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, ~~2016~~2017



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

For the transition period from to

Commission File Number: 001-11590




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



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

909 Silver Lake Boulevard, Dover, Delaware 19904

(Address of principal executive offices, including Zip Code)

(302) 734-6799

(Registrant’s telephone number, including area code)

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

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

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

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 — ~~16,301,161~~16,344,442 shares outstanding as of October 31, ~~2016~~2017.

Table of Contents




PART I—FINANCIAL INFORMATION		1

ITEM 1.	FINANCIAL STATEMENTS	1

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	3128

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	5550

ITEM 4.	CONTROLS AND PROCEDURES	5751

PART II—OTHER INFORMATION		5852

ITEM 1.	LEGAL PROCEEDINGS	5852

ITEM 1A.	RISK FACTORS	5852

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	5852

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	5852

ITEM 5.	OTHER INFORMATION	5852

ITEM 6.	EXHIBITS	5953

SIGNATURES		6054

Table of Contents

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

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

CDD: Cooling degree-day, which is ~~the~~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

Chesapeake or Chesapeake Utilities: Chesapeake Utilities Corporation, ~~its divisions~~ 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

CIAC: Contributions from customers that are used to construct facilities

CGC: Consumer Gas Cooperative, an Ohio natural gas cooperative

CHP: ~~A combined~~Combined heat and power plant ~~constructed by Eight Flags on Amelia Island, Florida~~

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

Company: Chesapeake Utilities Corporation, ~~its divisions~~ 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 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

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

Dts/d: Dekatherms per day

Eastern Shore: Eastern Shore Natural Gas Company, a wholly-owned natural gas transmission subsidiary of Chesapeake Utilities

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

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

EPA: United States Environmental Protection Agency

ESG: Eastern Shore Gas Company and its affiliates

FASB: Financial Accounting Standards Board

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

FDEP: Florida Department of Environmental Protection

~~FDOT:~~ ~~Florida Department of Transportation~~

~~Table of Contents~~

FGT: Florida Gas Transmission Company

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

~~Gatherco:~~ ~~Gatherco, Inc., a corporation that merged with and into Aspire Energy on April 1, 2015~~

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

Gulf Power: Gulf Power Company, 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

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

~~NAM:~~MWH: ~~Natural Attenuation Monitoring~~Megawatt hour, which is a unit of measurement for electricity

~~NYSE:~~ NYL:New York ~~Stock Exchange~~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

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

OTC: Over-the-counter

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

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

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 ~~for~~

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 ~~potential future~~date of issuance

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

~~Revolver:~~ ~~Our unsecured revolving credit facility with the Lenders~~

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., aChesapeake Utilities' wholly-owned subsidiary, ~~of Chesapeake Utilities providing~~which provides a tariff-based distribution service to customers in Worcester County, Maryland

~~Table of Contents~~

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

~~SCO supplier agreement:~~ ~~Standard Choice Offer (SCO) supplier agreement between PESCO and Columbia Gas~~

SEC: Securities and Exchange Commission

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

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

~~Shelf Agreement:~~ An agreement entered into by Chesapeake Utilities and Prudential pursuant to which Chesapeake Utilities may request that Prudential purchase, by October 8, 2018, up to $150.0 million of Shelf Notes at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance

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

SICP: 2013 Stock and Incentive Compensation Plan

~~SIR:~~ ~~A system improvement rate adder designed to fund system expansion costs in Sandpiper Energy’s service territories~~

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

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

Table of Contents

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					Nine Months Ended
	September 30,					September 30,						September 30,					September 30,
	2016			2015		2016			2015			2017		2016			2017			2016
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	70,019		$	63,796	$	226,630		$	235,438		$	69,703	$	70,019		$	238,353		$	226,630
Unregulated Energy and other	38,329			28,117		130,356			119,238			57,233		38,329			198,827			130,356
Total Operating Revenues	108,348			91,913		356,986			354,676			126,936		108,348			437,180			356,986
Operating Expenses
Regulated Energy cost of sales	24,644			23,161		81,184			101,414			22,794		24,644			87,206			81,184
Unregulated Energy and other cost of sales	28,183			17,959		85,142			73,465			44,066		28,183			145,325			85,142
Operations	30,126			26,388		85,370			79,522			29,667		30,126			92,990			85,370
Maintenance	3,542			2,603		8,925			8,033			2,737		3,542			9,370			8,925
Gain from a settlement	—			—		(130		)	(1,500		)	—		—			(130		)	(130		)
Depreciation and amortization	8,209			7,636		23,493			22,155			9,362		8,209			27,267			23,493
Other taxes	3,488			3,257		10,725			10,000			4,071		3,488			12,572			10,725
Total Operating Expenses	98,192			81,004		294,709			293,089			112,697		98,192			374,600			294,709
Operating Income	10,156			10,909		62,277			61,587			14,239		10,156			62,580			62,277
Other (expense) income, net	(28		)	36		(68		)	(3		)
Other income (expense), net												239		(28		)	(643		)	(68		)
Interest charges	2,722			2,492		7,996			7,425			3,321		2,722			9,133			7,996
Income Before Income Taxes	7,406			8,453		54,213			54,159			11,157		7,406			52,804			54,213
Income taxes	2,990			3,334		21,401			21,638			4,324		2,990			20,781			21,401
Net Income	$	4,416		$	5,119	$	32,812		$	32,521		$	6,833	$	4,416		$	32,023		$	32,812
Weighted Average Common Shares Outstanding:
Basic	15,372,413			15,258,819		15,324,932			15,035,569			16,344,442		15,372,413			16,334,210			15,324,932
Diluted	15,412,783			15,306,843		15,365,955			15,083,641			16,389,635		15,412,783			16,378,633			15,365,955
Earnings Per Share of Common Stock:
Basic	$	0.29		$	0.34	$	2.14		$	2.16		$	0.42	$	0.29		$	1.96		$	2.14
Diluted	$	0.29		$	0.33	$	2.14		$	2.16		$	0.42	$	0.29		$	1.96		$	2.14
Cash Dividends Declared Per Share of Common Stock	$	0.3050		$	0.2875	$	0.8975		$	0.8450		$	0.3250	$	0.3050		$	0.9550		$	0.8975

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						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2016			2015			2016			2015			2017			2016			2017			2016
(in thousands)
Net Income	$	4,416		$	5,119		$	32,812		$	32,521		$	6,833		$	4,416		$	32,023		$	32,812
Other Comprehensive Income (Loss), net of tax:
Other Comprehensive (Loss) Income, net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(8), $(7), $(23) and $(20), respectively	(12		)	(10		)	(37		)	(30		)
Net gain, net of tax of $66, $62, $200 and $187, respectively	100			93			300			278
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
Cash Flow Hedges, net of tax:
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $38, $(51), $360 and $(29), respectively	51			(75		)	548			(43		)
Total Other Comprehensive Income	139			8			811			205
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
Comprehensive Income	$	4,555		$	5,127		$	33,623		$	32,726		$	6,820		$	4,555		$	31,642		$	33,623

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

Table of Contents

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)


Assets	September 30, 2016			December 31, 2015			September 30, 2017			December 31, 2016
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	908,822		$	842,756		$	1,050,332		$	957,681
Unregulated Energy	194,743			145,734			207,331			196,800
Other businesses and eliminations	20,835			18,999			26,061			21,114
Total property, plant and equipment	1,124,400			1,007,489			1,283,724			1,175,595
Less: Accumulated depreciation and amortization	(237,434		)	(215,313		)	(267,138		)	(245,207		)
Plus: Construction work in progress	49,082			62,774			69,053			56,276
Net property, plant and equipment	936,048			854,950			1,085,639			986,664
Current Assets
Cash and cash equivalents	1,536			2,855			3,386			4,178
Accounts receivable (less allowance for uncollectible accounts of $792 and $909, respectively)	47,103			41,007
Accounts receivable (less allowance for uncollectible accounts of $912 and $909, respectively)							52,775			62,803
Accrued revenue	9,506			12,452			14,307			16,986
Propane inventory, at average cost	4,106			6,619			5,226			6,457
Other inventory, at average cost	3,867			3,803			12,711			4,576
Regulatory assets	6,045			8,268			9,761			7,694
Storage gas prepayments	8,192			3,410			6,876			5,484
Income taxes receivable	13,178			24,950			26,741			22,888
Prepaid expenses	7,603			7,146			10,899			6,792
Mark-to-market energy assets	477			153
Derivative assets, at fair value							1,526			823
Other current assets	543			1,044			4,797			2,470
Total current assets	102,156			111,707			149,005			141,151
Deferred Charges and Other Assets
Goodwill	15,070			14,548			21,944			15,070
Other intangible assets, net	1,938			2,222			4,608			1,843
Investments, at fair value	4,630			3,644			6,380			4,902
Regulatory assets	76,343			77,519			75,793			76,803
Receivables and other deferred charges	4,325			2,831			3,381			2,786
Total deferred charges and other assets	102,306			100,764			112,106			101,404
Total Assets	$	1,140,510		$	1,067,421		$	1,346,750		$	1,229,219

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, 2016			December 31, 2015			September 30, 2017			December 31, 2016
(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)	7,932			7,432			7,955			7,935
Additional paid-in capital	250,202			190,311			252,722			250,967
Retained earnings	185,195			166,235			208,402			192,062
Accumulated other comprehensive loss	(5,029		)	(5,840		)	(5,259		)	(4,878		)
Deferred compensation obligation	2,476			1,883			3,366			2,416
Treasury stock	(2,476		)	(1,883		)	(3,366		)	(2,416		)
Total stockholders’ equity	438,300			358,138			463,820			446,086
Long-term debt, net of current maturities	143,525			149,006			201,248			136,954
Total capitalization	581,825			507,144			665,068			583,040
Current Liabilities
Current portion of long-term debt	12,087			9,151			12,136			12,099
Short-term borrowing	154,490			173,397			203,098			209,871
Accounts payable	41,297			39,300			53,284			56,935
Customer deposits and refunds	26,858			27,173			32,493			29,238
Accrued interest	3,119			1,311			3,361			1,312
Dividends payable	4,678			4,390			5,312			4,973
Accrued compensation	7,823			10,014			8,544			10,496
Regulatory liabilities	2,412			7,365			5,338			1,291
Mark-to-market energy liabilities	29			433
Derivative liabilities, at fair value							1,732			773
Other accrued liabilities	10,260			7,059			13,972			7,063
Total current liabilities	263,053			279,593			339,270			334,051
Deferred Credits and Other Liabilities
Deferred income taxes	205,562			192,600			252,273			222,894
Regulatory liabilities	43,354			43,064			42,915			43,064
Environmental liabilities	8,682			8,942			8,382			8,592
Other pension and benefit costs	32,501			33,481			32,059			32,828
Deferred investment tax credits and other liabilities	5,533			2,597			6,783			4,750
Total deferred credits and other liabilities	295,632			280,684			342,412			312,128
Environmental and other commitments and contingencies (Note 5 and 6)
Environmental and other commitments and contingencies (Note 4 and 5)
Total Capitalization and Liabilities	$	1,140,510		$	1,067,421		$	1,346,750		$	1,229,219

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						Nine Months Ended
	September 30,						September 30,
	2016			2015			2017			2016
(in thousands)
Operating Activities
Net income	$	32,812		$	32,521		$	32,023		$	32,812
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	23,493			22,155			27,267			23,493
Depreciation and accretion included in other costs	5,357			5,280			5,989			5,357
Deferred income taxes, net	12,004			(1,155		)
Deferred income taxes							29,520			12,004
Realized gain on commodity contracts/sale of assets/investments	(405		)	(411		)	(2,817		)	(405		)
Unrealized (gain) loss on investments/commodity contracts	(243		)	60
Unrealized gain on investments/commodity contracts							(695		)	(243		)
Employee benefits and compensation	1,217			901			1,212			1,217
Share-based compensation	1,887			1,445			1,608			1,887
Other, net	42			13			(39		)	42
Changes in assets and liabilities:
Accounts receivable and accrued revenue	(3,835		)	21,898			12,912			(3,835		)
Propane inventory, storage gas and other inventory	(2,179		)	3,166			(8,256		)	(2,179		)
Regulatory assets/liabilities, net	(3,326		)	6,467			927			(3,326		)
Prepaid expenses and other current assets	485			(159		)	(2,860		)	485
Accounts payable and other accrued liabilities	3,679			(9,897		)	4,515			7,187
Income taxes receivable	14,897			14,883
Income taxes (payable) receivable							(3,810		)	14,897
Customer deposits and refunds	(314		)	(1,177		)	3,255			(314		)
Accrued compensation	(2,293		)	(1,406		)	(2,030		)	(2,293		)
Other assets and liabilities, net	(1,053		)	(652		)	(349		)	(1,053		)
Net cash provided by operating activities	82,225			93,932			98,372			85,733
Investing Activities
Property, plant and equipment expenditures	(106,851		)	(97,299		)	(130,137		)	(109,589		)
Proceeds from sales of assets	119			109			601			119
Acquisitions, net of cash acquired	—			(20,930		)	(11,707		)	—
Environmental expenditures	(260		)	(113		)	(210		)	(260		)
Net cash used in investing activities	(106,992		)	(118,233		)	(141,453		)	(109,730		)
Financing Activities
Common stock dividends	(12,964		)	(11,725		)	(14,780		)	(12,964		)
Issuance of stock for Dividend Reinvestment Plan	600			633			254			600
Stock issuance	57,306			—			(10		)	57,306
Tax withholding payments related to net settled stock compensation							(692		)	(770		)
Change in cash overdrafts due to outstanding checks	2,466			2,964			(3,013		)	2,466
Net (repayment) borrowing under line of credit agreements	(21,379		)	35,898
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	(2,581		)	(4,262		)	(5,510		)	(2,581		)
Net cash provided by financing activities	23,448			23,508			42,289			22,678
Net Decrease in Cash and Cash Equivalents	(1,319		)	(793		)	(792		)	(1,319		)
Cash and Cash Equivalents—Beginning of Period	2,855			4,574			4,178			2,855
Cash and Cash Equivalents—End of Period	$	1,536		$	3,781		$	3,386		$	1,536

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																			Common Stock ⁽¹⁾
(in thousands, except shares and per share data)	Number of Shares⁽¹⁾	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 ⁽²⁾
Balance at December 31, 2014	14,588,711	$	7,100	$	156,581	$	142,317		$	(5,676	)	$	1,258	$	(1,258	)	$	300,322
Net income		—		—		41,140			—			—		—			41,140
Other comprehensive loss	—	—		—		—			(164		)	—		—			(164		)
Dividend declared ($1.1325 per share)	—	—		—		(17,222		)	—			—		—			(17,222		)
Retirement savings plan and dividend reinvestment plan	43,275	21		2,214		—			—			—		—			2,235
Common stock issued in acquisition	592,970	289		29,876		—			—			—		—			30,165
Share-based compensation and tax benefit ^{(4) (5)}	45,703	22		1,640		—			—			—		—			1,662
Treasury stock activities	—	—		—		—			—			625		(625		)	—
Balance at December 31, 2015	15,270,659	7,432		190,311		166,235			(5,840		)	1,883		(1,883		)	358,138			15,270,659	$	7,432	$	190,311		$	166,235		$	(5,840	)	$	1,883	$	(1,883	)	$	358,138
Net income	—	—		—		32,812			—			—		—			32,812			—	—		—			44,675			—			—		—			44,675
Other comprehensive income	—	—		—		—			811			—		—			811			—	—		—			—			962			—		—			962
Dividend declared ($0.8975 per share)	—	—		—		(13,852		)	—			—		—			(13,852		)
Dividend declared ($1.2025 per share)																				—	—		—			(18,848		)	—			—		—			(18,848		)
Retirement savings plan and dividend reinvestment plan	30,041	15		1,859		—			—			—		—			1,874			36,253	17		2,225			—			—			—		—			2,242
Stock issuance ⁽³⁾	960,488	467		56,839		—			—			—		—			57,306			960,488	467		56,893			—			—			—		—			57,360
Share-based compensation and tax benefit ⁽⁴⁾ ⁽⁵⁾	36,099	18		1,193		—			—			—		—			1,211			36,099	19		1,538			—			—			—		—			1,557
Treasury stock activities	—	—		—		—			—			593		(593		)	—			—	—		—			—			—			533		(533		)	—
Balance at September 30, 2016	16,297,287	$	7,932	$	250,202	$	185,195		$	(5,029	)	$	2,476	$	(2,476	)	$	438,300
Balance at December 31, 2016																				16,303,499	7,935		250,967			192,062			(4,878		)	2,416		(2,416		)	446,086
Net income																				—	—		—			32,023			—			—		—			32,023
Other comprehensive loss																				—	—		—			—			(381		)	—		—			(381		)
Dividend declared ($0.9550 per share)																				—	—		—			(15,683		)	—			—		—			(15,683		)
Dividend reinvestment plan																				10,771	5		731			—			—			—		—			736
Stock issuance ⁽³⁾																				—	—		(10		)	—			—			—		—			(10		)
Share-based compensation and tax benefit ⁽⁴⁾ ⁽⁵⁾																				30,172	15		1,034			—			—			—		—			1,049
Treasury stock activities																				—	—		—			—			—			950		(950		)	—
Balance at September 30, 2017																				16,344,442	$	7,955	$	252,722		$	208,402		$	(5,259	)	$	3,366	$	(3,366	)	$	463,820


⁽¹⁾	~~Includes 80,024 and 70,631 shares at~~ ~~September 30, 2016~~ ~~and~~ ~~December 31, 2015, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.~~


⁽²⁾	~~2,000~~2,000,000 shares of preferred stock at ~~$0.00001~~$0.01 par value ~~has~~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 and 76,745 shares at September 30, 2017 and December 31, 2016, 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 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 ~~$57.3~~$57.4 million.


⁽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 months ended September 30, ~~2016,~~2017, and for the year ended December 31, ~~2015~~2016, we withheld ~~12,031~~10,269 and ~~12,620~~12,031 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, ~~2015.~~2016. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

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

We reclassified certain amounts in the condensed consolidated ~~balance sheet as of December 31, 2015. We have revised the condensed consolidated~~ statement of cash flows for the nine months ended September 30, ~~2015~~2016 to ~~reflect only property, plant and equipment expenditures paid in cash within~~conform to the Investing Activities section. The non-cash expenditures previously included in that section have now been included in the change in accounts payable and other accrued liabilities amount within the Operating Activities section.current year’s presentation. These ~~revisions~~reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.

~~On September 22, 2016,~~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. The acquired assets complement PESCO’s current asset portfolio and will expand our regional footprint and retail demand in a market where we ~~completed~~have existing pipeline capacity and wholesale liquidity. In connection with the acquisition, we recorded a ~~public offering~~contingent liability 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 $57.3~~$2.5 million, which represents the expected payment of contingent consideration to ARM. 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 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, Calhoun, Gadsden, Liberty, Bay and Washington Counties, Florida.

The revenue and net income from these acquisitions that we included in our condensed consolidated statements of income for the three and nine months ended September 30, 2017, were ~~added~~not material. The amounts recorded in conjunction with our acquisitions are preliminary and subject to ~~our general funds and used primarily to repay a portion of our short-term debt under unsecured lines of credit.~~adjustment based on additional valuations performed during the measurement period.

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

~~Interest - Imputation of Interest~~Inventory (ASC ~~835-30)~~330) - In ~~April~~July 2015, the FASB issued ASU ~~2015-03,~~2015-11, Simplifying the~~Presentation~~ Measurement of ~~Debt Issuance Costs~~Inventory. ~~. This standard requires debt issuance costs~~Under this guidance, inventories are required to be ~~presented in~~measured at the ~~balance sheet as a direct deduction from~~lower of cost or net realizable value. Net realizable value represents the ~~carrying value of the~~estimated selling price less costs associated ~~debt liability, consistent~~ with ~~the presentation of a debt discount.~~completion, disposal and transportation. We adopted ASU ~~2015-03 became effective for us~~2015-11 on January 1, 2016, and we applied the provisions of this standard on a retrospective basis. As a result of the adoption of this standard, debt issuance costs totaling $301,000 and $333,000 at September 30, 2016 and December 31, 2015, respectively, previously presented as other deferred charges, a non-current asset, are now presented as a deduction from long-term debt, net of current maturities, in our condensed consolidated balance sheets.

