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, ~~2015~~2016



¨	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 — ~~15,268,158~~16,301,161 shares outstanding as of October 31, ~~2015~~2016.

Table of Contents




PART I—FINANCIAL INFORMATION		1

ITEM 1.	FINANCIAL STATEMENTS	1

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

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	5355

ITEM 4.	CONTROLS AND PROCEDURES	5557

PART II—OTHER INFORMATION		5658

ITEM 1.	LEGAL PROCEEDINGS	5658

ITEM 1A.	RISK FACTORS	5658

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	5658

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	5658

ITEM 5.	OTHER INFORMATION	5658

ITEM 6.	EXHIBITS	5759

SIGNATURES		5860

Table of Contents

GLOSSARY OF DEFINITIONS

ASC: Accounting Standards Codification

ASU: Accounting Standards Update

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

~~BravePoint:~~ ~~BravePoint, Inc., our former advanced information services subsidiary, headquartered in Norcross, Georgia, which was sold on October 1, 2014~~

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

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

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

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

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

CHP: A combined heat and power plant ~~being~~ constructed by Eight Flags ~~in Nassau County,~~on Amelia Island, Florida

Columbia Gas: Columbia Gas of Ohio

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

Credit Agreement: ~~An agreement between~~The Credit Agreement dated October 8, 2015, among Chesapeake ~~PNC~~Utilities and ~~other participating lenders~~the Lenders related to ~~our unsecured revolving credit facility~~the Revolver

Deferred Compensation Plan: A non-qualified, deferred compensation arrangement under which certain of our executives and members of the Board of Directors are able to defer payment of all or a part of certain specified types of compensation, including executive cash bonuses, executive performance shares, and directors’ retainers ~~and fees~~

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

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 ~~Eastern Shore Gas Company~~ESG

Eight Flags: Eight Flags Energy, LLC, a subsidiary of Chesapeake OnSight Services, LLC

EPA: United States Environmental Protection Agency

ESG: Eastern Shore Gas Company and its affiliates

FASB: Financial Accounting Standards Board

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

FDEP: Florida Department of Environmental Protection

FDOT: Florida Department of Transportation

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FGT: Florida Gas Transmission Company

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

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

~~Table of Contents~~

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

~~FRP:~~ ~~Fuel Retention Percentage~~ 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

Gulfstream: Gulfstream Natural Gas System, LLC

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

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

Lenders: ~~Participating~~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 ~~including PNC, which have committed funds to our Revolver~~that entered into the Credit Agreement

MDE: Maryland Department of Environment

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

NAM: Natural Attenuation Monitoring

NYSE: New York Stock Exchange

~~Note Agreement:~~ ~~Note Purchase Agreement entered into by Chesapeake with Note Holders on September 5, 2013~~

~~Note Holders:~~ PAR U Hartford Life & Annuity Comfort Trust, The Prudential Insurance Company of America, The Gibraltar Life Insurance Co., Ltd., The Penn Mutual Life Insurance Company, Thrivent Financial for Lutherans, United of Omaha Life Insurance Company, and Companion Life Insurance Company, which are collectively the lenders that entered into the Note Agreement with Chesapeake on September 5, 2013

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

OPT ≤ 90 Service: Off Peak ≤ 90 Firm Transportation Service, ~~a new tariff associated with~~an Eastern ~~Shore's~~Shore firm transportation service that ~~will allow~~allows Eastern Shore ~~the right~~ not to schedule 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., ~~our~~a wholly-owned Florida intrastate pipeline subsidiary of Chesapeake Utilities

PESCO: Peninsula Energy Services Company, Inc., ~~our~~a 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 Shelf Agreement for the potential future purchase of our Shelf Notes

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

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

Revolver: ~~The~~Our unsecured revolving credit facility ~~issued to us by~~with the Lenders ~~including PNC as the primary lender~~

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

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

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

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

SEC: Securities and Exchange Commission

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

Shelf Agreement: An agreement entered into by Chesapeake Utilities and Prudential ~~related~~pursuant to ~~the~~which Chesapeake Utilities may request that Prudential purchase, by October 8, 2018, up to $150.0 million of ~~the~~ 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 ~~within the city limits of Ocean City, Maryland~~in Sandpiper Energy’s service territories

TETLP: Texas Eastern Transmission, LP

Xeron: Xeron, Inc., ~~our~~a propane wholesale marketing subsidiary ~~based in Houston, Texas~~of Chesapeake Utilities

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PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)


	Three Months Ended					Nine Months Ended					Three Months Ended					Nine Months Ended
	September 30,					September 30,					September 30,					September 30,
	2015		2014			2015			2014		2016			2015		2016			2015
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	63,796	$	59,356		$	235,438		$	223,168	$	70,019		$	63,796	$	226,630		$	235,438
Unregulated Energy and other	28,117		32,263			119,238			155,286		38,329			28,117		130,356			119,238
Total Operating Revenues	91,913		91,619			354,676			378,454		108,348			91,913		356,986			354,676
Operating Expenses
Regulated Energy cost of sales	23,161		23,040			101,414			102,020		24,644			23,161		81,184			101,414
Unregulated Energy and other cost of sales	17,959		22,935			73,465			112,702		28,183			17,959		85,142			73,465
Operations	26,388		25,365			79,522			76,604		30,126			26,388		85,370			79,522
Maintenance	2,603		2,562			8,033			7,168		3,542			2,603		8,925			8,033
Gain from a settlement	—		—			(1,500		)	—		—			—		(130		)	(1,500		)
Depreciation and amortization	7,636		6,774			22,155			20,146		8,209			7,636		23,493			22,155
Other taxes	3,257		3,151			10,000			9,942		3,488			3,257		10,725			10,000
Total Operating Expenses	81,004		83,827			293,089			328,582		98,192			81,004		294,709			293,089
Operating Income	10,909		7,792			61,587			49,872		10,156			10,909		62,277			61,587
Other income (loss), net of other expenses	36		(32		)	(3		)	380
Other (expense) income, net											(28		)	36		(68		)	(3		)
Interest charges	2,492		2,495			7,425			6,954		2,722			2,492		7,996			7,425
Income Before Income Taxes	8,453		5,265			54,159			43,298		7,406			8,453		54,213			54,159
Income taxes	3,334		2,085			21,638			17,303		2,990			3,334		21,401			21,638
Net Income	$	5,119	$	3,180		$	32,521		$	25,995	$	4,416		$	5,119	$	32,812		$	32,521
Weighted Average Common Shares Outstanding:
Basic	15,258,819		14,574,678			15,035,569			14,539,841		15,372,413			15,258,819		15,324,932			15,035,569
Diluted	15,306,843		14,616,665			15,083,641			14,588,130		15,412,783			15,306,843		15,365,955			15,083,641
Earnings Per Share of Common Stock:
Basic	$	0.34	$	0.22		$	2.16		$	1.79	$	0.29		$	0.34	$	2.14		$	2.16
Diluted	$	0.33	$	0.22		$	2.16		$	1.78	$	0.29		$	0.33	$	2.14		$	2.16
Cash Dividends Declared Per Share of Common Stock	$	0.2875	$	0.2700		$	0.8450		$	0.7967	$	0.3050		$	0.2875	$	0.8975		$	0.8450

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

~~- 1~~

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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,
	2015			2014			2015			2014			2016			2015			2016			2015
(in thousands)
Net Income	$	5,119		$	3,180		$	32,521		$	25,995		$	4,416		$	5,119		$	32,812		$	32,521
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(7), $(5), $(20) and $(18), respectively	(10		)	(9		)	(30		)	(26		)
Net gain, net of tax of $62, $26, $187 and $80, respectively	93			39			278			118
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
Cash Flow Hedges, net of tax:
Unrealized loss on commodity contract cash flow hedges, net of tax of $(51), $(18), $(29) and $(19), respectively	(75		)	(27		)	(43		)	(28		)
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	8			3			205			64			139			8			811			205
Comprehensive Income	$	5,127		$	3,183		$	32,726		$	26,059		$	4,555		$	5,127		$	33,623		$	32,726

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

~~- 2~~

Table of Contents

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)


Assets	September 30, 2015			December 31, 2014			September 30, 2016			December 31, 2015
(in thousands, except shares)
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	813,145		$	766,855		$	908,822		$	842,756
Unregulated Energy	141,393			84,773			194,743			145,734
Other businesses and eliminations	19,190			18,497			20,835			18,999
Total property, plant and equipment	973,728			870,125			1,124,400			1,007,489
Less: Accumulated depreciation and amortization	(210,979		)	(193,369		)	(237,434		)	(215,313		)
Plus: Construction work in progress	56,441			13,006			49,082			62,774
Net property, plant and equipment	819,190			689,762			936,048			854,950
Current Assets
Cash and cash equivalents	3,781			4,574			1,536			2,855
Accounts receivable (less allowance for uncollectible accounts of $1,088 and $1,120, respectively)	39,861			53,300
Accounts receivable (less allowance for uncollectible accounts of $792 and $909, respectively)							47,103			41,007
Accrued revenue	8,797			13,617			9,506			12,452
Propane inventory, at average cost	4,211			7,250			4,106			6,619
Other inventory, at average cost	4,143			3,699			3,867			3,803
Regulatory assets	7,653			8,967			6,045			8,268
Storage gas prepayments	3,839			4,258			8,192			3,410
Income taxes receivable	6,935			18,806			13,178			24,950
Deferred income taxes	338			—
Prepaid expenses	7,507			6,652			7,603			7,146
Mark-to-market energy assets	286			1,055			477			153
Other current assets	339			195			543			1,044
Total current assets	87,690			122,373			102,156			111,707
Deferred Charges and Other Assets
Goodwill	16,048			4,952			15,070			14,548
Other intangible assets, net	2,317			2,404			1,938			2,222
Investments, at fair value	3,412			3,678			4,630			3,644
Regulatory assets	77,332			78,136			76,343			77,519
Receivables and other deferred charges	2,453			3,164			4,325			2,831
Total deferred charges and other assets	101,562			92,334			102,306			100,764
Total Assets	$	1,008,442		$	904,469		$	1,140,510		$	1,067,421

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

~~- 3~~

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)


Capitalization and Liabilities	September 30, 2015			December 31, 2014			September 30, 2016			December 31, 2015
(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)	$	7,429		$	7,100		7,932			7,432
Additional paid-in capital	189,321			156,581			250,202			190,311
Retained earnings	162,036			142,317			185,195			166,235
Accumulated other comprehensive loss	(5,471		)	(5,676		)	(5,029		)	(5,840		)
Deferred compensation obligation	1,863			1,258			2,476			1,883
Treasury stock	(1,863		)	(1,258		)	(2,476		)	(1,883		)
Total stockholders’ equity	353,315			300,322			438,300			358,138
Long-term debt, net of current maturities	155,909			158,486			143,525			149,006
Total capitalization	509,224			458,808			581,825			507,144
Current Liabilities
Current portion of long-term debt	9,139			9,109			12,087			9,151
Short-term borrowing	127,093			88,231			154,490			173,397
Accounts payable	41,129			44,610			41,297			39,300
Customer deposits and refunds	24,020			25,197			26,858			27,173
Accrued interest	3,242			1,352			3,119			1,311
Dividends payable	4,388			3,939			4,678			4,390
Deferred income taxes	—			832
Accrued compensation	8,909			10,076			7,823			10,014
Regulatory liabilities	9,346			3,268			2,412			7,365
Mark-to-market energy liabilities	154			1,018			29			433
Other accrued liabilities	9,443			6,603			10,260			7,059
Total current liabilities	236,863			194,235			263,053			279,593
Deferred Credits and Other Liabilities
Deferred income taxes	174,247			160,232			205,562			192,600
Regulatory liabilities	43,356			43,419			43,354			43,064
Environmental liabilities	9,003			8,923			8,682			8,942
Other pension and benefit costs	32,619			35,027			32,501			33,481
Deferred investment tax credits and other liabilities	3,130			3,825			5,533			2,597
Total deferred credits and other liabilities	262,355			251,426			295,632			280,684
Other commitments and contingencies (Note 6)
Environmental and other commitments and contingencies (Note 5 and 6)
Total Capitalization and Liabilities	$	1,008,442		$	904,469		$	1,140,510		$	1,067,421

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

~~- 4~~

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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,
	2015			2014			2016			2015
(in thousands)
Operating Activities
Net income	$	32,521		$	25,995		$	32,812		$	32,521
Adjustments to reconcile net income to net operating cash:
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	22,155			20,146			23,493			22,155
Depreciation and accretion included in other costs	5,280			5,152			5,357			5,280
Deferred income taxes, net	(1,155		)	(156		)	12,004			(1,155		)
Realized gain on commodity contracts/sale of assets/investments	(411		)	(436		)	(405		)	(411		)
Unrealized loss (gain) on investments/commodity contracts	60			(44		)
Unrealized (gain) loss on investments/commodity contracts							(243		)	60
Employee benefits and compensation	901			476			1,217			901
Share-based compensation	1,445			1,519			1,887			1,445
Other, net	13			2			42			13
Changes in assets and liabilities:
Accounts receivable and accrued revenue	21,898			38,304			(3,835		)	21,898
Propane inventory, storage gas and other inventory	3,166			4,137			(2,179		)	3,166
Regulatory assets/liabilities, net	6,467			(8,865		)	(3,326		)	6,467
Prepaid expenses and other current assets	(159		)	(804		)	485			(159		)
Accounts payable and other accrued liabilities	(5,145		)	(18,704		)	3,679			(9,897		)
Income taxes receivable/payable	14,883			510
Income taxes receivable							14,897			14,883
Customer deposits and refunds	(1,177		)	(1,169		)	(314		)	(1,177		)
Accrued compensation	(1,406		)	(1,242		)	(2,293		)	(1,406		)
Other assets and liabilities, net	(652		)	198			(1,053		)	(652		)
Net cash provided by operating activities	98,684			65,019			82,225			93,932
Investing Activities
Property, plant and equipment expenditures	(102,051		)	(69,111		)	(106,851		)	(97,299		)
Proceeds from sales of assets	109			505			119			109
Acquisitions, net of cash acquired	(20,930		)	—			—			(20,930		)
Environmental expenditures	(113		)	(134		)	(260		)	(113		)
Net cash used in investing activities	(122,985		)	(68,740		)	(106,992		)	(118,233		)
Financing Activities
Common stock dividends	(11,725		)	(10,879		)	(12,964		)	(11,725		)
Issuance of stock for Dividend Reinvestment Plan	633			300			600			633
Stock issuance							57,306			—
Change in cash overdrafts due to outstanding checks	2,964			(503		)	2,466			2,964
Net borrowing (repayment) under line of credit agreements	35,898			(33,994		)
Proceeds from issuance of long-term debt	—			49,975
Net (repayment) borrowing under line of credit agreements							(21,379		)	35,898
Repayment of long-term debt and capital lease obligation	(4,262		)	(2,249		)	(2,581		)	(4,262		)
Net cash provided by financing activities	23,508			2,650			23,448			23,508
Net Decrease in Cash and Cash Equivalents	(793		)	(1,071		)	(1,319		)	(793		)
Cash and Cash Equivalents—Beginning of Period	4,574			3,356			2,855			4,574
Cash and Cash Equivalents—End of Period	$	3,781		$	2,285		$	1,536		$	3,781

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

~~- 5~~

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Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)


	Common Stock																			Common Stock
(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			Number of Shares⁽¹⁾	Par Value		Additional Paid-In Capital		Retained Earnings			Accumulated Other Comprehensive Loss			Deferred Compensation		Treasury Stock			Total ⁽²⁾
Balance at December 31, 2013	14,457,345	$	4,691	$	152,341	$	124,274		$	(2,533	)	$	1,124	$	(1,124	)	$	278,773
Balance at December 31, 2014																				14,588,711	$	7,100	$	156,581	$	142,317		$	(5,676	)	$	1,258	$	(1,258	)	$	300,322
Net income	—	—		—		36,092			—			—		—			36,092				—		—		41,140			—			—		—			41,140
Other comprehensive loss	—	—		—		—			(3,143		)	—		—			(3,143		)	—	—		—		—			(164		)	—		—			(164		)
Dividend declared ($1.0667 per share)	—	—		—		(15,675		)	—			—		—			(15,675		)
Dividend declared ($1.1325 per share)																				—	—		—		(17,222		)	—			—		—			(17,222		)
Retirement savings plan and dividend reinvestment plan	43,367	16		1,844		—			—			—		—			1,860			43,275	21		2,214		—			—			—		—			2,235
Conversion of debentures	47,313	15		520		—			—			—		—			535
Share-based compensation and tax benefit ^{(2) (3)}	40,686	13		1,876		—			—			—		—			1,889
Stock split in the form of stock dividend	—	2,365		—		(2,374		)	—			—		—			(9		)
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	—	—		—		—			—			134		(134		)	—			—	—		—		—			—			625		(625		)	—
Balance at December 31, 2014	14,588,711	7,100		156,581		142,317			(5,676		)	1,258		(1,258		)	300,322
Balance at December 31, 2015																				15,270,659	7,432		190,311		166,235			(5,840		)	1,883		(1,883		)	358,138
Net income	—	—		—		32,521			—			—		—			32,521			—	—		—		32,812			—			—		—			32,812
Other comprehensive income	—	—		—		—			205			—		—			205			—	—		—		—			811			—		—			811
Dividend declared ($0.8450 per share)	—	—		—		(12,802		)	—			—		—			(12,802		)
Dividend declared ($0.8975 per share)																				—	—		—		(13,852		)	—			—		—			(13,852		)
Retirement savings plan and dividend reinvestment plan	36,289	18		1,849		—			—			—		—			1,867			30,041	15		1,859		—			—			—		—			1,874
Common stock issued in acquisition	592,970	289		29,876		—			—			—		—			30,165
Share-based compensation and tax benefit ⁽³⁾	45,703	22		1,015		—			—			—		—			1,037
Stock issuance ⁽³⁾																				960,488	467		56,839		—			—			—		—			57,306
Share-based compensation and tax benefit ⁽⁴⁾ ⁽⁵⁾																				36,099	18		1,193		—			—			—		—			1,211
Treasury stock activities	—	—		—		—			—			605		(605		)	—			—	—		—		—			—			593		(593		)	—
Balance at September 30, 2015	15,263,673	$	7,429	$	189,321	$	162,036		$	(5,471	)	$	1,863	$	(1,863	)	$	353,315
Balance at September 30, 2016																				16,297,287	$	7,932	$	250,202	$	185,195		$	(5,029	)	$	2,476	$	(2,476	)	$	438,300


⁽¹⁾	Includes ~~70,253~~80,024 and ~~57,382~~70,631 shares at September 30, ~~2015~~2016 and December 31, ~~2014~~2015, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.


⁽²⁾	2,000 shares of preferred stock at $0.00001 par value has been authorized. None has been issued or is outstanding; accordingly, no information has been included in the statements of stockholders’ equity.


⁽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 million.


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


⁽³⁾⁽⁵⁾	The shares issued under the SICP are net of shares withheld for employee taxes. For the nine months ended September 30, ~~2015,~~2016, and for the year ended December 31, ~~2014~~2015, we withheld ~~12,620~~12,031 and ~~12,687~~12,620 shares, respectively, for taxes.

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

~~- 6~~

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)


1.	~~Summary of Accounting Policies~~

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, ~~2014.~~2015. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

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

~~Reclassifications~~

~~As a result of the sale of our advanced information services subsidiary in October 2014, we changed our operating segments (see Note 7,~~ ~~Segment Information~~). We reclassified certain amounts in the condensed consolidated ~~statements~~balance sheet as of ~~income for~~December 31, 2015. We have revised the ~~three and nine months ended September 30, 2014 and~~ condensed consolidated ~~statements~~statement of cash flows for the nine months ended September 30, ~~2014~~2015 to ~~conform to~~reflect only property, plant and equipment expenditures paid in cash within the ~~current year's presentation.~~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. These ~~reclassifications~~revisions are considered immaterial to the overall presentation of our condensed consolidated financial statements.

~~Gain Contingency~~

Effective May 29, 2015, we entered into a settlement agreement with a vendor related to the implementation of a customer billing system. Pursuant to the agreement, we received $1.5 million in cash, which is reflected as "Gain from a settlement" in the accompanying condensed consolidated statements of income. Previously, at December 31, 2014, we recorded a $6.5 million pretax, non-cash impairment loss related to the same billing system implementation. We may also receive $750,000 in additional cash and discounts on future services; however, the receipt or retention of additional cash and future discounts is contingent upon engaging this vendor to provide agreed-upon services over the next five years.

