Chesapeake Utilities - 10-Q quarterly report FY2018 Q2

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: June 30, 2018



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

For the transition period from to

Commission File Number: 001-11590




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



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

909 Silver Lake Boulevard, Dover, Delaware 19904

(Address of principal executive offices, including Zip Code)

(302) 734-6799

(Registrant’s telephone number, including area code)

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

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

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



Large accelerated filer	x	Accelerated filer	¨

Non-accelerated filer	¨	Smaller reporting company	¨

		Emerging growth company	¨

Table of Contents

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

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

Common Stock, par value $0.4867 — 16,378,545 shares outstanding as of July 31, 2018.

Table of Contents




PART I—FINANCIAL INFORMATION		1

ITEM 1.	FINANCIAL STATEMENTS	1

ITEM 2.	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	33

ITEM 3.	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	55

ITEM 4.	CONTROLS AND PROCEDURES	56

PART II—OTHER INFORMATION		57

ITEM 1.	LEGAL PROCEEDINGS	57

ITEM 1A.	RISK FACTORS	57

ITEM 2.	UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS	57

ITEM 3.	DEFAULTS UPON SENIOR SECURITIES	57

ITEM 5.	OTHER INFORMATION	57

ITEM 6.	EXHIBITS	58

SIGNATURES		59

Table of Contents

GLOSSARY OF DEFINITIONS

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

ASC: Accounting Standards Codification issued by the FASB

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

ASU: Accounting Standards Update issued by the FASB

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

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

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

CGC: Consumer Gas Cooperative, an Ohio natural gas cooperative

CGS: Community Gas Systems

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

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

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

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

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

CHP: Combined heat and power plant

CIAC: Contributions from customers that are used to construct facilities

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

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

CP: Certificate of Public Convenience and Necessity

Credit Agreement: The Credit Agreement dated October 8, 2015, among Chesapeake Utilities and the Lenders related to the Revolver

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

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

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

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

DNREC: Delaware Department of Natural Resources and Environmental Control

DSR: Delivery Service Rate

Table of Contents

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

Dts/d: Dekatherms per day

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

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

Eight Flags: Eight Flags Energy, LLC, a subsidiary of Chesapeake OnSight Services, LLC, which owns and operates a CHP plant on Amelia Island, Florida, that supplies electricity to FPU and industrial steam to Rayonier

EPA: United States Environmental Protection Agency

ESG: Eastern Shore Gas Company and its affiliates

FASB: Financial Accounting Standards Board

FDEP: Florida Department of Environmental Protection

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

FGT: Florida Gas Transmission Company

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

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

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

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

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

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

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

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

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

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

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

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

MDE: Maryland Department of Environment

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

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

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

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

Table of Contents

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

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

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

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

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

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

OTC: Over-the-counter

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

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

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

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

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

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

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

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

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

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

Revolver: Our unsecured revolving credit facility with the Lenders

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

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

SEC: U.S. Securities and Exchange Commission

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

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

SICP: 2013 Stock and Incentive Compensation Plan

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

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

Table of Contents

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

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

Table of Contents

PART I—FINANCIAL INFORMATION

Item 1. Financial Statements

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Income (Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
(in thousands, except shares and per share data)
Operating Revenues
Regulated Energy	$	70,504		$	70,996		$	179,897		$	168,650
Unregulated Energy and other	66,160			54,088			196,123			141,594
Total Operating Revenues	136,664			125,084			376,020			310,244
Operating Expenses
Regulated Energy cost of sales	20,010			24,167			68,241			64,411
Unregulated Energy and other cost of sales	49,393			40,505			149,219			101,260
Operations	36,281			30,013			68,983			62,502
Maintenance	3,619			3,403			7,211			6,634
Gain from a settlement	(130		)	(130		)	(130		)	(130		)
Depreciation and amortization	9,839			9,094			19,543			17,906
Other taxes	4,404			3,971			9,299			8,501
Total Operating Expenses	123,416			111,023			322,366			261,084
Operating Income	13,248			14,061			53,654			49,160
Other expense, net	(262		)	(1,002		)	(194		)	(1,703		)
Interest charges	3,881			3,073			7,545			5,811
Income Before Income Taxes	9,105			9,986			45,915			41,646
Income taxes	2,718			3,940			12,674			16,456
Net Income	$	6,387		$	6,046		$	33,241		$	25,190
Weighted Average Common Shares Outstanding:
Basic	16,369,641			16,340,665			16,360,540			16,329,009
Diluted	16,417,082			16,382,207			16,410,061			16,373,038
Earnings Per Share of Common Stock:
Basic	$	0.39		$	0.37		$	2.03		$	1.54
Diluted	$	0.39		$	0.37		$	2.03		$	1.54
Cash Dividends Declared Per Share of Common Stock	$	0.3700		$	0.3250		$	0.6950		$	0.6300

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

- 1

Table of Contents

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income (Unaudited)



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
(in thousands)
Net Income	$	6,387		$	6,046		$	33,241		$	25,190
Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(5), $(8), $(11) and $(16), respectively	(14		)	(12		)	(28		)	(23		)
Net gain, net of tax of $41, $69, $80 and $145, respectively	108			101			217			194
Cash Flow Hedges, net of tax:
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $429, $(554), $(327) and $(362), respectively	1,061			(875		)	(728		)	(537		)
Total Other Comprehensive Income (Loss), net of tax	1,155			(786		)	(539		)	(366		)
Comprehensive Income	$	7,542		$	5,260		$	32,702		$	24,824

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	June 30, 2018			December 31, 2017
(in thousands, except shares and per share data)
Property, Plant and Equipment
Regulated Energy	$	1,174,407		$	1,073,736
Unregulated Energy	216,125			210,682
Other businesses and eliminations	30,170			27,699
Total property, plant and equipment	1,420,702			1,312,117
Less: Accumulated depreciation and amortization	(287,942		)	(270,599		)
Plus: Construction work in progress	101,904			84,509
Net property, plant and equipment	1,234,664			1,126,027
Current Assets
Cash and cash equivalents	4,512			5,614
Trade and other receivables (less allowance for uncollectible accounts of $1,076 and $936, respectively)	53,419			77,223
Accrued revenue	12,353			22,279
Propane inventory, at average cost	6,597			8,324
Other inventory, at average cost	4,791			12,022
Regulatory assets	13,330			10,930
Storage gas prepayments	4,365			5,250
Income taxes receivable	6,420			14,778
Prepaid expenses	5,162			13,621
Derivative assets, at fair value	534			1,286
Other current assets	4,560			7,260
Total current assets	116,043			178,587
Deferred Charges and Other Assets
Goodwill	19,604			19,604
Other intangible assets, net	4,277			4,686
Investments, at fair value	7,486			6,756
Regulatory assets	76,427			75,575
Other assets	4,440			3,699
Total deferred charges and other assets	112,234			110,320
Total Assets	$	1,462,941		$	1,414,934