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

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

~~Business Combinations (ASC 805) - In September 2015, the FASB issued ASU 2015-16,~~ ~~Simplifying the Accounting for Measurement-Period Adjustments~~. The standard eliminates the requirement to restate prior period financial statements for measurement period adjustments and requires that the cumulative impact of a measurement-period adjustments (including

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the impact of prior periods) be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 was effective for our interim and annual financial statements issued after January 1, 2016 and was adopted2017, on a prospective basis. Adoption of this standard did not have a material impact on our financial position or results of operations.

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

Recent Accounting Standards Yet to be Adopted

Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled to 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, Principal versus Agent Considerations (Reporting Revenue Gross versus Net), to clarify the implementation guidance on principal versus agent considerations. For public entities, this standard is effective for 2018 interim and annual financial statements. We have engaged a third party to review our contracts with customers and to aid in assessing the impact this standard may have on our financial position and results of operations.

~~Inventory (ASC 330) - In July 2015, the FASB issued ASU 2015-11,~~ ~~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. ASU 2015-11 will be effective for our interim and annual financial statements issued beginning January 1, ~~2017; however, early adoption is permitted. The standard is to be adopted on a prospective basis.~~ 2018.

We ~~are~~have completed our evaluation of our revenue sources and will continue assessing the impact ~~this standard may have~~ on our financial position, ~~and~~ results of ~~operations.~~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 the standard. We plan to utilize the modified retrospective transition method upon adoption of this standard.

Based on our current assessment, we believe that the implementation of this new standard will not have a material impact on the amount and timing of revenue 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 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 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.

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 ~~update~~guidance will be applied using athe modified retrospective transition ~~approach~~method for leases existing at, or entered into after, the beginning of the earliest comparative period presented in the financial statements. ~~We are evaluating the effect of this update on our financial position and results of operations.~~

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

Statement of Cash Flows (ASC 230) - OnIn August ~~26,~~ 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 ~~are assessing~~believe that the ~~impact of the adoption~~implementation of this ~~ASU~~new standard will not have a material impact on our ~~statements~~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 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.

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. ASU 2017-07 will be effective for our annual and interim financial statements beginning January 1, 2018, although early adoption is permitted. The presentation of the service cost and other components in this update are to be applied retrospectively, and the

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

Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scopeof ModificationAccounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) changes as a result of a change in the terms or conditions of the award. The guidance is effective for our annual financial statements beginning January 1, 2018, although early adoption is permitted. The amendments included in this standard 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 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 the effect of this standard on our future financial position and results of operations.


2.	Calculation of Earnings Per Share


	Three Months Ended				Nine Months Ended				Three Months Ended				Nine Months Ended
	September 30,				September 30,				September 30,				September 30,
	2016		2015		2016		2015		2017		2016		2017		2016
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:

Net Income	$	4,416	$	5,119	$	32,812	$	32,521	$	6,833	$	4,416	$	32,023	$	32,812
Weighted average shares outstanding	15,372,413		15,258,819		15,324,932		15,035,569		16,344,442		15,372,413		16,334,210		15,324,932
Basic Earnings Per Share	$	0.29	$	0.34	$	2.14	$	2.16	$	0.42	$	0.29	$	1.96	$	2.14

Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	4,416	$	5,119	32,812		32,521		$	6,833	$	4,416	$	32,023	$	32,812
Reconciliation of Denominator:
Weighted shares outstanding—Basic	15,372,413		15,258,819		15,324,932		15,035,569		16,344,442		15,372,413		16,334,210		15,324,932
Effect of dilutive securities:
Share-based compensation	40,370		48,024		41,023		48,072
Effect of dilutive securities—Share-based compensation									45,193		40,370		44,423		41,023
Adjusted denominator—Diluted	15,412,783		15,306,843		15,365,955		15,083,641		16,389,635		15,412,783		16,378,633		15,365,955
Diluted Earnings Per Share	$	0.29	$	0.33	$	2.14	$	2.16	$	0.42	$	0.29	$	1.96	$	2.14


3.	~~Acquisitions~~

~~Gatherco Merger~~

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

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

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

The merger agreement provided for additional contingent cash consideration to Gatherco's shareholders of up to $15.0 million based on a percentage of revenue generated from potential new gathering opportunities during the five-year period following the closing. As of September 30, 2016, there have been no related gathering opportunities developed; therefore, no contingent consideration liability has been recorded. Based on the absence of related gathering opportunities being developed as of September 30, 2016, we are unable to estimate the range of undiscounted contingent liability outcomes at this time.

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We incurred $1.3 million in transaction costs associated with this merger of which we incurred $786,000 in 2014 and the remaining $514,000 in 2015. Transaction costs were included in operations expense in the accompanying condensed consolidated statements of income. The revenue and net loss from this merger for the three months ended September 30, 2016, included in our condensed consolidated statements of income, were $5.6 million and $563,000, respectively. The revenue and net income from this merger for the nine months ended September 30, 2016, included in our condensed consolidated statements of income, were $18.4 million and $1.1 million, respectively. This merger was accretive to earnings per share in the first full year of operations, generating $0.03 in additional earnings per share for such period.

~~The purchase price allocation of the Gatherco merger was as follows:~~

Purchase price
(in thousands) Allocation
Purchase price $ 57,658

Property plant and equipment 53,203
Cash 6,806
Accounts receivable 3,629
Income taxes receivable 3,163
Other assets 425
Total assets acquired 67,226

Long-term debt 1,696
Deferred income taxes 13,409
Accounts payable 3,837
Other current liabilities 745
Total liabilities assumed 19,687
Net identifiable assets acquired 47,539
Goodwill $ 10,119

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

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


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 as separate entities.~~PSC.

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Delaware

Rate Case Filing: OnIn December ~~21,~~ 2015, our Delaware Division filed an application with the Delaware PSC for a base rate increase and certain other changes to its tariff. We proposed an increase of approximately $4.7 million, or nearly ten percent, in our revenue requirement based on the test period ending March 31, 2016. We also proposed new service offerings to promote growth and a revenue normalization mechanism for residential and small commercial customers.

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~~We expect a decision on the application during the first quarter of 2017. Pending the decision, our~~The Delaware Division, ~~increased rates on an interim basis based on the $2.5 million annualized interim rates approved by the~~ Delaware PSC ~~effective February 19, 2016 ("Phase I"). We recognized incremental revenue of approximately $469,000 ($280,000 net of tax) and $1.4 million ($817,000 net of tax) for~~Staff, the ~~three and nine months ended September 30, 2016, respectively.~~

~~In addition, our Delaware~~ Division requested and received approval on July 26, 2016, from the Delaware PSC to implement revised interim rates totaling $4.7 million (equal to the initial rate increase in our application) annualized for usage on and after August 1, 2016 ("Phase II"). These revised interim rates represent a five-percent increase over Phase I rates. Revenue associated with these rates collected prior to a final Delaware PSC decision is subject to refund and, although the final decision is expected during the first quarter of 2017, we cannot predict the revenue requirement the Delaware PSC will ultimately authorize or forecast the timing of a final decision. Consequently, we will not recognize the impact of the ~~potential additional revenue related to the Phase II rate increase until the Delaware PSC issues its approval in a final ruling.~~

~~Maryland~~

~~Sandpiper Rate Case Filing:~~ ~~On December 1, 2015, Sandpiper filed an application with the Maryland PSC for a base rate increase~~Public Advocate and ~~certain~~ other changes to its tariff. We proposed an increase of $950,000, or approximately five- percent, in our revenue requirement, based on the test period ended December 31, 2015. We also proposed a stratification of rate classes, based on cost of service,intervenors met and a revenue normalization mechanism for residential and small commercial customers. The procedural schedule was suspended in early May 2016 to allow for the continuation of settlement discussions between Sandpiper, Maryland PSC Staff and the Maryland Office of People's Counsel. The parties reached a settlement agreement ~~which Sandpiper filed with the Commission on August 10,~~in November 2016. The terms of the settlement agreement ~~include revenue neutral rates for the first year, followed by a schedule~~included an annual increase of ~~rate reductions~~$2.3 million in subsequent years based upon the projected rate of propane to natural gas conversions. A revenue normalization mechanism and stratification of rate classes were also included in the settlement agreement. On September 28, 2016, the Public Utility Law Judge issued a proposed order recommending approval of the settlement terms.base rates. The order became final ~~on October 29,~~in December 2016, and the new rates ~~will be~~became effective January 1, 2017. Amounts collected through interim rates in ~~effect on~~excess of the respective portion of the $2.3 million increase through December ~~1, 2016.~~31, 2016 were accrued as of that date. In January 2017, we filed our proposed refund plan with the Delaware PSC and subsequently issued refunds to customers in March 2017.

~~Florida~~Maryland

OnThere 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 Electric Interconnect Project: In September 1, 2015, FPU’s electric division filed to recover the cost of the proposed Florida Power & Light Company interconnect project through FPU's annual Fuel and Purchased Power Cost Recovery Clause filing. The interconnect project ~~will~~would enable FPU's electric division to negotiate a new power purchase agreement ~~that will~~to mitigate fuel costs for its Northeast division. ~~This action~~FPU's proposal was approved by the Florida PSC at its Agenda Conference held onin December 3, 2015. OnIn January ~~22,~~ 2016, however, the Office of Public Counsel filed an appeal of the Florida PSC's decision with the Florida Supreme Court. ~~Legal~~The Florida Supreme Court reversed the Florida PSC decision in March 2017, after consideration of the parties' legal briefs ~~have been filed, but no decision has been reached at this time.~~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.

OnSurcharge Associated with Modernization of Electric Distribution System Project: In February ~~2, 2016,~~2017, FPU’s ~~natural gas~~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 ~~an amendment to~~a temporary surcharge. In April 2017, FPU voluntarily withdrew its ~~existing transportation agreement~~petition and subsequently filed the limited proceeding described in the next paragraph.

Electric Limited Proceeding: In July 2017, FPU’s electric division filed a petition with the City of Lake Worth, located in Palm Beach County, Florida. The amendment allows the city to resell natural gas distributed by FPU to the city’s compressed natural gas station. The city will then resell the natural gas, after compression, to its customers. The amendment to the transportation agreement was approved by the Florida PSC, atrequesting approval to include $15.2 million of certain capital project expenditures in its ~~Agenda Conference held April 5, 2016.~~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 grid. Included in the $15.2 million is the interconnection project with Florida Power & Light Company, which enables FPU to mitigate fuel costs for its electric customers. This petition is scheduled for the Florida PSC's December 2017 Agenda.

~~On April 11, 2016, FPU’s~~Northwest Florida Expansion Project: Peninsula Pipeline and FPU's natural gas ~~divisions~~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 ~~division filed~~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 ~~joint petition for approval to allow~~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 ~~and Chesapeake Utilities to expand the cost allocation of the intrastate and unreleased capacity-related components currently embedded in the purchased~~natural gas ~~adjustment and operational balancing account, which is currently allocated to a limited number of~~distribution customers. The expanded allocation of these costs includes additional customers, primarily transportation customers, benefiting from these costs but not currently paying for them. This petition was approved by the Florida PSC at its Agenda Conference in September 2016.

Eastern Shore

White Oak Mainline Expansion Project: ~~On November 21, 2014,~~In July 2016, Eastern Shore ~~submitted an application to the FERCseeking~~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.~~Delaware ("White Oak Mainline Project"). Eastern Shore ~~proposes to construct~~constructed approximately ~~7.2~~5.4 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and ~~3,550 horsepower of additional~~increased compression capability at Eastern Shore’s existing Delaware City compressor station in New Castle County, Delaware.

~~On November 18, 2015, Eastern Shore filed an amendment~~ At the end of March 2017, the entire project was placed into service. The total cost to ~~this application, which indicated~~complete the preferred pipeline route and shortened the total miles of the proposed pipeline to 5.4 miles. On February 10, 2016, the FERC issued a notice combining the White Oak Mainline Expansion Project and the System Reliability Project into a single environmental assessment.project was approximately $42.0 million.

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On July 21, 2016, the FERC issued a certificate of public convenience and necessity authorizing Eastern Shore to construct and operate the proposed White Oak Mainline Project. The FERC denied Eastern Shore’s request for a pre-determination of rolled-in rate treatment in the certificate proceeding. However, FERC’s determination is without prejudice to Eastern Shore filing for and fully supporting rolled-in rate treatment of these project facilities in a future general rate case. The certificate required Eastern Shore to comply with 19 environmental conditions.

On July 29, 2016, Eastern Shore accepted the certificate of public convenience and necessity and, on August 2, 2016, filed its Implementation Plan to comply with each environmental condition and to request approval to begin construction. On August 4, 2016, the FERC issued a “Notice to Proceed,” and Eastern Shore commenced construction during August 2016. Eastern Shore continues to file weekly status reports in compliance with one of the environmental conditions.

System Reliability Project: ~~On May 22, 2015, Eastern Shore submitted an application to~~In September 2016, the FERC ~~seeking authorization~~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. ~~The total project will benefit all of Eastern Shore’s customers by modifying the pipeline system to respond to severe operational conditions experienced during actual winter peak days~~Previously, in ~~2014 and 2015. Since the project is intended to improve system reliability, Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project.~~

On July ~~21,~~ 2016, the FERC ~~issued a certificate of public convenience and necessity authorizing Eastern Shore to construct and operate the proposed System Reliability Project. The FERC~~ granted Eastern Shore’s ~~request for a~~ pre-determination of rolled-in rate treatment absent any significant change in ~~its next rate base proceeding and required Eastern Shore to comply with 19 environmental conditions.~~circumstances.

~~On July 29, 2016, Eastern Shore accepted~~As of June 2017, the certificate and on August 5, 2016 filed its Implementation Plan to comply with each environmental condition and to request approval to begin construction. On August 12, 2016, the FERC issued a “Partial Notice to Proceed” approving construction for certain portions of the System Reliability Project. On September 15, 2016, the FERC granted approval to start construction on the remaining portion of the Project. Construction commenced on the Bridgeville Compressor Station and the Porter Road Loop in August 2016, and on the Dover Loop, in September 2016 and is ongoing. Eastern Shore continues to file weekly status reports in compliance with one of the environmental conditions.

~~TETLP Capacity Expansion Project:~~ On October 13, 2015, Eastern Shore submitted an application to the FERC to make certain measurement and related improvements at its TETLP interconnect facilities, which would enable Eastern Shore to increase natural gas receipts from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. On December 22, 2015, the FERC authorized Eastern Shore to proceed with the project. On March 11, 2016, the capacity expansionentire 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: OnIn May ~~12,~~ 2016, Eastern Shore submitted a request to the FERC to initiate the ~~FERC’s~~ pre-filing review procedures for Eastern Shore's 2017 expansion ~~project.~~project (the “2017 Expansion Project”). The ~~expansion project consists of approximately 33 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering~~2017 Expansion Project's facilities in Lancaster County, Pennsylvania; installation of an additional 3,550 horsepower 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. The expansion project is necessary to provide up to 86,437 Dts/d of additional firm natural gas transportation capacity to meet anticipated market demand. On May 17, 2016, the FERC approved Eastern Shore’s request to commence the pre-filing review process. Eastern Shore is currently working through the pre-filing process and anticipates filing, in December 2016, its application for a certificate of public convenience and necessity, seeking authorization to construct the expansion facilities.

Since the time the pre-filing was initiated, Eastern Shore has finalized market participation for the project. Seven of Eastern Shore’s existing customers have signed Precedent Agreements. As a result, the project will provide 61,162 Dts/d of additional firm natural gas transportation deliverability on Eastern Shore’s pipeline system. To provide this additional capacity, the project’s final facilities will consist ofinclude approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional ~~3,550 horsepower~~ compressor unit at Eastern Shore’s existing Daleville compressor station in Chester County,

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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 with seven existing customers, including three affiliates of Chesapeake Utilities, for a total of 61,162 Dts/d of additional firm natural gas transportation service on Eastern Shore’s pipeline system with an additional 52,500 Dts/d of firm transportation service at certain Eastern Shore receipt facilities.

In December 2016, Eastern Shore submitted an application for a CP seeking authorization to construct 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 the FERC staff's data requests.

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

Eastern Shore is preparing its implementation plan, which will be filed with the FERC, addressing the actions Eastern Shore will undertake to meet the Environmental Conditions set forth in the FERC's order. Eastern Shore anticipates placing certain facilities into service by the end of the year and completing the entire project in 2018.

2017 Rate Case ~~Filing~~

Filing: In January 2017, Eastern Shore ~~intends to file~~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 the rate case is resolved. Settlement discussions continue among the other parties to the case.

5.4. Environmental Commitments and Contingencies

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

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MGP Sites

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

As of September 30, ~~2016,~~2017, we had approximately ~~$9.9~~$9.7 million in environmental liabilities, ~~representing our estimate of the future costs associated with all of~~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 ~~all of~~ its MGP ~~sites, approximately $10.5~~sites. Approximately $10.9 million ~~of which~~ has been recovered as of September 30, ~~2016,~~2017, leaving approximately ~~$3.5~~$3.1 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

In addition to the FPU MGP sites, we had $298,000 in environmental liabilities at September 30, 2016, representing our estimate of future costs associated with Chesapeake Utilities' MGP site in Winter Haven, Florida.

During the first quarter of 2015, we established $273,000 in environmental liabilities related to Chesapeake Utilities' MGP site in Seaford, Delaware, representing our estimate of future costs associated with this site, and recorded a regulatory asset for the same amount for probable future recovery through Chesapeake Utilities' rates via our environmental rider. On February 23, 2016, the Delaware PSC approved an environmental surcharge for the recovery of Chesapeake Utilities' environmental expenses associated with the Seaford site for the period of October 1, 2014 through September 30, 2015. Chesapeake Utilities will file for recovery of its expenses incurred between October 1, 2015 and September 30, 2016 by October 31, 2016. As of September 30, 2016, we had approximately $156,000 in environmental liabilities and $267,000 in regulatory and other assets related to this site.

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

~~West Palm Beach, Florida~~

~~Remedial options are being evaluated to respond to environmental impacts to soil~~The following is a summary of our remediation status and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated a MGP. FPU is implementing a remedial plan approved by the FDEP for the east parcel of the West Palm Beach site, which includes installation of monitoring test wells, sparging of air into the groundwater system and extraction of vapors from the subsurface. The Start-Up and Monitoring Report, dated November 30, 2015, was submitted for review and comment. We received a letter dated January 6, 2016 from FDEP, which provided minor comments. On January 12, 2016, FDEP conducted a facility inspection and found no problems or deficiencies.

~~We expect that similar remedial actions will ultimately be implemented for other portions of the site. Estimated~~estimated costs of remediation for the West Palm Beach site range from approximately $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement ~~the remedial plan, and any potential costs associated with future redevelopment~~clean-up of ~~the properties.~~

our MGP sites:

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~~Sanford, Florida~~

FPU is the current owner of property in Sanford, Florida, which is the site on which a former MGP that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP previously located on this site. In January 2007, FPU and the Sanford Group signed a Third Participation Agreement, which provides for the funding of the final remedy approved by the EPA for the site. FPU’s share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000. As of September 30, 2016, FPU has paid $650,000 to the Sanford Group escrow account for its entire share of the funding requirements.

In December 2014, the EPA issued a preliminary close-out report, documenting the completion of all physical remedial construction activities at the Sanford site. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site. The total cost of the final remedy is estimated to be over $20.0 million, which includes long-term monitoring and the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation.

In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU advised the other members of the Sanford Group that it is unwilling to pay any sum in excess of the $650,000 paid by FPU under the Third Participation Agreement. The Sanford Group has not requested that FPU contribute to costs beyond the originally agreed upon $650,000 contribution.

As of September 30, 2016, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be $24,000. We are unable to determine, to a reasonable degree of certainty, whether the other members of the Sanford Group will accept FPU’s asserted defense as to its limited liability for future costs exceeding $13.0 million to implement the final remedy for this site, as provided for in the Third Participation Agreement, or whether the other members of the Sanford Group will pursue a claim against FPU for a sum in excess of the $650,000 that FPU has paid pursuant to the Third Participation Agreement. No such claims have been made as of September 30, 2016.