~~Subsequent Events~~

On ~~October 8, 2015,~~September 22, 2016, we ~~entered into~~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 ~~Shelf Agreement with Prudential. See Note 14,~~ ~~Long-Term Debt~~ ~~for further details. On the same date, we also entered into the Credit Agreement with the Lenders for~~sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.3 million, which were added to our general funds and used primarily to repay a ~~$150.0 million Revolver for a term~~portion of ~~five years. On October 19, 2015, we borrowed $25.0 million~~our short-term debt under ~~the Revolver. See Note 15,~~ ~~Short-Term Borrowing~~ ~~for further details.~~unsecured lines of credit.

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

Interest - Imputation of Interest (ASC 835-30) - In April 2015, the FASB issued ASU 2015-03, Simplifying thePresentation of Debt Issuance Costs. This standard requires debt issuance costs to be presented in the balance sheet as a direct deduction from the carrying value of the associated debt liability, consistent with the presentation of a debt discount. ASU 2015-03 became effective for us on January 1, 2016, and we applied the provisions of this standard on a retrospective basis. As a result of the adoption of this standard, debt issuance costs totaling $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 adopted 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 of Deferred Taxes, which requires all deferred assets and liabilities along with any related valuation allowance to be classified as noncurrent on the balance sheet for our annual financial statements beginning January 1, 2017 and for our interim financial statements beginning January 1, 2018; however, early adoption is permitted. We adopted this standard in the first quarter of 2016 on a retrospective basis and adjusted the December 31, 2015 balance sheet by eliminating the current deferred income taxes asset and decreasing 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.~~ Customers. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. ~~On July 9, 2015, the~~In March 2016, FASB ~~affirmed its proposal~~issued ASU 2016-08, Principal versus Agent Considerations (Reporting Revenue Gross versus Net), to ~~defer~~clarify the implementation ~~of this standard by one year.~~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. We are assessing the impact this standard may have on our financial position and results of operations.

~~Interest - Imputation of Interest~~Leases (ASC ~~835-30)~~842) - In ~~April 2015,~~February 2016, the FASB issued ASU ~~2015-03,~~2016-02, ~~Simplifying~~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 ~~Presentation~~required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. This update will be applied using a modified retrospective transition approach for leases existing at, or entered into after, the beginning of ~~Debt Issuance Costs. This standard requires debt issuance costs to be~~the earliest comparative period presented in the ~~balance sheet as a direct deduction from~~financial statements. We are evaluating the ~~carrying value~~effect of this update on our financial position and results of operations.

Compensation-Stock Compensation (ASC 718) - In March 2016, the ~~associated debt liability, consistent with~~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 ~~a debt discount.~~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) - On August 26, 2016, the FASB issued ASU ~~2015-03 is~~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 ~~interim~~annual and ~~annual~~interim financial statements ~~issued~~ beginning January 1, ~~2016. Early~~2018, although early adoption is ~~permitted for financial~~permitted. We are assessing the impact of the adoption of this ASU on our statements ~~that have not been previously issued. As~~ of ~~September 30, 2015, we had $312,000 of unamortized~~cash flows.

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debt issuance costs included in the accompanying condensed consolidated balance sheets. Upon adoption of ASU 2015-03, this will be presented as a deduction from long-term debt, net of current maturities.

~~Debt Issuance Costs (ASC 835-30) - In August 2015, the FASB issued ASU 2015-15,~~ ~~Simplifying the Presentation of Debt Issuance Costs Associated with Line-of-Credit Arrangements~~. This standard clarifies treatment of debt issuance costs associated with line-of-credit arrangements which 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 is effective for our interim and annual financial statements issued beginning January 1, 2016. Early adoption is permitted for financial statements that have not been previously issued. This standard is not expected to have a material impact on our financial position and results of operation.

~~Business Combinations (ASC 805) - In September 2015, the FASB issued ASU 2015-16,~~ ~~Simplifying the Accounting for Measurement-Period Adjustments.~~ The standard eliminates the requirement to restate prior period financial statements for measurement period adjustments. The new guidance requires that the cumulative impact of a measurement period adjustment (including the impact of prior periods) be recognized in the reporting period in which the adjustment is identified. ASU 2015-16 will be effective for our interim and annual financial statements issued beginning January 1, 2016 and is to be adopted on a prospective basis. Early adoption is permitted for financial statements that have not been previously issued. We are assessing the impact this standard may have on our financial position and results of operation.


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,
	2015		2014		2015		2014		2016		2015		2016		2015
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:

Net Income	$	5,119	$	3,180	$	32,521	$	25,995	$	4,416	$	5,119	$	32,812	$	32,521
Weighted average shares outstanding	15,258,819		14,574,678		15,035,569		14,539,841		15,372,413		15,258,819		15,324,932		15,035,569
Basic Earnings Per Share	$	0.34	$	0.22	$	2.16	$	1.79	$	0.29	$	0.34	$	2.14	$	2.16

Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	5,119	$	3,180	$	32,521	$	25,995	$	4,416	$	5,119	32,812		32,521
Reconciliation of Denominator:
Weighted shares outstanding—Basic	15,258,819		14,574,678		15,035,569		14,539,841		15,372,413		15,258,819		15,324,932		15,035,569
Effect of dilutive securities:
Share-based compensation	48,024		41,987		48,072		48,289		40,370		48,024		41,023		48,072
Adjusted denominator—Diluted	15,306,843		14,616,665		15,083,641		14,588,130		15,412,783		15,306,843		15,365,955		15,083,641
Diluted Earnings Per Share	$	0.33	$	0.22	$	2.16	$	1.78	$	0.29	$	0.33	$	2.14	$	2.16


3.	Acquisitions

Gatherco ~~Acquisition~~Merger

On April 1, 2015, we completed the merger ~~with Gatherco,~~ in which Gatherco merged with and into Aspire Energy, ~~of Ohio, a~~our then newly formed, wholly-owned ~~subsidiary of Chesapeake. As a result,~~subsidiary. Aspire Energy ~~of Ohio provides~~is an unregulated natural gas ~~midstream services, including natural gas gathering services and natural gas liquid processing services to over 300 producers, through 16 gathering systems and over 2,000~~infrastructure company with approximately 2,500 miles of ~~pipelines~~pipeline systems in ~~Central and Eastern~~40 counties throughout Ohio. The majority of Aspire ~~Energy of Ohio also supplies natural gas to~~Energy’s margin is derived from long-term supply agreements with Columbia Gas of Ohio ~~regional marketers of natural gas,~~ and ~~over 6,000 customers in Ohio through the~~ Consumers Gas Cooperative, ~~an independent entity,~~ which together serve more than 20,000 end-use customers. Aspire Energy ~~of Ohio manages under an operating agreement.~~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.

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


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

The merger agreement ~~provides~~provided for additional contingent cash consideration to Gatherco's shareholders of up to $15.0 million based on a percentage of revenue generated from potential new gathering opportunities ~~over~~during the ~~next five years.~~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 ~~$514,000~~ of which ~~was expensed~~we incurred $786,000 in 2014 and the ~~nine months ended September 30,~~remaining $514,000 in 2015. ~~Transactions~~Transaction costs ~~are~~were included in operations expense in the accompanying condensed consolidated statements of income. The revenue and net ~~income~~loss from this ~~acquisition~~merger for the three months ended September 30, ~~2015,~~2016, included in our condensed consolidated ~~statement~~statements of income, were ~~$5.7~~$5.6 million and ~~$55,000,~~$563,000, respectively. The revenue and net ~~loss~~income from this ~~acquisition~~merger for the nine months ended September 30, ~~2015,~~2016, included in our condensed consolidated ~~statement~~statements of income, were ~~$11.0~~$18.4 million and ~~$133,000,~~$1.1 million, respectively. ~~The financial results of Aspire Energy of Ohio are projected~~This merger was accretive to ~~have a minimal impact on our~~ earnings per share in 2015, since the merger was completed after the first quarter. The first quarter includes key winter months, which have historically produced a significant portion of Gatherco's annual earnings. This acquisition is expected to be accretive to our earnings in the first full year of operations, ~~which will include the first quarter of 2016~~.generating $0.03 in additional earnings per share for such period.

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


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

Property plant and equipment	52,578		53,203
Cash	6,806		6,806
Accounts receivable	3,629		3,629
Income taxes receivable	3,012		3,163
Other assets	247		425
Total assets acquired	66,272		67,226

Long-term debt	1,696		1,696
Deferred income taxes	13,863		13,409
Accounts payable	3,837		3,837
Other current liabilities	314		745
Total liabilities assumed	19,710		19,687
Net identifiable assets acquired	46,562		47,539
Goodwill	$	11,096	$	10,119

The excess of the purchase price over the estimated fair values of the assets acquired and the liabilities assumed was recognized as goodwill at the ~~acquisition~~merger date. The goodwill primarily reflects the value paid ~~primarily~~ for opportunities for growth in a new, strategic geographic area. All of the goodwill from this ~~acquisition~~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 ~~initial accounting for the Gatherco acquisition is not complete because the valuation necessary to assess~~adjustments resulted in a change in the fair ~~values~~value of property, plant and equipment, ~~and the related impact on~~ deferred income tax ~~amounts is considered preliminary as we continue~~liabilities, inventory, income taxes receivable and other current liabilities. Goodwill from the merger decreased from $11.1 million to ~~evaluate~~$10.1 million after incorporating these ~~assets.~~adjustments. The allocation of the purchase price and valuation of assets are final. The valuation of additional contingent cash consideration ~~and potential~~

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~~environmental remediation costs~~ may be adjusted as additional information becomes available. ~~Although the purchase price allocation can be modified up to one year from the date of the acquisition, we intend to finalize the allocation as soon as practicable.~~

~~Other acquisitions~~

On May 7, 2015, we purchased certain propane distribution assets used to serve 253 customers in Citrus County, Florida for approximately $242,000. In connection with this acquisition, we recorded $186,000 in intangible assets related to a non-compete agreement and the customer list to be amortized over six and 10 years, respectively. The remaining purchase price was allocated to property, plant and equipment and accounts receivable. The revenue and net income from this acquisition that were included in our condensed consolidated statements of income for the three and nine months ended September 30, 2015 were not material.


4.	Rates and Other Regulatory Activities

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

Delaware

~~There were no significant rates~~Rate Case Filing: On December 21, 2015, our Delaware Division filed an application with the Delaware PSC for a base rate increase and certain other ~~regulatory activities~~changes to its tariff. We proposed an increase of approximately $4.7 million, or nearly ten percent, in ~~Delaware~~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 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 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 ~~2015.~~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

~~Ocean City SIR~~Sandpiper Rate Case Filing: On ~~July 2,~~December 1, 2015, Sandpiper filed an application with the Maryland PSC for a base rate increase and certain other changes to ~~establish~~its tariff. We proposed an ~~SIR~~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, and a revenue normalization mechanism for residential and small commercial customers. The procedural schedule was suspended in early May 2016 to ~~further fund system expansion within~~allow for the ~~city limits~~continuation of ~~Ocean City, Maryland. The proposed SIR, which would only be charged to customers located within city limits, was supported by Ocean City's local government. On August 5, 2015,~~settlement discussions between Sandpiper, Maryland PSC Staff and the Maryland ~~PSC approved~~Office of People's Counsel. The parties reached a settlement agreement, which Sandpiper filed with the ~~application.~~Commission on August 10, 2016. The terms of the agreement include revenue neutral rates for the first year, followed by a schedule of rate reductions 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. The order became final on October 29, 2016 and the new rates will be in effect on December 1, 2016.

Florida

On January 16, 2015, Chesapeake's Florida natural gas distribution division filed a petition with the Florida PSC for approval of a contract with its affiliate, Peninsula Pipeline, for additional natural gas transportation services in the vicinity of Haines City, located in Polk County, Florida. This petition was approved by the Florida PSC at its Agenda Conference on May 5, 2015.

On July 1, 2015, FPU's electric division filed an electric depreciation study with the Florida PSC. Depending upon the Florida PSC’s decision in this proceeding, depreciation expense may change for FPU’s electric division as a result of a change in depreciation rates effective January 1, 2015. This action is scheduled for review by the Florida PSC at its Agenda Conference to be held in December 2015.

On September 1, 2015, FPU’s electric division filed to recover the cost of the proposed Florida Power & Light Company interconnect project through ~~the~~FPU's annual Fuel and Purchased Power Cost Recovery Clause filing. The interconnect project will enable FPU's electric division to negotiate a new power purchase agreement that will mitigate fuel costs for its Northeast ~~Division. The hearing on this Docket~~division. This action was ~~held on November 4, 2015. Ruling~~approved by the Florida PSC ~~on the docket is expected~~ at ~~the~~its Agenda Conference held on December 3, 2015. On January 22, 2016, the Office of Public Counsel filed an appeal of the Florida PSC's decision with the Florida Supreme Court. Legal briefs have been filed, but no decision has been reached at this time.

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

On April 11, 2016, FPU’s natural gas divisions and Chesapeake Utilities' Florida division filed a joint petition for approval to allow FPU and Chesapeake Utilities to expand the cost allocation of the intrastate and unreleased capacity-related components currently embedded in ~~December 2015.~~the purchased gas adjustment and operational balancing account, which is currently allocated to a limited number of 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, Eastern Shore submitted an application to the ~~FERC seeking~~FERCseeking authorization to construct, own and operate certain expansion facilities designed to provide 45,000 Dts/d of firm transportation service to an ~~industrial customer~~electric power generator in Kent County, Delaware. Eastern Shore proposes to construct approximately 7.2 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and 3,550 horsepower of additional compression at Eastern Shore’s existing Delaware City ~~Compressor Station~~compressor station in New Castle County, Delaware. ~~The estimated cost~~

On November 18, 2015, Eastern Shore filed an amendment to this application, which indicated the preferred pipeline route and shortened the total miles of the ~~project is $29.8 million.~~proposed pipeline to 5.4 miles. On ~~January 22, 2015,~~February 10, 2016, the FERC issued a ~~Notice of Intent to Prepare an Environmental Assessment for this project. In February, April~~notice combining the White Oak Mainline Expansion Project and ~~May 2015, Eastern Shore filed~~the System Reliability Project into a single environmental data in response to comments regarding evaluation of alternate routes for a segment of the pipeline route in the vicinity of the Kemblesville Historic District. On June 2, 2015, a field meeting was conducted to review the proposed route and alternate routes. In response to comments received from the National Park Service and other stakeholders, FERC Staff requestedassessment.

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~~that Eastern Shore conduct an additional investigation in relation to Eastern Shore's existing right-of-way.~~

On July ~~9, 2015,~~21, 2016, the FERC issued a ~~30-day~~certificate of public ~~scoping notice~~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 ~~advance~~the certificate proceeding. However, FERC’s determination is without prejudice to Eastern Shore filing for and fully supporting rolled-in rate treatment of ~~issuing an Environmental Assessment~~these project facilities in ~~order~~a future general rate case. The certificate required Eastern Shore to ~~solicit comments from~~comply with 19 environmental conditions.

On July 29, 2016, Eastern Shore accepted the certificate of public ~~regarding~~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 ~~Kemblesville loop. On August 18, 2015, Eastern Shore submitted supplemental information to the FERC regarding the results of its investigation of the Kemblesville loop.~~

environmental conditions.

System Reliability Project: On May 22, 2015, Eastern Shore submitted an application to the FERC seeking authorization to construct, own and operate approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further ~~proposes~~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 in 2014 and 2015. ~~The estimated cost of the project is $32.1 million.~~ 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 by December 2015.~~project.

On ~~June 8, 2015,~~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 in its next rate base proceeding and required Eastern Shore to comply with 19 environmental conditions.

On July 29, 2016, Eastern Shore accepted 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 ~~notice~~“Partial Notice to Proceed” approving construction for certain portions of the ~~application,~~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 ~~comment period ended~~Porter Road Loop in August 2016, and on ~~June 29, 2015.~~the Dover Loop, in September 2016 and is ongoing. Eastern Shore ~~anticipates FERC approval~~continues to file weekly status reports in compliance with one of ~~this project in~~ the ~~fourth quarter of 2015 and estimates that construction will start in the first quarter of 2016.~~

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 ~~will~~would enable Eastern Shore to increase natural gas receipts from TETLP by 53,000 Dts/~~day,~~d, for a total capacity of 160,000 Dts/d. On December 22, 2015, the FERC authorized Eastern Shore ~~expects~~to proceed with the project. On March 11, 2016, the capacity expansion project was placed into service.

2017 Expansion Project: On 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. The expansion project consists of approximately 33 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, 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 of approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to ~~be approved~~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.

2017 Rate Case Filing

In January 2017, Eastern Shore intends to file a base rate proceeding with the FERC, as required by the ~~end~~terms of ~~the year.~~its 2012 settlement agreement.


5.	~~Environmental Commitments and Contingencies~~

5. Environmental Commitments and Contingencies

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

MGP Sites

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

As of September 30, ~~2015~~,2016, we had approximately ~~$10.0~~$9.9 million in environmental liabilities, representing our estimate of the future costs associated with all of FPU’s MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach sites. FPU has approval to recover, from insurance and from customers through rates, up to ~~$14.0~~$14.0 million of its environmental costs related to all of its MGP sites, approximately ~~$10.0~~$10.5 million of which has been recovered as of September 30, ~~2015~~,2016, leaving approximately ~~$4.0~~$3.5 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

In addition to the FPU MGP sites, we had ~~$389,000~~$298,000 in environmental liabilities at September 30, ~~2015~~ ~~related to Chesapeake’s MGP sites in Maryland and Florida,~~2016, representing our estimate of future costs associated with ~~these sites. As of~~ ~~September 30, 2015, we had approximately~~ ~~$116,000~~Chesapeake Utilities' MGP site in ~~regulatory and other assets for future recovery through Chesapeake’s rates.~~Winter Haven, Florida.

During the first quarter of 2015, we established $273,000 in environmental liabilities related to ~~Chesapeake’s~~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’s~~Chesapeake Utilities' rates ~~although we have not yet sought~~via our environmental rider. On February 23, 2016, the Delaware PSC ~~approval~~approved an environmental surcharge for ~~recovery.~~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, ~~2015~~,2016, we had approximately ~~$239,000~~$156,000 in environmental liabilities and ~~$273,000~~$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

WeRemedial options are ~~evaluating remedial options~~being evaluated to respond to environmental impacts to soil and groundwater at and in the immediate vicinity of a parcel of property owned by FPU in West Palm Beach, Florida, where FPU previously operated a MGP.

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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 ~~anticipate~~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 costs of remediation for the West Palm Beach site range from approximately ~~$4.5~~$4.5 million to ~~$15.4~~$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.

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Sanford, Florida

FPU is the current owner of property in Sanford, Florida, which ~~was~~is the site on which a former MGP ~~site~~ that was operated by several other entities before FPU acquired the property. FPU was never an owner or an operator of the MGP atpreviously 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~~$13.0 million,, or ~~$650,000~~.$650,000. As of September 30, ~~2015~~,2016, FPU has paid ~~$650,000~~$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 ~~remediation~~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~~$20.0 million,, which includes long-term monitoring and the settlement of claims asserted by two adjacent property owners to resolve damages that the property owners allege they have incurred and will incur as a result of the implementation of the EPA-approved remediation.

In settlement of these claims, members of the Sanford Group, which in this instance does not include FPU, have agreed to pay specified sums of money to the parties. FPU has refused to participate in the funding of the third-party settlement agreements based on its contention that it did not contribute to the release of hazardous substances at the site giving rise to the third-party claims. FPU ~~has~~ advised the other members of the Sanford Group that it is unwilling ~~at this time to agree~~ to pay any sum in excess of the ~~$650,000~~ ~~committed~~$650,000 paid by FPU inunder 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, ~~2015~~,2016, FPU’s remaining remediation expenses, including attorneys’ fees and costs, are estimated to be ~~$24,000. However, we~~$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~~$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~~$650,000 that FPU has paid ~~under~~pursuant to the Third Participation Agreement. No such claims have been made as of September 30, ~~2015~~.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, 4, 2012. FDEP responded on October 9, 2012 that, based on the data, NAM appears to be an appropriate remedy for the site.

In October 2012, FDEP issued a RAP approval order, which requires a limited semi-annual ~~monitoring program.~~NAM. The most recent groundwater-monitoring event was conducted onin September ~~14, 2015.~~2016. Natural ~~Attenuation Default~~attenuation default criteria were met at all locations ~~sampled.~~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 ~~sampling event~~NAM is scheduled for ~~March 2016.~~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~~.$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

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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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~~$5,000~~.