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

- 3

Table of Contents

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Balance Sheets (Unaudited)



Capitalization and Liabilities	June 30, 2018			December 31, 2017
(in thousands, except shares and per share data)
Capitalization
Stockholders’ equity
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding	$	—		$	—
Common stock, par value $0.4867 per share (authorized 50,000,000 shares)	7,971			7,955
Additional paid-in capital	255,356			253,470
Retained earnings	250,377			229,141
Accumulated other comprehensive loss	(5,718		)	(4,272		)
Deferred compensation obligation	3,782			3,395
Treasury stock	(3,782		)	(3,395		)
Total stockholders’ equity	507,986			486,294
Long-term debt, net of current maturities	241,596			197,395
Total capitalization	749,582			683,689
Current Liabilities
Current portion of long-term debt	9,977			9,421
Short-term borrowing	235,288			250,969
Accounts payable	60,769			74,688
Customer deposits and refunds	32,018			34,751
Accrued interest	1,891			1,742
Dividends payable	6,060			5,312
Accrued compensation	7,953			13,112
Regulatory liabilities	22,194			6,485
Derivative liabilities, at fair value	886			6,247
Other accrued liabilities	11,495			10,273
Total current liabilities	388,531			413,000
Deferred Credits and Other Liabilities
Deferred income taxes	143,147			135,850
Regulatory liabilities	141,499			140,978
Environmental liabilities	8,090			8,263
Other pension and benefit costs	28,996			29,699
Deferred investment tax credits and other liabilities	3,096			3,455
Total deferred credits and other liabilities	324,828			318,245
Environmental and other commitments and contingencies (Note 5 and 6)
Total Capitalization and Liabilities	$	1,462,941		$	1,414,934

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

- 4

Table of Contents

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Cash Flows (Unaudited)



	Six Months Ended
	June 30,
	2018			2017
(in thousands)
Operating Activities
Net income	$	33,241		$	25,190
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	19,543			17,906
Depreciation and accretion included in other costs	4,428			3,939
Deferred income taxes	7,668			12,034
Realized loss on commodity contracts/sale of assets/investments	3,857			2,223
Unrealized (gain) loss on investments/commodity contracts	(114		)	184
Employee benefits and compensation	456			819
Share-based compensation	2,247			812
Other, net	(23		)	(17		)
Changes in assets and liabilities:
Accounts receivable and accrued revenue	32,230			26,862
Propane inventory, storage gas and other inventory	9,844			(2,543		)
Regulatory assets/liabilities, net	11,035			4,255
Prepaid expenses and other current assets	11,523			2,129
Accounts payable and other accrued liabilities	(26,152		)	(280		)
Income taxes receivable	8,358			8,500
Customer deposits and refunds	(2,733		)	1,487
Accrued compensation	(5,196		)	(3,876		)
Other assets and liabilities, net	(1,860		)	(3,254		)
Net cash provided by operating activities	108,352			96,370
Investing Activities
Property, plant and equipment expenditures	(126,811		)	(88,627		)
Proceeds from sales of assets	323			185
Environmental expenditures	(173		)	(135		)
Net cash used in investing activities	(126,661		)	(88,577		)
Financing Activities
Common stock dividends	(10,301		)	(9,636		)
(Purchase) issuance of stock under the Dividend Reinvestment Plan	(328		)	421
Tax withholding payments related to net settled stock compensation	(1,210		)	(692		)
Change in cash overdrafts due to outstanding checks	632			(2,370		)
Net repayment under line of credit agreements and short-term borrowing under the Revolver	(16,313		)	(61,910		)
Proceeds from long-term debt and long-term borrowing under the Revolver	74,916			69,800
Repayment of long-term debt, long-term borrowing under the Revolver and capital lease obligation	(30,189		)	(5,165		)
Net cash provided (used) in financing activities	17,207			(9,552		)
Net Decrease in Cash and Cash Equivalents	(1,102		)	(1,759		)
Cash and Cash Equivalents—Beginning of Period	5,614			4,178
Cash and Cash Equivalents—End of Period	$	4,512		$	2,419

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

- 5

Table of Contents

Chesapeake Utilities Corporation and Subsidiaries

Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)



	Common Stock ⁽¹⁾
(in thousands, except shares and per share data)	Number of Shares⁽²⁾	Par Value		Additional Paid-In Capital			Retained Earnings			Accumulated Other Comprehensive Loss			Deferred Compensation		Treasury Stock			Total
Balance at December 31, 2016	16,303,499	$	7,935	$	250,967		$	192,062		$	(4,878	)	$	2,416	$	(2,416	)	$	446,086
Net income	—	—		—			58,124			—			—		—			58,124
Other comprehensive income	—	—		—			—			606			—		—			606
Dividend declared ($1.28 per share)	—	—		—			(21,045		)	—			—		—			(21,045		)
Dividend reinvestment plan	10,771	5		730			—			—			—		—			735
Stock issuance	—	—		(10		)	—			—			—		—			(10		)
Share-based compensation and tax benefit ⁽³⁾⁽⁴⁾	30,172	15		1,783			—			—			—		—			1,798
Treasury stock activities	—	—		—			—			—			979		(979		)	—
Balance at December 31, 2017	16,344,442	7,955		253,470			229,141			(4,272		)	3,395		(3,395		)	486,294
Net income	—	—		—			33,241			—			—		—			33,241
Cumulative effect of the adoption of ASU 2014-09	—	—		—			(1,498		)	—			—		—			(1,498		)
Reclassification upon the adoption of ASU 2018-02	—	—		—			907			(907		)	—		—			—
Other comprehensive loss	—	—		—			—			(539		)	—		—			(539		)
Dividend declared ($0.6950 per share)	—	—		—			(11,414		)	—			—		—			(11,414		)
Dividend reinvestment plan	—	—		(2		)	—			—			—		—			(2		)
Share-based compensation and tax benefit ⁽³⁾ ⁽⁴⁾	34,103	16		1,888			—			—			—		—			1,904
Treasury stock activities	—	—		—			—			—			387		(387		)	—
Balance at June 30, 2018	16,378,545	$	7,971	$	255,356		$	250,377		$	(5,718	)	$	3,782	$	(3,782	)	$	507,986


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


⁽²⁾	Includes 96,204 and 90,961 shares at June 30, 2018 and December 31, 2017, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.