~~Key West, Florida~~

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

In October 2012, FDEP issued a RAP approval order, which requires a limited semi-annual NAM. The most recent groundwater-monitoring event was conducted in September 2016. Natural attenuation default criteria were met at all locations sampled and the semi-annual report was submitted on October 4, 2016 with the recommendation that semi-annual monitoring should continue at this facility. The next semi-annual NAM is scheduled for the first quarter of 2017.

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

~~Pensacola, Florida~~

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

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~~Winter Haven, Florida~~

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

Groundwater monitoring results on the southern portion of this site indicate that natural attenuation default criteria continue to be exceeded. Plans to modify the monitoring network on the southern portion of the site in order to collect additional data to support the development of a remedial plan were specified in a letter to FDEP, dated October 17, 2014. The well installation and abandonment program was implemented in October 2014, and documentation was reported in the next semi-annual RAP implementation status report, submitted on January 8, 2015. FDEP approved the plan to expand the bio-sparging operations in the southern portion of the site, and additional sparge points were installed and connected to the operating system in the first quarter of 2016.

Although specific remedial actions for the site have not yet been identified, we estimate that future remediation costs for the subsurface soils and groundwater at the site should not exceed $425,000, which includes an estimate of $100,000 to implement additional actions, such as institutional controls, at the site.

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

~~Salisbury, Maryland~~

We have substantially completed remediation of a site in Salisbury, Maryland, where it was determined that a former MGP caused localized groundwater contamination. In February 2002, the MDE granted permission to permanently decommission the systems used for remediation and to discontinue all on-site and off-site well monitoring, except for one well, which is being maintained for periodic product monitoring and recovery. As directed by MDE, additional measures were performed and this last remaining well was redeveloped in September 2016. Depending on future observations, additional testing may be required. We anticipate that the remaining costs for maintaining and monitoring this one remaining well will not exceed $5,000 annually. We cannot predict at this time when the MDE will grant permission to permanently decommission this well.

~~Seaford, Delaware~~

In a letter dated December 5, 2013, DNREC notified us that it would be conducting a facility evaluation of a former MGP site in Seaford, Delaware. In a report issued in January 2015, DNREC provided the evaluation, which found several compounds within the groundwater and soil that require further investigation. On September 17, 2015, DNREC approved our application to enter this site into the voluntary cleanup program. A remedial investigation was conducted in December 2015, and the resulting remedial investigation report was submitted to DNREC in May 2016. Based on findings from the remedial investigation, DNREC requested additional investigative work be performed prior to approval of potential remedial actions. We anticipate completing this additional investigative work by the end of the second quarter of 2017. We estimate the cost of potential remedial actions, based on the findings of the DNREC report, to be between $273,000 and $465,000.



Jurisdiction	MGP Site	Status	Cost to Clean up	Recovery through Rates
Florida	West Palm Beach	Remedial actions approved by FDEP have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions.	Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties	Yes
Florida	Sanford	In January 2007, FPU and the Sanford group signed a Third Participation Agreement. FPU's share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000, which has been paid to an escrow account. The EPA issued a preliminary close-out report in December 2014. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site.	FPU's remaining remediation expenses, including attorneys' fees and costs, are estimated to be approximately $24,000	Yes
Florida	Winter Haven	Remediation is ongoing.	Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site	Yes
Delaware	Seaford	Proposed plan for implementation approved by DNREC in July 2017.	$273,000 to $465,000	Yes
Maryland	Cambridge	Currently in discussions with MDE	Unable to estimate	N/A

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~~Cambridge, Maryland~~

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

~~Ohio~~

We have completed the investigation, assessment and remediation of eight natural gas pipeline facilities in Ohio that Aspire Energy acquired from Gatherco pursuant to the merger. Under the merger agreement, we are entitled to be indemnified from an escrow fund created at closing for certain matters, including certain claims related to environmental remediation. The costs incurred to date associated with remediation activities for these eight facilities is approximately $1.6 million. In September 2016, we and the Gatherco shareholder agent resolved certain disputes associated with our claims for indemnification, including claims for environmental matters. After deducting the amount of anticipated tax benefits related to our claims and an indemnification deductible in the amount of $431,250 in accordance with the merger agreement, we received a total of approximately $500,000 from the indemnification escrow in payment of our claims with no material impact to our financial statements. We do not anticipate submitting any additional claims for indemnification or receiving any additional indemnification payments related to or arising out of the Gatherco merger.


6.5.	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. ~~For~~In 2017, our ~~Delaware and Maryland~~Delmarva natural gas distribution ~~divisions, we have a contract~~operations entered into asset management agreements with ~~an unaffiliated energy marketing and risk management company~~PESCO to manage a portion of their natural gas transportation and storage ~~capacity, which expires~~capacity. The agreements were effective as of April 1, 2017, and each has a three-year term, expiring on March 31, ~~2017.~~2020. Previously, the Delaware PSC approved PESCO to serve as an asset manager.

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 ~~6.5~~2.8 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.

Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a six-year term ending in May 2019. Sharp's current annual commitment is estimated at approximately ~~6.5~~2.8 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement.

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

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times and (b) a fixed charge coverage ratio greater than 1.5 times. If ~~FPU fails to comply with~~ either ~~of these ratios,~~ratio is not met by FPU, it has 30 days to cure the default or provide an irrevocable letter of credit if the default is not ~~cured, to provide an irrevocable letter of credit.~~cured. 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~~)percent). If FPU fails to meet ~~either of these ratios,~~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, ~~2016~~,2017, FPU was in compliance with all of the requirements of its fuel supply contracts.

~~Corporate Guarantees~~

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 the property on which the CHP plant is located pursuant to a separate 20-year contract. The ~~Board of Directors has authorized us to issue corporate guarantees~~CHP plant is powered by natural gas transported by FPU through its distribution system and ~~to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit is $65.0 million.~~Peninsula Pipeline through its intrastate pipeline.

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~~Chesapeake Utilities has~~Corporate Guarantees

We have issued corporate guarantees to certain vendors of our ~~subsidiaries' vendors, the largest of which are for Xeron and~~subsidiaries, primarily PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event that ~~Xeron or~~ PESCO defaults. ~~Neither subsidiary~~PESCO has ~~ever~~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, ~~2016~~2017 was approximately ~~$53.9~~$71.9 million, with the guarantees expiring on various dates through September ~~2017.~~2018.

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 1413, Long-Term Debt, for further details).

WeLetters of Credit

As of September 30, 2017, we have issued letters of credit totaling approximately ~~$8.4~~$5.8 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, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through ~~September 2017.~~June 2018. There have been no draws on these letters of credit as of September 30, ~~2016.~~2017. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.

~~Tax-related Contingencies~~

We are subject to various audits and reviews by the federal, state, local and other governmental authorities regarding income taxes and taxes other than income. As of September 30, 2016 and December 31, 2015, we maintained a liability of approximately $50,000 related to unrecognized income tax benefits. As of December 31, 2015, we maintained a liability of approximately $310,000 related to contingencies for taxes other than income. We did not have a liability related to contingencies for taxes other than income at September 30, 2016.

Other

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


7.6.	Segment Information

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

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

Unregulated Energy. The Unregulated Energy segment includes propane distribution ~~and wholesale marketing operations, and~~as well as natural gas marketing, gathering, processing, transportation and supply. These operations ~~which~~ are unregulated as to their rates and services. ~~Effective April 1, 2015, this segment includes Aspire Energy, whose services include natural gas gathering, processing, transportation and supply (See Note 3,~~ ~~Acquisitions, regarding the merger with Gatherco).~~ Effective June 2016, this segment includes electricity and steam generation through Eight Flags' CHP plant. ~~Also included in~~Through March 2017, this segment ~~are other unregulated energy services, such as energy-related merchandise sales~~also included the operations of Xeron, our propane and ~~heating, ventilation and air conditioning, plumbing and electrical services.~~crude oil trading subsidiary that began winding down operations at the end of the first quarter of 2017.

~~The remainder of our~~Other operations isare presented as “Other businesses and ~~eliminations”,~~eliminations,” which ~~consists~~consist 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.

Table of Contents

The following table presents financial information about our reportable segments:


	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2016			2015			2016			2015			2017			2016			2017			2016
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	68,899		$	63,526		$	224,382		$	234,608		$	67,257		$	68,899		$	232,519		$	224,382
Unregulated Energy segment	39,449			28,387			132,604			120,068
Unregulated Energy segment and other businesses													59,679			39,449			204,661			132,604
Total operating revenues, unaffiliated customers	$	108,348		$	91,913		$	356,986		$	354,676		$	126,936		$	108,348		$	437,180		$	356,986
Intersegment Revenues ⁽¹⁾
Regulated Energy segment	$	1,120		$	270		$	2,248		$	830		$	2,446		$	1,120		$	5,834		$	2,248
Unregulated Energy segment	2,593			1,222			3,759			3,095			5,009			2,593			15,801			3,759
Other businesses	240			220			705			660			194			240			581			705
Total intersegment revenues	$	3,953		$	1,712		$	6,712		$	4,585		$	7,649		$	3,953		$	22,216		$	6,712
Operating Income
Regulated Energy segment	$	13,115		$	11,828		$	52,660		$	47,616		$	15,168		$	13,115		$	51,915		$	52,660
Unregulated Energy segment	(3,080		)	(1,022		)	9,267			13,666			(989		)	(3,080		)	10,504			9,267
Other businesses and eliminations	121			103			350			305			60			121			161			350
Total operating income	10,156			10,909			62,277			61,587			14,239			10,156			62,580			62,277
Other (expense) income, net	(28		)	36			(68		)	(3		)
Interest	2,722			2,492			7,996			7,425
Other income (expense), net													239			(28		)	(643		)	(68		)
Interest charges													3,321			2,722			9,133			7,996
Income before Income Taxes	7,406			8,453			54,213			54,159			11,157			7,406			52,804			54,213
Income taxes	2,990			3,334			21,401			21,638			4,324			2,990			20,781			21,401
Net Income	$	4,416		$	5,119		$	32,812		$	32,521		$	6,833		$	4,416		$	32,023		$	32,812


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


(in thousands)	September 30, 2016		December 31, 2015		September 30, 2017		December 31, 2016
Identifiable Assets
Regulated Energy segment	$	921,682	$	872,065	$	1,084,961	$	986,752
Unregulated Energy segment	207,083		171,840		233,785		226,368
Other businesses and eliminations	11,745		23,516		28,004		16,099
Total identifiable assets	$	1,140,510	$	1,067,421	$	1,346,750	$	1,229,219

~~Our operations are entirely domestic.~~

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8.7.	~~Accumulated Other Comprehensive Loss~~Stockholder's Equity

Preferred Stock

We had 2,000,000 authorized and unissued shares of preferred stock, $0.01 par value per share, as of September 30, 2017 and December 31, 2016. 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 priceper 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 ~~income (loss).~~ loss.

The following tables present the changes in the balance of accumulated other comprehensive loss for the nine months ended September 30, ~~2016~~2017 and ~~2015.~~2016. All amounts are presented net of tax.

Defined Benefit Commodity
Pension and Contracts
Postretirement Cash Flow
Plan Items Hedges Total
(in thousands)
As of December 31, 2015 $ (5,580 ) $ (260 ) $ (5,840 )
Other comprehensive gain before reclassifications —
641
641
Amounts reclassified from accumulated other comprehensive loss 263
(93 ) 170
Net current-period other comprehensive income 263
548
811
As of September 30, 2016 $ (5,317 ) $ 288
$ (5,029 )



	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	)

Table of Contents

Defined Benefit Commodity
Pension and Contracts
Postretirement Cash Flow
Plan Items Hedges Total
(in thousands)
As of December 31, 2014 $ (5,643 ) $ (33 ) $ (5,676 )
Other comprehensive loss before reclassifications —
(76 ) (76 )
Amounts reclassified from accumulated other comprehensive loss 248
33
281
Net prior-period other comprehensive income 248
(43 ) 205
As of September 30, 2015 $ (5,395 ) $ (76 ) $ (5,471 )



	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2015	$	(5,580	)	$	(260	)	$	(5,840	)
Other comprehensive income before reclassifications	—			641			641
Amounts reclassified from accumulated other comprehensive income/(loss)	263			(93		)	170
Net prior-period other comprehensive income	263			548			811
As of September 30, 2016	$	(5,317	)	$	288		$	(5,029	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, ~~2016~~2017 and ~~2015.~~2016. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement. ~~Gains or losses for our commodity contracts fair value hedges are recognized immediately in earnings.~~

~~Table of Contents~~


	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2016			2015			2016			2015			2017			2016			2017			2016
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost ⁽¹⁾	$	20		$	17		$	60		$	50
Prior service credit ⁽¹⁾													$	19		$	20		$	58		$	60
Net loss ⁽¹⁾	(166		)	(155		)	(500		)	(465		)	(171		)	(166		)	(509		)	(500		)
Total before income taxes	(146		)	(138		)	(440		)	(415		)	(152		)	(146		)	(451		)	(440		)
Income tax benefit	58			55			177			167			61			58			180			177
Net of tax	$	(88	)	$	(83	)	$	(263	)	$	(248	)	$	(91	)	$	(88	)	$	(271	)	$	(263	)

Gains and losses on commodity contracts cash flow hedges
Propane swap agreements ⁽²⁾	$	—		$	—		$	(322	)	$	—		$	198		$	—		$	663		$	(322	)
Call options ⁽²⁾	—			—			—			(55		)
Natural gas swaps ⁽²⁾													1			—			1			—
Natural gas futures ⁽²⁾	105			—			464			—			(852		)	105			929			464
Total before income taxes	105			—			142			(55		)	(653		)	105			1,593			142
Income tax benefit (expense)	(41		)	—			(49		)	22			248			(41		)	(628		)	(49		)
Net of tax	64			—			93			(33		)	(405		)	64			965			93
Total reclassifications for the period	$	(24	)	$	(83	)	$	(170	)	$	(281	)	$	(496	)	$	(24	)	$	694		$	(170	)

⁽¹⁾ These amounts are included in the computation of net periodic costs (benefits). See Note 98, Employee Benefit Plans, for additional details.

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

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

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9.8.	Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three and nine months ended September 30, ~~2016~~2017 and ~~2015~~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, 2016 2015 2016 2015 2016 2015 2016 2015 2016 2015
(in thousands)
Interest cost $ 105
$ 102
$ 635
$ 626
$ 23
$ 23
$ 11
$ 11
$ 14
$ 15
Expected return on plan assets (131 ) (135 ) (625 ) (777 ) —
—
—
—
—
—
Amortization of prior service cost —
—
—
—
—
2
(20 ) (19 ) —
—
Amortization of net loss 103
91
133
114
22
25
16
17
—
2
Net periodic cost (benefit) 77
58
143
(37 ) 45
50
7
9
14
17
Amortization of pre-merger regulatory asset —
—
191
191
—
—
—
—
2
2
Total periodic cost $ 77
$ 58
$ 334
$ 154
$ 45
$ 50
$ 7
$ 9

$ 16
$ 19

~~Table of Contents~~



	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,	2016			2015			2016			2015			2016		2015		2016			2015			2016		2015		2017			2016			2017			2016			2017		2016		2017			2016			2017		2016
(in thousands)
Interest cost	$	315		$	306		$	1,894		$	1,877		$	68	$	68	$	32		$	33		$	41	$	45	$	309		$	315		$	1,870		$	1,894		$	66	$	68	$	31		$	32		$	38	$	41
Expected return on plan assets	(392		)	(405		)	(2,027		)	(2,330		)	—		—		—			—			—		—		(381		)	(392		)	(2,098		)	(2,027		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			—		8		(60		)	(58		)	—		—
Amortization of prior service credit																											—			—			—			—			—		—		(58		)	(60		)	—		—
Amortization of net loss	309			272			389			341			66		74		51			53			—		5		319			309			392			389			65		66		50			51			—		—
Net periodic cost (benefit)	232			173			256			(112		)	134		150		23			28			41		50		247			232			164			256			131		134		23			23			38		41
Amortization of pre-merger regulatory asset	—			—			571			571			—		—		—			—			6		6		—			—			571			571			—		—		—			—			6		6
Total periodic cost	$	232		$	173		$	827		$	459		$	134	$	150	$	23		$	28		$	47	$	56	$	247		$	232		$	735		$	827		$	131	$	134	$	23		$	23		$	44	$	47

We expect to record pension and postretirement benefit costs of approximately $~~1.7~~1.6 million for ~~2016.~~2017. Included in these costs is approximately ~~$769,000~~$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 ~~$2.3~~$1.5 million and approximately $~~2.9~~2.1 million at September 30, ~~2016~~2017 and December 31, ~~2015~~2016, respectively. ~~The amortization included in pension expense is also being added to a net periodic loss of approximately $917,000, which will increase our total expected benefit costs to approximately $1.7 million.~~

Pursuant to a Florida PSC order, FPU continues to record, as a regulatory asset, a portion of the unrecognized pension and postretirement benefit costs related to its regulated operations after the FPU merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake Utilities' operations is recorded to accumulated other comprehensive loss.

Table of Contents

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, ~~2016~~2017 and ~~2015:~~2016:


For the Three 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 September 30, 2017															Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(20	)	$	—	$	(20	)	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	103		133		22		16			—		274			107		131		22		17			—		277
Total recognized in net periodic benefit cost	$	103	$	133	$	22	$	(4	)	$	—	$	254		107		131		22		(2		)	—		258
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	103	$	25	$	22	$	(4	)	$	—	$	146		107		25		22		(2		)	—		152
Recognized from regulatory asset	—		108		—		—			—		108			—		106		—		—			—		106
Total	$	103	$	133	$	22	$	(4	)	$	—	$	254		$	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
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(58	)	$	—	$	(58	)
Net loss	319		392		65		50			—		826
Total recognized in net periodic benefit cost	319		392		65		(8		)	—		768
Recognized from accumulated other comprehensive loss ⁽¹⁾	319		75		65		(8		)	—		451
Recognized from regulatory asset	—		317		—		—			—		317
Total	$	319	$	392	$	65	$	(8	)	$	—	$	768

Table of Contents


For the Three Months Ended September 30, 2015	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
For the Nine Months Ended September 30, 2016															Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service cost (credit)	$	—	$	—	$	2	$	(19	)	$	—	$	(17	)
Prior service credit															$	—	$	—	$	—	$	(60	)	$	—	$	(60	)
Net loss	91		114		25		17			2		249			309		389		66		51			—		815
Total recognized in net periodic benefit cost	$	91	$	114	$	27	$	(2	)	$	2	$	232		309		389		66		(9		)	—		755
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	91	$	22	$	27	$	(2	)	$	—	$	138		309		74		66		(9		)	—		440
Recognized from regulatory asset	—		92		—		—			2		94			—		315		—		—			—		315
Total	$	91	$	114	$	27	$	(2	)	$	2	$	232		$	309	$	389	$	66	$	(9	)	$	—	$	755

For the Nine 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 $ —
$ —
$ —
$ (60 ) $ —
$ (60 )
Net loss 309
389
66
51
—
$ 815
Total recognized in net periodic benefit cost $ 309
$ 389

$ 66

$ (9 )
$ —

$ 755
Recognized from accumulated other comprehensive loss ⁽¹⁾
$ 309
$ 74
$ 66
$ (9 ) $ —
$ 440
Recognized from regulatory asset —
315
—
—
—
315
Total $ 309
$ 389
$ 66
$ (9 ) $ —
$ 755

For the Nine Months Ended September 30, 2015 Chesapeake
Pension
Plan FPU
Pension
Plan Chesapeake SERP Chesapeake
Postretirement
Plan FPU
Medical
Plan Total
(in thousands)
Prior service cost (credit) $ —
$ —
$ 8
$ (58 ) $ —
$ (50 )
Net loss 272
341
74
53
5
745
Total recognized in net periodic benefit cost $ 272
$ 341
$ 82
$ (5 ) $ 5
$ 695
Recognized from accumulated other comprehensive loss ⁽¹⁾
$ 272
$ 65
$ 82
$ (5 ) $ 1
$ 415
Recognized from regulatory asset —
276
—
—
4
280
Total $ 272
$ 341
$ 82
$ (5 ) $ 5
$ 695


⁽¹⁾	~~See Note 8, Accumulated Other Comprehensive Loss~~⁽¹⁾See Note 7, Stockholder's Equity.