Winter Haven, Florida

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

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

Although specific remedial actions for the site have not yet been identified, we estimate that future remediation costs for the subsurface soils and groundwater at the site should not exceed ~~$443,000~~,$425,000, which includes an estimate of ~~$100,000~~$100,000 to implement additional actions, such as institutional controls, at the site. ~~We continue to believe that the entire amount will be recoverable from customers through rates.~~

FDEP previously indicated that we could also be required to remediate sediments along the shoreline of Lake Shipp, immediately west of the site. Based on studies performed to date, and our recent meeting with FDEP, we believe that corrective measures for lake sediments are not warranted and will not be required by ~~FDEP; therefore,~~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 ~~of the~~for maintaining and monitoring this one remaining ~~monitoring~~ well will not exceed ~~$5,000~~$5,000 annually. We cannot predict at this time when the MDE will grant permission to permanently decommission ~~the one remaining monitoring~~this well.

Seaford, Delaware

In a letter dated December 5, 2013, ~~the~~ DNREC notified us that it would be conducting a facility evaluation of a former MGP site in Seaford, Delaware. In a report issued in January 2015, DNREC provided the evaluation, which found several compounds within the groundwater and soil that require further investigation. ~~We submitted an application to the DNREC on April 2, 2015, which was approved on~~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.

~~Other~~

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Cambridge, Maryland

We are ~~in discussions~~discussing with the MDE ~~regarding~~ 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.	Other Commitments and Contingencies

Natural Gas, Electric and Propane Supply

~~Our natural gas, electric and propane distribution operations~~We have entered into contractual commitments to purchase natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. ~~Our~~For our Delaware and Maryland natural gas distribution divisions, we have a contract ~~through March 31, 2017,~~ with an unaffiliated energy marketing and risk management company to manage a portion of their natural gas transportation and storage ~~capacity.~~capacity, which expires on March 31, 2017.

In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a ~~six-year term. Approximately three years, four months remain under this contract.~~six-year term ending in May 2019. Sandpiper's current annual commitment is estimated at approximately 6.5 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.

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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.~~term ending in May 2019. Sharp's current annual commitment is estimated at approximately 6.5 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement.

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

~~In May 2015, PESCO renewed contracts to purchase natural gas from various suppliers. The total monthly purchase commitment ranges from 9,982 to 13,423 Dts/dfrom June 2015 to May 2016. These contracts expire in May 2016.~~

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEA requires FPU to comply with the following ratios based on the results of the prior 12 months: (a) total liabilities to tangible net worth less than 3.75 times and (b) a fixed charge coverage ratio greater than 1.5 times. If FPU fails to comply with either of these ratios, it has 30 days to cure the default or, if the default is not cured, to provide an irrevocable letter of credit. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet either of these ratios, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of September 30, ~~2015~~2016, FPU was in compliance with all of the requirements of its fuel supply contracts.

Corporate Guarantees

The Board of Directors has authorized us to issue corporate guarantees ~~securing obligations of our subsidiaries~~ and to obtain letters of credit securing our ~~obligations, including the obligations of our subsidiaries.~~subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit is ~~$50.0~~$65.0 million.

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Chesapeake Utilities has issued corporate guarantees to certain ~~vendors~~ of our ~~subsidiaries,~~subsidiaries' vendors, the largest ~~portion~~ of which isare for Xeron and PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases ~~respectively,~~ in the event that Xeron or PESCO defaults. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at September 30, ~~2015~~2016 was ~~$36.1~~approximately $53.9 million,, with the guarantees expiring on various dates through September ~~22, 2016.~~2017.

Chesapeake Utilities also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under ~~the~~this guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 14, Long-Term Debt, for further details).

~~In addition to the corporate guarantees, we have~~We issued ~~a letter~~letters of credit ~~for~~ ~~$1.0~~totaling approximately $8.4 million~~, which expires on~~ ~~September 12, 2016~~, related to the electric transmission services for ~~FPU’s northwest~~FPU's electric division. We have also issued a letter of credit to our current primary insurance company for $1.2 million which expires on October 31, 2016, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company, we renewed and decreased the letter of credit for $24,000 to our former primary insurance company, which will expire on June 1, 2016. We have also issued a letter of credit of $1.0 million which expires on March 31, 2016, related to PESCO's transactions at the Natural Gas Exchange, Inc.

~~We provided a letter of credit for $2.3 million to TETLP related to~~division, the firm transportation service agreement ~~with~~between TETLP and our Delaware and Maryland ~~divisions.~~

divisions, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through September 2017. There have been no draws on these letters of credit as of September 30, ~~2015.~~2016. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that the letters of credit will be renewed to the extent necessary in the future.

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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 ~~$100,000~~approximately $50,000 related to unrecognized income tax ~~benefits and $404,000~~benefits. As of December 31, 2015, we maintained a liability of approximately $310,000 related to contingencies for taxes other than income. ~~As of December 31, 2014, we maintained~~We did not have a liability of ~~$100,000~~ ~~related to unrecognized income tax benefits and $724,000~~ related to contingencies for taxes other than ~~income.~~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.	Segment Information

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

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

Unregulated Energy. The Unregulated Energy segment includes propane distribution and wholesale marketing operations, and natural gas marketing operations, which are unregulated as to their rates and services. Effective April 1, 2015, this segment includes Aspire Energy, ~~of Ohio,~~ whose services include natural gas gathering, processing, transportation and ~~processing~~supply (See Note 3, Acquisitions, regarding the ~~acquisition of~~merger with Gatherco). Effective June 2016, this segment includes electricity and steam generation through Eight Flags' CHP plant. Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services.

~~We had previously identified "Other" as a separate reportable segment, which consisted primarily~~The remainder of our ~~advanced information services subsidiary. As a result~~operations is presented as “Other businesses and eliminations”, which consists of ~~the sale of~~unregulated subsidiaries that ~~subsidiary on October 1, 2014, "Other" is no longer a separate reportable segment.~~own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations.

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The following table presents financial information about our reportable segments:


	Three Months Ended						Nine Months Ended					Three Months Ended						Nine Months Ended
	September 30,						September 30,					September 30,						September 30,
	2015			2014			2015			2014		2016			2015			2016			2015
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	63,526		$	59,086		$	234,608		$	222,308	$	68,899		$	63,526		$	224,382		$	234,608
Unregulated Energy segment	28,387			27,041			120,068			141,215		39,449			28,387			132,604			120,068
Other businesses	—			5,492			—			14,931
Total operating revenues, unaffiliated customers	$	91,913		$	91,619		$	354,676		$	378,454	$	108,348		$	91,913		$	356,986		$	354,676
Intersegment Revenues ⁽¹⁾
Regulated Energy segment	$	270		$	270		$	830		$	860	$	1,120		$	270		$	2,248		$	830
Unregulated Energy segment	1,222			30			3,095			150		2,593			1,222			3,759			3,095
Other businesses	220			258			660			760		240			220			705			660
Total intersegment revenues	$	1,712		$	558		$	4,585		$	1,770	$	3,953		$	1,712		$	6,712		$	4,585
Operating Income (Loss)
Operating Income
Regulated Energy segment	$	11,828		$	9,202		$	47,616		$	41,004	$	13,115		$	11,828		$	52,660		$	47,616
Unregulated Energy segment	(1,022		)	(1,972		)	13,666			8,843		(3,080		)	(1,022		)	9,267			13,666
Other businesses and eliminations	103			562			305			25		121			103			350			305
Total operating income	10,909			7,792			61,587			49,872		10,156			10,909			62,277			61,587
Other income (loss), net of other expenses	36			(32		)	(3		)	380
Other (expense) income, net												(28		)	36			(68		)	(3		)
Interest	2,492			2,495			7,425			6,954		2,722			2,492			7,996			7,425
Income before Income Taxes	8,453			5,265			54,159			43,298		7,406			8,453			54,213			54,159
Income taxes	3,334			2,085			21,638			17,303		2,990			3,334			21,401			21,638
Net Income	$	5,119		$	3,180		$	32,521		$	25,995	$	4,416		$	5,119		$	32,812		$	32,521


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


(in thousands)	September 30, 2015		December 31, 2014		September 30, 2016		December 31, 2015
Identifiable Assets
Regulated Energy segment	$	824,330	$	796,021	$	921,682	$	872,065
Unregulated Energy segment	156,838		84,732		207,083		171,840
Other businesses and eliminations	27,274		23,716		11,745		23,516
Total identifiable assets	$	1,008,442	$	904,469	$	1,140,510	$	1,067,421

Our operations are entirely domestic.

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8.	Accumulated Other Comprehensive Loss

Defined benefit pension and postretirement plan items, ~~and~~ unrealized gains (losses) of our propane swap agreements, ~~and~~ call options and natural gas futures contracts, designated as commodity contracts cash flow hedges, are the components of our accumulated comprehensive ~~loss.~~income (loss). The following tables present the changes in the balance of accumulated other comprehensive loss for the nine months ended September 30, ~~2015~~2016 and ~~2014.~~2015. All amounts are presented net of tax.


	Defined Benefit			Commodity						Defined Benefit			Commodity
	Pension and			Contracts						Pension and			Contracts
	Postretirement			Cash Flow						Postretirement			Cash Flow
	Plan Items			Hedges			Total			Plan Items			Hedges			Total
(in thousands)
As of December 31, 2014	$	(5,643	)	$	(33	)	$	(5,676	)
Other comprehensive loss before reclassifications	—			(76		)	(76		)
As of December 31, 2015										$	(5,580	)	$	(260	)	$	(5,840	)
Other comprehensive gain before reclassifications										—			641			641
Amounts reclassified from accumulated other comprehensive loss	248			33			281			263			(93		)	170
Net current-period other comprehensive income	248			(43		)	205			263			548			811
As of September 30, 2015	$	(5,395	)	$	(76	)	$	(5,471	)
As of September 30, 2016										$	(5,317	)	$	288		$	(5,029	)


	Defined Benefit			Commodity						Defined Benefit			Commodity
	Pension and			Contracts						Pension and			Contracts
	Postretirement			Cash Flow						Postretirement			Cash Flow
	Plan Items			Hedges			Total			Plan Items			Hedges			Total
(in thousands)
As of December 31, 2013	$	(2,533	)	$	—		$	(2,533	)
As of December 31, 2014										$	(5,643	)	$	(33	)	$	(5,676	)
Other comprehensive loss before reclassifications	—			(28		)	(28		)	—			(76		)	(76		)
Amounts reclassified from accumulated other comprehensive loss	92			—			92			248			33			281
Net current-period other comprehensive income (loss)	92			(28		)	64
As of September 30, 2014	$	(2,441	)	$	(28	)	$	(2,469	)
Net prior-period other comprehensive income										248			(43		)	205
As of September 30, 2015										$	(5,395	)	$	(76	)	$	(5,471	)

The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, ~~2015~~2016 and ~~2014.~~2015. 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.

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	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2015			2014			2015			2014			2016			2015			2016			2015
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service cost ⁽¹⁾	$	17		$	14		$	50		$	44		$	20		$	17		$	60		$	50
Net gain ⁽¹⁾	(155		)	(65		)	(465		)	(198		)
Net loss ⁽¹⁾													(166		)	(155		)	(500		)	(465		)
Total before income taxes	(138		)	(51		)	(415		)	(154		)	(146		)	(138		)	(440		)	(415		)
Income tax benefit	55			21			167			62			58			55			177			167
Net of tax	$	(83	)	$	(30	)	$	(248	)	$	(92	)	$	(88	)	$	(83	)	$	(263	)	$	(248	)

Gains and losses on commodity contracts cash flow hedges
Propane swap agreements ⁽²⁾	$	—		$	—		$	—		$	—		$	—		$	—		$	(322	)	$	—
Call options ⁽²⁾	—			—			(55		)	—			—			—			—			(55		)
Natural gas futures ⁽²⁾													105			—			464			—
Total before income taxes	—			—			(55		)	—			105			—			142			(55		)
Income tax benefit	—			—			22			—
Income tax benefit (expense)													(41		)	—			(49		)	22
Net of tax	—			—			(33		)	—			64			—			93			(33		)
Total reclassifications for the period	$	(83	)	$	(30	)	$	(281	)	$	(92	)	$	(24	)	$	(83	)	$	(170	)	$	(281	)

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

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

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


9.	Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three and nine months ended September 30, ~~2015~~2016 and ~~2014~~2015 are set forth in the following tables:


	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 Three Months Ended September 30,	2015			2014			2015			2014			2015		2014		2015			2014			2015		2014		2016			2015			2016			2015			2016		2015		2016			2015			2016		2015
(in thousands)
Interest cost	$	102		$	107		$	626		$	647		$	23	$	23	$	11		$	13		$	15	$	17	$	105		$	102		$	635		$	626		$	23	$	23	$	11		$	11		$	14	$	15
Expected return on plan assets	(135		)	(133		)	(777		)	(773		)	—		—		—			—			—		—		(131		)	(135		)	(625		)	(777		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			2		5		(19		)	(19		)	—		—		—			—			—			—			—		2		(20		)	(19		)	—		—
Amortization of net loss	91			37			114			—			25		12		17			16			2		—		103			91			133			114			22		25		16			17			—		2
Net periodic cost (benefit)	58			11			(37		)	(126		)	50		40		9			10			17		17		77			58			143			(37		)	45		50		7			9			14		17
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2		—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	58		$	11		$	154		$	65		$	50	$	40	$	9		$	10		$	19	$	19	$	77		$	58		$	334		$	154		$	45	$	50	$	7		$	9		$	16	$	19

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	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,	2015			2014			2015			2014			2015		2014		2015				2014			2015		2014		2016			2015			2016			2015			2016		2015		2016			2015			2016		2015
(in thousands)
Interest cost	$	306		$	320		$	1,877		$	1,941		$	68	$	69	$	33			$	39		$	45	$	50	$	315		$	306		$	1,894		$	1,877		$	68	$	68	$	32		$	33		$	41	$	45
Expected return on plan assets	(405		)	(398		)	(2,330		)	(2,318		)	—		—		—				—			—		—		(392		)	(405		)	(2,027		)	(2,330		)	—		—		—			—			—		—
Amortization of prior service cost	—			—			—			—			8		14		(58		)	��	(58		)	—		—		—			—			—			—			—		8		(60		)	(58		)	—		—
Amortization of net loss	272			112			341			—			74		36		53				50			5		—		309			272			389			341			66		74		51			53			—		5
Net periodic cost (benefit)	173			34			(112		)	(377		)	150		119		28				31			50		50		232			173			256			(112		)	134		150		23			28			41		50
Amortization of pre-merger regulatory asset	—			—			571			571			—		—		—				—			6		6		—			—			571			571			—		—		—			—			6		6
Total periodic cost	$	173		$	34		$	459		$	194		$	150	$	119	$	28			$	31		$	56	$	56	$	232		$	173		$	827		$	459		$	134	$	150	$	23		$	28		$	47	$	56

We expect to record pension and postretirement benefit costs of approximately $~~1.2~~1.7 million for ~~2015.~~2016. Included in these costs is approximately $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations for the changes in funded status that occurred, but were not recognized, as part of net periodic benefit costs prior to the FPU merger in 2009. This was deferred as a regulatory asset by FPU prior to the merger, to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was approximately $2.3 million and approximately $~~3.1 million~~ ~~and~~ ~~$3.6~~2.9 million at September 30, ~~2015~~2016 and December 31, ~~2014~~2015, respectively. The amortization included in pension expense is also being added to a net periodic loss of ~~$381,000,~~approximately $917,000, which will increase our total expected benefit costs to ~~$1.2~~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’s~~Chesapeake Utilities' operations is recorded to accumulated other comprehensive loss.

The following ~~table presents~~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, ~~2015~~2016 and ~~2014:~~2015:


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 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 cost (credit)	$	—	$	—	$	2	$	(19	)	$	—	$	(17	)
Prior service credit															$	—	$	—	$	—	$	(20	)	$	—	$	(20	)
Net loss	91		114		25		17			2		249			103		133		22		16			—		274
Total recognized in net periodic benefit cost	$	91	$	114	$	27	$	(2	)	$	2	$	232		$	103	$	133	$	22	$	(4	)	$	—	$	254
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	91	$	22	$	27	$	(2	)	$	—	$	138		$	103	$	25	$	22	$	(4	)	$	—	$	146
Recognized from regulatory asset	—		92		—		—			2		94			—		108		—		—			—		108
Total	$	91	$	114	$	27	$	(2	)	$	2	$	232		$	103	$	133	$	22	$	(4	)	$	—	$	254

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For the Nine Months Ended September 30, 2015	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
For the Three 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	)	$	—	$	—	$	2	$	(19	)	$	—	$	(17	)
Net loss	272		341		74		53			5		745			91		114		25		17			2		249
Total recognized in net periodic benefit cost	$	272	$	341	$	82	$	(5	)	$	5	$	695		$	91	$	114	$	27	$	(2	)	$	2	$	232
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	272	$	65	$	82	$	(5	)	$	1	$	415		$	91	$	22	$	27	$	(2	)	$	—	$	138
Recognized from regulatory asset	—		276		—		—			4		280			—		92		—		—			2		94
Total	$	272	$	341	$	82	$	(5	)	$	5	$	695		$	91	$	114	$	27	$	(2	)	$	2	$	232

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 nine months ended September 30, 2016 and 2015:


For the Three Months Ended September 30, 2014	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)	$	—	$	—	$	5	$	(19	)	$	—	$	(14	)
Prior service credit															$	—	$	—	$	—	$	(60	)	$	—	$	(60	)
Net loss	37		—		12		16			—		65			309		389		66		51			—		$	815
Total recognized in net periodic benefit cost	$	37	$	—	$	17	$	(3	)	$	—	$	51		$	309	$	389	$	66	$	(9	)	$	—	$	755
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	37	$	—	$	17	$	(3	)	$	—	$	51		$	309	$	74	$	66	$	(9	)	$	—	$	440
Recognized from regulatory asset	—		—		—		—			—		—			—		315		—		—			—		315
Total	$	37	$	—	$	17	$	(3	)	$	—	$	51		$	309	$	389	$	66	$	(9	)	$	—	$	755


For the Nine Months Ended September 30, 2014	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
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)	$	—	$	—	$	14	$	(58	)	$	—	$	(44	)	$	—	$	—	$	8	$	(58	)	$	—	$	(50	)
Net loss	112		—		36		50			—		198			272		341		74		53			5		745
Total recognized in net periodic benefit cost	$	112	$	—	$	50	$	(8	)	$	—	$	154		$	272	$	341	$	82	$	(5	)	$	5	$	695
Recognized from accumulated other comprehensive loss ⁽¹⁾	$	112	$	—	$	50	$	(8	)	$	—	$	154		$	272	$	65	$	82	$	(5	)	$	1	$	415
Recognized from regulatory asset	—		—		—		—			—		—			—		276		—		—			4		280
Total	$	112	$	—	$	50	$	(8	)	$	—	$	154		$	272	$	341	$	82	$	(5	)	$	5	$	695


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

During the three and nine months ended September 30, ~~2015,~~2016, we contributed ~~$127,000~~approximately $116,000 and ~~$346,000,~~$390,000, respectively, to the Chesapeake Pension Plan and ~~$402,000~~approximately $374,000 and ~~$1.1~~approximately $1.3 million, respectively, to the FPU Pension Plan. We expect to contribute a total of ~~$475,000~~approximately $508,000 and ~~$1.6~~approximately $1.6 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during ~~2015,~~2016, which represent the minimum annual contribution payments required.

The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three and nine months ended September 30, ~~2015,~~2016, were approximately $38,000 and ~~$109,000,~~approximately $114,000, respectively. We expect to pay total cash benefits of approximately ~~$151,000~~$151,000 under the Chesapeake Pension SERP in ~~2015.~~2016. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three and nine months ended September 30, ~~2015,~~2016, were ~~$14,000~~approximately $23,000 and ~~$42,000,~~approximately $59,000, respectively. We estimate that approximately ~~$79,000~~$82,000 will be paid

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for such benefits under the Chesapeake Postretirement Plan in ~~2015.~~2016. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and nine months ended September 30, ~~2015,~~2016, were ~~$47,000~~approximately $32,000 and ~~$163,000,~~approximately $97,000, respectively. We estimate that approximately ~~$207,000~~$149,000 will be paid for such benefits under the FPU Medical Plan in ~~2015.~~2016.