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


⁽⁴⁾	The shares issued under the SICP are net of shares withheld for employee taxes. For the six months ended June 30, 2018, and for the year ended December 31, 2017, we withheld 16,918 and 10,269 shares, respectively, for taxes.

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

- 6

Table of Contents

NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)

1. Summary of Accounting Policies

Basis of Presentation

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2017. In the opinion of management, these financial statements reflect normal recurring adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

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

ARM, Chipola and Central Gas Asset Acquisitions

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

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

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

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

FASB Statements and Other Authoritative Pronouncements

Recently Adopted Accounting Standards

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

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

- 7

Table of Contents

The following highlights the impact of the adoption of ASC 606 on our condensed consolidated income statements for the three and six months ended June 30, 2018 and condensed consolidated balance sheet as of June 30, 2018:



	Three months ended June 30, 2018							Six months ended June 30, 2018
Income statement	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)			As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Regulated Energy operating revenues	$	70,504	$	70,728	$	(224	)	$	179,897	$	180,780	$	(883	)
Regulated Energy cost of sales	20,010		20,139		(129		)	68,241		68,942		(701		)
Depreciation and amortization	9,839		9,832		7			19,543		19,521		22
Income before income taxes	9,105		9,207		(102		)	45,915		46,119		(204		)
Income taxes	2,718		2,746		(28		)	12,674		12,733		(59		)
Net income	6,387		6,461		(74		)	33,241		33,386		(145		)



	As of June 30, 2018
Balance sheet	As Reported		Without Adoption of ASC 606		Effect of Change Higher (Lower)
(in thousands)
Assets
Accrued revenues	$	12,353	$	13,659	$	(1,306	)
Other assets	$	4,440	$	4,777	$	(337	)

Capitalization
Retained earnings	$	250,377	$	248,734	$	1,643

The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $204,000 in revenue in the first six months of 2018 to future years and a cumulative adjustment that decreased retained earnings and other assets by $1.6 million at June 30, 2018, associated with a long-term firm transmission contract with an industrial customer.

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

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

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

Income Statement - Reporting Comprehensive Income (ASC 220) - In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification

- 8

Table of Contents

from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. We adopted ASU 2018-02 on January 1, 2018 and reclassified stranded tax effects from accumulated other comprehensive loss related to our employee benefit plans and commodity contract cash flows hedges. Implementation of this new standard did not have a material impact on our financial position and results of operations. See Note 8, Stockholders' Equity, for additional information.

Recent Accounting Standards Yet to be Adopted

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

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


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


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

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

Other practical expedients that can be elected individually are:


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


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

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

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

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

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

- 9

Table of Contents

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


2.	Calculation of Earnings Per Share



	Three Months Ended				Six Months Ended
	June 30,				June 30,
	2018		2017		2018		2017
(in thousands, except shares and per share data)
Calculation of Basic Earnings Per Share:

Net Income	$	6,387	$	6,046	$	33,241	$	25,190
Weighted average shares outstanding	16,369,641		16,340,665		16,360,540		16,329,009
Basic Earnings Per Share	$	0.39	$	0.37	$	2.03	$	1.54

Calculation of Diluted Earnings Per Share:
Reconciliation of Numerator:
Net Income	$	6,387	$	6,046	$	33,241	$	25,190
Reconciliation of Denominator:
Weighted shares outstanding—Basic	16,369,641		16,340,665		16,360,540		16,329,009
Effect of dilutive securities—Share-based compensation	47,441		41,542		49,521		44,029
Adjusted denominator—Diluted	16,417,082		16,382,207		16,410,061		16,373,038
Diluted Earnings Per Share	$	0.39	$	0.37	$	2.03	$	1.54

3. Revenue Recognition

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

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

- 10

Table of Contents



	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Florida natural gas division	$	6,317		$	—		$	—		$	6,317
Delaware natural gas division	11,882			—			—			11,882
FPU electric distribution	18,362			—			—			18,362
FPU natural gas distribution	18,281			—			—			18,281
Maryland natural gas division	4,001			—			—			4,001
Sandpiper	4,367			—			—			4,367
Total energy distribution	63,210			—			—			63,210

Energy transmission
Aspire Energy	—			5,854			—			5,854
Eastern Shore	14,502			—			—			14,502
Peninsula Pipeline	2,968			—			—			2,968
Total energy transmission	17,470			5,854			—			23,324

Energy generation
Eight Flags	—			4,230			—			4,230

Propane delivery
Delmarva Peninsula propane delivery	—			15,264			—			15,264
Florida propane delivery	—			4,942			—			4,942
Total propane delivery	—			20,206			—			20,206

Energy services
PESCO	—			48,798			—			48,798

Other and eliminations
Eliminations	(10,176		)	(3,248		)	(10,379		)	(23,803		)
Other	—			505			194			699
Total other and eliminations	(10,176		)	(2,743		)	(10,185		)	(23,104		)

Total operating revenues⁽¹⁾	$	70,504		$	76,345		$	(10,185	)	$	136,664

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $(356,000) and $82,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to weather normalization for Maryland division and Sandpiper and late fees.

- 11

Table of Contents

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



	Regulated Energy			Unregulated Energy			Other and Eliminations			Total
Energy distribution
Florida natural gas division	$	12,180		$	—		$	—		$	12,180
Delaware natural gas division	43,954			—			—			43,954
FPU electric distribution	37,103			—			—			37,103
FPU natural gas distribution	41,494			—			—			41,494
Maryland natural gas division	14,673			—			—			14,673
Sandpiper	13,331			—			—			13,331
Total energy distribution	162,735			—			—			162,735

Energy transmission
Aspire Energy	—			17,931			—			17,931
Eastern Shore	30,100			—			—			30,100
Peninsula Pipeline	5,065			—			—			5,065
Total energy transmission	35,165			17,931			—			53,096

Energy generation
Eight Flags	—			8,608			—			8,608

Propane delivery
Delmarva Peninsula propane delivery	—			60,735			—			60,735
Florida propane delivery	—			11,576			—			11,576
Total propane delivery	—			72,311			—			72,311

Energy services
PESCO	—			130,357			—			130,357

Other and eliminations
Eliminations	(18,003		)	(8,494		)	(25,976		)	(52,473		)
Other	—			999			387			1,386
Total other and eliminations	(18,003		)	(7,495		)	(25,589		)	(51,087		)

Total operating revenues⁽¹⁾	$	179,897		$	221,712		$	(25,589	)	$	376,020

⁽¹⁾ Includes other revenue (revenues from sources other than contracts with customers) of $(945,000) and $155,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to weather normalization for Maryland division and Sandpiper and late fees.