During the three and nine months ended September 30, ~~2016,~~2017, we contributed approximately ~~$116,000~~$67,000 and ~~$390,000,~~$234,000, respectively, to the Chesapeake Pension Plan and approximately ~~$374,000~~$110,000 and ~~approximately $1.3~~$1.6 million, respectively, to the FPU Pension Plan. We expect to contribute a total of approximately ~~$508,000~~$746,000 and approximately ~~$1.6~~$3.0 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during ~~2016,~~2017, which ~~represent~~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, ~~2016,~~2017, were approximately $38,000 and ~~approximately~~ $114,000, respectively. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake ~~Pension~~ SERP in ~~2016.~~2017. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three and nine months ended September 30, ~~2016,~~2017, were approximately ~~$23,000~~$30,000 and ~~approximately $59,000,~~$94,000, respectively. We estimate that approximately ~~$82,000~~$83,000 will be paid

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for such benefits under the Chesapeake Postretirement Plan in ~~2016.~~2017. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and nine months ended September 30, ~~2016,~~2017, were approximately ~~$32,000~~$13,000 and ~~approximately $97,000,~~$48,000, respectively. We estimate that approximately ~~$149,000~~$129,000 will be paid for such benefits under the FPU Medical Plan in ~~2016.~~2017.


~~10.~~9.	Investments

The investment balances at September 30, ~~2016~~2017 and December 31, ~~2015,~~2016, consisted of the following:



(in thousands)	September 30, 2016		December 31, 2015		September 30, 2017		December 31, 2016
Rabbi trust (associated with the Deferred Compensation Plan)	$	4,609	$	3,626	$	6,358	$	4,881
Investments in equity securities	21		18		22		21
Total	$	4,630	3,644		$	6,380	4,902

We classify these investments as trading securities and report them at their fair value. For the three months ended September 30, ~~2016~~2017 and ~~2015,~~2016, we recorded a net unrealized gain of approximately ~~$193,000~~$261,000 and ~~$238,000,~~$193,000, respectively, in other income (expense), net in the condensed consolidated statements of income related to these investments. For the nine months ended September 30, ~~2016~~2017 and ~~2015,~~2016, we recorded an unrealized gain of approximately ~~$246,000~~$694,000 and ~~a net unrealized loss of approximately $131,000,~~$246,000, respectively, in other income (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 for the gains and losses incurred by the investments in the Rabbi Trust.


~~11.~~10.	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, ~~2016~~2017 and ~~2015:~~2016:


	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2016			2015			2016			2015			2017			2016			2017			2016
(in thousands)
Awards to non-employee directors	$	135		$	165		$	445		$	475		$	134		$	135		$	406		$	445
Awards to key employees	488			334			1,442			970			662			488			1,202			1,442
Total compensation expense	623			499			1,887			1,445			796			623			1,608			1,887
Less: tax benefit	(251		)	(201		)	(760		)	(582		)	(320		)	(251		)	(647		)	(760		)
Share-based compensation amounts included in net income	$	372		$	298		$	1,127		$	863		$	476		$	372		$	961		$	1,127

Non-employee Directors

Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the grant date. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May ~~2016,~~2017, each of our non-employee directors received an annual retainer of ~~953~~835 shares of common stock under the SICP for service as a director through the ~~2017~~2018 Annual Meeting of Stockholders.

A summary of the stock activity for our non-employee directors during the nine months ended September 30, ~~2016~~2017 is presented below:

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	Number of Shares		Weighted Average Fair Value		Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2015	—		$	—
Outstanding— December 31, 2016					—		$	—
Granted	8,577		$	62.90	7,515		$	71.80
Vested	(8,577	)	$	62.90	(7,515	)	$	71.80
Outstanding— September 30, 2016	—		$	—
Outstanding— September 30, 2017					—		$	—

At September 30, ~~2016,~~2017, there was approximately $314,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service ~~period~~periods ending April 30, ~~2017.~~

2018.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the nine months ended September 30, ~~2016:~~2017:


	Number of Shares		Weighted Average Fair Value		Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2015	110,398		$	38.34
Outstanding— December 31, 2016					115,091		$	51.85
Granted	46,571		$	67.90	52,355		$	63.42
Vested	(39,553	)	$	31.79	(32,926	)	$	38.88
Expired	(2,325	)	$	42.25	(1,878	)	$	39.97
Outstanding— September 30, 2016	115,091		$	52.36
Outstanding— September 30, 2017					132,642		$	52.42

In February ~~2016,~~and May 2017, our Board of Directors granted awards of ~~46,571~~52,355 shares of common stock to key employees under the SICP. The shares granted in February ~~2016~~and May 2017 are multi-year awards that will vest at the end of the three-year service period ending December 31, ~~2018.~~2019. 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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At the election of certain of our executives, in March 2017, for shares that were awarded for the performance period ending December 31, 2016, we withheld shares with a value at least equivalent to each such executive’s minimum statutory obligation for applicable income and other employment taxes, remitted the cash to the appropriate taxing authorities, and paid the balance of such shares to each such executive. We withheld 10,269 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.

At September 30, ~~2016,~~2017, the aggregate intrinsic value of the SICP awards granted to key employees was approximately ~~$7.0~~$10.4 million. At September 30, ~~2016,~~2017, there was approximately $2.7 million of unrecognized compensation cost related to these awards, which is expected to be recognized from 2017 through 2019.

Stock Options

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


~~12.~~11.	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. WeOur 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, ~~2016,~~2017, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

Hedging Activities in 2017

In 2017, Sharp entered into several swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 11.1 million gallons expected to be purchased from October 2017 through September 2018. Under the swap agreements, Sharp will receive the difference between the index prices (Mont Belvieu prices in October 2017 through September 2018) and the swap prices of $0.5900 and $0.6750 per gallon, to the extent the index prices exceed the swap prices. If the index prices are lower than the swap price, Sharp will pay the difference. We accounted for these swap agreements as cash flow hedges, 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. 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 associated with the purchase and sale 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).

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

The impact of PESCO's financial instruments that were not designated as hedges in our condensed consolidated financial statements for the nine months ended September 30, 2017 was $13,000, which was recorded as an increase in gas costs and is associated with 1.4 million Dts of natural gas. This presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments.

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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 ~~4.1~~4.8 million gallons expected to be purchased ~~for the upcoming heating season.~~through September 2017. Under the swap agreements, Sharp ~~will~~would receive the difference between the index prices (Mont Belvieu prices in ~~December~~October 2016 through September 2017) and the swap prices of ~~$0.5250~~$0.5225 and ~~$0.5525~~$0.5650 per gallon, to the extent the index prices ~~exceed~~exceeded the swap prices. If the index prices ~~are~~were lower than the swap price, Sharp ~~will~~would pay the difference. ~~The~~Sharp received a total of approximately $193,000, which represented the difference between the index prices and swap ~~agreement essentially fixes~~prices during the ~~price~~months of ~~the 4.1 million gallons that we expect to purchase for the upcoming heating season.~~October 2016 through September 2017. We had accounted for these swap

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agreements as cash flow ~~hedges,~~hedges.

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 iswas no ineffective portion of these hedges. At September 30, 2016, the swap agreements had a fair value of approximately $237,000. The change in the fair value of the swap agreements is recorded as unrealized gain/loss in other comprehensive income (loss).

this hedge.

In January 2016, PESCO entered into a ~~SCO~~ supplier agreement with Columbia Gas to provide natural gas supply for ~~Columbia Gas to service~~ one of its local distribution customer ~~tranches.~~pools. PESCO also assumed the obligation to store natural gas inventory to satisfy its obligations under the ~~SCO~~ supplier agreement, which ~~terminates~~terminated on March 31, 2017.

In conjunction with the ~~SCO~~ 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. ~~The contracts expire within one year.~~ 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 ~~de-designated~~discontinued hedge accounting as the hedges ~~as they~~ were no longer highly effective. We are now accounting for them as derivatives on a mark-to-market basis with the change in fair value reflected as unrealized gain (loss) in current period earnings, and these are no longer offset by any associated gain (loss) in the value of the inventory previously hedged. As of September 30, ~~2016, we had a total of 1.8 million Dts/d in natural gas futures~~2017, these contracts ~~with a mark-to-market liability of $29,000.~~have all expired and are no longer reported on the balance sheet.

Beginning in October 2015, PESCO entered into natural gas futures contracts associated with the purchase and sale of natural gas to other specific customers. These contracts expire within two years, and we have accounted for them as cash flow hedges. There is no ineffective portion of these hedges. At September 30, 2016, PESCO had a total of 6.0 million Dts/d hedged under natural gas futures contracts, with an asset fair value of approximately $240,000. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss).

~~Fair Value Hedges~~

The impact of our natural gas futures commodity contracts previously designated as fair value hedges and the related hedged item on our condensed consolidated income statements for the three and nine months ended September 30, 2016 is presented below:

Three Months Ended Nine Months Ended
(in thousands)
September 30, 2016 ⁽¹⁾

September 30, 2016 ⁽¹⁾
Commodity contracts $ —
$ (233 )
Fair value adjustment for natural gas inventory designated as the hedged item —
681
Total increase in purchased gas cost $ —
$ 448

The increase in purchased gas cost is comprised of the following:
Basis ineffectiveness $ —
$ (83 )
Timing ineffectiveness —
531
Total ineffectiveness $ —
$ 448


⁽¹⁾	~~There were no natural gas futures commodity contracts designated as fair value hedges in 2015.~~

Basis ineffectiveness arises from natural gas market price differences between the locations of the hedged inventory and the delivery location specified in the hedging instruments. Timing ineffectiveness arises due to changes in the difference between the spot price and the futures price, as well as the difference between the timing of the settlement of the futures and the valuation of the underlying physical commodity. As the commodity contract nears the settlement date, spot-to-forward price differences should converge, which should reduce or eliminate the impact of this ineffectiveness on purchased gas cost. To the extent that our natural gas inventory does not qualify as a hedged item in a fair-value hedge, or has not been designated as such, the natural gas inventory is valued at the lower of cost or market.

~~Hedging Activities in 2015~~

In March, May and June 2015, Sharp paid a total of approximately $143,000 to purchase put options to protect against a decline in propane prices and related potential inventory losses associated with 2.5 million gallons for the propane price cap program in the 2015-2016 heating season. We exercised the put options as propane prices fell below the strike prices of $0.4950, $0.4888 and $0.4500 per gallon in December 2015 through February 2016 and $0.4200 per gallon in January through March 2016. We received approximately $239,000, which represents the difference between the market prices

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~~and the strike prices during those months. We accounted for the put options as fair value hedges.~~

In March, May and June 2015, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 2.5 million gallons purchased in December 2015 through March 2016. Under these swap agreements, Sharp would have received the difference between the index prices (Mont Belvieu prices in December 2015 through March 2016) and the swap prices, which ranged from $0.5200 to $0.5950 per gallon, for each swap agreement, to the extent the index prices exceeded the swap prices. If the index prices were lower than the swap prices, Sharp would pay the difference. These swap agreements essentially fixed the price of the 2.5 million gallons that we purchased during this period. We accounted for the swap agreements as cash flow hedges. Sharp paid approximately $484,000, which represents the difference between the index prices and swap prices during those months of the swap agreements.

Commodity Contracts for Trading Activities

Shortly after the first quarter of 2017, Xeron ~~engages~~wound down its operations. Xeron was previously engaged in trading activities using forward and futures contracts for propane and crude oil. These contracts ~~are~~were considered derivatives and ~~have been~~were accounted for using the mark-to-market method of accounting. Under this method, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statements of income for the period of change. As of September 30, ~~2016,~~2017, Xeron had no outstanding contracts that were accounted for as derivatives.

Xeron entered into master netting agreements with two counterparties to mitigate exposure to counterparty credit risk. The master netting agreements enable Xeron to net these two counterparties' outstanding accounts receivable and payable, which are presented on a gross basis in the accompanying condensed consolidated balance sheets. At September 30, 2016, Xeron had no accounts receivable or accounts payable balances to offset with these two counterparties. At December 31, 2015, Xeron had a right to offset $431,000 of accounts payable with these two counterparties. At December 31, 2015, Xeron did not have outstanding accounts receivable with these two counterparties.

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a ~~credit-risk-related~~credit risk-related contingency. The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of September 30, ~~2016~~2017 and December 31, ~~2015,~~2016, are as follows:


	Asset Derivatives
		Fair Value As Of					Fair Value As Of
(in thousands)	Balance Sheet Location	September 30, 2016		December 31, 2015		Balance Sheet Location	September 30, 2017		December 31, 2016
Derivatives not designated as hedging instruments
Forward & Future contracts	Mark-to-market energy assets	$	—	$	1
Derivatives designated as fair value hedges
Propane swap agreements						Derivative assets, at fair value	$	15	$	8
Put options	Mark-to-market energy assets	—		152		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	Mark-to-market energy assets	240		—		Derivative assets, at fair value	—		113
Propane swap agreements	Mark-to-market energy assets	237		—		Derivative assets, at fair value	1,510		693
Total asset derivatives		$	477	$	153		$	1,526	$	823

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	Liability Derivatives					Liability Derivatives
		Fair Value As Of					Fair Value As Of
(in thousands)	Balance Sheet Location	September 30, 2016		December 31, 2015		Balance Sheet Location	September 30, 2017		December 31, 2016
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy liabilities	$	—	$	1
Natural gas futures contracts	Mark-to-market energy liabilities	29		—
Derivatives designated as fair value hedges
Natural gas futures contracts	Mark-to-market energy liabilities	—		—		Derivative liabilities, at fair value	$	13	$773
Derivatives designated as cash flow hedges
Propane swap agreements	Mark-to-market energy liabilities	—		323
Natural gas swap contracts						Derivative liabilities, at fair value	412		—
Natural gas futures contracts	Mark-to-market energy liabilities	—		109		Derivative liabilities, at fair value	1,307		—
Total liability derivatives		$	29	$	433		$	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 September 30,						For the Nine Months Ended September 30,
(in thousands)	(Loss) on Derivatives	2016			2015			2016			2015			(Loss) on Derivatives	2017			2016			2017			2016
Derivatives not designated as hedging instruments
Realized gain (loss) on forward contracts ⁽¹⁾	Revenue	$	(231	)	$	187		$	44		$	393
Realized gain on forward contracts and options ⁽¹⁾														Revenue	$	—		$	(231	)	$	112		$	44
Unrealized gain (loss) on forward contracts ⁽¹⁾	Revenue	(2		)	(7		)	—			71			Revenue	—			(2		)	—			—
Natural gas futures contracts	Cost of sales	205			—			205			—			Cost of sales	286			205			907			205
Propane swap agreements	Cost of sales	—			—			—			18			Cost of sales	15			—			11			—
Natural gas swap contracts														Cost of sales	1			—			1			—
Derivatives designated as fair value hedges
Put /Call options	Cost of sales	—			—			73			506
Put /Call options⁽²⁾	Propane Inventory	—			(46		)	—			(79		)
Put /Call option ⁽²⁾														Cost of sales	—			—			(9		)	73
Natural gas futures contracts	Natural Gas Inventory	—			—			(233		)	—			Natural gas inventory	—			—			—			(233		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	—			—			(364		)	—			Cost of sales	198			—			663			(364		)
Propane swap agreements	Other Comprehensive Gain (Loss)	213			(126		)	559			(128		)	Other comprehensive income	1,590			213			814			559
Call options	Cost of sales	—			—			—			(81		)
Natural gas futures contracts	Cost of sales	105			—			464			—			Cost of sales	(852		)	105			929			464
Natural gas futures contracts	Other Comprehensive Gain (Loss)	(123		)	—			349			—			Other comprehensive income (loss)	(1,296		)	(123		)	(1,420		)	349
Natural gas swap agreements														Cost of sales	1			—			1			—
Natural gas swap agreements														Other comprehensive loss	(413		)	—			(413		)	—
Total		$	167		$	8		$	1,097		$	700			$	(470	)	$	167		$	1,596		$	1,097


⁽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.~~inventory on the condensed consolidated balance sheets.


~~13.~~12.	Fair Value of Financial Instruments

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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, ~~2016~~2017 and December 31, ~~2015:~~2016:


			Fair Value Measurements Using:								Fair Value Measurements Using:
As of September 30, 2016	Fair Value		Quoted- Prices- in Active Markets (Level 1)		Significant- Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
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)
(in thousands)
Assets:
Investments—equity securities	$	21	$	21	$	—	$	—	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	$	485	$	—	$	—	$	485	642		—		—		642
Investments—mutual funds and other	$	4,124	$	4,124	$	—	$	—	5,716		5,716		—		—
Mark-to-market energy assets, incl. put options and swap agreements	$	477	$	—	$	477	$	—
Total investments									6,380		5,738		—		642
Derivative assets									1,526		—		1,526		—
Total assets									$	7,906	$	5,738	$	1,526	$	642
Liabilities:
Mark-to-market energy liabilities incl. swap agreements	$	29	$	—	$	29	$	—
Derivative liabilities									$	1,732	$	—	$	1,732	$	—


			Fair Value Measurements Using:								Fair Value Measurements Using:
As of December 31, 2015	Fair Value		Quoted- Prices- in Active Markets (Level 1)		Significant- Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
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)
(in thousands)
Assets:
Investments—equity securities	$	18	$	18	$	—	$	—	$	21	$	21	$	—	$	—
Investments—guaranteed income fund	$	279	$	—	$	—	$	279	561		—		—		561
Investments—mutual funds and other	$	3,347	$	3,347	$	—	$	—	4,320		4,320		—		—
Mark-to-market energy assets, incl. put/call options	$	153	$	—	$	153	$	—
Total investments									4,902		4,341		—		561
Derivative assets									823		—		823		—
Total assets									$	5,725	$	4,341	$	823	$	561
Liabilities:
Mark-to-market energy liabilities, incl. swap agreements	$	433	$	—	$	433	$	—
Derivative liabilities									$	773	$	—	$	773	$	—

The following valuation techniques were used to measure the fair value of assets and liabilities in the tables ~~above on a recurring basis as of~~ ~~September 30, 2016~~ ~~and December 31, 2015:~~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.

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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:

~~Mark-to-market energy~~Derivative assets and liabilities — ~~These~~The fair values of forward contracts are ~~valued~~measured using market transactions in either the listed or OTC markets.

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

Level 3 Fair Value Measurements:

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

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the nine months ended September 30, ~~2016~~2017 and ~~2015:~~2016:


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2016			2015			2017			2016
(in thousands)
Beginning Balance	$	279		$	287		$	561		$	279
Purchases and adjustments	120			(11		)	76			120
Transfers	88			(3		)	—			88
Distribution	(8		)	—			(2		)	(8		)
Investment income	6			3			7			6
Ending Balance	$	485		$	276		$	642		$	485

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

At September 30, ~~2016~~,2017, 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, ~~2016~~2017, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of approximately ~~$151.8~~$211.4 million. This compares to a fair value of approximately ~~$173.5~~$224.2 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At December 31, ~~2015,~~2016, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of approximately ~~$153.7~~$145.9 million, compared to the estimated fair value of approximately ~~$165.1~~$161.5 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

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~~14.~~13.	Long-Term Debt

Our outstanding long-term debt is shown below:


	September 30,			December 31,			September 30,			December 31,
(in thousands)	2016			2015			2017			2016
FPU secured first mortgage bonds ⁽¹⁾:
9.08% bond, due June 1, 2022	$	7,976		$	7,973		$	7,981		$	7,978
Uncollateralized senior notes:
6.64% note, due October 31, 2017	5,455			5,455			2,727			2,727
5.50% note, due October 12, 2020	10,000			10,000			8,000			8,000
5.93% note, due October 31, 2023	22,500			24,000			19,500			21,000
5.68% note, due June 30, 2026	29,000			29,000			26,100			29,000
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			—
Promissory notes	168			238			97			168
Capital lease obligation	3,814			4,824			2,425			3,471
Less: debt issuance costs							(446		)	(291		)
Total long-term debt	155,913			158,490			213,384			149,053
Less: current maturities	(12,087		)	(9,151		)	(12,136		)	(12,099		)
Less: debt issuance costs	(301		)	(333		)
Total long-term debt, net of current maturities	$	143,525		$	149,006		$	201,248		$	136,954

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

Shelf ~~Agreement~~Agreements

OnIn October 8, 2015, we entered into athe Prudential Shelf Agreement, ~~with Prudential. Under the terms of the Shelf Agreement, through October 8, 2018,~~under which we may request that Prudential purchase, through October 8, 2018, up to $150.0 million of ~~our~~Prudential Shelf Notes. The Prudential Shelf Notes athave a fixed interest rate and ~~with~~ a maturity date not to exceed 20 years from the date of issuance. Prudential is under no obligation to purchase any of the 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. We currently anticipate the proceeds from the sale of any series of Shelf Notes will be used for general corporate purposes, including refinancing of short-term borrowing and/or repayment of outstanding indebtedness

In May 2016, Prudential confirmed and ~~financing capital expenditures on future projects; however, actual use of such proceeds will be determined at the time of a purchase.~~

~~On May 13, 2016, we submitted a~~accepted our request that Prudential purchase $70.0 million of 3.25 percent Prudential Shelf Notes, ~~under the Shelf Agreement. On May 20, 2016, Prudential accepted and confirmed our request.~~which were issued on April 21, 2017. The proceeds received from ~~the issuances~~this issuance of ~~the~~Prudential Shelf Notes ~~will be~~were used to reduce short-term borrowings under the ~~Company’s revolving credit facility, lines of credit and/or to fund~~Revolver. The balance under the Revolver had accumulated over time as capital ~~expenditures. The closing of the sale and issuance of the Shelf Notes is expected to occur on or before April 28, 2017.~~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.