~~- 20~~

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10.	Investments

The investment balances at September 30, ~~2015~~2016 and December 31, ~~2014,~~2015, consisted of the following:



(in thousands)	September 30, 2015		December 31, 2014		September 30, 2016		December 31, 2015
Rabbi trust (associated with the Deferred Compensation Plan)	$	3,394	$	3,678	$	4,609	$	3,626
Investments in equity securities	18		—		21		18
Total	$	3,412	$	3,678	$	4,630	3,644

We classify these investments as trading securities and report them at their fair value. For the three months ended September 30, 2016 and 2015, ~~and 2014,~~ we recorded a net unrealized gain of ~~$238,000~~approximately $193,000 and ~~$41,000,~~$238,000, respectively, in other income in the condensed consolidated statements of income related to these investments. For the nine months ended September 30, ~~2015~~2016 and ~~2014,~~2015, we recorded an unrealized gain of approximately $246,000 and a net unrealized loss of approximately $131,000, ~~and a net unrealized gain of $111,000,~~ respectively, in other income in the condensed consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the condensed consolidated balance sheets and is adjusted each month for the gains and losses incurred by the investments in the Rabbi Trust.


11.	Share-Based Compensation

Our non-employee directors and key employees are granted share-based awards through ~~the~~our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the ~~grant~~ 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, ~~2015~~2016 and ~~2014:~~2015:


	Three Months Ended						Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,						September 30,						September 30,						September 30,
	2015			2014			2015			2014			2016			2015			2016			2015
(in thousands)
Awards to non-employee directors	$	165		$	137		$	475		$	394		$	135		$	165		$	445		$	475
Awards to key employees	334			317			970			1,125			488			334			1,442			970
Total compensation expense	499			454			1,445			1,519			623			499			1,887			1,445
Less: tax benefit	(201		)	(183		)	(582		)	(612		)	(251		)	(201		)	(760		)	(582		)
Share-based compensation amounts included in net income	$	298		$	271		$	863		$	907		$	372		$	298		$	1,127		$	863

Non-employee Directors

Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the grant date. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May ~~2015,~~2016, each of our non-employee directors received an annual retainer of ~~1,207~~953 shares of common stock under the SICP for ~~Board~~ service as a director through the ~~2016~~2017 Annual Meeting of Stockholders.

A summary of the stock activity for our non-employee directors during the nine months ended September 30, ~~2015~~2016 is presented below:

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	Number of Shares		Weighted Average Fair Value		Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2014	—		$	—
Outstanding— December 31, 2015					—		$	—
Granted	14,484		$	45.54	8,577		$	62.90
Vested	(14,484	)	$	45.54	(8,577	)	$	62.90
Outstanding— September 30, 2015	—		$	—
Outstanding— September 30, 2016					—		$	—

At September 30, ~~2015~~,2016, there was ~~$385,000~~approximately $314,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service ~~periods~~period ending April 30, ~~2016.~~2017.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the nine months ended September 30, ~~2015:~~2016:


	Number of Shares		Weighted Average Fair Value		Number of Shares		Weighted Average Fair Value
Outstanding— December 31, 2014	123,038		$	32.60
Outstanding— December 31, 2015					110,398		$	38.34
Granted	33,719		$	48.21	46,571		$	67.90
Vested	(43,839	)	$	28.01	(39,553	)	$	31.79
Expired	(2,520	)	$	28.83	(2,325	)	$	42.25
Outstanding— September 30, 2015	110,398		$	38.34
Outstanding— September 30, 2016					115,091		$	52.36

In ~~January and March 2015,~~February 2016, our Board of Directors granted awards of ~~33,719~~46,571 shares of common stock to key employees under the SICP. The shares granted in ~~January and March 2015~~February 2016 are multi-year awards that will vest at the end of the three-year service period ending December 31, ~~2017.~~2018. All of these stock awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprise both market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the grant date of each award. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

At September 30, ~~2015,~~2016, the aggregate intrinsic value of the SICP awards granted to key employees was ~~$5.9~~approximately $7.0 million. At September 30, ~~2015,~~2016, there was ~~$1.7~~approximately $2.7 million of unrecognized compensation cost related to these awards, which is expected to be recognized ~~during 2015~~from 2016 through ~~2017.~~2018.


12.	Derivative Instruments

We use derivative and non-derivative contracts to engage in trading activities and manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. ~~Our natural gas, electric and propane distribution operations~~We have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to ~~their~~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 ~~operation~~and natural gas marketing operations may also enter into fair value hedges of ~~its~~their inventory or cash flow hedges of ~~its~~their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of September 30, ~~2015,~~2016, our natural gas and electric distribution operations did not have any outstanding derivative contracts.

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 million gallons expected to be purchased for the upcoming heating season. Under the swap agreements, Sharp will receive the difference between the index prices (Mont Belvieu prices in December 2016 through September 2017) and the swap prices of $0.5250 and $0.5525 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. The swap agreement essentially fixes the price of the 4.1 million gallons that we expect to purchase for the upcoming heating season. We accounted for these swap

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agreements as cash flow hedges, and there is 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).

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. PESCO also assumed the obligation to store natural gas inventory to satisfy its obligations under the SCO supplier agreement, 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 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 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 contracts with a mark-to-market liability of $29,000.

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 ~~upcoming~~2015-2016 heating season. ~~The~~We exercised the put options ~~are exercised if~~as propane prices ~~fall~~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. ~~If exercised, we will receive~~We received approximately $239,000, which represents the difference between the market ~~price~~ prices

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and the strike ~~price~~prices during those months. We accounted for the put options as fair value ~~hedges, and there is no ineffective portion of these~~ hedges. ~~As of September 30, 2015, the put options had a fair value of $64,000. The change in fair value of the put options effectively reduced our propane inventory balance.~~

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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 ~~expected to be~~ purchased ~~for the upcoming heating season.~~in December 2015 through March 2016. Under these swap agreements, Sharp ~~receives~~would have received the difference between the index prices (Mont Belvieu prices in December 2015 through March 2016) and the swap prices, ofwhich ranged from $0.5200 to $0.5950 $0.5888, $0.5500 and $0.5200 per gallon for each swap agreement, to the extent the index prices exceed the swap prices. If the index prices are lower than the swap prices, Sharp will pay the difference. These swap agreements essentially fix the price of the 2.5 million gallons that we expect to purchase for the upcoming heating season. We accounted for the swap agreements as cash flow hedges, and there is no ineffective portion of these hedges. At September 30, 2015, the swap agreements had a liability fair value of $128,000. The change in the fair value of the swap agreements is recorded as unrealized gain/loss in other comprehensive income (loss).

~~Hedging Activities in 2014~~

In August and October 2014, Sharp entered into call options to protect against an increase in propane prices associated with 1.3 million gallons purchased at market-based prices to supply the demands of our propane price cap program customers. The retail price that we charged to those customers during the heating season was capped at a pre-determined level. We would have exercised the call options if the propane prices had risen above the strike price of $1.0875 per gallon in December 2014 through February of 2015, and $1.0650 per gallon in January through March 2015. In that event, we would have received the difference between the market price and the strike price during those months. We paid $98,000 to purchase the call options, which expired without exercise as the market prices were below the strike prices. We accounted for the call options as cash flow hedges.

In May 2014, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 630,000 gallons purchased in December 2014 through February 2015. Under these swap agreements, Sharp would have received the difference between the index prices (Mont Belvieu prices in December 2014 through February 2015) and the swap prices of $1.1350, $1.0975 and $1.0475 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 ~~630,000~~2.5 million gallons that we purchased during this period. We ~~had initially~~ accounted for ~~them~~the swap agreements as cash flow ~~hedges as the swap agreements met all the requirements. We~~hedges. Sharp paid ~~$1.1 million, representing~~approximately $484,000, which represents the difference between the ~~market~~index prices and ~~strike~~swap prices during those months ~~for~~of the swap agreements. At December 31, 2014, we elected to discontinue hedge accounting on the swap agreements and reclassified $735,000 of unrealized loss from other comprehensive loss to propane cost of sales. Subsequently, we accounted for them as derivative instruments on a mark-to-market basis with the change in the fair value reflected in current period earnings.

In May 2014, Sharp entered into put options to protect against declines in propane prices and related potential inventory losses associated with 630,000 gallons for the propane price cap program in December 2014 through February 2015. We exercised the put options because the propane prices fell below the strike prices of $1.0350, $0.9975, and $0.9475 per gallon, for each option agreement in December 2014 through February 2015, respectively. We paid $128,000 to purchase the put options and received $868,000, representing the difference between the market prices and strike prices during those months. We accounted for them as fair value hedges.

Commodity Contracts for Trading Activities

Xeron engages in trading activities using forward and futures ~~contracts.~~contracts for propane and crude oil. These contracts are considered derivatives and have been accounted for using the mark-to-market method of accounting. Under this method, the trading contracts are recorded at fair value, and the changes in fair value of those contracts are recognized as unrealized gains or losses in the statements of income for the period of change. As of September 30, ~~2015, we~~2016, Xeron had ~~the following~~no outstanding ~~trading~~ contracts ~~which we~~that were accounted for as ~~derivatives:~~derivatives.

Quantity in Estimated Market Weighted Average
At September 30, 2015 Gallons Prices Contract Prices
Forward Contracts
Sale 2,940,000
$0.4750 - $0.5288 $ 0.5210
Purchase 2,940,000
$0.4350 - $0.5025 $ 0.4545

~~Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the fourth quarter of 2015.~~

Xeron ~~has~~ 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, ~~2015,~~2016, Xeron had no accounts receivable or accounts payable balances to offset with these two

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counterparties. At December 31, ~~2014,~~2015, Xeron had a right to offset ~~$1.6 million and $1.2 million~~$431,000 of accounts ~~receivable and accounts~~ payable ~~respectively,~~ with these two counterparties. At December 31, 2015, Xeron did not have outstanding accounts receivable with these two counterparties.

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of September 30, ~~2015~~2016 and December 31, ~~2014,~~2015, are as follows:


	Asset Derivatives					Asset Derivatives
		Fair Value As Of					Fair Value As Of
(in thousands)	Balance Sheet Location	September 30, 2015		December 31, 2014		Balance Sheet Location	September 30, 2016		December 31, 2015
Derivatives not designated as hedging instruments
Forward contracts	Mark-to-market energy assets	$	222	$	407
Forward & Future contracts						Mark-to-market energy assets	$	—	$	1
Derivatives designated as fair value hedges
Put options	Mark-to-market energy assets	64		622		Mark-to-market energy assets	—		152
Derivatives designated as cash flow hedges
Call options	Mark-to-market energy assets	—		26
Natural gas futures contracts						Mark-to-market energy assets	240		—
Propane swap agreements						Mark-to-market energy assets	237		—
Total asset derivatives		$	286	$	1,055		$	477	$	153

Liability Derivatives
Fair Value As Of
(in thousands) Balance Sheet Location September 30, 2015 December 31, 2014
Derivatives not designated as hedging instruments
Forward contracts Mark-to-market energy liabilities $ 26
$ 283
Propane swap agreements Mark-to-market energy liabilities —
735
Derivatives designated as cash flow hedges
Propane swap agreements Mark-to-market energy liabilities 128
—
Total liability derivatives $ 154
$ 1,018

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	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	September 30, 2016		December 31, 2015
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	—		—
Derivatives designated as cash flow hedges
Propane swap agreements	Mark-to-market energy liabilities	—		323
Natural gas futures contracts	Mark-to-market energy liabilities	—		109
Total liability derivatives		$	29	$	433

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


		Amount of Gain (Loss) on Derivatives:													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	2015			2014			2015			2014			(Loss) on Derivatives	2016			2015			2016			2015
Derivatives not designated as hedging instruments
Realized gain on forward contracts ⁽¹⁾	Revenue	$	187		$	54		$	393		$	1,384
Realized gain (loss) on forward contracts ⁽¹⁾														Revenue	$	(231	)	$	187		$	44		$	393
Unrealized gain (loss) on forward contracts ⁽¹⁾	Revenue	(7		)	(5		)	71			(67		)	Revenue	(2		)	(7		)	—			71
Call option	Cost of sales	—			—			—			137
Natural gas futures contracts														Cost of sales	205			—			205			—
Propane swap agreements	Cost of sales	—			—			18			—			Cost of sales	—			—			—			18
Derivatives designated as fair value hedges
Put options	Cost of sales	—			(43		)	506			(92		)
Put options ⁽²⁾	Propane Inventory	(46		)	—			(79		)	—
Put /Call options														Cost of sales	—			—			73			506
Put /Call options⁽²⁾														Propane Inventory	—			(46		)	—			(79		)
Natural gas futures contracts														Natural Gas Inventory	—			—			(233		)	—
Derivatives designated as cash flow hedges
Propane swap agreements	Other Comprehensive Loss	(126		)	(45		)	(128		)	(46		)	Cost of sales	—			—			(364		)	—
Propane swap agreements														Other Comprehensive Gain (Loss)	213			(126		)	559			(128		)
Call options	Cost of sales	—			—			(81		)	—			Cost of sales	—			—			—			(81		)
Natural gas futures contracts														Cost of sales	105			—			464			—
Natural gas futures contracts														Other Comprehensive Gain (Loss)	(123		)	—			349			—
Total		$	8		$	(39	)	$	700		$	1,316			$	167		$	8		$	1,097		$	700


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


13.	Fair Value of Financial Instruments

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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:

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, ~~2015~~2016 and December 31, ~~2014:~~2015:

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			Fair Value Measurements Using:								Fair Value Measurements Using:
As of September 30, 2015	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
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)
(in thousands)
Assets:
Investments—equity securities	$	18	$	18	$	—	$	—	$	21	$	21	$	—	$	—
Investments—guaranteed income fund	$	276	$	—	$	—	$	276	$	485	$	—	$	—	$	485
Investments—other	$	3,118	$	3,118	$	—	$	—
Investments—mutual funds and other									$	4,124	$	4,124	$	—	$	—
Mark-to-market energy assets, incl. put options and swap agreements	$	286	$	—	$	286	$	—	$	477	$	—	$	477	$	—
Liabilities:
Mark-to-market energy liabilities incl. swap agreements	$	154	$	—	$	154	$	—	$	29	$	—	$	29	$	—


			Fair Value Measurements Using:								Fair Value Measurements Using:
As of December 31, 2014	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
As of December 31, 2015									Fair Value		Quoted- Prices- in Active Markets (Level 1)		Significant- Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities									$	18	$	18	$	—	$	—
Investments—guaranteed income fund	$	287	$	—	$	—	$	287	$	279	$	—	$	—	$	279
Investments—other	$	3,391	$	3,391	$	—	$	—
Investments—mutual funds and other									$	3,347	$	3,347	$	—	$	—
Mark-to-market energy assets, incl. put/call options	$	1,055	$	—	$	1,055	$	—	$	153	$	—	$	153	$	—
Liabilities:
Mark-to-market energy liabilities, incl. swap agreements	$	1,018	$	—	$	1,018	$	—	$	433	$	—	$	433	$	—

The following valuation techniques were used to measure fair value assets in the tables above on a recurring basis as of September 30, ~~2015~~2016 and December 31, ~~2014:~~2015:

Level 1 Fair Value Measurements:

~~Investments-~~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.

Level 2 Fair Value Measurements:

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

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

Level 3 Fair Value Measurements:

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

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The following table sets forth the summary of the changes in the fair value of Level 3 investments for the nine months ended September 30, ~~2015~~2016 and ~~2014:~~2015:


	Nine Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2016			2015
(in thousands)
Beginning Balance	$	287		$	458		$	279		$	287
Purchases and adjustments	(11		)	(89		)	120			(11		)
Transfers	(3		)	(58		)	88			(3		)
Distribution							(8		)	—
Investment income	3			4			6			3
Ending Balance	$	276		$	315		$	485		$	276

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

At September 30, ~~2015~~2016, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.

Other Financial Assets and Liabilities

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

At September 30, ~~2015~~2016, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of ~~$159.9~~approximately $151.8 million. This compares to a fair value of ~~$175.8~~approximately $173.5 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, ~~2014,~~2015, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of ~~$161.5~~approximately $153.7 million, compared to the estimated fair value of ~~$180.7~~approximately $165.1 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

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14.	Long-Term Debt

Our outstanding long-term debt is shown below:


	September 30,			December 31,			September 30,			December 31,
(in thousands)	2015			2014			2016			2015
FPU secured first mortgage bonds ⁽¹⁾:
9.08% bond, due June 1, 2022	$	7,973		$	7,969		$	7,976		$	7,973
Uncollateralized senior notes:
6.64% note, due October 31, 2017	8,182			8,182			5,455			5,455
5.50% note, due October 12, 2020	12,000			12,000			10,000			10,000
5.93% note, due October 31, 2023	25,500			27,000			22,500			24,000
5.68% note, due June 30, 2026	29,000			29,000			29,000			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
Promissory notes	238			314			168			238
Capital lease obligation	5,155			6,130			3,814			4,824
Total long-term debt	165,048			167,595			155,913			158,490
Less: current maturities	(9,139		)	(9,109		)	(12,087		)	(9,151		)
Less: debt issuance costs							(301		)	(333		)
Total long-term debt, net of current maturities	$	155,909		$	158,486		$	143,525		$	149,006

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

Shelf Agreement

On October 8, 2015, we entered into a Shelf Agreement with Prudential. Under the terms of the Shelf Agreement, through October 8, 2018, we may request that Prudential purchase ~~over the next three years,~~ up to $150.0 million of our Shelf Notes at a fixed interest rate and with a maturity date not to exceed ~~twenty~~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 ~~each request for purchase with respect to a series~~confirmed our request. The proceeds received from the issuances of the Shelf Notes will ~~specify~~be used to reduce short-term borrowings under the ~~exact use~~Company’s revolving credit facility, lines of credit and/or to fund capital expenditures. The closing of the ~~proceeds.~~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 usour ability, and the ability of our subsidiaries, ~~from incurring~~to incur indebtedness, ~~and incurring~~place or permit liens and encumbrances on any of our ~~property.~~property or the property of our subsidiaries.


15.	Short-Term Borrowing

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

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

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to increase the Revolver to $200.0 million, with any increase at the sole discretion of each ~~Lender. On October 19,~~Lender. At September 30, 2016 and December 31, 2015, we ~~borrowed $25.0~~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

~~- 28~~

~~Table of Contents~~

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, ~~2014,~~2015, including the audited consolidated financial statements and notes thereto.

Safe Harbor for Forward-Looking Statements

We make statements in this Quarterly Report on Form 10-Q that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. One can typically identify forward-looking statements by the use of forward-looking words, such as “project,” “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “continue,” “potential,” “forecast” or other similar words, or future or conditional verbs such as “may,” “will,” “should,” “would” or “could.” These statements represent our intentions, plans, expectations, assumptions and beliefs about future financial performance, business strategy, projected plans and objectives of the Company. These statements are subject to many risks, uncertainties and other important factors that could cause actual results to differ materially from those expressed in the forward-looking statements. Such factors include, but are not limited to:

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

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

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

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

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

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 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 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, including any potential effects arising from terrorist attacks~~conditions;

the ability to establish and ~~any hostilities or other external factors over which we have no control;~~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;

~~the results of financing efforts, including our ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and~~ general economic ~~conditions;~~

~~the impact of~~conditions, including any potential ~~downturns in the financial markets, lower discount rates,~~effects arising from terrorist attacks and any hostilities or ~~costs associated with the Patient Protection and Affordable Care Act on the asset values and resulting higher costs and funding obligations of the Company's pension and~~ other ~~postretirement benefit plans;~~

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

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

~~the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;~~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;~~plans, regulatory or other limitations imposed as a result of a merger, acquisition or ~~divestiture;~~divestiture, and the success of the business following a merger, acquisition or divestiture;

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

risks related to ~~establish and maintain new key supply sources;~~cyber-attacks that could disrupt our business operations or result in failure of information technology systems.

~~the effect~~

Table of ~~spot, forward and future market prices on our distribution, wholesale marketing and energy trading businesses;~~Contents

the effect of competition on our businesses;

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

the timing of regulatory and other governmental approvals, authorizations, and permits; and

the loss of customers due to ~~construct facilities at or below estimated costs; and~~a government-mandated sale of our utility distribution facilities.

~~risks related to cyber-attack or failure of information technology systems.~~

~~- 29~~

~~Table of Contents~~

Introduction

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

Our strategy is focused on growing earnings from a stable utility foundation and investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. The key elements of this strategy include:

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

expanding the regulated energy distribution and transmission businesses into new geographic areas and providing new services in our current service territories;

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

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

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

pursuing and entering new unregulated energy markets and business lines that will complement our existing strategy and operating units;

enhancing marketing channels to attract new customers;

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

engaging our customers through a distinctive service excellence initiative;

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

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

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

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

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

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

creating and maintaining a diversified customer base, energy portfolio and utility foundation.