Regulated Energy segment

The businesses within our Regulated Energy segment are regulated utilities whose operations and customer contracts are subject to rates approved by the state PSC or the FERC.

Our energy distribution operations deliver natural gas or electricity to customers and we bill the customers for both the delivery of natural gas or electricity and the related commodity, where applicable. In most jurisdictions, our customers are also required to purchase the commodity from us, although certain customers in some jurisdictions may purchase the commodity from a third-party retailer (in which case we provide delivery service only). We consider the delivery of natural gas or electricity and/or the related commodity sale as one performance obligation because the commodity and its delivery are highly interrelated with two-way dependency on one another. Our performance obligation is satisfied over time as natural gas or electricity is delivered and consumed by the customer. We recognize revenues based on monthly meter readings, which are based on the quantity of natural gas or electricity used and the approved rates. We accrue

- 12

Table of Contents

unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period to the extent that billing and delivery do not coincide.

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

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

Unregulated Energy segment

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

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

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

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

- 13

Table of Contents

Contract balances

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




	Trade Receivables			Contract Assets (Non-current)		Contract Liabilities (Current)
in thousands
Balance at 12/31/2017	$	74,962		$	1,270	$	407
Balance at 6/30/2018	51,511			1,967		175
Increase (decrease)	$	(23,451	)	$	697	$	(232	)

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

At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. At June 30, 2018 and December 31, 2017, we had a contract liability, which was included in other accrued liabilities in the condensed consolidated balance sheet, of $175,000 and $407,000, respectively, and which relates to non-refundable prepaid fixed fees for our Delmarva Peninsula propane delivery operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the three and six months ended June 30, 2018, we recognized revenue of $84,000 and $336,000, respectively.

Practical expedients

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

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


4.	Rates and Other Regulatory Activities

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

Delaware

Effect of the TCJA on rate payers: As a result of the enactment of the TCJA, the Delaware PSC issued an order requiring all rate-regulated utilities to file estimates of the impact of the TCJA on their cost of service for the most recent test year available (including new rate schedules). The order also required utilities to propose procedures for changing rates to reflect those impacts on or before March 31, 2018. Our Delaware Division filed the requisite reports with the Delaware PSC on March 30, 2018. Subsequently, the Delaware Division filed an updated report reflecting the impact of the TCJA on May 31, 2018. If, after reviewing the required filing, the Delaware PSC determines to reduce our rates, it will open a new docket and establish a procedural schedule for conducting an evidentiary hearing regarding the impacts of the TCJA on our operations and existing rates.

In addition, on February 1, 2018, the Delaware PSC issued an order requiring Delaware rate-regulated public utilities to accrue regulatory liabilities reflecting the jurisdictional revenue requirement impacts of changes in the federal corporate

- 14

Table of Contents

income tax laws. In compliance with this order, we have established a regulatory liability to reflect the estimated impacts of the changes in the federal corporate income tax rate. We believe that the ultimate impact of the TCJA on rates charged by our Delaware Division will not have a material effect on our financial position or results of operations.

Underserved Area Rates: In December 2017, we filed an application for approval of natural gas expansion service offerings. We requested authorization to utilize existing expansion area tariff rates to serve customers located outside of the current Sussex County, Delaware expansion area boundaries that cannot be economically served under the regular tariff rates. In June 2018, we reached a settlement agreement with the relevant parties, which allows us to utilize higher rates for areas outside of our existing expansion area. The settlement agreement was presented before the Delaware PSC at its public meeting on July 10, 2018, where it was unanimously passed.

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

Maryland Division and Sandpiper

Effect of the TCJA on rate payers: The Maryland PSC issued an order requiring all Maryland public utilities whose rates are explicitly grossed-up for income taxes to track the impacts of the TCJA beginning January 1, 2018. The order required utilities to: (a) apply regulatory accounting treatment, which includes the use of regulatory assets and liabilities, for all impacts of the TCJA; (b) file an explanation of the expected effects of the TCJA on their expenses and revenues; and (c) explain when and how they expect to pass on to their customers the net results of those effects. We established a regulatory liability to reflect the impacts of the changes in the federal corporate income tax rate in compliance with the Maryland PSC’s order. In addition, our Maryland Division and Sandpiper made compliance filings that included preliminary estimates of the annual impact of the change in the statutory federal income tax rate from 35 percent to 21 percent. In April 2018, the Maryland PSC ordered both the Maryland Division and Sandpiper to implement reduced rates effective May 1, 2018 reflecting the impact of the TCJA. We implemented a one-time bill credit for the regulatory liability established for the refunds and issued the refunds to customers in June. We must also submit an informational filing to the Maryland PSC within 60 days of the refund payment date. Additionally, pursuant to the Maryland PSC’s order, if in the future the Maryland Division or Sandpiper identify any additional tax savings, we must submit an additional filing to the Maryland PSC in order to return those savings to customers as soon as possible. We believe that the ultimate impact of the TCJA on rates charged by our Maryland Division and Sandpiper will not have a material effect on our financial position or results of operations.

Florida

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

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

Effect of the TCJA on ratepayers: The Office of Public Counsel filed a petition requesting that the Florida PSC establish a general docket to investigate and adjust rates for all investor-owned utilities related to the passage of the TCJA. The Florida PSC issued a Memorandum with a recommendation that, if utilities do not agree to a January 1, 2018 effective date, then the effective date should be February 6, 2018. On January 30, 2018, the Florida PSC scheduled informal meetings between its staff and interested persons to discuss the impact of the TCJA. Hearings for Florida’s electric utilities

- 15

Table of Contents

are tentatively scheduled for the first quarter of 2019 and hearings for the natural gas utilities are tentatively scheduled for the fourth quarter of 2018.

