 30, 2017 increased by $1.1 million, compared to the same period in 2016, attributable to an increase of $691,000 in interest on higher short-term borrowings and an increase of $618,000 in interest on long-term debt, largely as a result of the issuance of the Prudential Shelf Notes in April 2017.

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INCOME TAXES

For the quarter ended ~~September 30, 2017~~March 31, 2018 compared to the quarter ended ~~September 30, 2016~~March 31, 2017

Income tax expense was ~~$4.3~~$10.0 million for the three months ended ~~September 30, 2017,~~March 31, 2018, compared to ~~$3.0~~$12.5 million in the same period in 2016. The increase in income tax expense was due primarily to an increase in our operating results. Our effective income tax rate was 38.8 percent and 40.4 percent, for the three months ended September 30, 2017 and 2016, respectively.

~~For the nine months ended September 30, 2017 compared to the nine months ended September 30, 2017~~

~~Income tax expense was $20.8 million for the nine months ended September 30, 2017, compared to $21.4 million in the same period in 2016.~~2017. The decrease in income tax expense was due primarily to ~~a decrease~~the impact of the TCJA in ~~our operating results.~~the first quarter of 2018. Our effective income tax rate was ~~39.4~~27.0 percent and 39.5 percent, for the ~~nine~~three months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ respectively.

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FINANCIAL POSITION, LIQUIDITY AND CAPITAL RESOURCES

Our capital requirements reflect the capital-intensive and seasonal nature of our business and are principally attributable to investment in new plant and equipment, retirement of outstanding debt and seasonal variability in working capital. We rely on cash generated from operations, short-term borrowings, and other sources to meet normal working capital requirements and to temporarily finance capital expenditures. We may also issue long-term debt and equity to fund capital expenditures and to more closely align our capital structure to our target capital structure.

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

Capital expenditures for investments in new or acquired plant and equipment are our largest capital requirements. Our capital expenditures were ~~$132.4~~$61.2 million for the ~~nine~~three months ended ~~September 30, 2017.~~March 31, 2018.

We ~~originally~~ budgeted ~~$260.3~~$181.6 million for capital expenditures ~~during 2017, and we currently project~~in 2018. The following table shows the 2018 capital ~~expenditures of approximately $214.7 million in 2017. Our current forecast~~expenditure budget by segment and by business ~~line is shown below:~~line:


	2017		2018
(dollars in thousands)
Regulated Energy:
Natural gas distribution	$	76,771	$	53,899
Natural gas transmission	93,737		92,562
Electric distribution	10,768		7,972
Total Regulated Energy	181,276		154,433
Unregulated Energy:
Propane distribution	10,458		11,235
Other unregulated energy	16,417		5,827
Total Unregulated Energy	26,875		17,062
Other:
Corporate and other businesses	6,507		10,097
Total Other	6,507		10,097
Total 2017 Capital Expenditures	$	214,658
Total 2018 Budgeted Capital Expenditures			$	181,592

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

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

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Capital Structure

We are committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access capital markets when required. This commitment, along with adequate and timely rate relief for our regulated energy operations, is intended to ensure our ability to attract capital from outside sources at a reasonable cost. We believe that the achievement of these objectives will provide benefits to our customers, creditors and investors.

The following table presents our capitalization, excluding and including short-term borrowings, as of ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016:~~2017:


	September 30, 2017				December 31, 2016				March 31, 2018				December 31, 2017
(in thousands)
Long-term debt, net of current maturities	$	201,248	30	%	$	136,954	23	%	$	222,014	31	%	$	197,395	29	%
Stockholders’ equity	463,820		70	%	446,086		77	%	505,241		69	%	486,294		71	%
Total capitalization, excluding short-term debt	$	665,068	100	%	$	583,040	100	%	$	727,255	100	%	$	683,689	100	%

	September 30, 2017				December 31, 2016				March 31, 2018				December 31, 2017
(in thousands)
Short-term debt	$	203,098	23	%	$	209,871	26	%	$	229,108	24	%	$	250,969	26	%
Long-term debt, including current maturities	213,384		24	%	149,053		19	%	231,403		24	%	206,816		22	%
Stockholders’ equity	463,820		53	%	446,086		55	%	505,241		52	%	486,294		52	%
Total capitalization, including short-term debt	$	880,302	100	%	$	805,010	100	%	$	965,752	100	%	$	944,079	100	%

Included in the long-term debt balances at ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016,~~2017, was a capital lease obligation associated with Sandpiper's capacity, supply and operating agreement (at ~~September 30, 2017, $1.0 million~~March 31, 2018, $249,000 excluding current maturities and ~~$2.4~~$1.7 million including current maturities and, at December 31, ~~2016, $2.1 million~~2017, $620,000 excluding current maturities and ~~$3.5~~$2.1 million including current maturities). At the closing of the ESG acquisition in May 2013, Sandpiper entered into this agreement, which has a six-year term. The capacity portion of this agreement is accounted for as a capital lease.

Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. We have maintained a ratio of equity to total capitalization, including short-term borrowings, between 50 percent and 5759 percent during the past three years. In September 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million, which were added to our general funds and used primarily to repay a portion of our short-term debt under unsecured lines of credit.

As described below under “Short-term Borrowings,” we entered into the Credit Agreement and the Revolver with the Lenders in October 2015, which increased our borrowing capacity by $150.0 million. To facilitate the refinancing of a portion of the short-term borrowings into long-term debt, as appropriate, we also entered into the Prudential Shelf Agreement with Prudential for the potential private placement of the Prudential Shelf Notes as further described below under the heading “Shelf Agreements.” In addition, we also entered into the MetLife and NYL Shelf Agreements, as described in further detail below, to have additional debt capital available to fund future growth capital expenditures.

~~For larger revenue-generating capital projects, we~~We will seek to align, as much as feasible, any long-term debt or equity issuance(s) with the commencement of service, and associated ~~earnings.~~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 ~~through October 8, 2018,~~ we may request that Prudential purchase up to $150.0 million of our ~~Prudential Shelf Notes. The Prudential Shelf Notes~~unsecured senior debt. As of March 31, 2018, we have a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance. Prudential is under no obligation to purchase any of the Prudential Shelf Notes. The interest rate and terms of payment of any series of the Prudential Shelf Notes will be determined at the time of purchase.

~~In May 2016, Prudential confirmed and accepted our request that Prudential purchase~~issued $70.0 million of ~~3.25 percent~~3.25% Prudential Shelf Notes under the Prudential Shelf Agreement. We issued the Prudential Shelf Notes on April 21, 2017 and used the proceeds to reduce short-term borrowings under the Revolver, which had increased as a result of funding capital expenditures on a temporary basis.

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In March 2017, we entered into the MetLife Shelf Agreement and the NYL Shelf Agreement, under which we may request that MetLife and NYL, through March 2, 2020, purchase up to $150.0 million and $100.0 million, respectively, of our unsecured senior debt. The unsecured senior debt atwould have a fixed interest rate and ~~with~~ 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.

As of ~~September 30, 2017, no unsecured notes~~March 31, 2018, we have ~~been issued~~$230.0 million of additional potential borrowing capacity under ~~either~~ the Prudential and MetLife Shelf Agreements. The Prudential Shelf Agreement orand the NYL Shelf ~~Agreement.~~Agreement set forth certain business covenants to which we are subject when any note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.

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Short-term Borrowings

Our outstanding short-term borrowings at ~~September 30, 2017~~March 31, 2018 and December 31, ~~2016~~2017 were ~~$203.1~~$229.1 million and ~~$209.9~~$251.0 million ~~respectively. The~~at weighted average interest rates ~~for our short-term borrowings were 1.96~~of 2.71 percent and ~~1.49~~2.42 percent, ~~for the nine months ended September 30, 2017 and 2016,~~ 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, 2017,~~March 31, 2018, we had ~~four~~five unsecured bank credit facilities with ~~three~~four financial institutions totaling ~~$180.0~~$220.0 million in available credit.

In addition, since October 2015, we have $150.0 million of additional short-term debt capacity available under the Revolver. The terms of the Revolver ~~with five participating Lenders.~~ are described in further detail below. None of the unsecured bank lines of credit requires compensating balances.

The $150.0 million Revolver ~~has a five-year term~~is available through October 8, 2020 and is subject to the terms and conditions set forth in the Credit Agreement. Borrowings under the Revolver will be used for general corporate purposes, including repayments of short-term borrowings, working capital requirements and capital expenditures. Borrowings under the Revolver will bear interest at: (i) the LIBOR Rate plus an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization, both as defined by the Credit Agreement, or (ii) the base rate plus 0.25% or less. Interest is payable quarterly, and the Revolver is subject to a commitment fee on the unused portion of the facility. We have the right, under certain circumstances, to extend the expiration date for up to two years on any anniversary date of the Revolver, with such extension subject to the Lenders' approval. We may also request the Lenders to increase the Revolver to $200.0 million, with any increase at the sole discretion of each Lender.