The following discussions and those elsewhere in the document on operating income and segment results include the use of the term “gross margin.” “Gross ~~margin~~margin” is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased fuel cost offor natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities. Gross margin should not be considered an alternative to operating income or net income, which isare determined in accordance with GAAP. ~~We believe~~Chesapeake Utilities believes that gross margin, although a non-GAAP measure, is ~~useful~~meaningful in our regulated operations because the cost of natural gas and ~~meaningful~~electricity are passed through to ~~investors as a basis for making investment decisions. It~~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 provides investors with information that demonstrates the profitability achieved by usChesapeake Utilities under ~~our~~its allowed rates for regulated ~~energy~~ operations and under ~~our~~its competitive pricing structure for non-regulated segments. ~~Our~~Chesapeake Utilities' management uses gross margin in measuring ~~our~~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.

~~As a result of the sale of BravePoint in October 2014, we no longer report the Other segment.~~

~~- 30~~

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Results of Operations for the Three and Nine Months ended September 30, ~~2015~~2016

Overview and Highlights

Our net income for the quarter ended September 30, ~~2015~~2016 was ~~$5.1~~$4.4 million, or ~~$0.33~~$0.29 per share. This represents ~~an increase~~a decrease of ~~$1.9 million,~~$703,000, or ~~$0.11~~$0.04 per share, compared to the net income of ~~$3.2~~$5.1 million, or ~~$0.22~~$0.33 per share, as reported for the same quarter in ~~2014. Increases in operating~~2015. Operating income ~~from both the Regulated Energy and Unregulated Energy segments were the key drivers in our net income growth.~~

Three Months Ended
September 30, Increase
2015 2014 (decrease)
(in thousands except per share)
Business Segment:
Regulated Energy segment $ 11,828
$ 9,202
$ 2,626
Unregulated Energy segment (1,022 ) (1,972 ) 950
Other businesses and eliminations 103
562
(459 )
Operating Income $ 10,909
$ 7,792
3,117
Other Income (Loss), net of Other Expenses 36
(32 ) 68
Interest Charges 2,492
2,495
(3 )
Pre-tax Income 8,453
5,265
3,188
Income Taxes 3,334
$ 2,085
1,249
Net Income $ 5,119
$ 3,180
$ 1,939
Earnings Per Share of Common Stock
Basic $ 0.34
$ 0.22
$ 0.12
Diluted $ 0.33
$ 0.22
$ 0.11

~~- 31~~

~~Table of Contents~~

~~Key variances included:~~

(in thousands, except per share)
Pre-tax
Income

Net
Income

Earnings
Per Share
Third Quarter of 2014 Reported Results $ 5,265
$ 3,180
$ 0.22
Adjusting for Unusual Items:
Absence of BravePoint, which was sold in October 2014 (454 ) (274 ) (0.02 )
(454 ) (274 ) (0.02 )
Increased (Decreased) Gross Margins:
Contribution from Aspire Energy of Ohio 2,037
1,230
0.08
Service expansions (See Major Projects and Initiatives table) 1,708
1,031
0.07
GRIP 1,144
691
0.05
Higher retail propane margins 1,029
621
0.04
Natural gas growth (excluding service expansions) 895
540
0.04
FPU electric base rate increase 673
406
0.03
Natural gas marketing 479
289
0.02
7,965
4,808
0.33
Increased Other Operating Expenses:
     Expenses from Aspire Energy of Ohio (1,933 ) (1,167 ) (0.08 )
     Higher payroll and benefits costs (1,098 ) (663 ) (0.05 )
Higher depreciation, asset removal and property tax costs due to recent capital investments (647 ) (391 ) (0.03 )
     Increased accrual for incentive compensation (314 ) (190 ) (0.01 )
(3,992 ) (2,411 ) (0.17 )
Interest Charges 3
2
—
Net Other Changes ⁽¹⁾
(334 ) (186 ) (0.03 )
Third Quarter of 2015 Reported Results $ 8,453
$ 5,119
$ 0.33

⁽¹⁾ The earnings per share impact net of other changes shown above includes $(0.01) of dilution from the issuance of 592,970 shares of our common stock in conjunction with the merger of Gatherco into Aspire Energy of Ohio on April 1, 2015.

~~- 32~~

~~Table of Contents~~

~~Our net income~~decreased $753,000 for the ~~nine~~three months ended September 30, ~~2015 was $32.5~~2016. Gross margin increased by $4.7 million, ~~or $2.16 per share. This represents an~~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 ~~$6.5 million, or $0.38 per share, compared to net income of $26.0 million, or $1.78 per share, as reported for~~our businesses are largely recognized equally across the ~~same period~~year, while the margin from this growth is more concentrated in ~~2014. Increases in operating income from both~~ the ~~Regulated Energy~~heating season during the fourth and Unregulated Energy segments were the key drivers in our net income growth. Also included in our results for the nine months ended September 30, 2015 was a $902,000 after-tax gain ($1.5 million in operating income), or $0.06 per share, related to cash received from a settlement with a vendor regarding a customer billing system implementation.first quarters.


	Nine Months Ended								Three Months Ended
	September 30,					Increase			September 30,						Increase
	2015			2014		(decrease)			2016			2015			(decrease)
(in thousands except per share)
Business Segment:
Regulated Energy segment	$	47,616		$	41,004	$	6,612		$	13,115		$	11,828		$	1,287
Unregulated Energy segment	13,666			8,843		4,823			(3,080		)	(1,022		)	(2,058		)
Other businesses and eliminations	305			25		280			121			103			18
Operating Income	61,587			49,872		11,715			$	10,156		$	10,909		$	(753	)
Other Income (Loss), net of Other Expenses	(3		)	380		(383		)
Interest Charges	7,425			6,954		471
Other (expense) income, net									(28		)	36			(64		)
Interest charges									2,722			2,492			230
Pre-tax Income	54,159			43,298		10,861			7,406			8,453			(1,047		)
Income Taxes	21,638			17,303		4,335
Income taxes									2,990			3,334			(344		)
Net Income	$	32,521		$	25,995	$	6,526		$	4,416		$	5,119		$	(703	)
Earnings Per Share of Common Stock
Basic	$	2.16		$	1.79	$	0.37		$	0.29		$	0.34		$	(0.05	)
Diluted	$	2.16		$	1.78	$	0.38		$	0.29		$	0.33		$	(0.04	)

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Key variances, between the third quarter of 2015 and the third quarter of 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

*See the Major Projects and Initiatives table.

~~- 33~~Table of Contents

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.

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~~Key variances included:~~

(in thousands, except per share) Pre-tax
Income Net
Income Earnings
Per Share
Nine months ended September 30, 2014 Reported Results $ 43,298
$ 25,995
$ 1.78
Adjusting for Unusual Items:
Gain from a customer billing system settlement 1,500
902
0.06
Gain on sale of business, recorded in 2014 (397 ) (238 ) (0.02 )
Absence of BravePoint, which was sold in October 2014 303
182
0.01
1,406
846
0.05
Increased (Decreased) Gross Margins:
Higher retail propane margins 6,742
4,048
0.28
Service expansions (See Major Projects and Initiatives table) 4,085
2,453
0.17
Contribution from Aspire Energy of Ohio 3,661
2,198
0.15
Natural gas growth (excluding service expansions) 3,149
1,891
0.13
GRIP 3,070
1,843
0.13
FPU electric base rate increase 2,366
1,421
0.10
Propane wholesale marketing (854 ) (513 ) (0.04 )
22,219
13,341
0.92
Increased Other Operating Expenses:
Expenses from Aspire Energy of Ohio (3,828 ) (2,298 ) (0.16 )
Higher payroll and benefits costs (2,762 ) (1,658 ) (0.11 )
Higher depreciation, asset removal costs and property tax costs due to recent capital investments (1,700 ) (1,021 ) (0.07 )
Increased accruals for incentive compensation (1,150 ) (690 ) (0.05 )
Costs associated with a customer billing system settlement and other transactions (1,081 ) (649 ) (0.04 )
Higher facility maintenance (729 ) (438 ) (0.03 )
Higher service contractor and other consulting costs (694 ) (417 ) (0.03 )
Higher amortization expense (463 ) (278 ) (0.02 )
(12,407 ) (7,449 ) (0.51 )
Interest Charges (471 ) (283 ) (0.02 )
Net Other Changes ⁽¹⁾
114
71
(0.06 )
Nine months ended September 30, 2015 Reported Results $ 54,159
$ 32,521
$ 2.16

⁽¹⁾ The earnings per share impact net of other changes shown above includes $(0.06) of dilution from the issuance of 592,970 shares of our common stock in conjunction with the merger of Gatherco into Aspire Energy of Ohio on April 1, 2015.

~~- 34~~

~~Table of Contents~~

Summary of Key Factors

Major Projects and Initiatives

The following table summarizes gross margin for our ~~existing and future~~ major projects and initiatives 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

⁽¹⁾This represents gross margin for the System Reliability and 2017 Expansion projects.

Major Projects and Initiatives Completed Since 2014

The following table summarizes gross margin generated by our major projects and initiatives 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, 2014 Estimate for
2015 2014 2015 2014 Margin 2015 2016 2017
Existing major projects and initiatives $ 7,490
$ 1,928
$ 17,030
$ 3,848
$ 7,114
$ 25,510
$ 33,438
$ 35,295
Future major projects and initiatives —
—
—
—
—
—
11,200
17,450
$ 7,490
$ 1,928
$ 17,030
$ 3,848
$ 7,114
$ 25,510
$ 44,638
$ 52,745

~~Existing Major Projects and Initiatives~~

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


					Gross Margin for the Period ⁽¹⁾																	Gross Margin for the Period
	Three Months Ended							Nine Months Ended						Total								Three Months Ended							Nine Months Ended							Total
	September 30,							September 30,						2014		Estimate for						September 30,							September 30,							2015		Estimate for
	2015		2014		Variance			2015		2014		Variance		Margin		2015		2016		2017		2016		2015		Variance			2016		2015		Variance			Margin		2016		2017		2018
Acquisition:
Aspire Energy of Ohio (formerly Gatherco) ⁽²⁾	$	2,037	$	—	$	2,037		$	3,661	$	—	$	3,661	$	—	$	7,673	$	13,000	$	13,000
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	$	507	$	657	$	(150	)	$	1,998	$	1,256	$	742	$	2,026	$	2,505	$	2,029	$	1,561	$	664	$	507	$	157		$	2,040	$	1,998	$	42		$	2,682	$	2,910	$	2,275	$	714
Kent County, Delaware ⁽³⁾	1,055		—		1,055			1,453		—		1,453		—		1,663		—		—		2,416		1,055		1,361			6,231		1,453		4,778			2,270		7,982		1,377		—
Total short-term Contracts	1,562		657		905			3,451		1,256		2,195		2,026		4,168		2,029		1,561
Long-term Contracts
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	463		—		463			1,389		—		1,389		463		1,844		1,815		1,789		455		463		(8		)	1,366		1,389		(23		)	1,844		1,815		7,629		7,605
Polk County, Florida	340		—		340			501		—		501		—		908		1,627		1,627		407		340		67			1,221		501		720			908		1,627		1,627		1,627
Total long-term contracts	$	803	$	—	$	803		$	1,890	$	—	$	1,890	$	463	$	2,752	$	3,442	$	3,416	$	862	$	803	$	59		$	2,587	$	1,890	$	697		$	2,752	$	3,442	$	9,256	$	9,232
Total Expansions & Contracts	$	2,365	$	657	$	1,708		$	5,341	$	1,256	$	4,085	$	2,489	$	6,920	$	5,471	$	4,977	$	3,942	$	2,365	$	1,577		$	10,858	$	5,341	$	5,517		$	7,704	$	14,334	$	12,908	$	9,946
Florida GRIP	$	2,067	$	923	$	1,144		$	5,314	$	2,244	$	3,070	$	3,356	$	7,355	$	11,405	$	13,756	$	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	$	348	$	673		$	2,714	$	348	$	2,366	$	1,269	$	3,562	$	3,562	$	3,562	$	1,021	$	1,021	$	—		$	2,714	$	2,714	$	—		$	3,734	$	3,562	$	3,562	$	3,562
Total Major Projects and Initiatives	$	7,490	$	1,928	$	5,562		$	17,030	$	3,848	$	13,182	$	7,114	$	25,510	$	33,438	$	35,295
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

⁽¹⁾ ~~Gross~~

Aspire Energy

Aspire Energy's gross margin ~~of $4.7 million and $16.5 million~~decreased by $407,000 for the three ~~and nine~~ months ended September 30, ~~2014, respectively,~~2016, partly due to increased deliveries and $21.8 million for the year ended December 31, 2014, related to projects initiated prior to 2014. These projects were previously disclosed and are excluded from this table as they no longer result in period-over-period variances.

⁽²⁾ ~~During the three and nine months ended September 30, 2015, we incurred $1.9 million and $3.8 million, respectively, in other operating expenses related to~~imbalance positions that favorably impacted Aspire Energy ~~of Ohio's operation. We expect to incur a total of $6.0 million in other operating expenses in 2015.~~

⁽³⁾ The gross margin is attributable to interruptible service Eastern Shore provided to an industrial customer beginning in April 2015. The interruptible service will be replaced by a 20-year OPT ≤ 90 Service beginning in the third quarter of ~~2016.~~2015, which are non-recurring. Lower margin associated with system volumes and imbalance positions in third quarter of 2016 also contributed to the decrease.

~~- 35~~

Table of Contents

~~Gatherco Acquisition~~

On April 1, 2015, we completed the merger with Gatherco, pursuant to which Gatherco merged with and into Aspire Energy of Ohio. Aspire Energy of Ohio provides unregulated natural gas midstream services including natural gas gathering services and natural gas liquid processing services to over 300 producers through 16 gathering systems and over 2,000 miles of pipelines in Central and Eastern Ohio. Aspire Energy of Ohio also supplies natural gas to Columbia Gas of Ohio, regional marketers of natural gas, and over 6,000 customers in Ohio through the Consumers Gas Cooperative, an independent entity, which Aspire Energy of Ohio manages under an operating agreement.

Aspire Energy of Ohio generated $2.0 million in additional gross margin and incurred $1.9 million in other operating expenses for the three months ended September 30, 2015. For the six months following the merger through September 30, 2015, we generated $3.7 million of gross margin and incurred $3.8 million of other operating expenses. The results of Aspire Energy of Ohio are projected to have a minimal impact on our earnings per share in 2015, since the merger was completed after the first quarter, which has historically produced a significant portion of Gatherco's annual earnings. This acquisition is expected to be accretive to our earnings in the first full year of operations, which will include the first quarter of 2016.

~~Service Expansions~~

During 2014, Eastern Shore, executed a one-year contract with an industrial customer in New Castle County, Delaware to provide 50,000 Dts/d of additional transmission service from April 2014 to April 2015. This contract was subsequently amended to provide 55,580 Dts/d of transmission service at a lower reservation rate through August 2020. The net impact of the contract resulted in a gross margin decline of $150,000 for the quarter ended September 30, 2015. For the nine months ended September 30, ~~2015, the extension of the contract~~2016, Aspire Energy generated $4.5 million in additional gross margin ~~of $509,000, net of the impact of the lower rate,~~ compared to the same period in ~~2014, and will generate additional~~2015. Aspire Energy's gross margin ~~of $334,000~~ for ~~2015 compared to 2014.~~

~~In December 2014, Eastern Shore executed another short-term contract with~~ the same ~~customer~~period in ~~New Castle County, Delaware~~2015 was lower due in part to ~~provide an additional 10,000 Dts/d~~the fact that the period included only six months of ~~OPT ≤ 90 Service from December 2014 to March~~results commencing on April 1, 2015. ~~This short-term contract~~Aspire Energy also generated additional gross margin primarily as a result of ~~$233,000 for~~pricing amendments to long-term gas sales agreements, additional management fees and the ~~nine months ended September 30, 2015.~~

~~On October 1, 2014, Eastern Shore commenced a new lateral service~~optimization of gathering system receipts and deliveries. As projected, this merger was accretive to an industrial customer facility in Kent County, Delaware. This service commenced after construction of new facilities, including approximately 5.5 miles of pipeline lateral and metering facilities extending from Eastern Shore's mainline to the new industrial customer facility. This service generated $463,000 and $1.4 million of gross margin for the three and nine months ended September 30, 2015, respectively. On an annual basis, we expect this service to generate $1.8 million of gross margin in 2015 and annual gross margin of approximately $1.2 million to $1.8 million during the 37-year service period.

In April 2015, Eastern Shore commenced interruptible service to the same industrial customer in Kent County, Delaware and generated additional gross margin of $1.1 million and $1.5 million for the three and nine months ended September 30, 2015, respectively. The interruptible service is expected to generate $1.7 million of gross margin in 2015, and it is expected to be replaced by a 20-year OPT ≤ 90 Service beginningearnings per share in the ~~third quarter~~first full year of ~~2016.~~operations.

Service Expansions

On January 16, 2015, the Florida PSC approved a firm transportation agreement between Peninsula Pipeline and our Florida natural gas distribution division. ~~Under~~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, generating $340,000~~2015. This new service generated $67,000 and ~~$501,000~~$720,000 of additional gross margin for the three and nine months ended September 30, ~~2015, respectively. This~~2016, respectively, compared to the same periods in 2015. When all phases of this service ~~is expected to~~are complete, this expansion will generate an estimated annual gross margin of ~~$908,000~~$1.6 million.

In April 2015, Eastern Shore commenced interruptible service to an electric power generator in Kent County, Delaware. The interruptible service concluded in December 2015 and was replaced by a short-term OPT ≤ 90 Service, which generated additional gross margin of $901,000 and $4.3 million during the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015. The short-term OPT ≤ 90 Service is expected to be replaced by a 20-year contract for OPT ≤ 90 Service in the first quarter of 2017.

On 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. In December 2015, the FERC authorized Eastern Shore to proceed with this project, which was completed and placed in service in March 2016. Approximately 85 percent of the increased capacity has been subscribed on a short-term firm service basis. This service generated an additional gross margin of $617,000 and $744,000 for the three and nine months ended September 30, 2016, respectively, compared to the same periods in 2015, and ~~once completed, all phases of this service will~~is expected to generate ~~an estimated annualized~~approximately $1.4 million in additional gross margin ~~of $1.6 million.~~for the year. The remaining capacity is available for firm or interruptible service.

GRIP

GRIP is a natural gas pipe replacement program approved by the Florida PSC, designed to expedite the replacement of qualifying distribution mains and services (any material other than coated steel or plastic) to enhance reliability and integrity of ~~our~~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, ~~our Florida natural gas distribution operations~~we have invested ~~$69.6~~$97.3 million to replace ~~153~~209 miles of qualifying distribution mains, ~~$25.5~~including $20.4 million ~~of which was invested~~ during the first nine months of ~~2015.~~2016. We expect to invest an additional ~~$3.4 million~~$650,000 in this program ~~through~~during the ~~end~~remainder of ~~2015.~~2016. The increased investment in GRIP generated additional gross margin of ~~$1.1 million~~$920,000 and $3.1 million for the three and nine months ended September 30, ~~2015,~~2016, respectively, compared to the same periods in ~~2014.~~2015.

Eight Flags

~~- 36~~

~~Table~~In June 2016, Eight Flags, completed construction of ~~Contents~~

~~Florida Electric Rate Case~~

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 of base load power and includes a heat recovery steam generator capable of providing approximately 75,000 pounds per hour of residual steam. On ~~September 15, 2014,~~June 13, 2016, Eight Flags began selling power generated from the ~~Florida PSC approved~~CHP plant to FPU, our wholly-owned subsidiary, pursuant to a ~~settlement~~20-year power purchase agreement ~~between~~for distribution to its retail electric customers. On July 1, 2016, it also started selling steam to an industrial customer pursuant to a separate 20-year contract. The CHP plant is powered by natural gas transported by FPU through its distribution system. Eight Flags and ~~the Florida Office~~other affiliates of ~~Public Counsel in FPU's base rate case filing for its electric operation, which included, among other things, an increase in FPU's annual revenue requirement of approximately $3.8~~Chesapeake Utilities generated $2.0 million and a 10.25 percent rate of return on common equity. The new rates became effective for all meter reads on or after November 1, 2014. Previously, the Florida PSC approved interim rate relief, effective for meter readings on or after August 10, 2014. The higher base rates in FPU's electric operation generated $673,000 and $2.4$2.6 million in additional gross margin as a result of these new services, for the three and nine months ended September 30, ~~2015, respectively.~~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 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.