In December 2017, the Florida PSC issued an order regarding the limited proceeding for FPU's electric division, which prescribes the applicability, timing and treatment of the implications of the TCJA, as discussed above. In June, each of our Florida natural gas operations filed a petition and testimony in support of the disposition of the impacts created by the TCJA. We believe that the ultimate impact of the TCJA on rates charged by FPU's electric division and our Florida natural gas operations will not have a material effect on our financial position or results of operations.

Eastern Shore

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

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

In December 2017, the TETLP interconnect upgrade was placed into service. In June 2018, the Fair Hill Loop in Chester County, Pennsylvania and Cecil County, Maryland was placed into service. With the exception of some minor facilities, the remaining segments of the 2017 Expansion Project are expected to be placed into service in various phases during the remainder of 2018.

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

In August 2017, Eastern Shore implemented new rates, subject to refund, based on the outcome of the rate proceeding. Eastern Shore recorded incremental revenue of approximately $3.7 million for the year ended December 31, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates until the rate case settlement is approved by the FERC and customers receive refunds according to the terms of the settlement agreement. Eastern Shore filed an uncontested settlement agreement and a motion to place interim settlement rates into effect beginning on January 1, 2018. The FERC approved the settlement agreement in February 2018, and it became final in March 2018. Exclusive of the TCJA impact, base rates would have increased, on an annual basis, by approximately $9.8 million.

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

In March 2018, the FERC issued a Notice of Proposed Rulemaking that proposed a process to determine which jurisdictional natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the TCJA and changes to the FERC’s income tax allowance policies following the United Airlines, Inc. v. FERC decision. The Notice of Proposed Rulemaking proposed requiring interstate natural gas pipelines to provide an informational filing to allow the FERC to evaluate the impact of the TCJA on the pipelines’ revenue requirement. In April 2018, Eastern Shore filed comments in this proceeding requesting confirmation that Eastern Shore is not required to provide an informational filing because it has already implemented lower rates in accordance with the settlement agreement in its 2017 rate case approved by the FERC. In July 2018, the FERC issued a final rule, which largely adopted the process proposed in the Notice of Proposed Rulemaking requiring all interstate natural gas companies

- 16

Table of Contents

to file an informational filing for the purpose of evaluating the impact of the TCJA and the United Airlines, Inc. v. FERC decision on interstate natural gas pipelines’ revenue requirements. The final rule provides that an individual pipeline has the option to request a waiver if the pre-March 2018 settlement justifies not adjusting its rates at this time. We plan to file such a request. We believe that the ultimate resolution of this matter will not have a material effect on Eastern Shore’s financial position or results of operations.

5. Environmental Commitments and Contingencies

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

MGP Sites

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

As of June 30, 2018, we had approximately $9.5 million in environmental liabilities related to FPU’s MGP sites in Key West, Pensacola, Sanford and West Palm Beach, Florida. FPU has approval to recover, from insurance and from customers through rates, up to $14.0 million of its environmental costs related to its MGP sites. Approximately $11.3 million has been recovered as of June 30, 2018, leaving approximately $2.7 million in regulatory assets for future recovery of environmental costs from FPU’s customers.

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

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

- 17

Table of Contents



Jurisdiction	MGP Site	Status	Cost to Clean up	Recovery through Rates
Florida	West Palm Beach	Remedial actions approved by the FDEP have been implemented on the east parcel of the site. We expect to implement similar remedial actions on other remaining portions, including the anticipated demolition of buildings on the site's west parcel in 2018.	Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the properties.	Yes
Florida	Sanford	In March 2018, the EPA approved a "site-wide ready for anticipated use" status, which is the final step before delisting a site. Construction has been completed and restrictive covenants are in place to ensure protection of human health. The only remaining activity is long-term groundwater monitoring. It is unlikely that FPU will incur any significant future costs associated with the site.	FPU's remaining remediation expenses, including attorneys' fees and costs, are anticipated to be less than $10,000.	Yes
Florida	Winter Haven	Remediation is ongoing.	Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site.	Yes
Delaware	Seaford	Proposed plan for implementation approved by the DNREC in July 2017. Site assessment is ongoing.	Between $273,000 and $465,000.	Yes
Maryland	Cambridge	Currently in discussions with the MDE.	Unable to estimate.	N/A


6.	Other Commitments and Contingencies

Natural Gas, Electric and Propane Supply

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

In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term ending in May 2019. Sandpiper's current annual commitment is approximately 2.2 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.

Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a six-year term ending in May 2019. Sharp's current annual commitment is approximately 2.2 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.

- 18

Table of Contents

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

FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with FPL requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If FPU fails to meet this ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2 times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of June 30, 2018, FPU was in compliance with all of the requirements of its fuel supply contracts.

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

Corporate Guarantees

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily PESCO. These corporate guarantees provide for the payment of natural gas purchases in the event that PESCO defaults. PESCO has never defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at June 30, 2018 was approximately $72.5 million, with the guarantees expiring on various dates through June 2019.

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

Letters of Credit

As of June 30, 2018, we have issued letters of credit totaling approximately $5.0 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, the payment of natural gas purchases for PESCO, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through December 2019. There have been no draws on these letters of credit as of June 30, 2018. We do not anticipate that the counterparties will draw upon these letters of credit, and we expect that the letters of credit will be renewed to the extent necessary in the future.

Other

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


7.	Segment Information

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

Our operations are comprised of two reportable segments:


•	Regulated Energy. Includes energy distribution and transmission services (natural gas distribution, natural gas transmission and electric distribution operations). All operations in this segment are regulated, as to their rates

- 19

Table of Contents

and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.

•

Unregulated Energy. Includes energy transmission, energy generation, propane delivery, and other energy services (propane distribution, the operations of our Eight Flags' CHP plant, as well as natural gas marketing, gathering, processing, transportation and supply). These operations are unregulated as to their rates and services. Through March 2017, this segment also included the operations of Xeron, our propane and crude oil trading subsidiary that wound down its operations shortly after the first quarter of 2017. Also included in this segment are other unregulated energy services, such as energy-related merchandise sales and heating, ventilation and air conditioning, plumbing and electrical services.