~~None of the unsecured bank lines of credit requires compensating balances. We are currently authorized by our Board of Directors to incur up to $275.0 million of short-term borrowing.~~

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 and ~~2016:~~2017:


	Nine Months Ended						Three Months Ended
	September 30,						March 31,
	2017			2016			2018			2017
(in thousands)
Net cash provided by (used in):
Operating activities	$	98,372		$	85,733		$	66,672		$	59,954
Investing activities	(141,453		)	(109,730		)	(62,971		)	(42,193		)
Financing activities	42,289			22,678			(3,319		)	(16,239		)
Net decrease in cash and cash equivalents	(792		)	(1,319		)
Net increase in cash and cash equivalents							382			1,522
Cash and cash equivalents—beginning of period	4,178			2,855			5,614			4,178
Cash and cash equivalents—end of period	$	3,386		$	1,536		$	5,996		$	5,700

Cash Flows Provided By Operating Activities

Changes in our cash flows from operating activities are attributable primarily to changes in net income, adjusted for non-cash items such as depreciation and changes in deferred income taxes, ~~depreciation~~ 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.

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During the ~~nine~~three months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ net cash provided by operating activities was ~~$98.4~~$66.7 million and ~~$85.7~~$60.0 million, respectively, resulting in an increase in cash flows of ~~$12.6~~$6.7 million. Significant operating activities generating the cash flows change were as follows:

Net income, adjusted for reconciling activities, increased cash flows by $17.9 million, due primarily to an increase in deferred income taxes as a result of the availability and utilization of bonus depreciation in the first nine months of 2017, which resulted in a higher book-to-tax timing difference and higher non-cash adjustments for depreciation and amortization related to increased investing activities.

~~Changes in income taxes receivable decreased cash flows by $18.7 million, due to lower tax refunds during the first nine months of 2017 compared to the same period in 2016.~~

Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities ~~increased~~decreased cash flows by ~~$14.1~~$16.5 million, due primarily to ~~higher revenues and~~ the timing of the receipt of customer payments as well as the timing of payments to vendors.

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

Net cash flows from changes in ~~other~~propane inventories ~~decreased~~increased by approximately ~~$6.1~~$5.8 million, ~~due primarily to additional pipes and other construction inventory purchases,~~as a result of higher use of propane, which ~~increased~~decreased the levels of our inventory.

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Changes in net regulatory assets and liabilities increased cash flows by ~~$4.3~~$5.4 million, due primarily to ~~changes~~the change in ~~GRIP and~~ fuel costs collected through the various cost recovery mechanisms.

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

Changes in accrued compensation, other assets and liabilities and ~~accrued compensation increased~~income tax receivables decreased cash ~~flows~~flow by ~~$1.2~~$4.8 million.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled ~~$141.5~~$63.0 million and ~~$109.7~~$42.2 million during the ~~nine~~three months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ respectively, resulting in a decrease in cash flows of ~~$31.8~~$20.8 million. ~~Significant investing activities generating the cash flows change were as follows:~~

Cash paid for capital expenditures increased by ~~$20.5~~$20.9 million to ~~$130.1~~$63.1 million for the first ~~nine~~three months of ~~2017,~~2018, compared to ~~$109.6~~$42.2 million for the same period in ~~2016.~~

~~Net cash~~2017, which was slightly offset by an increase in proceeds from the sales of ~~$11.7 million was used to acquire ARM and Chipola during the first nine months of 2017; there were no corresponding transactions in 2016.~~assets.

Cash Flows Used in Financing Activities

Net cash ~~provided~~used in financing activities totaled ~~$42.3~~$3.3 million and ~~$22.7~~$16.2 million during the ~~nine~~three months ended ~~September 30,~~March 31, 2018 and 2017, ~~and 2016,~~ respectively. The ~~increase~~decrease in net cash used in financing activities for the ~~nine~~three months ended ~~September 30, 2017~~March 31, 2018 resulted primarily from the following:

We received ~~$69.8~~$25.0 million in net cash proceeds from the ~~issuance~~Revolver, which was advanced on a long-term basis, partially offset by an increased repayment of ~~the Prudential Shelf Notes, and we paid $2.9~~short-term borrowing of $13.1 million ~~more in scheduled long-term debt principal payments and capital lease obligations payments.~~

~~Net cash flows decreased by $57.3 million from proceeds related to the issuance of common stock during the third quarter of 2016.~~

~~Net repayments~~ under our line of credit ~~arrangements~~arrangements. Our additional financing needs are a result of ~~$3.8 million for~~ the ~~nine months ended September 30, 2017, compared to net repayments of $21.4 million for~~additional capital expenditures during the ~~same period in 2016, increased cash flows by $17.6 million. Change in cash overdrafts decreased cash flows by $5.5 million.~~quarter.