~~Future~~

Table of Contents

Major Projects and Initiatives Underway

White Oak Mainline Expansion Project: In ~~December~~August 2014, Eastern Shore entered into a precedent agreement with an ~~industrial customer~~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 ~~new~~ 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 ~~7.2~~5.4 miles of 16-inch pipeline looping and 3,550 horsepower of new compression in Delaware to provide this service. ~~The estimated cost of these new facilities is approximately $30.0 million. Eastern Shore anticipates service to commence in the third quarter of 2016, following construction of the new facilities.~~ As previously discussed, during the three and nine months ended September 30, 2016, compared to the same periods in 2015, we generated ~~$1.1 million~~$901,000 and ~~$1.5~~$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 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 approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposes to reinforce critical points on its pipeline system. The total project will benefit all of Eastern Shore’s customers by modifying the pipeline system to respond to severe operational conditions experienced during actual winter peak ~~days in 2014 and 2015.~~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 by December 2015.~~authorization. This project ~~is expected to be in service by late third quarter of 2016 and~~ will be included in Eastern Shore's upcoming 2017 rate case filing. ~~The estimated cost of the project is $32.1 million.~~ The estimated annual gross margin associated with this project, assuming recovery in the 2017 rate case, ~~filing,~~ is approximately $4.5 million. 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. Construction of the project is underway.

~~TETLP Capacity~~2017 Expansion Project:On ~~October 13, 2015,~~May 12, 2016, Eastern Shore submitted ~~an application~~a request to the FERC to ~~make certain measurement and related improvements at~~initiate the FERC's pre-filing procedures for its ~~TETLP interconnect facilities which will enable~~proposed 2017 Expansion Project. Since the time the pre-filing was initiated, Eastern Shore ~~to increase~~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 ~~receipts from TETLP by 53,000 Dts/day, for a total~~transportation deliverability on Eastern Shore’s pipeline system. To provide this additional capacity, the project’s final facilities will consist of ~~160,000 Dts/d.~~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 expects the~~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 project ~~to be approved by the end of the year and in service by the end of February 2016. On a short-term basis, we anticipate that Eastern Shore~~ will generate approximately ~~$2.1~~$15.7 million in ~~additional gross margin.~~

~~Eight Flags:~~ ~~Eight Flags, one of our unregulated energy subsidiaries, is engaged in~~ the development and construction of a CHP plant in Nassau County, Florida. This CHP plant, which will consist of a natural-gas-fired turbine and associated electric generator, is designed to generate approximately 20 megawatts of base load power and will include a heat recovery system generator capable of providing approximately 75,000 pounds per hour of unfired steam. Eight Flags will sellfirst full year after the power generated from the CHP plant to FPU for distribution to its retail electric customers pursuant to a 20-year power purchase agreement. It will also sell the steam to an industrial customer pursuant to a separate 20-year contract. FPU will transport natural gas through its distribution system to Eight Flags’ CHP plant, which will produce power and steam. On a consolidated basis, this project is expected to generate approximately $7.3 million in annual gross margin, which could fluctuate based upon various factors, including, but not limited to, the quantity of steam delivered and the CHP plant’s hours of operations. Eight Flags' CHP plant is expected to be operational at the beginning of the third quarter of 2016. Our total projected investment, by Eight Flags and our affiliates, to construct the CHP plant and associated facilities is approximately $40.0 million.new transportation services go into effect.

~~- 37~~

~~Table of Contents~~

~~The following table summarizes estimated in-service dates and gross margin for the foregoing projects (dollars in thousands):~~

Estimate for
Project Estimated In-Service Date Annualized
Margin 2016 2017
White Oak Mainline Expansion Project in Kent County, Delaware Third quarter of 2016 $ 5,400
$ 5,400
$ 5,800
Eastern Shore System Reliability Project Late third quarter of 2016 4,500
—
2,250
Eastern Shore TETLP Capacity Expansion Project February 2016 2,100
2,100
2,100
Eight Flags CHP plant in Nassau County, Florida Early third quarter of 2016 7,300
3,700
7,300
$ 19,300
$ 11,200
$ 17,450

Other factors ~~contributing to~~influencing gross margin ~~increase~~

Weather and Consumption

~~Weather~~Although weather was not a significant factor in the ~~gross margin increase for~~second and third quarters, warmer temperatures during the ~~quarter~~first three months of 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 nine months ended September 30, ~~2015,~~2016, reduced gross margin by $7.5 million compared to the same period in 2014. Weather was also not a significant factor in the gross margin increase for the nine months ended September 30, 2015, compared to the same period in 2014, because the first quarter of 2015 and 2014 were both significantly colder than normal (10-year average weather) on the Delmarva Peninsula.2015. The following tables summarize the ~~heating degree-day ("HDD")~~HDD and ~~cooling degree-day ("CDD")~~CDD information for the three and nine months ended September 30, ~~2015~~2016 and ~~2014 and the gross margin variance~~2015 resulting from weather fluctuations in those periods.

Table of Contents

HDD and CDD Information


	Three Months Ended					Nine Months Ended						Three Months Ended						Nine Months Ended
	September 30,					September 30,						September 30,						September 30,
	2015		2014	Variance		2015		2014		Variance		2016		2015		Variance		2016		2015		Variance
Delmarva
Actual HDD	41		89	(48	)	3,249		3,262		(13	)	11		41		(30	)	2,590		3,249		(659	)
10-Year Average HDD ("Normal")	65		61	4		2,908		2,893		15
Variance from Normal	(24	)	28			341		369
10-Year Average HDD ("Delmarva Normal")												65		65		—		2,919		2,908		11
Variance from Delmarva Normal												(54	)	(24	)			(329	)	341
Florida
Actual HDD	—		—	—		501		574		(73	)	—		—		—		646		501		145
10-Year Average HDD ("Normal")	—		—	—		557		555		2
Variance from Normal	—		—			(56	)	19
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	1,591		1,528	63		2,827		2,498		329		1,523		1,591		(68	)	2,737		2,827		(90	)
10-Year Average CDD ("Normal")	1,524		1,519	5		2,506		2,501		5
Variance from Normal	67		9			321		(3	)
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

~~- 38~~

~~Table of Contents~~
⁽¹⁾

~~Gross Margin Variance attributed to Weather~~

(in thousands) Q3 2015 vs. Q3 2014 Q3 2015 vs. Normal Q3 2014 vs. Normal YTD 2015 vs. YTD 2014 YTD 2015 vs. Normal YTD 2014 vs. Normal
Delmarva
Regulated Energy segment $ (157 ) $ (31 ) $ 167
$ (87 ) $ 872
$ 803
Unregulated Energy segment (8 ) 27
(13 ) 20
1,005
1,037
Florida
Regulated Energy segment (232 ) (40 ) 38
134
(239 ) (284 )
Unregulated Energy segment —
—
—
(10 ) 122
81
Total $ (397 ) $ (44 ) $ 192
$ 57
$ 1,760
$ 1,637
HDD for Ohio is presented from April 1, 2015 through September 30, 2015.

Propane prices

~~Higher~~Lower retail propane margins per gallon ~~generated $597,000 and $5.7 million in additional~~on the Delmarva Peninsula decreased gross margin by ~~the Delmarva propane distribution operation~~$344,000 and $2.2 million, for the three and nine months ended September 30, ~~2015,~~2016, respectively, compared to the same periods in ~~2014. A large decline in~~2015. Margins per retail gallon returned to more normal levels, driven principally by lower propane prices ~~in the first quarter~~and local market conditions. The level of 2015 had a significant impact on the amount of revenue and cost of sales associated with our propane distribution operations. Based on the Mont Belvieu wholesale propane index, propane prices in the first quarter of 2015 were approximately 59 percent lower than prices in the same quarter in 2014. As a result of favorable supply management and hedging activities, the Delmarva propane distribution operation experienced a decrease in its average propane cost in addition to the decrease in wholesale prices, which generated increased retail margins per ~~gallon. During~~gallon generated during 2015 were not expected to be sustained over the ~~second and third quarters of 2015, wholesale propane prices~~long term; accordingly, we have continued to ~~remain significantly lower than prices~~assume more normal levels of margins in ~~the same quarters of 2014.~~our long-term financial plans and forecasts.

In Florida, ~~higher~~ retail propane margins per gallon, ~~as a result~~generated $70,000 of ~~local market conditions generated $432,000~~lower margin and ~~$1.1 million~~$61,000 of additional gross margin for the three and nine months ended September 30, ~~2015, respectively.~~2016, respectively, compared to the same periods in 2015.

These market conditions, which are influenced by competition with other propane suppliers as well as the availability and price of alternative energy sources, may fluctuate based on changes in demand, supply and other energy commodity prices. ~~The level of retail margins per gallon generated during the first nine months of 2015 is not typical and, therefore, is not included in our long-term financial plans or forecasts.~~

Xeron, which benefits from wholesale price volatility by entering into trading transactions, generated additional gross margin of $131,000 for the three months ended September 30, 2015. On a year-to-date basis, Xeron experienced a gross margin decrease of $854,000, compared to the same period in 2014, due to lower wholesale price volatility.

Other Natural Gas Growth - Distribution Operations

In addition to service expansions, the natural gas distribution operations on the Delmarva Peninsula generated ~~$250,000~~$253,000 and $1.1 million in additional gross margin for the three and nine months ended September 30, ~~2015,~~2016, respectively, compared to the same periods in ~~2014,~~2015, due to an increase in residential, commercial and industrial customers served. The average number of residential customers on the Delmarva Peninsula during the three and nine months ended September 30, 2016, increased by ~~2.7~~4.2 percent ~~in the third quarter of 2015,~~and 3.5 percent, respectively, compared to the same ~~quarter~~periods in ~~2014.~~2015. The natural gas distribution operations in Florida generated ~~$443,000~~$350,000 and ~~$1.4~~$1.1 million in additional gross margin for the three and nine months ended September 30, ~~2015,~~2016, respectively, compared to the same periods in ~~2014,~~2015, due primarily to an increase in commercial and industrial customers in Florida.

~~Capital Expenditures~~

Table of Contents

Delaware Division rate case

On December 21, 2015, our Delaware Division filed an application with the Delaware PSC for a base rate increase and certain other changes to its tariff. We ~~have~~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. We expect a decision on the application during 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, 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 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 ~~capital expenditures forecast~~application) annualized for ~~2015 to be in the range of $130.0 million to $160.0 million, excluding amounts expended to acquire Gatherco. This range represents~~usage on and after August 1, 2016 ("Phase II"). These revised interim rates represent a ~~significant~~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 ~~average level of annual capital expenditures~~final decision is expected during the ~~past three years, which equaled $94.8 million. The updated capital~~first quarter of 2017, we cannot predict the revenue requirement the Delaware PSC will ultimately authorize or forecast ~~reflects a shift in~~ the timing of ~~certain capital expenditures from 2015 to 2016. Major projects currently underway, such as~~a final decision. Consequently, we will not recognize the Eight Flags' CHP plant and associated facilities, anticipated new facilities to serve an industrial customer in Kent County, Delaware under the OPT ≤ 90 Service, and additional GRIP investments projected for 2015, account for approximately $99.0 millionimpact of the ~~capital expenditures forecast for 2015. In addition, Eastern Shore is seeking FERC~~potential additional revenue related to the Phase II rate increase until the Delaware PSC issues its approval ofin a ~~$32.1 million project to construct facilities that will improve the overall reliability and flexibility of its pipeline system. Capital expenditures are subject to continuous review and~~final ruling.

~~- 39~~

Table of Contents

modification by our management and Board of Directors, and some anticipated capital expenditures are subject to approval by the applicable regulators. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, changes in customer expectations or service needs, 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.

In order to fund the 2015 capital expenditures currently budgeted, we expect to increase the level of borrowings during the remainder of 2015 to supplement cash provided by operating activities. Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent, and we have maintained a ratio of equity to total capitalization, including short-term borrowings, between 54 and 60 percent during the past three years. If we increase the level of debt during 2015 and 2016 to fund the budgeted capital expenditures, our ratio of equity to total capitalization, including short-term borrowings, will temporarily decline.

On October 8, 2015, we entered into the Revolver with the Lenders, 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 entered into a long-term private placement Shelf Agreement also for $150.0 million. The exact timing of any long-term debt or equity issuance(s) will be based on market conditions. In addition, for larger capital projects, we will seek to align, as much as feasible, any such long-term debt or equity issuance(s) with the earnings associated with commencement of service on such projects. For additional information on the Shelf Agreement and Revolver, see Note 14, ~~Long-Term Debt, and Note 15,~~ ~~Short-Term Borrowing~~ ~~in the Condensed Consolidated Financial Statements.~~

~~- 40~~

~~Table of Contents~~

Regulated Energy Segment

For the quarter ended September 30, ~~2015~~2016 compared to the quarter ended September 30, ~~2014~~2015


	Three Months Ended						Three Months Ended
	September 30,				Increase		September 30,				Increase
	2015		2014		(decrease)		2016		2015		(decrease)
(in thousands)
Revenue	$	63,796	$	59,356	$	4,440	$	70,019	$	63,796	$	6,223
Cost of sales	23,161		23,040		121		24,644		23,161		1,483
Gross margin	40,635		36,316		4,319		45,375		40,635		4,740
Operations & maintenance	19,882		18,906		976		22,912		19,882		3,030
Depreciation & amortization	6,129		5,633		496		6,346		6,129		217
Other taxes	2,796		2,575		221		3,002		2,796		206
Other operating expenses	28,807		27,114		1,693		32,260		28,807		3,453
Operating income	$	11,828	$	9,202	$	2,626	$	13,115	$	11,828	$	1,287

Operating income for the Regulated Energy segment for the quarter ended September 30, ~~2015~~2016 was ~~$11.8~~$13.1 million,, an increase of ~~$2.6~~$1.3 million,, or ~~28.5~~10.9 percent,, compared to the same quarter in ~~2014.~~2015. The increased operating income ~~reflects additional~~was due primarily to an increase in gross margin of ~~$4.3~~$4.7 million,~~, which was~~ partially offset by ~~a net~~an increase in ~~other~~ operating expenses of ~~$1.7 million to support growth.~~$3.4 million.

Gross Margin

Items contributing to the quarter-over-quarter increase of ~~$4.3~~$4.7 million,, or ~~11.9~~11.7 percent,, in gross margin are listed in the following table:


(in thousands)
Gross margin for the three months ended September 30, 2014	$	36,316
Factors contributing to the gross margin increase for the three months ended September 30, 2015:
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	1,708			1,577
Natural gas growth (excluding service expansions)				943
Additional revenue from GRIP in Florida	1,144			920
Natural gas distribution customer growth	693
FPU electric base rate increase	673
Growth in natural gas transmission services (other than service expansions)	203
Implementation of Delaware Division interim rates				469
Margin from service to Eight Flags				464
Sandpiper SIR				226
Other	(101		)	141
Gross margin for the three months ended September 30, 2015	$	40,635
Gross margin for the three months ended September 30, 2016				$	45,375

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:

$~~1.1~~901,000 attributable to $1.9 million from ~~interruptible service~~the short-term OPT ≤ 90 Service that commenced in ~~April~~December 2015 to an ~~industrial customer~~electric power generator in Kent County, ~~Delaware. The~~Delaware and offset by a $1.0 million decrease in gross margin from the conclusion of the interruptible service ~~is expected to generate $1.7 million of gross margin~~Eastern Shore provided this customer in ~~2015, and it~~2015. The short-term OPT ≤ 90 Service is expected to be replaced by a 20-year OPT ≤ 90 Service ~~beginning~~ in the ~~third~~first quarter of ~~2016.~~2017.

$~~463,000~~617,000 from ~~a new~~short-term firm service ~~to the same industrial customer in Kent County, Delaware,~~ that commenced ~~on October 1, 2014, upon completion of new facilities, including approximately 5.5 miles of pipeline lateral~~in March 2016, following certain measurement and ~~metering facilities extending from~~related improvements to Eastern Shore's ~~mainline to the industrial customer facility.~~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 ~~is expected to~~will generate ~~$1.8~~approximately $1.4 million ofin additional gross margin in ~~2015.~~2016. The remaining capacity is available for firm or interruptible service.

~~$340,000 from natural gas transmission service as part of the major expansion initiative in Polk County, Florida.~~

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~~These increases were partially offset by a decrease in~~Natural Gas Growth (excluding service expansions)

Increased gross margin of $150,000 due primarily to a decrease in the reservation rate for a contract with an existing industrial customer in New Castle County, Delaware to provide 50,000 Dts/d of service from April 2014 to April 2015. This contract was subsequently amended to provide 55,580 Dts/d of service through August 2020 at a lower reservation rate. The increased Dts/d to be transported under the contract, net of the lower reservation rate, is expected to generate $2.3 million of gross margin in 2015, compared to $1.9 million of gross margin generated in 2014.

~~Additional Revenue from GRIP in Florida~~

~~Additional GRIP investments during 2014 and 2015 by our Florida natural gas distribution operations generated $1.1 million in additional gross margin.~~

~~Natural Gas Distribution Customer Growth~~

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

$~~443,000~~368,000 from Eastern Shore interruptible service provided to customers;

$350,000 from Florida natural gas customer growth due primarily to new services to commercial and industrial customers; and

$~~250,000~~253,000 from a ~~2.7-percent~~4.2 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~~customers.

Additional Revenue from GRIP in ~~Worcester County, Maryland.~~Florida

~~FPU Electric Base Rate Increase~~Additional GRIP investments during 2015 and 2016 by our Florida natural gas distribution operations generated $920,000 in additional gross margin in the third quarter of 2016, compared to the same period in 2015.

~~FPU's electric distribution operation~~Implementation of Delaware Division Interim Rates

Delaware Division generated additional gross margin of ~~$673,000 due to higher base~~$469,000 from the implementation of interim rates ~~approved by the Florida PSC in September 2014~~ as a result of ~~the~~its rate case ~~settlement. The new rates became effective~~filing. See Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for ~~all meter reads on or after November 1, 2014.~~additional details.

~~Growth in Natural Gas Transmission Services (Other Than Service Expansions)~~

~~Increased~~Margin from service to Eight Flags

We generated additional gross margin of $464,000 in the third quarter of 2016, compared to the same period in 2015, from ~~other growth in~~new natural gas transmission and distribution services ~~was~~provided to our Eight Flags' CHP plant.

Sandpiper SIR

Sandpiper generated ~~primarily~~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 ~~following:~~

~~$236,000~~continuing conversion of the Sandpiper system from propane service to natural gas ~~transmission service to commercial customers in Florida, partially offset by a decrease of $34,000 from interruptible service to an industrial customer in New Castle County, Delaware.~~

service.

Other Operating Expenses

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

$~~696,000~~1.3 million in higher payroll and benefits costs ~~as a result of~~for additional personnel to support growth;

$~~507,000~~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;~~growth and

~~$208,000 in higher accruals for incentive compensation as a result of the higher quarterly financial results.~~ system integrity.

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Table of Contents

For the nine months ended September 30, ~~2015~~2016 compared to the nine months ended September 30, ~~2014~~2015


	Nine Months Ended							Nine Months Ended
	September 30,				Increase			September 30,				Increase
	2015		2014		(decrease)			2016		2015		(decrease)
(in thousands)
Revenue	$	235,438	$	223,168	$	12,270		$	226,630	$	235,438	$	(8,808	)
Cost of sales	101,415		102,020		(605		)	81,184		101,414		(20,230		)
Gross margin	134,023		121,148		12,875			145,446		134,024		11,422
Operations & maintenance	59,648		55,416		4,232			64,673		59,648		5,025
Depreciation & amortization	18,109		16,783		1,326			18,909		18,109		800
Other taxes	8,650		7,945		705			9,204		8,650		554
Other operating expenses	86,407		80,144		6,263			92,786		86,407		6,379
Operating income	$	47,616	$	41,004	$	6,612		$	52,660	$	47,617	$	5,043

Operating income for the Regulated Energy segment for the nine months ended September 30, ~~2015~~2016 was ~~$47.6~~$52.7 million, an increase of ~~$6.6~~$5.0 million, or, ~~16.1~~10.6 percent, compared to the same period in ~~2014.~~2015. The increased operating income ~~reflects additional~~was primarily due to an increase in gross margin of ~~$12.9~~$11.4 million ~~and $1.5 million received in connection with the customer billing system settlement, which were~~ partially offset by ana $6.4 million increase in ~~other~~ operating expenses ~~of $7.8 million~~ to support growth.