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

The following table presents financial information about our reportable segments:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy segment	$	67,731		$	68,815		$	173,685		$	165,261
Unregulated Energy segment and other businesses	68,933			56,269			202,335			144,983
Total operating revenues, unaffiliated customers	$	136,664		$	125,084		$	376,020		$	310,244
Intersegment Revenues ⁽¹⁾
Regulated Energy segment	$	2,773		$	2,181		$	6,212		$	3,389
Unregulated Energy segment	7,412			6,780			19,377			10,791
Other businesses	194			159			387			387
Total intersegment revenues	$	10,379		$	9,120		$	25,976		$	14,567
Operating Income
Regulated Energy segment	$	14,304		$	14,086		$	41,015		$	37,481
Unregulated Energy segment	490			2			14,174			11,577
Other businesses and eliminations	(1,546		)	(27		)	(1,535		)	102
Total operating income	13,248			14,061			53,654			49,160
Other expense, net	(262		)	(1,002		)	(194		)	(1,703		)
Interest charges	3,881			3,073			7,545			5,811
Income before Income Taxes	9,105			9,986			45,915			41,646
Income taxes	2,718			3,940			12,674			16,456
Net Income	$	6,387		$	6,046		$	33,241		$	25,190


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



(in thousands)	June 30, 2018		December 31, 2017
Identifiable Assets
Regulated Energy segment	$	1,199,672	$	1,121,673
Unregulated Energy segment	227,191		259,041
Other businesses and eliminations	36,078		34,220
Total identifiable assets	$	1,462,941	$	1,414,934

Our operations are entirely domestic.

- 20

Table of Contents


8.	Stockholder's Equity

Preferred Stock

We had 2,000,000 authorized and unissued shares of preferred stock, $0.01 par value per share, as of June 30, 2018 and December 31, 2017. Shares of preferred stock may be issued from time to time, by authorization of our Board of Directors and without the necessity of further action or authorization by stockholders, in one or more series and with such voting powers, designations, preferences and relative, participating, optional or other special rights and qualifications as the Board of Directors may, in its discretion, determine.

Accumulated Other Comprehensive Loss

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

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



	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2017	$	(4,743	)	$	471		$	(4,272	)
Other comprehensive loss before reclassifications	—			(1,440		)	(1,440		)
Amounts reclassified from accumulated other comprehensive income	189			712			901
Net current-period other comprehensive income/(loss)	189			(728		)	(539		)
Stranded tax reclassification to retained earnings	(1,022		)	115			(907		)
As of June 30, 2018	$	(5,576	)	$	(142	)	$	(5,718	)

- 21

Table of Contents



	Defined Benefit			Commodity
	Pension and			Contracts
	Postretirement			Cash Flow
	Plan Items			Hedges			Total
(in thousands)
As of December 31, 2016	$	(5,360	)	$	482		$	(4,878	)
Other comprehensive (loss)/income before reclassifications	(9		)	837			828
Amounts reclassified from accumulated other comprehensive income/(loss)	180			(1,374		)	(1,194		)
Net prior-period other comprehensive income/(loss)	171			(537		)	(366		)
As of June 30, 2017	$	(5,189	)	$	(55	)	$	(5,244	)

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit ⁽¹⁾	$	19		$	20		$	39		$	39
Net loss⁽¹⁾	(149		)	(170		)	(297		)	(339		)
Total before income taxes	(130		)	(150		)	(258		)	(300		)
Income tax benefit	36			61			69			120
Net of tax	$	(94	)	$	(89	)	$	(189	)	$	(180	)

Gains and losses on commodity contracts cash flow hedges:
Propane swap agreements ⁽²⁾	$	(181	)	$	77		$	(645	)	$	465
Natural gas swaps ⁽²⁾	(31		)	—			(481		)	—
Natural gas futures ⁽²⁾	(161		)	631			137			1,781
Total before income taxes	(373		)	708			(989		)	2,246
Income tax benefit (expense)	105			(273		)	277			(872		)
Net of tax	(268		)	435			(712		)	1,374
Total reclassifications for the period	$	(362	)	$	346		$	(901	)	$	1,194

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

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

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

- 22

Table of Contents


9.	Employee Benefit Plans

Net periodic benefit costs for our pension and post-retirement benefits plans for the three and six months ended June 30, 2018 and 2017 are set forth in the following tables:



	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Three Months Ended June 30,	2018			2017			2018			2017			2018		2017		2018			2017			2018		2017
(in thousands)
Interest cost	$	98		$	103		$	592		$	624		$	21	$	22	$	9		$	11		$	13	$	13
Expected return on plan assets	(138		)	(127		)	(774		)	(700		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(19		)	(20		)	—		—
Amortization of net loss	88			106			108			131			25		22		15			17			—		—
Net periodic cost (benefit) ⁽¹⁾	48			82			(74		)	55			46		44		5			8			13		13
Amortization of pre-merger regulatory asset	—			—			191			191			—		—		—			—			2		2
Total periodic cost	$	48		$	82		$	117		$	246		$	46	$	44	$	5		$	8		$	15	$	15



	Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP				Chesapeake Postretirement Plan						FPU Medical Plan
For the Six Months Ended June 30,	2018			2017			2018			2017			2018		2017		2018			2017			2018		2017
(in thousands)
Interest cost	$	195		$	206		$	1,184		$	1,247		$	42	$	44	$	19		$	21		$	26	$	26
Expected return on plan assets	(276		)	(254		)	(1,549		)	(1,399		)	—		—		—			—			—		—
Amortization of prior service credit	—			—			—			—			—		—		(39		)	(39		)	—		—
Amortization of net loss	176			213			217			262			50		44		30			32			—		—
Net periodic cost (benefit) ⁽¹⁾	95			165			(148		)	110			92		88		10			14			26		26
Amortization of pre-merger regulatory asset	—			—			381			381			—		—		—			—			4		4
Total periodic cost	$	95		$	165		$	233		$	491		$	92	$	88	$	10		$	14		$	30	$	30

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

We expect to record pension and postretirement benefit costs of approximately $913,000 for 2018. Included in these costs is approximately $769,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations for the changes in funded status that occurred, but were not recognized, as part of net periodic benefit costs prior to the FPU merger in 2009. This was deferred as a regulatory asset by FPU prior to the merger, to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was approximately $942,000 and approximately $1.3 million at June 30, 2018 and December 31, 2017, respectively.