~~15.~~	~~Short-Term Borrowing~~

~~On October 8, 2015,~~In March 2017, we entered into the ~~Credit~~MetLife Shelf Agreement ~~with~~and the ~~Lenders for a~~NYL Shelf Agreement, under which we may request that MetLife and NYL, through March 2, 2020, purchase up to $150.0 million ~~Revolver for~~and $100.0 million, respectively, of our unsecured senior debt. The unsecured senior debt would have a ~~term~~fixed interest rate and a maturity date not to exceed 20 years from the date of ~~five years, subject~~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 ~~terms and conditions~~time of ~~the Credit Agreement. Borrowings~~purchase. As of September 30, 2017, no unsecured senior debt has been issued under the ~~Revolver will be used for general corporate purposes, including repayments of short-term borrowings, working capital requirements~~MetLife and ~~capital expenditures.~~NYL Shelf Agreements.

Borrowings under the Revolver will bear interest at: (i) the LIBOR Rate plus an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization, both as defined by the Credit Agreement, or (ii) the base rate plus 0.25 percent or less. Interest will be payable quarterly, and the Revolver is subject to a commitment fee on the unused portion of the facility. We may extend the expiration date for up to two years on any anniversary date of the Revolver, with such extension subject to the Lenders' approval. We may also request the Lenders

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~~to increase the Revolver to $200.0 million, with any increase at the sole discretion of each Lender. At~~ ~~September 30, 2016 and December 31, 2015, we had outstanding borrowings of $50.0 million and $35.0 million, respectively, under the Revolver.~~

The net proceeds from the sale of our common stock on September 22, 2016, of approximately $57.3 million, after deducting underwriting commissions and expenses, were added to our general funds and used to repay a portion of our short-term debt under unsecured lines of credit.

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K for the year ended December 31, ~~2015,~~2016, 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 or otherwise. These statements are subject to many risks ~~uncertainties~~ and ~~other~~uncertainties. In addition to the risk factors described under Item 1A, Risk Factors in our 2016 Annual Report on Form 10-K, the following important factors, ~~that~~among others, could cause actual future results to differ materially from those expressed in the forward-looking ~~statements. Such factors include, but are not limited to:~~statements:

state and federal legislative and regulatory initiatives (including deregulation) that affect cost and investment recovery, have an impact on rate structures and affect the speed ~~at,~~ and ~~the~~ degree ~~to, which~~of competition ~~enters~~entering the electric and natural gas industries;

the outcomes of regulatory, tax, environmental and legal matters, including whether pending matters are resolved within current estimates and whether the costs associated with such matters are adequately covered by insurance or recoverable in rates;

the timing of certificate authorizations associated with new capital projects;

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 or contraction in our markets or service territories;

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

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

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

the ability to establish 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 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 establish and maintain new key supply sources;~~

~~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;~~

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

~~conditions of the capital markets and equity markets during the periods covered by the forward-looking statements;~~

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

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

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

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

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

the ability to successfully execute, manage and integrate merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture, and the success of the business following a merger, acquisition or divestiture;

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

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

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~~the effect of competition on our businesses;~~

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

the 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 ~~regulatory~~technological improvements;

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

the impact of significant changes to current tax regulations and ~~other governmental approvals, authorizations, and permits;~~rates; and

~~the loss~~

Table of ~~customers due to a government-mandated sale of our utility distribution facilities.~~Contents

the impact of future rate case proceedings.

Introduction

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

Our strategy is focused on growing earnings from a stable utility foundation and investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. 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 ~~organic~~ growth opportunities that generate returns equal to or greater than our cost of capital;

expanding ~~the regulated~~our energy distribution and transmission businesses organically as well as into new geographic ~~areas and~~ areas;

providing new services in our current service territories;

expanding ~~the propane distribution business~~our footprint in ~~existing and new~~potential growth markets ~~through leveraging our community gas system services, our vehicular fuel offerings and our bulk delivery capabilities;~~

~~expanding both our regulated and unregulated energy businesses~~ through strategic acquisitions;

~~utilizing our expertise across our various businesses to improve overall performance;~~

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

~~enhancing marketing channels to attract new customers;~~

~~providing reliable and responsive customer service to existing customers so they become our best promoters;~~

~~engaging our customers~~differentiating the Company as a full-service energy supplier/partner/provider through a ~~distinctive service excellence initiative;~~

~~developing and retaining a high-performing team that advances our goals;~~

~~empowering and engaging our employees at all levels to live our brand and vision;~~

~~demonstrating community leadership and engaging our local communities and governments in a cooperative and mutually beneficial way;~~

~~maintaining a capital structure that enables us to access capital as needed;~~

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

~~maintaining a consistent and competitive dividend for stockholders; and~~

~~creating and maintaining a diversified customer base, energy portfolio and utility foundation.~~customer-centric model.

The following discussions and those elsewhere in ~~the document~~this Quarterly Report on Form 10-Q on operating income and segment results include the use of the term “gross ~~margin.”~~ ~~“Gross margin”~~margin", which is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased ~~fuel~~ cost ~~for~~of natural gas, electricity and propane and the cost of labor spent on direct revenue-producing ~~activities.~~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. ~~Chesapeake Utilities believes~~We believe that gross margin, although a non-GAAP measure, is useful and meaningful ~~in our regulated operations because the cost of natural gas and electricity are passed through~~ to ~~customers and changes in commodity prices can cause revenue to go up and down in ways that are not indicative of volumes sold or tied to profitability. Gross margin~~investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by ~~Chesapeake Utilities~~us under ~~its~~our allowed rates for regulated operations and under ~~its~~our competitive pricing structure for non-regulated segments. ~~Chesapeake Utilities'~~Our management uses gross margin in measuring its business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.

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

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Results of Operations for the Three and Nine Months ended September 30, ~~2016~~2017

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 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, ~~2016~~2017 was $6.8 million, or $0.42 per share. This represents an increase of $2.4 million, or $0.13 per share, compared to net income of $4.4 million, or $0.29 per share, reported for the same quarter in 2016. Operating income increased $4.1 million for the three months ended September 30, 2017.



	Three Months Ended
	September 30,						Increase
	2017			2016			(decrease)
(in thousands except per share)
Business Segment:
Regulated Energy segment	$	15,168		$	13,115		$	2,053
Unregulated Energy segment	(989		)	(3,080		)	2,091
Other businesses and eliminations	60			121			(61		)
Operating Income	$	14,239		$	10,156		$	4,083
Other income (expense), net	239			(28		)	267
Interest charges	3,321			2,722			599
Pre-tax Income	11,157			7,406			3,751
Income taxes	4,324			2,990			1,334
Net Income	$	6,833		$	4,416		$	2,417
Earnings Per Share of Common Stock
Basic	$	0.42		$	0.29		$	0.13
Diluted	$	0.42		$	0.29		$	0.13

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Key variances, between the third quarter of 2017 and the third quarter of 2016, 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

*See the Major Projects and Initiatives table.

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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 ~~$703,000,~~$789,000, or ~~$0.04~~$0.18 per share, compared to ~~the~~ net income of ~~$5.1~~$32.8 million, or ~~$0.33~~$2.14 per share, as reported for the same ~~quarter~~period in ~~2015.~~2016. Operating income ~~decreased $753,000~~increased $303,000 for the ~~three~~nine months ended September 30, 2016. Gross margin increased by $4.7 million, although other operating expenses increased by $5.5 million. The increase in other operating expenses, in part, reflects the fact that the higher expenses to support growth of our businesses are largely recognized equally across the year, while the margin from this growth is more concentrated in the heating season during the fourth and first quarters.2017.


	Three Months Ended									Nine Months Ended
	September 30,						Increase			September 30,						Increase
	2016			2015			(decrease)			2017			2016			(decrease)
(in thousands except per share)
Business Segment:
Regulated Energy segment	$	13,115		$	11,828		$	1,287		$	51,915		$	52,660		$	(745	)
Unregulated Energy segment	(3,080		)	(1,022		)	(2,058		)	10,504			9,267			1,237
Other businesses and eliminations	121			103			18			161			350			(189		)
Operating Income	$	10,156		$	10,909		$	(753	)	$	62,580		$	62,277		$	303
Other (expense) income, net	(28		)	36			(64		)
Other expense, net										(643		)	(68		)	(575		)
Interest charges	2,722			2,492			230			9,133			7,996			1,137
Pre-tax Income	7,406			8,453			(1,047		)	52,804			54,213			(1,409		)
Income taxes	2,990			3,334			(344		)	20,781			21,401			(620		)
Net Income	$	4,416		$	5,119		$	(703	)	$	32,023		$	32,812		$	(789	)
Earnings Per Share of Common Stock
Basic	$	0.29		$	0.34		$	(0.05	)	$	1.96		$	2.14		$	(0.18	)
Diluted	$	0.29		$	0.33		$	(0.04	)	$	1.96		$	2.14		$	(0.18	)

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Key variances, between the ~~third quarter of 2015~~nine months ended 2017 and the ~~third quarter of~~nine months ended 2016, included:

(in thousands, except per share data) Pre-tax
Income Net
Income Earnings
Per Share
Third Quarter of 2015 Reported Results $ 8,453
$ 5,119
$ 0.33

Increased (Decreased) Gross Margins:
Eight Flags* 2,033
1,212
0.08
Service expansions* 1,577
940
0.06
Natural gas growth (excluding service expansions) 943
562
0.04
GRIP* 920
549
0.04
Implementation of Delaware Division interim rates* 469
280
0.02
Lower retail propane margins (414 ) (247 ) (0.02 )
Lower margins for Xeron (413 ) (246 ) (0.02 )
Aspire Energy* (407 ) (243 ) (0.02 )
4,708
2,807
0.18
Decreased (Increased) Other Operating Expenses:
Higher payroll and benefits costs (1,830 ) (1,091 ) (0.07 )
Eight Flags operating expenses (1,065 ) (635 ) (0.04 )
Higher outside services costs (928 ) (553 ) (0.04 )
Higher facility maintenance (601 ) (358 ) (0.02 )
Higher depreciation, asset removal and property tax costs (466 ) (278 ) (0.02 )
(4,890 ) (2,915 ) (0.19 )
Interest charges (230 ) (137 ) (0.01 )
Net Other Changes (635 ) (458 ) (0.02 )
Third Quarter of 2016 Reported Results $ 7,406
$ 4,416
$ 0.29



(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.

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Our net income for the nine months ended September 30, 2016 was $32.8 million, or $2.14 per share. This represents an increase of $291,000 or a decrease of $0.02 per share, compared to net income of $32.5 million, or $2.16 per share, as reported for the same period in 2015. Our growth projects and initiatives generated earnings that were offset by the effect of warmer weather, primarily in the normally colder first quarter, as well as the $1.4 million lower net settlement gain associated with the customer billing system. The warmer weather reduced year-to-date earnings per share by $0.31 compared to the same period last year.

Nine Months Ended Increase
September 30, (decrease)
2016 2015
(in thousands except per share)
Business Segment:
Regulated Energy segment $ 52,660
$ 47,616
$ 5,044
Unregulated Energy segment 9,267
13,666
(4,399 )
Other businesses and eliminations 350
305
45
Operating Income $ 62,277
$ 61,587
690
Other (expense) income, net (68 ) (3 ) (65 )
Interest charges 7,996
7,425
571
Pre-tax Income 54,213
54,159
54
Income taxes 21,401
21,638
(237 )
Net Income $ 32,812
$ 32,521
$ 291
Earnings Per Share of Common Stock
Basic $ 2.14
$ 2.16
$ (0.02 )
Diluted $ 2.14
$ 2.16
$ (0.02 )

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~~Key variances, between the first nine months of 2015 and the first nine months of 2016, included:~~

(in thousands, except per share data) Pre-tax Income Net Income Earnings Per Share
Nine months ended September 30, 2015 Reported Results $ 54,159
$ 32,521
$ 2.16
Adjusting for Unusual Items:
Weather impact, primarily in the first quarter (7,548 ) (4,533 ) (0.31 )
Net gain from settlement agreement associated with customer billing system (1,367 ) (821 ) (0.06 )
(8,915 ) (5,354 ) (0.37 )
Increased (Decreased) Gross Margins:
Service expansions* 5,516
3,312
0.22
GRIP* 3,069
1,843
0.12
Natural gas growth (excluding service expansions) 2,630
1,579
0.11
Eight Flags* 2,581
1,550
0.10
Lower retail propane margins (2,204 ) (1,324 ) (0.09 )
Implementation of Delaware Division interim rates* 1,350
811
0.05
Natural gas marketing 1,062
638
0.04
Sandpiper SIR 618
371
0.03
14,622
8,780
0.58
Decreased (Increased) Other Operating Expenses:
Higher payroll and benefits costs (2,144 ) (1,287 ) (0.09 )
Higher depreciation, asset removal and property tax costs (1,705 ) (1,024 ) (0.07 )
Eight Flags operating expenses (1,136 ) (682 ) (0.05 )
Higher outside services costs (1,100 ) (661 ) (0.04 )
Higher facility maintenance (787 ) (473 ) (0.03 )
Lower bad debt, sales and advertising 427
256
0.02
(6,445 ) (3,871 ) (0.26 )
Net contribution from Aspire Energy, including impact of shares issued* 2,069
1,274
0.08
Interest Charges (571 ) (343 ) (0.02 )
Net Other Changes (706 ) (195 )
(0.03 )
Nine months ended September 30, 2016 Reported Results $ 54,213
$ 32,812
$ 2.14

*See the Major Projects and Initiatives table.

Table of Contents

Summary of Key Factors

Major Projects and Initiatives

The following table summarizes gross margin for our major projects and initiatives recently completed ~~since 2014 and our major projects~~ and initiatives currently underway, but which will be completed in the future. Gross margin reflects operating revenue less cost of sales, excluding depreciation, amortization and accretion (dollars in thousands):

Gross Margin for the Period
Three Months Ended Nine Months Ended Total
September 30, September 30, 2015 Estimate for
2016 2015 2016 2015 Margin 2016 2017 2018
Major projects and initiatives completed since 2014 $ 12,083
$ 7,490
$ 34,086
$ 17,030
$ 25,270
$ 47,603
$ 54,258
$ 54,727
Major projects and initiatives underway ⁽¹⁾
—
—
—
—
—
—
5,255
20,238
$ 12,083
$ 7,490
$ 34,086
$ 17,030
$ 25,270
$ 47,603
$ 59,513
$ 74,965



	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

⁽¹⁾~~This represents gross margin for~~ 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, ~~Expansion projects.~~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.

Major Projects and Initiatives Recently Completed ~~Since 2014~~

The following table summarizes gross margin generated by our major projects and initiatives recently completed ~~since 2014 on an individual basis~~ (dollars in thousands):

Gross Margin for the Period
Three Months Ended Nine Months Ended Total
September 30, September 30, 2015 Estimate for
2016 2015 Variance 2016 2015 Variance Margin 2016 2017 2018
Acquisition:
Aspire Energy $ 1,630
$ 2,037
$ (407 ) $ 8,203
$ 3,661
$ 4,542
$ 6,324
$ 12,674
$ 13,376
$ 14,302
Natural Gas Transmission Expansions and Contracts:
Short-term contracts
New Castle County, Delaware $ 664
$ 507
$ 157
$ 2,040
$ 1,998
$ 42
$ 2,682
$ 2,910
$ 2,275
$ 714
Kent County, Delaware 2,416
1,055
1,361
6,231
1,453
4,778
2,270
7,982
1,377
—
Total short-term contracts $ 3,080
$ 1,562
$ 1,518
$ 8,271
$ 3,451
$ 4,820
$ 4,952
$ 10,892
$ 3,652
$ 714
Long-term contracts
Kent County, Delaware 455
463
(8 ) 1,366
1,389
(23 ) 1,844
1,815
7,629
7,605
Polk County, Florida 407
340
67
1,221
501
720
908
1,627
1,627
1,627
Total long-term contracts $ 862
$ 803
$ 59
$ 2,587
$ 1,890
$ 697
$ 2,752
$ 3,442
$ 9,256
$ 9,232
Total Expansions & Contracts $ 3,942
$ 2,365
$ 1,577
$ 10,858
$ 5,341
$ 5,517
$ 7,704
$ 14,334
$ 12,908
$ 9,946
Florida GRIP $ 2,987
$ 2,067
$ 920
$ 8,383
$ 5,314
$ 3,069
$ 7,508
$ 11,405
$ 13,756
$ 15,960
Florida Electric Rate Case $ 1,021
$ 1,021
$ —
$ 2,714
$ 2,714
$ —
$ 3,734
$ 3,562
$ 3,562
$ 3,562
Delaware Division Rate Case $ 469
$ —
$ 469
$ 1,347
$ —
$ 1,347
$ —
$ 2,164
$ 2,500
$ 2,500
Eight Flags CHP Plant $ 2,034
$ —
$ 2,034
$ 2,581
$ —
$ 2,581
$ —
$ 3,464
$ 8,156
$ 8,457
Total Completed Major Projects and Initiatives $ 12,083
$ 7,490
$ 4,593
$ 34,086
$ 17,030
$ 17,056
$ 25,270
$ 47,603
$ 54,258
$ 54,727

~~Aspire Energy~~

Aspire Energy's gross margin decreased by $407,000 for the three months ended September 30, 2016, partly due to increased deliveries and imbalance positions that favorably impacted Aspire Energy in the third quarter of 2015, which are non-recurring. Lower margin associated with system volumes and imbalance positions in third quarter of 2016 also contributed to the decrease.



	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 ~~nine months ended September 30, 2016, Aspire Energy generated $4.5 million~~third quarter of 2017, a portion of the increase in ~~additional gross margin compared~~rates, implemented subject to ~~the same period~~refund in 2015. Aspire Energy's gross margin for the same period in 2015 was lower due in part to the fact that the period included only six months of results commencing on April 1, 2015. Aspire Energy also generated additional gross margin primarilyAugust 2017, has been recorded as ~~a result of pricing amendments to long-term gas sales agreements, additional management fees~~revenue and the ~~optimization of gathering system receipts~~remainder has been reserved pending the settlement. See Note 3, Rates and ~~deliveries. As projected, this merger was accretive to earnings per share in the first full year of operations.~~Other Regulatory Activities, for additional information.

Service Expansions

On January 16, 2015, the Florida PSC approved a firm transportation agreement between Peninsula Pipeline and our Florida natural gas distribution division. Pursuant to this agreement, Peninsula Pipeline provides natural gas transmission service to support our expansion of natural gas distribution service in Polk County, Florida. Peninsula Pipeline began the initial phase of its service to Chesapeake Utilities' Florida natural gas distribution division in March 2015. This new service generated $67,000 and $720,000 of additional gross margin for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015. When all phases of this service are complete, this expansion will generate an estimated annual gross margin of $1.6 million.