Gross Margin

Items contributing to the period-over-period increase of ~~$12.9~~$11.4 million, or ~~10.6~~8.5 percent, in gross margin are listed in the following table:


(in thousands)
Gross margin for the nine months ended September 30, 2014	$	121,148
Factors contributing to the gross margin increase for the nine months ended September 30, 2015:
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	4,085		5,516
Additional revenue from GRIP in Florida	3,070		3,069
Natural gas distribution customer growth	2,517
FPU electric base rates increase	2,366
Growth in natural gas transmission services (other than service expansions)	633
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	204		(512		)
Gross margin for the nine months ended September 30, 2015	$	134,023
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:

$~~1.5~~4.3 million attributable to $5.6 million from ~~interruptible service~~the short-term OPT ≤ 90 Service that commenced in ~~April~~December 2015 to an ~~industrial customer facility~~electric power generator in Kent County, Delaware ~~mentioned above. The~~and offset by a $1.3 million decrease in gross margin from the conclusion of the interruptible service ~~is expected to generate $1.7 million~~Eastern Shore provided this customer in ~~2015, and it~~2015. The short-term OPT ≤ 90 Service is expected to be replaced by a 20-year OPT ≤ 90 Service ~~beginning~~ in the ~~third~~first quarter of ~~2016.~~2017.

$~~1.4 million~~744,000 from ~~a new~~short-term firm service ~~to the same industrial customer in Kent County, Delaware,~~ that commenced ~~on October 1, 2014 upon completion of new facilities, which included approximately 5.5 miles of pipeline lateral~~in March 2016, following certain measurement and ~~metering facilities extending from~~related improvements to Eastern Shore's ~~mainline to the new industrial customer facility.~~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 ~~is expected to~~will generate ~~$1.8~~approximately $1.4 million ofin additional gross margin in ~~2015.~~

$509,000 from a short-term contract with an existing industrial customer in New Castle County, Delaware to provide 50,000 Dts/d of service from April 2014 to April 2015. This contract was subsequently amended to provide 55,580 Dts/d of service at a lower reservation rate through August 2020. Although the lower rate decreased gross margin by $384,000

~~- 43~~

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2016. The remaining capacity is available for the nine months ended September 30, 2015, the extension of the contract at a higher volume generated additional gross margin of $893,000 for the nine months ended September 30, 2015. This service is expected to generate $2.3 million of gross margin in 2015 compared to $1.9 million of gross margin generated in 2014.

$233,000 from another short-term contract with the same industrial customer in New Castle County, Delaware, to provide an additional 10,000 Dts/d of OPT≤90 Service transmission service from December 2014 to March 2015.

firm or interruptible service.

$~~501,000~~720,000 from natural gas transmission service as part of the major expansion initiative in Polk County, Florida.

Table of Contents

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 ~~2014~~2015 and ~~2015~~2016 by our Florida natural gas distribution operations generated $3.1 million in additional gross ~~margin.~~margin during the first nine months of 2016, compared to the same period in 2015.

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

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

$~~1.4~~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; and~~customers.

$~~1.1 million~~348,000 from ~~a 2.7-percent increase in residential customers in the Delmarva natural gas distribution operations, as well as growth in commercial and industrial customers in Worcester County, Maryland.~~Eastern Shore interruptible service provided to other customers.

~~FPU Electric Base Rate Increase~~Implementation of Delaware Division Interim Rates

~~FPU's electric distribution operation~~Our Delaware Division generated additional gross margin of ~~$2.4~~$1.4 million ~~due to higher base~~from the implementation of interim rates ~~approved in September 2014~~ as a result of ~~the~~its rate case ~~settlement. The new rates became effective~~filing, during the first nine months of 2016. See Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for ~~all meter reads on or after November 1, 2014.~~additional details.

~~Growth in Natural Gas Transmission Services (Other Than Service Expansions)~~Margin from service to Eight Flags

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

Sandpiper SIR Rates

Sandpiper generated ~~primarily~~additional gross margin of $618,000 from a higher system improvement rate resulting from the ~~following:~~

~~$559,000~~continuing conversion of the Sandpiper system from propane service to natural gas ~~transmission service~~service.

Decreased Customer Consumption - Weather and Other

The above increases were partially offset by $2.1 million in lower gross margin due to ~~commercial customers~~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 ~~Florida, and~~

~~$57,000 from interruptible service to an industrial customer in New Castle County, Delaware.~~2015.

Other Operating Expenses

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

$~~1.9~~2.0 million in higher payroll and benefits costs ~~as a result of~~for additional personnel to support ~~growth and increased overtime on the Delmarva Peninsula in early 2015~~growth;

$1.4 million due to ~~colder weather;~~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;

$~~1.3~~1.4 million in higher depreciation, asset removal and property tax costs associated with recent capital investments to support ~~growth;~~growth and system integrity; and

$~~987,000~~817,000 in ~~legal and consulting~~higher outside services costs primarily associated with ~~the billing system settlement~~growth and ~~other initiatives;~~

~~$811,000 in higher accruals for incentive compensation as a result of improved year-to-date financial performance;~~

~~$680,000 in higher service contractor and other consulting costs;~~

~~$497,000 in additional amortization expense due to a change in the amortization of regulatory assets and liabilities, primarily in the Florida electric distribution operation; and~~

~~$353,000 in additional costs for facility maintenance.~~ongoing compliance activities.

~~These increases were partially offset by a gain of $1.5 million from the billing system settlement, which reduced other operating expenses for the nine months ended September 30, 2015.~~

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Unregulated Energy Segment

For the quarter ended September 30, ~~2015~~2016 compared to the quarter ended September 30, ~~2014~~2015


	Three Months Ended									Three Months Ended
	September 30,						Increase			September 30,						Increase
	2015			2014			(decrease)			2016			2015			(decrease)
(in thousands)
Revenue	$	29,609		$	27,071		$	2,538		$	42,042		$	29,609		$	12,433
Cost of sales	19,402			20,623			(1,221		)	31,840			19,402			12,438
Gross margin	10,207			6,448			3,759			10,202			10,207			(5		)
Operations & maintenance	9,305			7,063			2,242			10,975			9,305			1,670
Depreciation & amortization	1,483			1,014			469			1,840			1,483			357
Other taxes	441			343			98			467			441			26
Other operating expenses	11,229			8,420			2,809			13,282			11,229			2,053
Operating Loss	$	(1,022	)	$	(1,972	)	$	950		$	(3,080	)	$	(1,022	)	$	(2,058	)

Operating loss for the Unregulated Energy segment ~~decreased by $950,000, to~~ ~~$1.0~~for the quarter ended September 30, 2016 was $3.1 million, ~~in the third quarter~~ an increase of ~~2015,~~$2.1 million compared to ~~$2.0 million in~~ the same quarter of ~~2014.~~2015. The Unregulated Energy segment typically reports an operating loss in the third quarter due to the seasonal nature ~~of our operations of a large portion of~~the businesses included in this segment. ~~The results~~Gross margin for the ~~third~~ quarter ~~include gross margin of $2.0~~was $10.2 million, ~~and other~~which was more than offset by operating expenses of ~~$1.9~~$13.3 million, ~~from Aspire Energy~~to generate the operating loss of ~~Ohio. Excluding these impacts, gross margin increased by $1.7 million, which was partially offset by an $877,000 increase in other operating expenses.~~$3.1 million.

Gross Margin

Items contributing to the quarter-over-quarter ~~increase~~decrease of ~~$3.8 million, or 58.3 percent,~~$5,000 in gross margin are listed in the following table:

(in thousands)
Gross margin for the three months ended September 30, 2014 $ 6,448
Factors contributing to the gross margin increase for the three months ended September 30, 2015:
Contributions from acquisitions 2,047
Increased retail propane margins 1,029
Natural gas marketing 479
Other 204
Gross margin for the three months ended September 30, 2015 $ 10,207



(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

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

~~Contributions from Acquisitions~~Eight Flags

~~Aspire Energy of Ohio~~Eight Flags' CHP plant, which commenced operations in June 2016, generated ~~$2.0~~$1.6 million in additional gross ~~margin for the three months ended September 30, 2015.~~margin.

~~Increased~~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 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.

Lower Margins for Xeron

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

Decreased Retail Propane Margins

~~Higher~~Lower retail propane margins for our Delmarva ~~Peninsula~~ and Florida propane distribution operations during the third quarter of 2015 generated $597,000 and $432,000, respectively, in additional gross margin. The higher retail propane margins were due to the retail pricing strategy guided by local market conditions and lower propane costs.

~~Natural Gas Marketing~~

~~Our natural gas marketing operation generated $479,000 in additional~~decreased gross margin ~~for~~by $414,000, of which $344,000 is associated with the ~~quarter ended September 30, 2015,~~Delmarva Peninsula propane distribution operation, as ~~the results of our strategic growth initiatives have started to materialize.~~retail margins per gallon returned

~~- 45~~

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to more normal levels; accordingly, we have continued to assume more normal levels of margins in our long-term financial plans and forecasts. 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.

Other Operating Expenses

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

$~~1.9~~1.1 million in ~~costs from~~other operating expenses incurred by the ~~operation of Aspire Energy of Ohio, following the acquisition of Gatherco on April 1, 2015;~~Eight Flags CHP plant;

$~~443,000~~545,000 in higher payroll and benefits costs ~~primarily due to~~for additional personnel ~~hired~~ to support growth; and

$~~141,000~~225,000 in higher ~~depreciation~~outside services costs primarily associated with growth and ~~property tax costs reflecting a higher level of assets resulting from our growth;~~

~~$126,000 in additional costs for facility maintenance; and~~

~~$102,000 in higher accruals for incentive compensation as a result of the higher year-to-date financial results and a larger workforce.~~ongoing compliance activities.

For the nine months ended September 30, ~~2015~~2016 compared to the nine months ended September 30, ~~2014~~2015


	Nine Months Ended							Nine Months Ended
	September 30,				Increase			September 30,				Increase
	2015		2014		(decrease)			2016		2015		(decrease)
(in thousands)
Revenue	$	123,164	$	141,365	$	(18,201	)	$	136,361	123,164		$	13,197
Cost of sales	77,235		105,802		(28,567		)	90,981		77,235		13,746
Gross margin	45,929		35,563		10,366			45,380		45,929		(549		)
Operations & maintenance	26,993		22,508		4,485			30,136		26,993		3,143
Depreciation & amortization	3,973		2,981		992			4,512		3,973		539
Other taxes	1,297		1,231		66			1,465		1,297		168
Other operating expenses	32,263		26,720		5,543			36,113		32,263		3,850
Operating Income	$	13,666	$	8,843	$	4,823		$	9,267	$	13,666	$	(4,399	)

Operating income for the Unregulated Energy segment ~~increased by $4.8~~for the nine months ended September 30, 2016 was $9.3 million, a decrease of $4.4 million, or ~~54.5~~32.2 percent ~~to $13.7 million in~~for the same period of 2015. The results for the first nine months of 2015, compared to $8.8 million in the same period of 2014. Excluding the impact generated by Aspire Energy of Ohio as a result of the Gatherco acquisition on April 1, 2015 ($3.7 million in gross margin and $3.8 million of other operating expenses), the increased operating income was driven by a $6.7 millioninclude an increase in gross margin ~~which was partially offset by a $1.7~~of $4.5 million ~~increase in~~and other operating ~~expenses.~~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.

Gross Margin

A significant decline in natural gas and propane commodity prices decreased both revenue and related cost of commodities sold to our propane distribution and natural gas marketing customers, resulting in a period-over-period increase of $10.4 million, or 29.2 percent, in gross margin. Items contributing to ~~this increase~~the period-over-period decrease of $549,000 in gross margin are listed in the following table:

(in thousands)
Gross margin for the nine months ended September 30, 2014 $ 35,563
Factors contributing to the gross margin increase for the nine months ended September 30, 2015:
Increase in retail propane margins 6,742
Contributions from acquisitions 3,679
Propane wholesale marketing (854 )
Natural gas marketing 404
Increased customer consumption - weather and other 258
Other 137
Gross margin for the nine months ended September 30, 2015 $ 45,929



(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

~~- 46~~

Table of Contents

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

~~Increased Retail Propane Margins~~

Higher retail propane margins for our Delmarva Peninsula and Florida propane distribution operations during the first nine months of 2015 generated $5.7 million and $1.1 million, respectively, in additional gross margin. A large decline in wholesale propane prices during 2015, coupled with favorable supply management and hedging activities, resulted in a decrease in the average propane costs for the Delmarva propane distribution operation, which generated increased retail propane margins per gallon.

~~Contributions from Acquisitions~~Aspire Energy

Aspire Energy ~~of Ohio~~ generated $8.2 million in gross margin compared to $3.7 million in ~~additional gross margin in the first nine months of 2015.~~

~~Lower Propane Wholesale Marketing Results~~

~~Xeron's gross margin decreased by $854,000 during the first nine months of 2015, compared to~~ the same period ~~in 2014, as a result~~ of ~~a 12-percent decrease in trading activity and lower margins on executed trades. In contrast, Xeron experienced higher price volatility and higher trading volumes in the first nine months~~2015, an increase of ~~2014, which resulted in unusually high profitability during that period.~~

~~Natural Gas Marketing~~

~~Our natural gas marketing operation generated $404,000 in additional gross margin~~$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 million in additional gross margin.

Natural Gas Marketing

PESCO generated $1.1 million in additional gross margin due to customer growth and 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 compared to the same period in ~~2014.~~2015, also contributed to this decrease.

Decreased Retail Propane Margins

Lower retail propane margins for our Delmarva propane distribution operation decreased gross margin by $2.2 million, as margins per retail gallon returned to more normal levels. The ~~increase~~decline in ~~natural gas marketing~~ margin was ~~primarily from execution~~driven principally by lower propane prices and local market conditions. The level of ~~its growth strategy.~~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.

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.

~~Increased~~Decreased Customer Consumption - Weather and Other

~~Higher~~Gross margin decreased by $4.1 million due to lower customer consumption ~~increased gross margin~~of propane. The decrease was driven mainly by ~~$258,000. The increase was due to an increase in non-weather consumption~~weather as a result of warmer temperatures on the Delmarva Peninsula ~~partially offset by decreased non-weather consumption in Florida.~~during the first nine months of 2016 compared to colder temperatures during the first nine months of 2015.

Other Operating Expenses

Other operating expenses increased by ~~$5.5~~$3.9 million. The significant components of the increase in other operating expenses included:

$2.5 million ~~due primarily to $3.8 million of~~in other operating expenses incurred by Aspire Energy, given the additional quarter's results included in 2016, compared to only six months of ~~Ohio. The remaining increase~~results in the nine months ended September 30, 2015; and

$1.1 million in other operating expenses ~~was due primarily to:~~

~~$1.0 million~~incurred by Eight Flags, which commenced operations in June 2016 ~~in higher payroll and benefits expense due to increased seasonal overtime and additional resources hired to support growth;~~.

~~$379,000~~ ~~in additional costs for facility maintenance;~~

~~$337,000 in increased accruals for incentive compensation as a result of improved year-to-date financial results in 2015 as well as a larger workforce; and~~

~~$184,000 in lower expenses for credit and collections activities, which partially offset the above increases in expenses.~~

Interest Charges

For the quarter ended September 30, ~~2015~~2016 compared to the quarter ended September 30, ~~2014~~2015

Interest charges for the three months ended September 30, ~~2015 decreased slightly~~2016 increased by approximately $~~3,000~~230,000, compared to the same quarter in ~~2014.~~2015, attributable to an increase of $392,000 in interest from higher short-term borrowings, partially offset by a decrease of $117,000 in interest from long-term debt.

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For the nine months ended September 30, ~~2015~~2016 compared to the nine months ended September 30, ~~2014~~2015

Interest charges for the nine months ended September 30, ~~2015~~2016 increased by approximately ~~$471,000, or seven percent,~~$571,000, compared to the same period in ~~2014. The increase in interest charges is~~2015, attributable to an increase of ~~$262,000 in long-term interest charges as a result of $50.0~~$1.1 million ~~of Notes issued in May 2014 and an increase of $122,000~~ in interest ~~expense~~ from higher short-term ~~borrowings.~~borrowings, partially offset by a decrease of $352,000 in interest from long-term debt.

Income Taxes

For the quarter ended September 30, ~~2015~~2016 compared to the quarter ended September 30, ~~2014~~2015

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Income tax expense was ~~$3.3~~$3.0 million in the third quarter of ~~2015,~~2016, compared to ~~$2.1~~$3.3 million in the same quarter in ~~2014.~~2015. The ~~increase~~slight decrease in income tax expense was due primarily to ~~higher~~lower taxable income. Our effective income tax rate was at ~~39.4~~40.4 percent ~~for the third quarter of 2015~~ and ~~39.6~~39.4 percent, for the third quarter of ~~2014.~~2016 and 2015, respectively.

For the nine months ended September 30, ~~2015~~2016 compared to the nine months ended September 30, ~~2014~~2015

Income tax expense was ~~$21.6~~$21.4 million in the nine months ended September 30, ~~2015,~~2016, compared to ~~$17.3~~$21.6 million in the same period in ~~2014.~~2015. The ~~increase~~slight decrease in income tax expense was due primarily to ~~higher~~lower taxable income. Our effective income tax rate ~~remained unchanged at~~was 39.5 percent and 40.0 percent, for the first nine months of 2016 and 2015, ~~and 2014.~~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 ~~natural gas, electric and propane distribution~~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 byto customers through our natural gas, electric, and propane distribution operations ~~to customers~~and our natural gas gathering and processing operation during the peak heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.

Our ~~largest~~ capital ~~requirements are~~expenditures for ~~investments~~the nine months ended September 30, 2016 were approximately $106.3 million. We currently project aggregate capital expenditures between $150.0 and $170.0 million in ~~new or acquired plant and equipment.~~2016. Our current forecast ~~of capital expenditures for 2015 ranges from $130.0 million to $160.0 million. The following table sets forth the revised 2015 forecast of capital expenditures~~ by ~~segment:~~

segment and business line is shown below:


	Range of Capital Expenditures				Low		High
(dollars in thousands)	Low		High
Regulated Energy:
Natural gas distribution	$	59,589	$	80,281	$	60,000	$	65,000
Natural gas transmission	21,426		30,734		55,000		60,000
Electric distribution	4,824		4,824		10,000		13,000
Total Regulated Energy	85,839		115,839		125,000		138,000
Unregulated Energy:
Propane distribution	9,196		9,196		10,000		12,000
Other unregulated energy	28,447		28,447		10,000		13,000
Total Unregulated Energy	37,643		37,643		20,000		25,000

Other	6,518		6,518		5,000		7,000

Total 2015 projected capital expenditures	$	130,000	$	160,000
Total 2016 capital expenditures					$	150,000	$	170,000

The ~~current~~2016 forecast ~~of capital~~includes expenditures ~~is a significant increase over our average annual level of capital expenditures over~~for the ~~past three years of $94.8 million. This increase is due~~following projects: Eight Flags' CHP plant; anticipated new facilities 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 and transmission ~~systems, increased~~systems; continued natural gas infrastructure improvement ~~activities, improvement~~activities; expenditures for continued replacement under the Florida GRIP; replacement of ~~our~~several facilities and ~~systems~~information technology systems; and other strategic initiatives and investments expected in 2015. The reduction from the original capital expenditure budget of $223.4 million to the current forecast of capital expenditures is due primarily to a shift in the timing of certain capital expenditures from 2015 to 2016.

investments.