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

- 23

Table of Contents

The following tables present the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three months ended June 30, 2018 and 2017:



For the Three Months Ended June 30, 2018	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(19	)	$	—	$	(19	)
Net loss	88		108		25		15			—		236
Total recognized in net periodic benefit cost	88		108		25		(4		)	—		217
Recognized from accumulated other comprehensive loss ⁽¹⁾	88		21		25		(4		)	—		130
Recognized from regulatory asset	—		87		—		—			—		87
Total	$	88	$	108	$	25	$	(4	)	$	—	$	217



For the Three Months Ended June 30, 2017	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(20	)	$	—	$	(20	)
Net loss	106		131		22		17			—		276
Total recognized in net periodic benefit cost	106		131		22		(3		)	—		256
Recognized from accumulated other comprehensive loss ⁽¹⁾	106		25		22		(3		)	—		150
Recognized from regulatory asset	—		106		—		—			—		106
Total	$	106	$	131	$	22	$	(3	)	$	—	$	256



For the Six Months Ended June 30, 2018	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(39	)	$	—	$	(39	)
Net loss	176		217		50		30			—		473
Total recognized in net periodic benefit cost	176		217		50		(9		)	—		434
Recognized from accumulated other comprehensive loss ⁽¹⁾	176		41		50		(9		)	—		258
Recognized from regulatory asset	—		176		—		—			—		176
Total	$	176	$	217	$	50	$	(9	)	$	—	$	434

- 24

Table of Contents



For the Six Months Ended June 30, 2017	Chesapeake Pension Plan		FPU Pension Plan		Chesapeake SERP		Chesapeake Postretirement Plan			FPU Medical Plan		Total
(in thousands)
Prior service credit	$	—	$	—	$	—	$	(39	)	$	—	$	(39	)
Net loss	213		262		44		32			—		551
Total recognized in net periodic benefit cost	213		262		44		(7		)	—		512
Recognized from accumulated other comprehensive loss ⁽¹⁾	213		50		44		(7		)	—		300
Recognized from regulatory asset	—		212		—		—			—		212
Total	$	213	$	262	$	44	$	(7	)	$	—	$	512

⁽¹⁾See Note 8, Stockholder's Equity.

During the three and six months ended June 30, 2018, we contributed approximately $126,000 and $198,000, respectively, to the Chesapeake Pension Plan and approximately $539,000 and $848,000, respectively, to the FPU Pension Plan. We expect to contribute a total of approximately $359,000 and approximately $1.5 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2018, which represents the minimum annual contribution payments required.

The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three and six months ended June 30, 2018, were approximately $38,000 and $76,000, respectively. We expect to pay total cash benefits of approximately $151,000 under the Chesapeake SERP in 2018. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for the three and six months ended June 30, 2018, were approximately $7,000 and $18,000, respectively. We estimate that approximately $97,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2018. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and six months ended June 30, 2018, were approximately $13,000 and $24,000, respectively. We estimate that approximately $88,000 will be paid for such benefits under the FPU Medical Plan in 2018.


10.	Investments

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



(in thousands)	June 30, 2018		December 31, 2017
Rabbi trust (associated with the Deferred Compensation Plan)	$	7,465	$	6,734
Investments in equity securities	21		22
Total	$	7,486	6,756

We classify these investments as trading securities and report them at their fair value. For the three months ended June 30, 2018 and 2017, we recorded a net unrealized loss of approximately $158,000 and a net unrealized gain of approximately $181,000, respectively, in other expense, net in the condensed consolidated statements of income related to these investments. For the six months ended June 30, 2018 and 2017, we recorded a net unrealized loss of approximately $113,000 and a net unrealized gain of approximately $433,000, respectively, in other expense, net in the condensed consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust.


11.	Share-Based Compensation

Our non-employee directors and key employees are granted share-based awards through our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the date it was granted and the number of shares to be issued at the end of the service period.

- 25

Table of Contents

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



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018			2017			2018			2017
(in thousands)
Awards to non-employee directors	$	135		$	136		$	269		$	271
Awards to key employees	1,190			37			2,575			541
Total compensation expense	1,325			173			2,844			812
Less: tax benefit	(363		)	(70		)	(779		)	(327		)
Share-based compensation amounts included in net income	$	962		$	103		$	2,065		$	485

Non-employee Directors

Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the grant date. We record a prepaid expense equal to the fair value of the shares issued and amortize the expense equally over a one-year service period. In May 2018, each of our non-employee directors received an annual retainer of 792 shares of common stock under the SICP for service as a director through the 2019 Annual Meeting of Stockholders. The table below presents the summary of the stock activity for awards to non-employee directors for the six months ended June 30, 2018:



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

At June 30, 2018, there was approximately $450,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2019. See Note 1, Summary of Accounting Policies, for additional information regarding ASU 2018-07 and its impact on the accounting for non-employee share-based payments.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the six months ended June 30, 2018:



	Number of Shares		Weighted Average Fair Value
Outstanding—December 31, 2017	132,642		$	59.31
Granted	49,494		$	67.76
Vested	(29,786	)	$	47.39
Vested - Accelerated pursuant to separation agreement⁽¹⁾	(16,676	)	$	75.78
Expired	(3,933	)	$	49.66
Outstanding—June 30, 2018	131,741		$	67.46

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

In February 2018, our Board of Directors granted awards of 49,494 shares of common stock to key employees under the SICP. The shares granted are multi-year awards that will vest at the end of the three-year service period ending December 31, 2020. All of these stock awards are earned based upon the successful achievement of long-term financial results, which comprise market-based and performance-based conditions or targets. The fair value of each performance-

- 26

Table of Contents

based condition or target is equal to the market price of our common stock on the grant date of each award. For the market-based conditions, we used the Black-Scholes pricing model to estimate the fair value of each market-based award granted.

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

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

At June 30, 2018, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $10.5 million. At June 30, 2018, there was approximately $3.2 million of unrecognized compensation cost related to these awards, which is expected to be recognized from 2018 through 2020.

Stock Options

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


12.	Derivative Instruments

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

Hedging Activities in 2018

PESCO enters into natural gas futures contracts associated with the purchase and sale of natural gas to specific customers. These contracts are effective through March 2022, and we designate and account for them as cash flow hedges. There is no ineffective portion of these hedges. At June 30, 2018, PESCO had a total of 16.9 million Dts hedged under natural gas futures contracts, with a liability fair value of approximately $779,000. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss).

In June 2018, Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 1.4 million gallons of propane expected to be purchased from August 2018 through June 2021. Under the futures and swap agreements, Sharp will receive the difference between the index prices (Mont Belvieu prices in August 2018 through June 2021) and the swap prices of $0.76 to $0.875 per gallon, to the extent the index price exceeds the contracted prices. If the index prices are lower than the swap prices, Sharp will pay the difference. At June 30, 2018, the futures and swap agreements had a fair value asset of approximately $18,000 and a fair value liability of $30,000. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss).