In ~~April 2015,~~August 2014, Eastern Shore ~~commenced interruptible service to~~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. ~~The interruptible~~Eastern Shore provided interim services to this customer pending construction of facilities. Construction of the project was completed, and long-term service ~~concluded~~commenced in ~~December 2015 and was replaced by a short-term OPT ≤ 90 Service, which~~March 2017. This service generated an additional gross margin of ~~$901,000 and $4.3 million~~$106,000 during the ~~three and~~ nine months ended September 30, ~~2016, respectively,~~2017 compared to the same ~~periods~~period in ~~2015. The short-term OPT ≤ 90 Service~~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 ~~be replaced by a 20-year contract~~generate gross margin of $7.0 million for ~~OPT ≤ 90 Service in~~2017 and between $5.8 million and $7.8 million annually through the ~~first quarter~~remaining term of ~~2017.~~the agreement.

~~On October 13,~~In December 2015, ~~Eastern Shore submitted an application to~~ the FERC approved Eastern Shore's application to make certain ~~measurement~~meter tube and control valve replacements and related improvements at its TETLP interconnect facilities ~~which would enable Eastern Shore~~ to increase natural gas receipts from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. ~~In December 2015, the FERC authorized Eastern Shore to proceed with this~~The project ~~which~~ was completed and placed in service in March 2016. Approximately 8535 percent of the increased capacity has been subscribed on a short-term firm service ~~basis.~~basis through October 2017. This service generated an additional gross margin of ~~$617,000~~$80,000 and ~~$744,000~~$1.3 million for the three and nine months ended September 30, ~~2016,~~2017, respectively, compared to the same periods in ~~2015, and is expected to generate approximately $1.4 million in additional gross margin for the year.~~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 program allows recovery, through regulated rates, of capital and other program-related costs, inclusive of a return on investment, associated with the replacement of the mains and services. Since the program's inception ~~of the program~~ in August 2012, we have invested ~~$97.3~~$110.5 million to replace ~~209~~240 miles of qualifying distribution mains, including ~~$20.4~~$7.6 million during the first nine months of ~~2016. We expect to invest an additional $650,000 in this program during the remainder of 2016.~~2017. The increased investment in GRIP generated additional gross margin of ~~$920,000~~$406,000 and ~~$3.1~~$1.6 million for the three and nine months ended September 30, ~~2016,~~2017, respectively, compared to the same periods in ~~2015.~~

2016.

Eight ~~Flags~~Flags' CHP plant

In June 2016, Eight Flags completed construction of a CHP plant on Amelia Island, Florida. This CHP plant, which consists of a natural-gas-fired turbine and associated electric generator, produces approximately 20 ~~megawatts~~MWH of base load power and includes a heat recovery steam generator capable of providing approximately 75,000 pounds per hour of residual steam. OnIn June ~~13,~~ 2016, Eight Flags began selling power generated from the CHP plant to FPU, ~~our wholly-owned subsidiary,~~ pursuant to a 20-year power purchase agreement for distribution to its retail electric customers. OnIn July 1, 2016, it also started selling steam to anthe 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.~~system and by Peninsula Pipeline. For the three and nine months ended September 30, 2017, Eight Flags and other affiliates of Chesapeake Utilities generated ~~$2.0 million~~$304,000 and ~~$2.6~~$4.7 million, in additional gross margin as a result of these ~~new~~ 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, ~~2016 in which the CHP was operational. This amount includes gross margin of $464,000 and $892,000, for the three and nine months ended September 30, 2016, attributed~~2017, respectively, attributable to natural gas distribution and transportation services provided by our affiliates. On a consolidated basis, this project is expected to generate approximately $8.2 million in annual gross margin in 2017, which could fluctuate based upon various factors, including, but not limited to the ~~quantity of steam delivered and the~~ CHP ~~plant’s hours of operations.~~plant by Chesapeake Utilities' regulated affiliates.

System Reliability Project

~~Table of Contents~~

~~Major Projects and Initiatives Underway~~

~~White Oak Mainline Expansion Project:~~In August 2014, Eastern Shore entered into a precedent agreement with an electric power generator in Kent County, Delaware, to provide a 20-year natural gas transmission service for 45,000 Dts/d for the customer's facility, upon the satisfaction of certain conditions. This new service will be provided as a long-term OPT ≤ 90 Service and is expected to generate at least $5.8 million in annual gross margin. In November 2014, Eastern Shore requested authorization by the FERC to construct 5.4 miles of 16-inch pipeline looping and 3,550 horsepower of new compression in Delaware to provide this service. As previously discussed, during the three and nine months ended September 30, 2016, compared to the same periods in 2015, we generated $901,000 and $4.3 million, respectively, in additional gross margin by providing interruptible service and short-term OPT ≤ 90 Service to this customer. On July ~~21,~~ 2016, the FERC ~~issued a certificate of public convenience and necessity authorizing~~authorized Eastern Shore to construct and operate the ~~proposed White Oak Mainline Project. Construction of the project is underway.~~

System Reliability ~~Project:On May 22, 2015, Eastern Shore submitted an application to the FERC, seeking authorization to construct, own and operate~~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. ~~Eastern Shore further proposes to reinforce critical points on its pipeline system.~~A 2.5 mile looping segment was completed and placed into service in December 2016. The ~~total project will benefit all~~remaining looping and the new compressor were completed and placed into service in the second quarter of Eastern Shore’s customers by modifying the pipeline system to respond to severe operational conditions experienced during actual winter peak days. Since the project is intended to improve system reliability, Eastern Shore requested a predetermination of rolled-in rate treatment for the costs of the project and an order granting the requested authorization.2017. This project ~~will be~~was included in Eastern Shore's ~~upcoming~~January 2017 base rate case ~~filing.~~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.

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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, ~~assuming recovery~~once in ~~the 2017 rate case,~~service, is approximately ~~$4.5~~$5.1 million. ~~On July 21, 2016,~~

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 ~~FERC issued a certificate of public convenience~~FGT interconnect that will be operated by Peninsula Pipeline and ~~necessity authorizing Eastern Shore to construct and operate the proposed System Reliability Project. Construction of the~~will serve FPU natural gas distribution customers. The estimated annual gross margin associated with this project, once in service, is ~~underway.~~approximately $1.4 million.

2017 Expansion ~~Project:~~Project On

In May ~~12,~~ 2016, Eastern Shore submitted a request to the FERC to initiate the FERC's pre-filing ~~procedures~~process for its proposed 2017 Expansion Project. ~~Since the time the pre-filing was initiated,~~This project, which will expand Eastern ~~Shore has finalized market participation for the project. Seven of Eastern Shore’s existing customers have signed Precedent Agreements. As a result, the project~~Shore's firm service capacity by 26 percent, will provide 61,162 Dts/d of additional firm natural gas transportation ~~deliverability~~service on Eastern ~~Shore’s~~Shore's pipeline system. To provide this additional capacity, the project’s final facilities will consist of approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation ofsystem with an additional ~~3,550 horsepower compressor unit~~52,500 Dts/d of firm transportation service at certain Eastern ~~Shore’s~~Shore receipt facilities pursuant to precedent agreements Eastern Shore entered into with existing ~~Daleville compressor station~~customers. We expect to invest approximately $115.0 million in ~~Chester County, Pennsylvania;~~this expansion project, and ~~approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware. The~~for the project ~~will~~to generate approximately ~~$15.7~~$15.8 million of gross margin in the first full year after the new transportation services go into effect. On October 4, 2017, the FERC issued a CP authorizing Eastern Shore to construct and operate the proposed 2017 expansion project.

Other major factors influencing gross margin

Weather and Consumption

~~Although weather was not a significant factor~~Temperature variation in 2017 negatively impacted our earnings. Compared to the ~~second~~prior year, cooler temperatures in Florida during the third quarter of 2017, reduced gross margin by $333,000, and ~~third quarters,~~ warmer temperatures in all of our service territories during the first ~~three~~nine months of 2017, reduced gross margin by $1.8 million, respectively. Warmer than normal temperatures for the ~~year, compared to temperatures in 2015, had a significant impact on the our earnings. Lower customer consumption, directly attributable to warmer temperatures during the~~quarter and nine months ended September 30, ~~2016,~~2017 reduced gross margin by ~~$7.5~~$193,000 and $4.3 million, ~~compared to the same period in 2015.~~respectively. The following ~~tables summarize the~~table summarizes HDD and CDD ~~information~~variances from the 10-year average HDD/CDD ("Normal") for the three and nine months ended September 30, ~~2016~~2017 and ~~2015 resulting from weather fluctuations in those periods.~~2016.

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HDD and CDD Information

Three Months Ended Nine Months Ended
September 30, September 30,
2016 2015 Variance 2016 2015 Variance
Delmarva
Actual HDD 11
41
(30 ) 2,590
3,249
(659 )
10-Year Average HDD ("Delmarva Normal") 65
65
—
2,919
2,908
11
Variance from Delmarva Normal (54 ) (24 ) (329 ) 341

Florida
Actual HDD —
—
—
646
501
145
10-Year Average HDD ("Florida Normal") —
—
—
553
557
(4 )
Variance from Florida Normal —
—

93
(56 )
Ohio ⁽¹⁾

Actual HDD
65
78
(13 ) 3,747
710
3,037
10-Year Average HDD ("Ohio Normal") 137
143
(6 ) 3,979
811
3,168
Variance from Ohio Normal (72 ) (65 ) (232 ) (101 )
Florida
Actual CDD 1,523
1,591
(68 ) 2,737
2,827
(90 )
10-Year Average CDD ("Florida CDD Normal") 1,523
1,524
(1 ) 2,548
2,506
42
Variance from Florida CDD Normal —
67
189
321

⁽¹⁾~~HDD for Ohio is presented from April 1, 2015 through September 30, 2015.~~



	Three Months Ended						Nine Months Ended
	September 30,						September 30,
	2017		2016		Variance		2017		2016		Variance
Delmarva
Actual HDD	16		11		5		2,262		2,590		(328	)
10-Year Average HDD ("Delmarva Normal")	62		65		(3	)	2,845		2,919		(74	)
Variance from Delmarva Normal	(46	)	(54	)			(583	)	(329	)
Florida
Actual HDD	—		—		—		298		514		(216	)
10-Year Average HDD ("Florida Normal")	—		—		—		602		553		49
Variance from Florida Normal	—		—				(304	)	(39	)
Ohio
Actual HDD	80		39		41		3,072		3,596		(524	)
10-Year Average HDD ("Ohio Normal")	92		103		(11	)	3,866		3,865		1
Variance from Ohio Normal	(12	)	(64	)			(794	)	(269	)
Florida
Actual CDD	1,526		1,679		(153	)	2,606		2,792		(186	)
10-Year Average CDD ("Florida CDD Normal")	1,542		1,523		19		2,579		2,548		31
Variance from Florida CDD Normal	(16	)	156				27		244

Propane ~~prices~~Operations

~~Lower retail~~Our Florida and Delmarva propane ~~margins per gallon on the Delmarva Peninsula decreased gross margin by $344,000~~distribution operations added $2.0 million and ~~$2.2~~$1.4 million, ~~for the three and nine months ended September 30, 2016, respectively, compared to the same periods~~ in 2015. Margins per retail gallon returned to more normal levels, driven principally by lower propane prices and local market conditions. The level of retail margins per gallon generated during 2015 were not expected to be sustained over the long term; accordingly, we have continued to assume more normal levels of margins in our long-term financial plans and forecasts.

~~In Florida, retail propane margins per gallon, generated $70,000 of lower margin and $61,000 of additional gross~~incremental margin for the three and nine months ended September 30, ~~2016,~~2017, respectively, compared to the same periods in ~~2015.~~2016. Higher volumes sold to retail customers and improved margins due to effective supply management activities generated $905,000 and $440,000, in incremental margin, for the three months ended September 30, 2017, respectively, compared to the same period in 2016 and higher service revenue added $187,000 in additional margin, during the quarter.

~~These market conditions, which are influenced by competition~~For the nine months ended September 2017, higher volumes sold 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 margins resulting from supply management activities.

PESCO

PESCO provides natural gas supply and supply management services to residential, commercial, industrial and wholesale customers. PESCO operates primarily in Florida, on the Delmarva Peninsula, in Ohio, and, as a result of the recent acquisition of certain operating assets of ARM, in western Pennsylvania. PESCO competes with regulated utilities and other ~~propane suppliers~~unregulated third-party marketers to sell natural gas supplies directly to residential, commercial and industrial customers through competitively-priced contracts. PESCO does not currently own or operate any natural gas transmission or distribution assets but sells gas that is delivered to retail, commercial or wholesale customers through affiliated and non-affiliated local distribution company systems and transmission pipelines.

In 2017, our Delmarva natural gas distribution operations entered into asset management agreements with PESCO to manage a portion of their natural gas transportation and storage capacity. The asset 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, PESCO manages capacity on regional pipelines as well as third-party storage contracts for our Delmarva natural gas distribution operations in conjunction with PESCO's asset management services.

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

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of 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 margin in the Mid-Atlantic region, primarily during the first quarter of 2017.

Xeron

As disclosed previously, Xeron's operations were wound down during the second quarter of 2017. As a result, Xeron did not generate an operating loss during the third quarter of 2017 and ~~price~~will not report operating results during the fourth quarter of ~~alternative energy sources, may fluctuate based on changes~~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 ~~demand, supply~~2016, driven primarily by non-recurring employee severance costs and ~~other energy commodity prices.~~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 ~~$253,000~~$379,000 and ~~$1.1~~$1.0 million in additional gross margin for the three and nine months ended September 30, ~~2016,~~2017, respectively, compared to the same periods in ~~2015,~~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, ~~2016, increased by 4.2 percent and 3.5 percent,~~2017, respectively, compared to the same periods in ~~2015.~~2016. The natural gas distribution operations in Florida generated ~~$350,000~~$187,000 and ~~$1.1~~$1.2 million in additional gross margin for the three and nine months ended September 30, ~~2016,~~2017, respectively, compared to the same periods in ~~2015,~~2016, due primarily to an increase in commercial and industrial customers in Florida.

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Regulatory Proceedings

Delaware Division ~~rate case~~Rate Case

OnIn December ~~21, 2015, our Delaware Division filed an application with~~2016, the Delaware PSC ~~for~~approved a ~~base rate increase and certain~~settlement agreement, which, among other ~~changes to its tariff. We proposed~~things, provided for an increase ~~of approximately $4.7 million, or nearly ten percent,~~ in our Delaware division revenue requirement ~~based on the test period ending March 31, 2016. We also proposed new service offerings to promote growth~~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 ~~normalization mechanism for residential~~decreased by $38,000, reflecting the variance between settled and ~~small commercial customers. We expect a decision on~~interim rates. For the ~~application during~~nine months ended September 30, 2017 compared to the first quarter of 2017. Pending the decision, our Delaware Division increased rates on an interim basis based on the $2.5 million annualized interim rates approved by the Delaware PSC, effective February 19,same period in 2016, ~~("Phase I"). We recognized~~we recorded incremental revenue of approximately ~~$469,000 ($280,000 net~~$249,000 related to the rate case. Any amounts collected through 2016 interim rates in excess of ~~tax)~~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 ~~$1.4~~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 ~~($817,000 net of tax)~~ for the three and nine months ended September 30, ~~2016, respectively.~~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.

~~In addition,~~Investing for Future Growth

To support and continue our ~~Delaware Division~~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 ~~received approval on July 26, 2016 from~~Eight Flags, also requires additional staff as well as corporate resources to support the ~~Delaware PSC~~increased level of business operations. Finally, to ~~implement revised interim rates totaling~~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, ~~(equal~~respectively, or three percent and nine percent, respectively, compared to the ~~initial rate increase~~same periods in ~~our application) annualized for usage on~~2016. We are prudently managing the pace and after August 1, 2016 ("Phase II"). These revised interim rates represent a five percent increase over Phase I rates. Revenue associated with these rates collected prior to a final Delaware PSC decision is subject to refund and, although the final decision is expected during the first quarter of 2017, we cannot predict the revenue requirement the Delaware PSC will ultimately authorize or forecast the timing of a final decision. Consequently, we will not recognize the impactmagnitude of the ~~potential additional revenue related~~investments being made, while ensuring that we appropriately expand our human resources and systems capabilities to ~~the Phase II rate increase until the Delaware PSC issues its approval in a final ruling.~~

capitalize on future growth opportunities.

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Regulated Energy Segment

For the quarter ended September 30, ~~2016~~2017 compared to the quarter ended September 30, ~~2015~~2016


	Three Months Ended						Three Months Ended
	September 30,				Increase		September 30,				Increase
	2016		2015		(decrease)		2017		2016		(decrease)
(in thousands)
Revenue	$	70,019	$	63,796	$	6,223	$	69,703	$	70,019	$	(316	)
Cost of sales	24,644		23,161		1,483		22,794		24,644		(1,850		)
Gross margin	45,375		40,635		4,740		46,909		45,375		1,534
Operations & maintenance	22,912		19,882		3,030		21,149		22,912		(1,763		)
Depreciation & amortization	6,346		6,129		217		7,338		6,346		992
Other taxes	3,002		2,796		206		3,254		3,002		252
Other operating expenses	32,260		28,807		3,453		31,741		32,260		(519		)
Operating income	$	13,115	$	11,828	$	1,287	$	15,168	$	13,115	$	2,053

Operating income for the Regulated Energy segment for the ~~quarter~~three months ended September 30, ~~2016~~2017 was ~~$13.1~~$15.2 million, an increase of ~~$1.3~~$2.1 million ~~or 10.9 percent,~~ compared to the same ~~quarter~~period in ~~2015.~~2016. The increased operating income ~~was due primarily to an increase in~~resulted from increased gross margin of ~~$4.7~~$1.5 million ~~partially offset by an increase~~and a decrease in operating expenses of ~~$3.4 million.~~$519,000.

Gross Margin

Items contributing to the quarter-over-quarter increase of ~~$4.7~~$1.5 million, or ~~11.7~~3.4 percent, in gross margin are listed in the following table:

(in thousands)
Gross margin for the three months ended September 30, 2015 $ 40,635
Factors contributing to the gross margin increase for the three months ended September 30, 2016:
Service expansions 1,577
Natural gas growth (excluding service expansions) 943
Additional revenue from GRIP in Florida 920
Implementation of Delaware Division interim rates 469
Margin from service to Eight Flags 464
Sandpiper SIR 226
Other 141
Gross margin for the three months ended September 30, 2016 $ 45,375



(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 ~~foregoing~~ table.

Implementation of Eastern Shore Rates

~~Service Expansions~~

~~Increased~~Eastern Shore generated additional gross margin ~~from natural gas service expansions was generated primarily from the following:~~

~~$901,000 attributable to $1.9~~of $1.0 million from the ~~short-term OPT ≤ 90 Service that commenced~~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.

Additional Revenue from GRIP in ~~December 2015 to an electric power generator~~Florida

Increased investment in Kent County, Delaware and offset by a $1.0 million decrease in gross margin from the conclusion of the interruptible service Eastern Shore provided this customer in 2015. The short-term OPT ≤ 90 Service is expected to be replaced by a 20-year OPT ≤ 90 Service in the first quarter of 2017.

$617,000 from short-term firm service that commenced in March 2016, following certain measurement and related improvements to Eastern Shore's interconnect with TETLP that increased its natural gas receipt capacity from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. This service will generate approximately $1.4 million inGRIP generated additional gross margin of $406,000 for the three months ended September 30, 2017, compared to the same period in 2016. ~~The remaining capacity is available for firm or interruptible service.~~

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Natural Gas Growth (excluding service expansions)

Increased gross margin of ~~$943,000~~$347,000 from other growth in natural gas (excluding service expansions) was generated primarily from the following:

$~~368,000~~379,000 from ~~Eastern Shore interruptible service provided to~~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;

$~~350,000~~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:

$~~253,000~~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 ~~4.2 percent~~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

~~Additional Revenue~~Eastern Shore generated increased gross margin of $1.4 million from ~~GRIP~~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

~~Additional GRIP investments~~ 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 ~~2015 and 2016 by our Florida natural gas distribution operations generated $920,000 in additional gross margin in~~ the ~~third quarter~~first nine months of ~~2016, compared to the same period in 2015.~~2017.