We paid ~~$14.8~~$5.1 million in cash dividends for the ~~nine~~three months ended ~~September 30, 2017,~~March 31, 2018, compared to ~~$13.0~~$4.8 million for the ~~nine~~three months ended ~~September 30, 2016.~~March 31, 2017.

Off-Balance Sheet Arrangements

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. ~~PESCO has~~These subsidiaries have never defaulted on ~~its~~their obligations to pay ~~its~~their suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at ~~September 30, 2017~~March 31, 2018 was ~~$71.9~~$72.7 million, with the guarantees expiring on various dates through ~~September 2018.~~March 2019.

We have issued letters of credit totaling ~~$5.8~~$5.0 million related to the electric transmission services for FPU's northwest electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, and to our current and previous primary insurance ~~carriers.~~carrier. These letters of credit have ~~various~~varying expiration dates through ~~June 2018.~~December 2019. There have been no draws on these letters of credit as of ~~September 30, 2017.~~March 31, 2018. We do not anticipate that the letters of credit will be drawn upon by

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the counterparties, and we expect that they will be renewed to the extent necessary in the future. Additional information is presented in Note 56, 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 ~~2016~~2017 Annual Report on Form 10-K, except for ~~long-term debt,~~ commodity purchase obligations and forward contracts entered into in the ordinary course of our business. The following table summarizes ~~long-term debt,~~the commodity purchase and forward contract obligations at ~~September 30, 2017:~~March 31, 2018:


	Payments Due by Period										Payments Due by Period
	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total		Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
(in thousands)
Long-term debt ⁽¹⁾	$	10,698	$	24,226	$	40,700	$	135,800	$	211,424
Purchase obligations - Commodity ⁽²⁾	47,069		1,693		—		—		48,762
Purchase obligations - Commodity ⁽¹⁾											$	70,476	$	55,912	$	—	$	—	$	126,388
Total	$	57,767	$	25,919	$	40,700	$	135,800	$	260,186	$	70,476	$	55,912	$	—	$	—	$	126,388


⁽¹⁾	~~Excludes capital lease obligation, debt issuance costs and unamortized debt discount of $1,960.~~

⁽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.

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Rates and Regulatory Matters

Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by the respective state PSC; Eastern Shore is subject to regulation by the FERC; and Peninsula Pipeline is subject to regulation by the Florida PSC. At ~~September 30, 2017,~~March 31, 2018, we were involved in regulatory matters in each of the jurisdictions in which we operate. Our significant regulatory matters are fully described in Note 34, 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, 2017~~,March 31, 2018, consists of fixed-rate Senior Notes and $8.0 million of fixed-rate secured debt. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowings based in part on the fluctuation in interest rates. Additional information about our long-term debt is disclosed in Note ~~13,~~14, Long-term Debt, in the condensed consolidated financial statements.

COMMODITY PRICE RISK

Regulated Energy Segment

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

Unregulated Energy Segment

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

We can store up to approximately ~~6.2~~6.8 million gallons of propane (including leased storage and rail cars) during the winter season to meet our customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause

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

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

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

PESCO is subject to commodity price risk on its open positions to the extent that market prices for natural gas liquids and natural gas deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts is monitored daily for compliance with our Risk Management Policy, which includes volumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed daily by our oversight officials. In addition, the Risk Management Committee reviews periodic reports on markets, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts.

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



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

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

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



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

WHOLESALE CREDIT RISK

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

Additional information about our derivative instruments is disclosed in Note ~~11,~~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, 2017.~~March 31, 2018. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of ~~September 30, 2017.~~March 31, 2018.

Changes in Internal Control over Financial Reporting

Beginning January 1, 2018, we adopted ASU 2014-09, Revenue from Contracts with Customers. The impacts of the adoption are discussed in detail in Note 1, Summary of Accounting Policies, and Note 3, Revenue Recognition, in the notes to the condensed consolidated financial statements within this Form 10-Q. In conjunction with this adoption, we implemented changes to our controls related to revenue which were not material to our internal controls over financial reporting. These included the development of new policies based on the five-step model provided in the new revenue standard, enhanced contract review requirements, and other ongoing monitoring activities. These controls were designed to provide assurance, at a reasonable level, of the fair presentation of our condensed consolidated financial statements and related disclosures. During the quarter ended ~~September 30, 2017,~~March 31, 2018, there was no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION

Item 1. Legal Proceedings

As disclosed in Note 56, 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, ~~2016,~~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, 2017
through July 31, 2017 ⁽¹⁾
387
$ 75.75
—
—
August 1, 2017
through August 31, 2017
—
$ —
—
—
September 1, 2017
through September 30, 2017
—
$ —
—
—
Total 387
$ 75.75
—
—



	Total Number of Shares	Average Price Paid		Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Number of Shares That May Yet Be Purchased Under the Plans
Period	Purchased	per Share		or Programs ⁽²⁾	or Programs ⁽²⁾
January 1, 2018 through January 31, 2018 ⁽¹⁾	388	$	76.00	—	—
February 1, 2018 through February 28, 2018	—	$	—	—	—
March 1, 2018 through March 31, 2018	—	$	—	—	—
Total	388	$	76.00	—	—

⁽¹⁾

Chesapeake Utilities purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain ~~Directors~~directors and ~~Senior Executives~~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, ~~2016~~2017. During the quarter ended ~~September 30, 2017, 387~~March 31, 2018, 388 shares were purchased through the reinvestment of dividends on deferred stock units.


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

Item 3. Defaults upon Senior Securities

None.

Item 5. Other Information

~~None.~~Departure of named executive officer

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

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Item 6.	Exhibits




10.1		Form of Performance Share Agreement, effective February 26, 2018 for the period 2018 to 2020, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Michael P. McMasters, Beth W. Cooper, Stephen C. Thompson, Jeffry M. Householder and James F. Moriarty is filed herewith.

31.1		Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

31.2		Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.

32.1		Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350.

32.2		Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350.

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

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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, 2017~~May 8, 2018

- 5452



	Gross Margin for the Period
	Three Months Ended							Nine Months Ended						Year Ended
	September 30,							September 30,						December 31,		Estimate for
	2017		2016		Variance			2017		2016		Variance		2016		2017		2018		2019
Major Projects and Initiatives Recently Completed
Capital Investment Projects	$	9,807	$	8,963	$	844		$	29,533	$	21,822	$	7,711	$	29,819	$	35,346	$	31,814	$	32,724
Eastern Shore Rate Case ⁽¹⁾	1,020		—		1,020			1,020		—		1,020		—		TBD		TBD		TBD
Settled Delaware Division Rate Case	431		469		(38		)	1,596		1,347		249		1,487		2,250		2,250		2,250
Total Major Projects and Initiatives Recently Completed	11,258		9,432		1,826			32,149		23,169		8,980		31,306		37,596		34,064		34,974
Future Major Projects and Initiatives
Capital Investment Projects
2017 Eastern Shore System Expansion	—		—		—			—		—		—		—		126		9,313		15,799
Northwest Florida Expansion	—		—		—			—		—		—		—		—		3,484		5,127
Other Florida Pipeline Expansions	—		—		—			—		—		—		—		—		2,044		2,542
Total Future Major Projects and Initiatives	—		—		—			—		—		—		—		126		14,841		23,468
Total	$	11,258	$	9,432	$	1,826		$	32,149	$	23,169	$	8,980	$	31,306	$	37,722	$	48,905	$	58,442



(in thousands)
Gross margin for the three months ended September 30, 2016	$	45,375
Factors contributing to the gross margin increase for the three months ended September 30, 2017:
Implementation of Eastern Shore rates	1,020
Additional Revenue from GRIP in Florida	406
Natural gas growth (excluding service expansions)	347
Other	(239		)
Gross margin for the three months ended September 30, 2017	$	46,909



(in thousands)
Gross margin for the nine months ended September 30, 2016	$	145,446
Factors contributing to the gross margin increase for the nine months ended September 30, 2017:
Additional revenue from GRIP in Florida	1,619
Natural gas growth (excluding service expansions)	1,574
Service expansions	1,371
Customer consumption - weather and other	(1,249		)
Implementation of Eastern Shore rates	1,020
Service to Eight Flags	534
Implementation of Delaware Division Rates	249
Other	583
Gross margin for the nine months ended September 30, 2017	$	151,147



(in thousands)
Gross margin for the three months ended September 30, 2016	$	10,202
Factors contributing to the gross margin increase for the three months ended September 30, 2017:
Customer Consumption - Weather and Other	1,165
Retail Propane Margins	440
Eight Flags' CHP Plant	297
Pricing Amendments to Aspire Energy's Long-Term Agreements	291
Wholesale Propane Margins	271
Wind-down of Xeron operations	233
Other	373
Gross margin for the three months ended September 30, 2017	$	13,272