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 ~~acquisition~~timing of ~~Gatherco, which we completed on April 1, 2015, was not included in our original~~ capital ~~budget of $223.4 million or in our current 2015 capital expenditure forecast shown above. At closing, we issued 592,970 shares of our common stock, valued at $30.2 million~~expenditures can vary based on ~~the closing price of our common stock, as reported on the NYSE on April 1, 2015,~~securing environmental approvals and ~~paid $27.5 million in cash. We also acquired $6.8 million of Gatherco's cash at closing~~other permits. The regulatory application and ~~assumed $1.7 million of Gatherco’s debt, which was paid off on the same day.~~approval process has lengthened, 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 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, ~~2015~~2016 and December 31, ~~2014:~~2015:


	September 30, 2015				December 31, 2014				September 30, 2016				December 31, 2015
(in thousands)
Long-term debt, net of current maturities	$	155,909	31	%	$	158,486	35	%	$	143,525	25	%	$	149,006	29	%
Stockholders’ equity	353,315		69	%	300,322		65	%	438,300		75	%	358,138		71	%
Total capitalization, excluding short-term debt	$	509,224	100	%	$	458,808	100	%	$	581,825	100	%	$	507,144	100	%
	September 30, 2015				December 31, 2014				September 30, 2016				December 31, 2015
(in thousands)
Short-term debt	$	127,093	20	%	$	88,231	16	%	$	154,490	20	%	$	173,397	25	%
Long-term debt, including current maturities	165,048		26	%	167,595		30	%	155,612		21	%	158,157		23	%
Stockholders’ equity	353,315		54	%	300,322		54	%	438,300		59	%	358,138		52	%
Total capitalization, including short-term debt	$	645,456	100	%	$	556,148	100	%	$	748,402	100	%	$	689,692	100	%

Included in the long-term debt balances at September 30, ~~2015~~2016 and December 31, ~~2014~~,2015, was a capital lease obligation associated with Sandpiper's capacity, supply and operating agreement (~~$3.8~~($2.4 million and ~~$4.8~~$3.5 million, respectively, net of current maturities, and ~~$5.2~~$3.8 million and ~~$6.1~~$4.8 million, respectively, including current maturities). Sandpiper entered into this six-year agreement at the closing of the ESG acquisition in May 2013. The capacity portion of this agreement is accounted for as a capital lease.

In order to fund the 2015 capital expenditures, currently estimated to be in the range of $130.0 million to $ 160.0 million, we expect to increase the level of borrowings during the remainder of 2015 to supplement cash provided by operating activities. Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. ~~We have maintained~~On September 22, 2016, we completed a ~~ratio~~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 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 ~~including short-term borrowings, between 54 percent and 60 percent during the past three years. As we increase the level~~ratio representing 59% as of ~~debt during 2015 to fund the capital expenditures we expect to fund at this time, the ratio of equity to total capitalization, including short-term borrowings, will temporarily decline.~~ September 30, 2016.

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

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

Short-term Borrowings

Our outstanding short-term borrowings at September 30, ~~2015~~2016 and December 31, ~~2014~~2015 were ~~$127.1~~$154.5 million and ~~$88.2~~$173.4 million, ~~respectively, at~~respectively. The weighted average interest rates offor our short-term borrowings were 1.49 percent and 1.09 percent, for the nine months ended September 30, 2016 and ~~1.15 percent,~~2015, respectively.

We utilize bank lines of credit to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of the capital expenditure program. As of September 30, ~~2015,~~2016, we had ~~six~~four unsecured bank credit facilities with three financial institutions ~~with $210.0~~totaling $170.0 million ofin total available credit. ~~Three~~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 ~~totaling $120.0 million, are available under committed lines of credit. Two of these credit facilities, totaling $40.0 million, were available under uncommitted lines of credit, which~~when they expired on October 31, ~~2015, and were not renewed.~~2015. None of ~~these~~the unsecured bank lines of credit requires compensating balances. Advances offered under the uncommitted lines of credit are subject to the discretion of the banks. In addition to these bank lines of credit, one of the lenders has made available a $50.0 million short-term revolving credit note. We are currently authorized by our Board of Directors to borrow up to ~~$200.0~~$275.0 million of short-term ~~borrowings, as required.~~borrowing.

~~On October 8, 2015, we entered into the Credit Agreement with the Lenders to provide a~~The $150.0 million Revolver ~~for five years~~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.

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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 ~~may~~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. ~~On October 19,~~At September 30, 2016 and December 31, 2015, we ~~borrowed $25.0~~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 ~~committed~~ Shelf Agreement with ~~Prudential and other purchasers that may become a party to the Shelf Agreement.~~Prudential. Under the terms of the Shelf Agreement, through October 8, 2018, we may request that Prudential purchase ~~over the next three years,~~ up to $150.0 million of our Shelf Notes at a fixed interest rate and with a maturity date not to exceed ~~twenty~~20 years from the date of issuance. Prudential ~~and its affiliates are~~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 ~~that~~ the proceeds from the sale of any series of Shelf Notes will be used for general corporate purposes, including refinancing of short-term ~~borrowings~~borrowing and/or repayment of outstanding indebtedness and financing of capital expenditures on future projects; however, actual use of such proceeds will be determined at the time of a purchase.

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the nine months ended September 30, ~~2015~~2016 and ~~2014:~~2015:


	Nine Months Ended						Nine Months Ended
	September 30,						September 30,
	2015			2014			2016			2015
(in thousands)
Net cash provided by (used in):
Operating activities	$	98,684		$	65,019		$	82,225		$	93,932
Investing activities	(122,985		)	(68,740		)	(106,992		)	(118,233		)
Financing activities	23,508			2,650			23,448			23,508
Net decrease in cash and cash equivalents	(793		)	(1,071		)	(1,319		)	(793		)
Cash and cash equivalents—beginning of period	4,574			3,356			2,855			4,574
Cash and cash equivalents—end of period	$	3,781		$	2,285		$	1,536		$	3,781

Cash Flows Provided By Operating Activities

Changes in our cash flows from operating activities are attributable primarily to changes in net income, non-cash adjustments for depreciation, deferred income taxes and working capital. Changes in working capital are determined by a variety of factors, including weather, the prices of natural gas, electricity and propane, the timing of customer collections, payments for purchases of natural gas, electricity and propane, and deferred fuel cost recoveries.

During the nine months ended September 30, ~~2015~~2016 and ~~2014,~~2015, net cash provided by operating activities was ~~$98.7~~$82.2 million and ~~$65.0~~$93.9 million,, respectively, resulting in ~~an increase~~a decrease in cash flows of ~~$33.7~~$11.7 million. Significant operating activities generating the cash flows change were as follows:

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

Table of Contents~~The changes~~

Changes in net regulatory assets and liabilities ~~increased~~decreased cash flows by ~~$15.3~~$9.8 million,, due primarily to ~~the change~~changes in fuel costs collected through the various fuel cost recovery mechanisms.

The change in income taxes receivable increased cash flows by $14.4 million, due primarily to the receipt of a tax refund related to our 2014 federal income tax obligation. Our tax deductions, which were higher-than-projected, due to bonus depreciation (approved by the President of the United States in December 2014), reduced our 2014 federal income tax obligation.

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~~The changes~~Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities decreased cash flows by ~~$2.8 million~~, due primarily to the timing of the collections and payments associated with trading contracts entered into by our propane wholesale marketing subsidiary, which were partially offset by an increase in net cash flows from receivables and payables in various other operations.

~~Net income, adjusted for reconciling activities, increased cash flows by $8.2~~$12.2 million, due primarily to higher ~~earnings~~revenues and ~~higher non-cash adjustments for depreciation~~the timing of the receipt of customer payments as well as increased operating expenses and ~~amortization.~~the timing of payments to vendors.

~~Net cash flows from changes~~Changes in propane, natural gas and materials inventories decreased net cash flows by approximately ~~$971,000, compared to 2014.~~$5.3 million.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled ~~$123.0~~$107.0 million and ~~$68.7~~$118.2 million during the nine months ended September 30, ~~2015~~2016 and ~~2014,~~2015, respectively, resulting in ~~a decrease~~an increase in cash flows of ~~$54.2~~$11.2 million. ~~Significant investing activities generating the cash flows change were as follows:~~

~~An increase in cash paid for capital expenditures,~~This was due primarily to ~~our GRIP investment in our Florida natural gas distribution operations and Eight Flags' construction of~~ the ~~CHP plant, decreased cash flows by $32.9 million.~~

~~We paid~~ $20.7 million net cash ($27.5 million cash paid, less $6.8 million of cash acquired)used for the Gatherco acquisition in ~~conjunction with the acquisition~~2015. An increase in capital investments of ~~Gatherco on April 1, 2015.~~$9.7 million partially offset this decrease.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities totaled ~~$23.5~~$23.4 million in the first nine months of ~~2015, compared~~both 2016 and 2015. Net proceeds of $57.3 million, after deducting underwriting commissions and expenses, from the issuance of common stock during the third quarter of 2016, was used to ~~$2.7 million~~ ~~in the same period in 2014. The increase in net~~pay down short-term debt. Net cash provided by financing activities ~~during the first nine months~~further increased as a result of ~~2015 was due primarily to $69.9 million in higher borrowing under our line of credit agreements and a $3.5 million~~an increase in a cash ~~overdrafts, which were~~overdraft of $2.5 million and an increase in short-term borrowing of $35.9 million, partially offset by ~~$50.0~~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 million in ~~proceeds from~~net additional borrowings, offset by common stock dividends of $11.7 million and $633,000 of stock issued for the ~~issuance of long-term debt in May 2014 and $1.7 million of outstanding debt assumed in the Gatherco merger that was paid off immediately after the closing of the merger on April 1, 2015.~~Dividend Reinvestment Plan.

Off-Balance Sheet Arrangements

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily Xeron and PESCO, which provide for the payment of propane and natural gas purchases in the event that the subsidiary defaults. Neither subsidiary has ever defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at September 30, ~~2015~~2016 was ~~$36.1~~$53.9 million,, with the guarantees expiring on various dates through September ~~22, 2016.~~2017.

We have issued ~~a letter~~letters of credit ~~for~~ ~~$1.0~~totaling $8.4 million~~, which was renewed through~~ ~~September 12, 2016~~, related to the electric transmission services for ~~FPU’s~~FPU's northwest electric division. We also issued a letter of credit to our current primary insurance company for $1.2 million, which expires on October 31, 2016, as security to satisfy the deductibles under our various insurance policies. As a result of a change in our primary insurance company, we renewed and decreased to $24,000 the letter of credit to our former primary insurance company, which will expire on April 8, 2016. We have also issued a letter of credit of $1.0 million, which expires on March 31, 2016, related to PESCO's transactions at the Natural Gas Exchange, Inc.

~~We provided a letter of credit for $2.3 million to TETLP related to~~division, the firm transportation service agreement ~~with~~between TETLP and our Delaware and Maryland ~~divisions.~~

divisions, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through September 2017. There have been no draws on these letters of credit as of September 30, ~~2015.~~2016. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that ~~the letters of credit~~they will be renewed to the extent necessary in the future. Additional information is presented inItem 1, Financial Statements, Note 6, Other Commitments and Contingencies in the Condensed Consolidated Financial Statements.

Contractual Obligations

There has ~~not~~ been ~~any~~no material change in the contractual obligations presented in our ~~2014~~2015 Annual Report on Form 10-K, except for commodity purchase obligations and forward contracts entered into in the ordinary course of our business. The following table summarizes commodity and forward contract obligations at September 30, ~~2015.~~2016:

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	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⁾	$	40,246	$	6,088	$	1,425	$	—	$	47,759	$	42,155	$	3,417	$	—	$	—	$	45,572
Forward purchase contracts - Propane ⁽²⁾	1,336		—		—		—		1,336
Total	$	41,582	$	6,088	$	1,425	$	—	$	49,095

⁽¹⁾

In addition to the obligations noted above, ~~the natural gas, electric and propane distribution operations~~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.


⁽²⁾ Table of Contents	~~We have also entered into forward sale contracts. See Item 3,~~ ~~Quantitative and Qualitative Disclosures About Market Risk~~ ~~for further information.~~

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, ~~2015~~2016, we were involved in regulatory matters in each of the jurisdictions in which we operate. Our significant regulatory matters are fully described in Note 4, Rates and Other Regulatory Activities, to the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

Recent Authoritative Pronouncements on Financial Reporting and Accounting

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

Market risk represents the potential loss arising from adverse changes in market rates and prices. Long-term debt is subject to potential losses based on changes in interest rates. Our long-term debt consists of fixed-rate senior notes and secured debt. All of our long-term debt, excluding a capital lease obligation, is fixed-rate debt and was not entered into for trading purposes. The carrying value of our long-term debt, including current maturities, but excluding a capital lease obligation, was ~~$159.9~~$151.8 million at September 30, ~~2015~~2016, as compared to a fair value of ~~$175.8~~$173.5 million,, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, with adjustments for duration, optionality, credit risk, and risk profile. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowing, based in part on the fluctuation in interest rates.

Our propane distribution business is exposed to market risk as a result of our propane storage activities and entering into fixed price contracts for supply. We can store up to approximately ~~6.5~~6.8 million gallons of propane (including leased storage and rail cars) during the winter season to meet our customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline. To mitigate the impact of price fluctuations, we have adopted a Risk Management Policy that allows the propane distribution operation to ~~enter~~hedge its inventory.

In 2016, PESCO entered into ~~fair value hedges or other economic hedges~~a SCO supplier agreement with Columbia Gas to provide natural gas supply for Columbia Gas to service one of ~~our inventory.~~its local distribution customer tranches. PESCO also assumed the obligation to store natural gas inventory to satisfy its obligations under the SCO supplier agreement, 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 in order to protect its natural gas inventory against market price fluctuations.

Our propane wholesale marketing operation is a party to ~~natural gas liquids (primarily propane)~~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 at a fixed price at fixed future dates. At expiration, the contracts are typically settled financially without taking physical delivery of ~~propane.~~propane 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.~~propane or crude oil.

The forward and futures contracts are entered into for trading and wholesale marketing purposes. The propane wholesale marketing business is subject to commodity price risk on its open positions to the extent that market prices for natural gas liquids deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts is monitored daily for compliance with our Risk Management Policy, which includes ~~volumetric~~dollar limits for open positions. To manage exposures to

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changing market prices, open positions are marked up or down to market prices and reviewed daily by our oversight officials. In addition, the Risk Management Committee reviews periodic reports on markets and the credit risk of counter-parties, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts. ~~Quantitative information on forward and future contracts at~~As of September 30, ~~2015~~2016 ~~is presented in the following table:~~, there were no outstanding contracts.

~~Estimated market prices and weighted average contract prices are in dollars per gallon. All contracts expire by the end of the fourth quarter of 2015.~~

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

At September 30, ~~2015~~2016 and December 31, ~~2014,~~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:

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(in thousands) September 30, 2015 December 31, 2014
Mark-to-market energy assets, including put and call options and swap agreements $ 286
$ 1,055
Mark-to-market energy liabilities, including swap agreements $ 154
$ 1,018




(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 ~~the Company,~~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, ~~2015~~2016. 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, ~~2015~~2016.

Changes in Internal Control over Financial Reporting

During the quarter ended September 30, ~~2015~~2016, there was no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

~~- 55~~

Table of Contents

PART II—OTHER INFORMATION


Item 1.	Legal Proceedings

As disclosed in Note 6, Other Commitments and Contingencies, of the unaudited condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we are involved in certain legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental or regulatory agencies concerning rates and other regulatory actions. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on our condensed consolidated financial position, results of operations or cash flows.


Item 1A.	Risk Factors

Our business, operations, and financial condition are subject to various risks and uncertainties. The risk factors described in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K, for the year ended December 31, ~~2014,~~2015, should be carefully considered, together with the other information contained or incorporated by reference in this Quarterly Report on Form 10-Q and in our other filings with the SEC in connection with evaluating ~~the Company,~~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 ~~the Company.~~Chesapeake Utilities. The occurrence of any of these known or unknown risks could have a material adverse impact on our business, financial condition and results of operations.


Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds

Total
Number of
Shares

Average
Price Paid

Total Number of Shares
Purchased as Part of
Publicly Announced Plans

Maximum Number of
Shares That May Yet Be
Purchased Under the Plans
Period Purchased per Share
or Programs ⁽²⁾

or Programs ⁽²⁾
July 1, 2015
through July 31, 2015 ⁽¹⁾
369
$ 54.45
—
—
August 1, 2015
through August 31, 2015
—
$ —
—
—
September 1, 2015
through September 30, 2015
—
$ —
—
—
Total 369
$ 54.45
—
—



	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	—	—

⁽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, ~~2014~~2015. During the quarter ended September 30, ~~2015,~~2016, ~~369~~366 shares were purchased through the reinvestment of dividends on deferred stock units.


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


Item 3.	Defaults upon Senior Securities

None.


Item 5.	Other Information

None.

~~- 56~~

Table of Contents


Item 6.	Exhibits



~~4.1~~		~~Private Shelf~~
1.1		Underwriting Agreement ~~dated October 8, 2015, between~~entered into by Chesapeake Utilities Corporation ~~as issuer,~~ and ~~Prudential Investment Management~~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 ~~purchase~~sale and issuance of ~~Chesapeake Utilities Corporation unsecured senior notes,~~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 ~~herewith.~~on September 28, 2016, File No. 001-11590.

~~10.1~~3.3		~~Revolving Credit Agreement dated October 8, 2015, between~~Second Amendment to the Amended and Restated Bylaws of Chesapeake Utilities Corporation, ~~and PNC Bank, National Association, Bank of America, N.A., Citizens Bank N.A., Royal Bank of Canada and Wells Fargo Bank, National Association as lenders,~~effective November 2, 2016, is filed herewith.

~~10.2~~		Form of Performance Share Agreement, dated March 6, 2015 for the period 2015 to 2017, pursuant to Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and James F. Moriarty, is filed herewith.

31.1		Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of ~~1934, dated November 5, 2015.~~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, dated November 5, 2015.~~1934.

32.1		Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section ~~1350, dated November 5, 2015.~~1350.

32.2		Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section ~~1350, dated November 5, 2015.~~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.

~~- 57~~

Table of Contents

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 ~~5, 2015~~3, 2016

- 5860



	Quantity in	Estimated Market	Weighted Average
At September 30, 2015	Gallons	Prices	Contract Prices
Forward Contracts
Sale	2,940,000	$0.4750 - $0.5288	$	0.5210
Purchase	2,940,000	$0.4350 - $0.5025	$	0.4545



(in thousands, except per share)	Pre-tax Income			Net Income			Earnings Per Share
Third Quarter of 2014 Reported Results	$	5,265		$	3,180		$	0.22
Adjusting for Unusual Items:
Absence of BravePoint, which was sold in October 2014	(454		)	(274		)	(0.02		)
	(454		)	(274		)	(0.02		)
Increased (Decreased) Gross Margins:
Contribution from Aspire Energy of Ohio	2,037			1,230			0.08
Service expansions (See Major Projects and Initiatives table)	1,708			1,031			0.07
GRIP	1,144			691			0.05
Higher retail propane margins	1,029			621			0.04
Natural gas growth (excluding service expansions)	895			540			0.04
FPU electric base rate increase	673			406			0.03
Natural gas marketing	479			289			0.02
	7,965			4,808			0.33
Increased Other Operating Expenses:
Expenses from Aspire Energy of Ohio	(1,933		)	(1,167		)	(0.08		)
Higher payroll and benefits costs	(1,098		)	(663		)	(0.05		)
Higher depreciation, asset removal and property tax costs due to recent capital investments	(647		)	(391		)	(0.03		)
Increased accrual for incentive compensation	(314		)	(190		)	(0.01		)
	(3,992		)	(2,411		)	(0.17		)
Interest Charges	3			2			—
Net Other Changes ⁽¹⁾	(334		)	(186		)	(0.03		)
Third Quarter of 2015 Reported Results	$	8,453		$	5,119		$	0.33



		Estimate for
Project	Estimated In-Service Date	Annualized Margin		2016		2017
White Oak Mainline Expansion Project in Kent County, Delaware	Third quarter of 2016	$	5,400	$	5,400	$	5,800
Eastern Shore System Reliability Project	Late third quarter of 2016	4,500		—		2,250
Eastern Shore TETLP Capacity Expansion Project	February 2016	2,100		2,100		2,100
Eight Flags CHP plant in Nassau County, Florida	Early third quarter of 2016	7,300		3,700		7,300
		$	19,300	$	11,200	$	17,450



(in thousands)	Q3 2015 vs. Q3 2014			Q3 2015 vs. Normal			Q3 2014 vs. Normal			YTD 2015 vs. YTD 2014			YTD 2015 vs. Normal			YTD 2014 vs. Normal
Delmarva
Regulated Energy segment	$	(157	)	$	(31	)	$	167		$	(87	)	$	872		$	803
Unregulated Energy segment	(8		)	27			(13		)	20			1,005			1,037
Florida
Regulated Energy segment	(232		)	(40		)	38			134			(239		)	(284		)
Unregulated Energy segment	—			—			—			(10		)	122			81
Total	$	(397	)	$	(44	)	$	192		$	57		$	1,760		$	1,637

Large accelerated filer

Accelerated filer

Non-accelerated filer

Smaller reporting company