Implementation of ~~Delaware Division Interim~~Eastern Shore Rates

~~Delaware Division~~Eastern Shore generated additional gross margin of ~~$469,000~~$1.0 million from ~~the~~ implementation of ~~interim~~new rates as a result of its rate case filing. See Note 4,3, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.

~~Margin from service~~Service to Eight Flags

We generated additional gross margin of ~~$464,000~~$534,000 in the ~~third quarter of 2016,~~nine months ended September 30, 2017, compared to the same period in ~~2015,~~2016, from new natural gas transmission and distribution services provided by our affiliates to ~~our~~ Eight Flags' CHP plant.

~~Sandpiper SIR~~

Sandpiper generated additional gross margin of $226,000, in the third quarter of 2016, compared to the same period in 2015, from a higher system improvement rate resulting from the continuing conversion of the Sandpiper system from propane service to natural gas service.

~~Other Operating Expenses~~

~~Other operating expenses increased by $3.4 million. The significant components of the increase in other operating expenses included:~~

~~$1.3 million in higher payroll and benefits costs for additional personnel to support growth;~~

~~$702,000 in higher outside services costs primarily associated with growth and ongoing compliance activities;~~

~~$517,000 in higher facilities costs to support growth; and~~

~~$401,000 in higher depreciation, asset removal and property tax costs associated with recent capital investments to support growth and system integrity.~~

~~Table of Contents~~

~~For the nine months ended September 30, 2016 compared to the nine months ended September 30, 2015~~

Nine Months Ended
September 30, Increase
2016 2015 (decrease)
(in thousands)
Revenue $ 226,630
$ 235,438
$ (8,808 )
Cost of sales 81,184
101,414
(20,230 )
Gross margin 145,446
134,024
11,422
Operations & maintenance 64,673
59,648
5,025
Depreciation & amortization 18,909
18,109
800
Other taxes 9,204
8,650
554
Other operating expenses 92,786
86,407
6,379
Operating income $ 52,660
$ 47,617

$ 5,043

Operating income for the Regulated Energy segment for the nine months ended September 30, 2016 was $52.7 million, an increase of $5.0 million, or, 10.6 percent, compared to the same period in 2015. The increased operating income was primarily due to an increase in gross margin of $11.4 million partially offset by a $6.4 million increase in operating expenses to support growth.

~~Gross Margin~~

~~Items contributing to the period-over-period increase of $11.4 million, or 8.5 percent, in gross margin are listed in the following table:~~

(in thousands)
Gross margin for the nine months ended September 30, 2015 $ 134,024
Factors contributing to the gross margin increase for the nine months ended September 30, 2016:
Service expansions 5,516
Additional revenue from GRIP in Florida 3,069
Natural gas growth (excluding service expansions) 2,630
Implementation of Delaware Division interim rates 1,350
Margin from service to Eight Flags 892
Sandpiper SIR 618
Decreased customer consumption - weather and other (2,141 )
Other (512 )
Gross margin for the nine months ended September 30, 2016 $ 145,446

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

~~Service Expansions~~

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

$4.3 million attributable to $5.6 million from the short-term OPT ≤ 90 Service that commenced in December 2015 to an electric power generator in Kent County, Delaware and offset by a $1.3 million decrease in gross margin from the conclusion of the interruptible service Eastern Shore provided this customer in 2015. The short-term OPT ≤ 90 Service is expected to be replaced by a 20-year OPT ≤ 90 Service in the first quarter of 2017.

$744,000 from short-term firm service that commenced in March 2016, following certain measurement and related improvements to Eastern Shore's interconnect with TETLP that increased its natural gas receipt capacity from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. This service will generate approximately $1.4 million in additional gross margin in 2016. The remaining capacity is available for firm or interruptible service.

~~$720,000 from natural gas transmission service as part of the major expansion initiative in Polk County, Florida.~~

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The foregoing gross margin increases were offset by a gross margin decrease of $243,000 resulting from a reduction in rates for a long-term firm service to an industrial customer in New Castle County, Delaware.

~~Additional Revenue from GRIP in Florida~~

Additional GRIP investments during 2015 and 2016 by our Florida natural gas distribution operations generated $3.1 million in additional gross margin during the first nine months of 2016, compared to the same period in 2015.

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

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

$1.1 million from a 3.5 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.

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

~~$348,000 from Eastern Shore interruptible service provided to other customers.~~

Implementation of Delaware Division ~~Interim~~ Rates

Our Delaware Division generated additional gross margin of ~~$1.4 million from the implementation of interim rates~~$249,000 as a result of ~~its~~the settlement of the rate ~~case filing, during the first nine months of 2016.~~case. See Note 4,3, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.

~~Margin from service to Eight Flags~~

~~We generated additional gross margin of $892,000 from new natural gas transmission and distribution services provided to our Eight Flags' CHP plant, commencing in June of 2016.~~

~~Sandpiper SIR Rates~~

Sandpiper generated additional gross margin of $618,000 from a higher system improvement rate resulting from the continuing conversion of the Sandpiper system from propane service to natural gas service.

~~Decreased Customer Consumption - Weather and Oth~~er

The above increases were partially offset by $2.1 million in lower gross margin due to reduced consumption of natural gas and electricity, largely as a result of warmer weather during the first quarter of 2016, compared to the same period in 2015.

Other Operating Expenses

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

$~~2.0 million in higher payroll and benefits costs for additional personnel to support growth;~~

$1.4 million due to the absence of a $1.5 million gain from a customer billing system settlement, recorded in 2015, which was partially offset by an associated gain of $130,000 during the third quarter of 2016, representing an additional current portion of the contingent settlement recovery;

~~$1.4~~3.5 million in higher depreciation, asset removal and property tax costs associated with recent capital ~~investments~~investments;

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

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

$~~817,000~~722,000 in higher ~~outside services~~benefits and employee-related costs ~~primarily associated with growth and ongoing compliance activities.~~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, ~~2016~~2017 compared to the quarter ended September 30, ~~2015~~2016


	Three Months Ended									Three Months Ended
	September 30,						Increase			September 30,						Increase
	2016			2015			(decrease)			2017			2016			(decrease)
(in thousands)
Revenue	$	42,042		$	29,609		$	12,433		$	64,688		$	42,042		$	22,646
Cost of sales	31,840			19,402			12,438			51,416			31,840			19,576
Gross margin	10,202			10,207			(5		)	13,272			10,202			3,070
Operations & maintenance	10,975			9,305			1,670			11,460			10,975			485
Depreciation & amortization	1,840			1,483			357			2,001			1,840			161
Other taxes	467			441			26			800			467			333
Other operating expenses	13,282			11,229			2,053
Operating Loss	$	(3,080	)	$	(1,022	)	$	(2,058	)
Total operating expenses										14,261			13,282			979
Operating loss										$	(989	)	$	(3,080	)	$	2,091

Operating loss for the Unregulated Energy segment for the ~~quarter~~three months ended September 30, ~~2016~~2017 was ~~$3.1 million, an increase of $2.1 million~~$989,000, compared to the same quarter of 2015. The Unregulated Energy segment typically reports an operating loss in the third quarter due to the seasonal nature the businesses included in this segment. Gross margin for the quarter was $10.2 million, which was more than offset by operating expenses of $13.3 million, to generate the operating loss of $3.1 ~~million.~~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 ~~decrease~~increase of ~~$5,000~~$3.1 million in gross margin are listed in the following table:

(in thousands)
Gross margin for the three months ended September 30, 2015 $ 10,207
Factors contributing to the gross margin decrease for the three months ended September 30, 2016:
Eight Flags 1,570
Aspire Energy (407 )
Lower margins for Xeron (413 )
Decreased retail propane margins (414 )
Other (341 )
Gross margin for the three months ended September 30, 2016 $ 10,202



(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 ~~foregoing~~ table.

Customer Consumption - Weather and Other

Gross margin increased by $1.2 million, due primarily to increased sales volumes of propane to wholesale and retail customers on the Delmarva Peninsula and higher retail propane sales volumes in Florida due primarily to the timing of deliveries.

Retail Propane Margins

Gross margin increased by $440,000, due primarily to favorable supply management activities.

Eight Flags

Eight Flags' CHP plant, which commenced operations in June 2016, generated ~~$1.6 million~~$297,000 in additional gross ~~margin.~~

~~Aspire Energy~~

~~$407,000 of decreased gross~~ margin ~~from Aspire Energy as a result of increased deliveries and imbalance positions that favorably impacted Aspire Energy~~due primarily to Eight Flags being fully on-line in the third quarter of ~~2015, which are non-recurring. Lower margin associated with system volumes and imbalance positions~~2017.

Pricing Amendments to Aspire Energy Long-Term Agreements

An increase in ~~third quarter of 2016, also contributed to the decrease.~~

~~Lower Margins for Xeron~~

~~Xeron's~~ gross margin ~~decreased by $413,000 resulting from lower margins on executed trades.~~

~~Decreased Retail Propane Margins~~

~~Lower retail propane margins for our Delmarva and Florida propane distribution operations decreased gross margin by $414,000,~~ of ~~which $344,000 is associated with the Delmarva Peninsula propane distribution operation, as retail margins per gallon returned~~$291,000 was due to pricing amendments to long-term sales agreements.

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Wholesale Propane Margins

Gross margin increased by $271,000, due primarily to ~~more normal levels; accordingly, we have continued to assume more normal levels~~favorable supply management activities for the Delmarva propane distribution operations.

Xeron

The absence of ~~margins in our long-term financial plans and forecasts. The decline in~~the prior year operating loss increased gross margin ~~was driven principally~~ by ~~lower propane prices and local market conditions. The level of retail margins per gallon generated during 2015 were not expected to be sustained over the long term.~~

$233,000.

Other Operating Expenses

Other operating expenses increased by ~~$2.1~~$1.0 million. The significant components of the increase in other operating expenses included:

$~~1.1 million in other operating expenses incurred by the Eight Flags CHP plant;~~

~~$545,000~~730,000 in higher ~~payroll~~staffing and ~~benefits~~associated costs for additional personnel to support ~~growth;~~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

$~~225,000~~293,000 in ~~higher outside services costs primarily~~expenses associated with ~~growth and ongoing compliance activities.~~the incremental margin from Eight Flags

For the nine months ended September 30, ~~2016~~2017 compared to the nine months ended September 30, ~~2015~~2016


	Nine Months Ended							Nine Months Ended
	September 30,				Increase			September 30,				Increase
	2016		2015		(decrease)			2017		2016		(decrease)
(in thousands)
Revenue	$	136,361	123,164		$	13,197		$	220,462	$	136,361	$	84,101
Cost of sales	90,981		77,235		13,746			166,635		90,981		75,654
Gross margin	45,380		45,929		(549		)	53,827		45,380		8,447
Operations & maintenance	30,136		26,993		3,143			34,971		30,136		4,835
Depreciation & amortization	4,512		3,973		539			5,833		4,512		1,321
Other taxes	1,465		1,297		168			2,519		1,465		1,054
Other operating expenses	36,113		32,263		3,850
Operating Income	$	9,267	$	13,666	$	(4,399	)
Total operating expenses								43,323		36,113		7,210
Operating income								$	10,504	$	9,267	$	1,237

Operating income for the Unregulated Energy segment for the nine months ended September 30, ~~2016~~2017 was ~~$9.3~~$10.5 million, ~~a decrease~~an increase of ~~$4.4~~$1.2 million ~~or 32.2 percent for~~compared to the same period ~~of 2015.~~in 2016. The ~~results for the first nine months include~~increased operating income was due to an increase in gross margin of ~~$4.5~~$8.4 million, ~~and other~~which was partially offset by a $7.2 million increase in operating expenses of $2.5 million, each associated with Aspire Energy. Excluding these impacts from Aspire Energy, gross margin decreased by $5.1 million, and other operating expenses increased by $1.4 million.expenses.

Gross Margin

Items contributing to the period-over-period ~~decrease~~increase of ~~$549,000~~$8.4 million in gross margin are listed in the following table:

(in thousands)
Gross margin for the nine months ended September 30, 2015 $ 45,929
Factors contributing to the gross margin decrease for the nine months ended September 30, 2016:
Aspire Energy 4,542
Eight Flags 1,689
Natural gas marketing 1,062
Lower margins for Xeron (419 )
Decreased wholesale propane sales (436 )
Decreased retail propane margins (2,204 )
Decreased customer consumption - weather and other (4,059 )
Other (724 )
Gross margin for the nine months ended September 30, 2016 $ 45,380

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(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

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 ~~foregoing~~ table.

~~Aspire Energy~~

Aspire Energy generated $8.2 million in gross margin compared to $3.7 million in the same period of 2015, an increase of $4.5 million. Results for the first nine months of 2015 reflect only six months of margin for Aspire Energy, which became a wholly-owned subsidiary of Chesapeake Utilities on April 1, 2015. In addition, Aspire Energy generated additional margins as a result of pricing amendments to long-term gas sales agreements, additional management fees and the optimization of gathering system receipts and deliveries.

Eight Flags

Eight Flags' CHP plant, which commenced operations in June 2016, generated ~~$1.7~~$4.2 million in additional gross margin.

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Natural Gas Marketing

PESCO generated ~~$1.1 million in~~ additional gross margin ~~due to customer growth and~~of $1.8 million for the ~~positive impact from favorable supply management and hedging activities, which generated additional gross margin.~~

~~Lower Margins for Xeron~~

~~Xeron's gross margin decreased by $419,000 resulting from lower margins on executed trades.~~

~~Decreased Propane Wholesale Sales~~

Gross margin decreased by $436,000 as a result of lower propane wholesale sales associated with the supply agreement between an affiliate of ESG and Sandpiper Energy. The lower sales are expected as more customers in Ocean City, Maryland and surrounding areas are converted from propane to natural gas. Lower sales due to significantly warmer weather in the first nine months ~~of 2016~~ended September 30, 2017 compared to the same period in ~~2015, also contributed~~2016. The increase in gross margin was generated primarily from providing natural gas to ~~this decrease.~~approximately 40,000 end users within one customer pool pursuant to the supplier agreement with Columbia Gas, which expired on March 31, 2017, as well as an increase in commercial and industrial customers served in Florida, offset by lower gross margin in the Mid-Atlantic region.

Pricing Amendments to Aspire Energy's Long-Term Agreements

~~Decreased Retail~~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

~~Lower retail propane margins~~Gross margin increased by $728,000, due primarily to favorable supply management activities for ~~our~~the Delmarva propane distribution operation decreased gross margin by $2.2 million, as margins per retail gallon returned to more normal levels. The decline in margin was driven principally by lower propane prices and local market conditions. The level of retail margins per gallon generated during 2015 were not expected to be sustained over the long term; accordingly, we have continued to assume more normal levels of margins in our long-term financial plans and forecasts.operations.

~~This decrease was partially offset by $61,000 in higher retail propane margins per gallon for our Florida propane distribution operation as a result of local market conditions.~~

~~Decreased~~ Customer Consumption - Weather and Other

Gross margin ~~decreased~~increased by ~~$4.1 million~~$168,000, due primarily to ~~lower customer consumption~~higher sales of ~~propane. The decrease was driven mainly by weather~~propane as a result of timing of deliveries for our propane distributions operations, coupled with increased demand for propane in Florida due to weather conditions in the third quarter of 2017. This was partially offset by the impact of warmer ~~temperatures on the Delmarva Peninsula~~weather primarily during the first ~~nine~~three months of ~~2016 compared to colder temperatures during the first nine months of 2015.~~

2017.

Other Operating Expenses

Other operating expenses increased by ~~$3.9~~$7.2 million. The significant components of the increase in other operating expenses included:

$~~2.5~~2.8 million in ~~other~~higher operating expenses ~~incurred~~ by ~~Aspire Energy, given~~Eight Flags' CHP plant in support of the margin generated;

$1.5 million in higher payroll costs for additional ~~quarter's results included~~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 ~~compared to only six months of results~~recorded in conjunction with the ~~nine months ended September 30, 2015;~~final valuation for Aspire Energy; and

$~~1.1 million~~350,000 in ~~other operating expenses incurred by Eight Flags, which commenced operations in June 2016~~.

higher outside services costs associated primarily with growth and ongoing compliance activities.

OTHER INCOME (EXPENSE), NET

~~Interest Charges~~

For the quarter ended September 30, ~~2016~~2017 compared to the quarter ended September 30, ~~2015~~2016

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, increased by $267,000 in the third quarter of 2017, 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.

INTEREST CHARGES

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

Interest charges for the three months ended September 30, ~~2016~~2017 increased by ~~approximately~~ ~~$230,000~~,$599,000, compared to the same ~~quarter~~period in ~~2015,~~2016, attributable to an increase of ~~$392,000~~$410,000 in interest ~~from~~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 in interest on higher short-term ~~borrowings, partially offset by a decrease of $117,000 in interest from long-term debt.~~

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borrowings.

For the nine months ended September 30, ~~2016~~2017 compared to the nine months ended September 30, ~~2015~~2016

Interest charges for the nine months ended September 30, ~~2016~~2017 increased by ~~approximately $571,000,~~$1.1 million, compared to the same period in ~~2015,~~2016, attributable to an increase of ~~$1.1 million~~$691,000 in interest ~~from~~on higher short-term borrowings ~~partially offset by a decrease~~and an increase of ~~$352,000~~$618,000 in interest ~~from~~on long-term ~~debt.~~debt, largely as a result of the issuance of the Prudential Shelf Notes in April 2017.

~~Income Taxes~~

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INCOME TAXES

For the quarter ended September 30, ~~2016~~2017 compared to the quarter ended September 30, ~~2015~~2016

Income tax expense was $4.3 million for the three months ended September 30, 2017, compared to $3.0 million in the ~~third quarter of 2016, compared to $3.3 million~~same period in ~~the same quarter in 2015.~~2016. The ~~slight decrease~~increase in income tax expense was due primarily to ~~lower taxable income.~~an increase in our operating results. Our effective income tax rate was ~~40.4~~38.8 percent and ~~39.4~~40.4 percent, for the ~~third quarter of~~three months ended September 30, 2017 and 2016, ~~and 2015,~~ respectively.

For the nine months ended September 30, ~~2016~~2017 compared to the nine months ended September 30, ~~2015~~2017

Income tax expense was ~~$21.4~~$20.8 million infor the nine months ended September 30, ~~2016,~~2017, compared to ~~$21.6~~$21.4 million in the same period in ~~2015.~~2016. The ~~slight~~ decrease in income tax expense was due primarily to ~~lower taxable income.~~a decrease in our operating results. Our effective income tax rate was ~~39.5~~39.4 percent and ~~40.0~~39.5 percent, for the ~~first~~ nine months ofended September 30, 2017 and 2016, ~~and 2015,~~ 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 ~~target.~~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 ~~to customers through~~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 million for the nine months ended September 30, ~~2016 were approximately $106.3 million.~~ 2017.

We originally budgeted $260.3 million for capital expenditures during 2017, and we currently project ~~aggregate~~ capital expenditures ~~between $150.0 and $170.0~~of approximately $214.7 million in ~~2016.~~2017. Our current forecast by segment and by business line is shown below:


	Low		High		2017
(dollars in thousands)
Regulated Energy:
Natural gas distribution	$	60,000	$	65,000	$	76,771
Natural gas transmission	55,000		60,000		93,737
Electric distribution	10,000		13,000		10,768
Total Regulated Energy	125,000		138,000		181,276
Unregulated Energy:
Propane distribution	10,000		12,000		10,458
Other unregulated energy	10,000		13,000		16,417
Total Unregulated Energy	20,000		25,000		26,875

Other	5,000		7,000

Total 2016 capital expenditures	$	150,000	$	170,000
Other:
Corporate and other businesses					6,507
Total Other					6,507
Total 2017 Capital Expenditures					$	214,658

The ~~2016 forecast includes expenditures for the following projects: Eight Flags' CHP plant; anticipated new facilities~~capital expenditure projection is subject to ~~serve an electric power generator in Kent County, Delaware under the OPT ≤ 90 Service; Eastern Shore's system reliability project; additional expansions of our natural gas distribution~~continuous review and transmission systems; continued natural gas infrastructure improvement activities; expenditures for continued replacement under the Florida GRIP; replacement of several facilities and information technology systems; and other strategic initiatives and investments.

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, ~~2016~~2017 and December 31, ~~2015:~~2016:


	September 30, 2016				December 31, 2015				September 30, 2017				December 31, 2016
(in thousands)
Long-term debt, net of current maturities	$	143,525	25	%	$	149,006	29	%	$	201,248	30	%	$	136,954	23	%
Stockholders’ equity	438,300		75	%	358,138		71	%	463,820		70	%	446,086		77	%
Total capitalization, excluding short-term debt	$	581,825	100	%	$	507,144	100	%	$	665,068	100	%	$	583,040	100	%
	September 30, 2016				December 31, 2015
									September 30, 2017				December 31, 2016
(in thousands)
Short-term debt	$	154,490	20	%	$	173,397	25	%	$	203,098	23	%	$	209,871	26	%
Long-term debt, including current maturities	155,612		21	%	158,157		23	%	213,384		24	%	149,053		19	%
Stockholders’ equity	438,300		59	%	358,138		52	%	463,820		53	%	446,086		55	%
Total capitalization, including short-term debt	$	748,402	100	%	$	689,692	100	%	$	880,302	100	%	$	805,010	100	%

Included in the long-term debt balances at September 30, ~~2016~~2017 and December 31, ~~2015,~~2016, was a capital lease obligation associated with Sandpiper's capacity, supply and operating agreement ~~($2.4~~(at September 30, 2017, $1.0 million excluding current maturities and $2.4 million including current maturities, and, at December 31, 2016, $2.1 million excluding current maturities and $3.5 million ~~respectively, net of current maturities, and $3.8 million and $4.8 million, respectively,~~ including current maturities). ~~Sandpiper entered into this six-year agreement at~~At the closing of the ESG acquisition in May ~~2013.~~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. OnWe have maintained a ratio of equity to total capitalization, including short-term borrowings, between 50 percent and 57 percent during the past three years. In September ~~22,~~ 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 ~~$57.3~~$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. ~~The issuance of equity resulted in our equity to total capitalization ratio representing 59% as of September 30, 2016.~~

As described below under “Short-term Borrowings,” we entered into the Credit Agreement and the Revolver with the Lenders onin October 8, 2015, which increased our borrowing capacity by $150.0 million. To facilitate the refinancing of a portion of the short-term borrowings into long-term debt, as appropriate, we also entered into ~~a long-term~~the Prudential Shelf Agreement with Prudential for the potential private placement of the Prudential Shelf Notes as further described below under the heading “Shelf ~~Agreement.~~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, ~~to the extent feasible,~~ we will seek to align, as much as feasible, any ~~planned~~ long-term debt or equity ~~issuances with the earnings associated~~issuance(s) with the commencement of ~~long-term~~ service ~~for larger revenue-generating capital projects. The~~and associated earnings. In addition, the exact timing of any long-term debt or equity ~~issuances~~issuance(s) will be based on market conditions.

Shelf Agreements

In October 2015, we entered into the 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 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 $70.0 million of 3.25 percent 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 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 at 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 have been issued under either the MetLife Shelf Agreement or the NYL Shelf Agreement.

Short-term Borrowings

Our outstanding short-term borrowings at September 30, ~~2016~~2017 and December 31, ~~2015~~2016 were ~~$154.5~~$203.1 million and ~~$173.4~~$209.9 million, respectively. The weighted average interest rates for our short-term borrowings were ~~1.49~~1.96 percent and ~~1.09~~1.49 percent, for the nine months ended September 30, ~~2016~~2017 and ~~2015,~~2016, respectively.

We utilize bank lines of credit to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of the capital expenditure program. As of September 30, ~~2016,~~2017, we had four unsecured bank credit facilities with three financial institutions totaling ~~$170.0~~$180.0 million in ~~total~~ available credit.

In addition, since October 2015, we have $150.0 million of additional short-term debt capacity available under the Revolver with five participating Lenders. The terms of the Revolver are described in further detail below. We also had access to two credit facilities with a total of $40.0 million of available credit. The Revolver replaced these credit facilities when they expired on October 31, 2015. None of the unsecured bank lines of credit requires compensating balances. We are currently authorized by our Board of Directors to borrow up to $275.0 million of short-term borrowing.

The $150.0 million Revolver has a five-year term 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

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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. ~~At September 30, 2016 and December 31, 2015, we had outstanding borrowings of $50.0 million and $35.0 million, respectively, under the Revolver.~~

~~Shelf Agreement~~

~~On October 8, 2015, we entered into a Shelf Agreement with Prudential. Under the terms~~None of the Shelf Agreement, through October 8, 2018, we may request that Prudential purchase up to $150.0 million of our Shelf Notes at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance. Prudential is under no obligation to purchase any of the Shelf Notes. The interest rate and terms of payment of any series of Shelf Notes will be determined at the time of purchase. We currently anticipate the proceeds from the sale of any series of Shelf Notes will be used for general corporate purposes, including refinancing of short-term borrowing and/or repayment of outstanding indebtedness and financing capital expenditures on future projects; however, actual use of such proceeds will be determined at the time of a purchase.

On May 13, 2016, we submitted a request that Prudential purchase $70.0 million of 3.25 percent Shelf Notes under the Shelf Agreement. On May 20, 2016, Prudential accepted and confirmed our request. The proceeds received from the issuances of the Shelf Notes will be used to reduce short-term borrowings under the Company’s revolving credit facility,unsecured bank lines of credit ~~and/or to fund capital expenditures. The closing~~requires compensating balances. We are currently authorized by our Board of ~~the sale and issuance of the Shelf Notes is expected to occur on or before April 28, 2017.~~

The Shelf Agreement sets forth certain business covenants to which we are subject when any Shelf Note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries,Directors to incur ~~indebtedness, place or permit liens and encumbrances on any~~up to $275.0 million of ~~our property or the property of our subsidiaries.~~short-term borrowing.

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the nine months ended September 30, ~~2016~~2017 and ~~2015:~~2016:


	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
	2016			2015			2017			2016
(in thousands)
Net cash provided by (used in):
Operating activities	$	82,225		$	93,932		$	98,372		$	85,733
Investing activities	(106,992		)	(118,233		)	(141,453		)	(109,730		)
Financing activities	23,448			23,508			42,289			22,678
Net decrease in cash and cash equivalents	(1,319		)	(793		)	(792		)	(1,319		)
Cash and cash equivalents—beginning of period	2,855			4,574			4,178			2,855
Cash and cash equivalents—end of period	$	1,536		$	3,781		$	3,386		$	1,536

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 ~~adjustments for depreciation,~~items such as 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 months ended September 30, ~~2016~~2017 and ~~2015,~~2016, net cash provided by operating activities was ~~$82.2~~$98.4 million and ~~$93.9~~$85.7 million, respectively, resulting in ~~a decrease~~an increase in cash flows of ~~$11.7~~$12.6 million. Significant operating activities generating the cash flows change were as follows:

Net income, adjusted for reconciling activities, increased cash flows by ~~$15.4~~$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 ~~2016,~~2017, which resulted in a higher book-to-tax timing difference and higher non-cash adjustments for depreciation and ~~amortization.~~

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amortization related to increased investing activities.

Changes in ~~net regulatory assets and liabilities~~income taxes receivable decreased cash flows by ~~$9.8~~$18.7 million, due ~~primarily~~ to ~~changes~~lower tax refunds during the first nine months of 2017 compared to the same period in ~~fuel costs collected through the various fuel cost recovery mechanisms.~~2016.

Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities ~~decreased~~increased cash flows by ~~$12.2~~$14.1 million, due primarily to higher revenues and the timing of the receipt of customer payments as well as ~~increased operating expenses and~~ the timing of payments to vendors.

Net cash flows from changes in other inventories decreased by approximately $6.1 million, due primarily to additional pipes and other construction inventory purchases, which increased the levels of our inventory.

Changes in ~~propane, natural gas~~net regulatory assets and ~~materials inventories decreased net~~liabilities increased cash flows by ~~approximately $5.3~~$4.3 million, due primarily to changes 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, other assets and liabilities and accrued compensation increased cash flows by $1.2 million.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled ~~$107.0~~$141.5 million and ~~$118.2~~$109.7 million during the nine months ended September 30, ~~2016~~2017 and ~~2015,~~2016, respectively, resulting in ~~an increase~~a decrease in cash flows of ~~$11.2~~$31.8 million. ~~This was due primarily~~Significant investing activities generating the cash flows change were as follows:

Cash paid for capital expenditures increased by $20.5 million to ~~the $20.7~~$130.1 million ~~net cash ($27.5 million cash paid, less $6.8 million of cash acquired)used~~ for the ~~Gatherco acquisition~~first nine months of 2017, compared to $109.6 million for the same period in ~~2015. An increase~~2016.

Net cash of $11.7 million was used to acquire ARM and Chipola during the first nine months of 2017; there were no corresponding transactions in ~~capital investments of $9.7 million partially offset this decrease.~~2016.

Cash Flows ~~Provided by~~Used in Financing Activities

Net cash provided byin financing activities totaled ~~$23.4~~$42.3 million and $22.7 million during the nine months ended September 30, 2017 and 2016, respectively. The increase in net cash used in financing activities for the nine months ended September 30, 2017 resulted primarily from the following:

We received $69.8 million in net cash proceeds from the ~~first nine months~~issuance of ~~both 2016~~the Prudential Shelf Notes, and ~~2015.~~ we paid $2.9 million more in scheduled long-term debt principal payments and capital lease obligations payments.

Net ~~proceeds of~~cash flows decreased by $57.3 million ~~after deducting underwriting commissions and expenses,~~ from proceeds related to the issuance of common stock during the third quarter of ~~2016, was used to pay down short-term debt.~~ 2016.

Net ~~cash provided by financing activities further increased as a result~~repayments under our line of ~~an increase in a cash overdraft~~credit arrangements of ~~$2.5~~$3.8 million ~~and an increase in short-term borrowing of $35.9 million, partially offset by common stock dividends of $13.0 million and $600,000 of stock issued~~ for ~~the Dividend Reinvestment Plan. During~~ the nine months ended September 30, ~~2015, there were approximately $31.6~~2017, compared to net repayments of $21.4 million for the same period in 2016, increased cash flows by $17.6 million. Change in cash overdrafts decreased cash flows by $5.5 million.

We paid $14.8 million in ~~net additional borrowings, offset by common stock~~cash dividends ~~of $11.7 million and $633,000 of stock issued~~ for the ~~Dividend Reinvestment Plan.~~nine months ended September 30, 2017, compared to $13.0 million for the nine months ended September 30, 2016.

Off-Balance Sheet Arrangements

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily ~~Xeron and PESCO, which~~PESCO. These corporate guarantees provide for the payment of ~~propane and~~ natural gas purchases in the event ~~that the subsidiary defaults. Neither subsidiary~~of default. PESCO has ~~ever~~never defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at September 30, ~~2016~~2017 was ~~$53.9~~$71.9 million, with the guarantees expiring on various dates through September ~~2017.~~2018.

We have issued letters of credit totaling ~~$8.4~~$5.8 million related to the electric transmission services for FPU's northwest electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through ~~September 2017.~~June 2018. There have been no draws on these letters of credit as of September 30, ~~2016.~~2017. 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 ~~Item 1, Financial Statements,~~ Note 65, Other Commitments and Contingencies in the ~~Condensed Consolidated Financial Statements.~~condensed consolidated financial statements.

Contractual Obligations

There has been no material change in the contractual obligations presented in our ~~2015~~2016 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, commodity and forward contract obligations at September 30, ~~2016:~~2017:


	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)
Purchase obligations - Commodity ⁽¹⁾	$	42,155	$	3,417	$	—	$	—	$	45,572
Long-term debt ⁽¹⁾											$	10,698	$	24,226	$	40,700	$	135,800	$	211,424
Purchase obligations - Commodity ⁽²⁾											47,069		1,693		—		—		48,762
Total											$	57,767	$	25,919	$	40,700	$	135,800	$	260,186


⁽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, ~~2016~~,2017, we were involved in regulatory matters in each of the jurisdictions in which we operate. Our significant regulatory matters are fully described in Note 43, Rates and Other Regulatory Activities, to the ~~unaudited~~ condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

Recent Authoritative Pronouncements on Financial Reporting and Accounting

Recent accounting developments applicable to us and their impact on our financial position, results of operations and cash flows are described in Note 1, Summary of Accounting Policies, to the ~~unaudited~~ condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

~~Market risk represents the potential loss arising from adverse changes in market rates and prices.~~ INTEREST RATE RISK

Long-term debt is subject to potential losses based on changes in interest rates. Our long-term debt consists of fixed-rate senior notes and secured debt. All of our long-term debt, excluding a capital lease obligation, is fixed-rate debt and was not entered into for trading purposes. The carrying value of our long-term debt, including current maturities, but excluding a capital lease obligation, was $151.8 million at September 30, ~~2016~~2017, ~~as compared to a fair value~~consists of ~~$173.5~~fixed-rate Senior Notes and $8.0 million using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, with adjustments for duration, optionality, credit risk, and risk profile.of fixed-rate secured debt. We evaluate whether to refinance existing debt or permanently refinance existing short-term ~~borrowing,~~borrowings based in part on the fluctuation in interest rates. Additional information about our long-term debt is disclosed in Note 13, 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 ~~propane~~regulated energy distribution ~~business is~~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 ~~market~~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 ~~entering into fixed price~~forward contracts for supply.

We can store up to approximately ~~6.8~~6.2 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.~~decline, particularly if we utilize fixed price forward contracts for supply. To mitigate the ~~impact~~risk of propane commodity price fluctuations on the inventory valuation, we have adopted a Risk Management Policy that allows ~~the~~our propane distribution operation to ~~hedge its~~enter into fair value hedges, cash flows hedges or other economic hedges of our inventory.

~~In 2016, PESCO entered into a SCO supplier agreement with Columbia Gas~~Aspire Energy is exposed to ~~provide~~commodity price risk, primarily during the winter season, to the extent we are not successful in balancing our natural gas ~~supply for Columbia Gas~~purchases and sales and have to ~~service one of its local distribution customer tranches. PESCO also assumed the obligation to store~~secure natural gas ~~inventory~~from alternative sources at higher spot prices. In order to ~~satisfy its obligations under the SCO supplier agreement,~~mitigate this risk, we procure firm capacity that meets our estimated volume requirements and we continue to seek out new producers with which ~~terminates on March 31, 2017. In conjunction with the SCO supplier agreement, PESCO entered into natural gas futures contracts during the second quarter of 2016~~to contract in order to ~~protect its~~fulfill our natural gas ~~inventory against market price fluctuations.~~purchase requirements.

~~Our propane wholesale marketing operation~~PESCO is a party to ~~propane and crude oil futures and forward contracts, with various third parties, which require that the propane wholesale marketing operation purchase or sell~~ natural gas ~~liquids or crude oil~~futures contracts. These contracts provide PESCO with the right to purchase natural gas at a fixed price at ~~fixed~~ future dates. AtUpon expiration, the contracts ~~are typically~~can be settled financially without taking ~~physical~~ delivery of ~~propane~~natural gas, or crude oil. The propane wholesale marketing operation also enters into futures contracts that are traded on the Intercontinental Exchange, Inc. In certain cases, the futures contracts are settled by the payment or receipt of a net amount equal to the difference between the current market price of the futures contract and the original contract price; however, they may also be settled by physical receipt or delivery of propane or crude oil.PESCO can procure natural gas for its customers.

~~The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing business~~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 ~~dollar~~volumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed daily by our oversight officials. In addition, the Risk Management Committee reviews periodic reports on markets, ~~and the credit risk of counter-parties,~~ approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. ~~As of~~

W~~September 30, 2016~~HOLESALE ~~, there were no outstanding contracts.~~CREDIT RISK

~~We have entered into agreements~~The Risk Management Committee reviews credit risks associated with ~~various suppliers~~counterparties to ~~purchase natural gas, electricity and propane for resale~~commodity derivative contracts prior to ~~our customers. Purchases under these~~such contracts ~~either do not meet the definition of derivatives or are considered “normal purchases and sales” and are accounted for on an accrual basis.~~

being approved.

AtAdditional information about our derivative instruments is disclosed in Note 11, ~~September 30, 2016~~Derivative Instruments, ~~and December 31, 2015, we marked these forward and other contracts to market, using market transactions in either the listed or OTC markets, which resulted~~ in the ~~following assets and liabilities:~~condensed consolidated financial statements.

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(in thousands) September 30, 2016 December 31, 2015
Mark-to-market energy assets, including call options, swap agreements and futures $ 477
$ 153
Mark-to-market energy liabilities, including swap agreements and futures $ 29
$ 433

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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, ~~2016~~.2017. 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, ~~2016~~.2017.

Changes in Internal Control over Financial Reporting

During the quarter ended September 30, ~~2016~~,2017, 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~~

Item 1. Legal Proceedings

As disclosed in Note 65, Other Commitments and Contingencies, of the ~~unaudited~~ condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we are involved in certain legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental or regulatory agencies concerning rates and other regulatory actions. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on our condensed consolidated financial position, results of operations or cash flows.


~~Item 1A.~~	Item 1A. Risk Factors

Our business, operations, and financial condition are subject to various risks and uncertainties. The risk factors described in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K, for the year ended December 31, ~~2015,~~2016, 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~~

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, 2016
through July 30, 2016 ⁽¹⁾
366
$ 66.35
—
—
August 1, 2016
through August 31, 2016
—
$ —
—
—
September 1, 2016
through September 30, 2016
—
$ —
—
—
Total 366
$ 66.35
—
—



	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	—	—

⁽¹⁾

Chesapeake Utilities purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain Directors and Senior Executives under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Item 8 under the heading “Notes to the Consolidated Financial Statements—Note 16, Employee Benefit Plans” in our latest Annual Report on Form 10-K for the year ended December 31, ~~2015~~2016. During the quarter ended September 30, ~~2016,~~ ~~366~~2017, 387 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~~

Item 3. Defaults upon Senior Securities

None.


~~Item 5.~~	~~Other Information~~

Item 5. Other Information

None.

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Item 6.	Exhibits




~~1.1~~		Underwriting Agreement entered into by Chesapeake Utilities Corporation and Wells Fargo Securities, LLC, RBC Capital Markets, LLC, Janney Montgomery Scott LLC., Robert W. Baird & Co., Incorporated, J.J.B. Hilliard, W.L. Lyons, LLC, Ladenburg Thalmann & Co. Inc., U.S. Capital Advisors LLC and BB&T Securities, LLC on September 22, 2016, relating to the sale and issuance of 835,207 shares of the Company’s common stock, is incorporated herein by reference to Exhibit 1.1 of the Company’s current report on Form 8-K, filed on September 28, 2016, File No. 001-11590.

~~3.3~~		~~Second Amendment to the Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective November 2, 2016, 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 ~~3, 2016~~9, 2017

- 6054



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



	Purchase price
(in thousands)	Allocation
Purchase price	$	57,658

Property plant and equipment	53,203
Cash	6,806
Accounts receivable	3,629
Income taxes receivable	3,163
Other assets	425
Total assets acquired	67,226

Long-term debt	1,696
Deferred income taxes	13,409
Accounts payable	3,837
Other current liabilities	745
Total liabilities assumed	19,687
Net identifiable assets acquired	47,539
Goodwill	$	10,119



(in thousands)
Gross margin for the nine months ended September 30, 2015	$	134,024
Factors contributing to the gross margin increase for the nine months ended September 30, 2016:
Service expansions	5,516
Additional revenue from GRIP in Florida	3,069
Natural gas growth (excluding service expansions)	2,630
Implementation of Delaware Division interim rates	1,350
Margin from service to Eight Flags	892
Sandpiper SIR	618
Decreased customer consumption - weather and other	(2,141		)
Other	(512		)
Gross margin for the nine months ended September 30, 2016	$	145,446

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company