Hedging Activities in 2017

In 2017, Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 7.7 million gallons of propane expected to be purchased from October 2017 through March 2019, of which positions covering 1.4 million gallons of forecasted future purchases were outstanding as of June 30, 2018. Under the futures and swap agreements, Sharp will receive the difference between the index prices (Mont Belvieu prices in October 2017 through March 2019) and the swap prices of $0.59 per gallon, to the extent the index price exceeds the contracted price. If the index prices are lower than the swap prices, Sharp will pay the difference. Sharp received

- 27

Table of Contents

approximately $645,000, which represented the difference between the index prices and the contracted prices in 2018 related to hedging activities originated in 2017 and received $11,000, which represented the mark-to-market activities for the three months ended June 30, 2018. At June 30, 2018, the futures and swap agreements had a fair value asset of approximately $306,000. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss).

In August 2017, PESCO entered into natural gas swap agreements associated with financial contracts acquired in the ARM acquisition to mitigate the risk of fluctuations in wholesale natural gas prices associated with 844,000 Dts of natural gas PESCO expects to purchase through January 2020. We accounted for these swap agreements as cash flow hedges, which have a fair value liability of approximately $120,000 at June 30, 2018. The change in fair value of the natural gas swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss).

The impact of PESCO's financial instruments that were not designated as hedges in our consolidated financial statements as of June 30, 2018 was a fair value asset of $90,000 and fair value liability of $77,000, respectively, which was recorded as an increase in gas costs during the six months ended June 30, 2018 associated with 1.1 million and 512,500 Dts of natural gas, respectively.

Balance Sheet Offsetting

PESCO has entered into master netting agreements with counterparties that enable it to net the counterparties' outstanding accounts receivable and payable, which are presented on a net basis in the consolidated balance sheets. The following table summarizes the accounts receivable and payable on a gross and net basis at June 30, 2018 and December 31, 2017:



	At June 30, 2018
(in thousands)	Gross amounts		Amounts offset		Net amounts
Accounts receivable	$	5,723	$	1,288	$	4,435
Accounts payable	$	10,326	$	1,288	$	9,038



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

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

The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of June 30, 2018 and December 31, 2017, are as follows:



	Asset Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Propane swap agreements	Derivative assets, at fair value	$	—	$	13
Natural gas futures contracts	Derivative assets, at fair value	90		—
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative assets, at fair value	120		92
Propane swap agreements	Derivative assets, at fair value	324		1,181
Total asset derivatives		$	534	$	1,286

- 28

Table of Contents



	Liability Derivatives
		Fair Value As Of
(in thousands)	Balance Sheet Location	June 30, 2018		December 31, 2017
Derivatives not designated as hedging instruments
Natural gas futures contracts	Derivative liabilities, at fair value	$	77	$	5,776
Derivatives designated as cash flow hedges
Natural gas futures contracts	Derivative liabilities, at fair value	779		469
Natural gas swap contracts	Derivative liabilities, at fair value	—		2
Propane swap agreements	Derivative liabilities, at fair value	30		—
Total liability derivatives		$	886	$	6,247

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



		Amount of Gain (Loss) on Derivatives:
	Location of Gain	For the Three Months Ended June 30,						For the Six Months Ended June 30,
(in thousands)	(Loss) on Derivatives	2018			2017			2018			2017
Derivatives not designated as hedging instruments
Realized gain on forward contracts and options ⁽¹⁾	Revenue	$	—		$	—		$	—		$	112
Natural gas futures contracts	Cost of sales	(128		)	497			(2,963		)	621
Propane swap agreements	Cost of sales	(4		)	—			(13		)	(4		)
Derivatives designated as fair value hedges
Put /Call option ⁽²⁾	Cost of sales	—			—			—			(9		)
Derivatives designated as cash flow hedges
Propane swap agreements	Cost of sales	(181		)	77			(645		)	465
Propane swap agreements	Other comprehensive loss	106			(218		)	(886		)	(775		)
Natural gas futures contracts	Cost of sales	(161		)	631			137			1,781
Natural gas swap contracts	Cost of sales	(31		)	—			(481		)	—
Natural gas swap contracts	Other comprehensive income	523			—			588			—
Natural gas futures contracts	Other comprehensive loss	861			(1,211		)	(871		)	(124		)
Total		$	985		$	(224	)	$	(5,134	)	$	2,067


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

⁽²⁾

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


13.	Fair Value of Financial Instruments

GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are the following:

Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;

- 29

Table of Contents

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 June 30, 2018 and December 31, 2017:



			Fair Value Measurements Using:
As of June 30, 2018	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	21	$	21	$	—	$	—
Investments—guaranteed income fund	671		—		—		671
Investments—mutual funds and other	6,794		6,794		—		—
Total investments	7,486		6,815		—		671
Derivative assets	534		—		534		—
Total assets	$	8,020	$	6,815	$	534	$	671
Liabilities:
Derivative liabilities	$	886	$	—	$	886	$	—



			Fair Value Measurements Using:
As of December 31, 2017	Fair Value		Quoted Prices in Active Markets (Level 1)		Significant Other Observable Inputs (Level 2)		Significant Unobservable Inputs (Level 3)
(in thousands)
Assets:
Investments—equity securities	$	22	$	22	$	—	$	—
Investments—guaranteed income fund	648		—		—		648
Investments—mutual funds and other	6,086		6,086		—		—
Total investments	6,756		6,108		—		648
Derivative assets	1,286		—		1,286		—
Total assets	$	8,042	$	6,108	$	1,286	$	648
Liabilities:
Derivative liabilities	$	6,247	$	—	$	6,247	$	—

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

Level 1 Fair Value Measurements:

Investments - equity securities — The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.

Investments - mutual funds and other — The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares.

- 30

Table of Contents

Level 2 Fair Value Measurements:

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

Level 3 Fair Value Measurements:

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

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the six months ended June 30, 2018 and 2017:



	Six Months Ended June 30,
	2018			2017
(in thousands)
Beginning Balance	$	648		$	561
Purchases and adjustments	54			65
Transfers	(24		)	—
Distribution	(12		)	—
Investment income	5			4
Ending Balance	$	671		$	630

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

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

Other Financial Assets and Liabilities

Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its short maturities and because interest rates approximate current market rates (Level 3 measurement). At June 30, 2018, long-term debt, including current maturities but excluding a capital lease obligation, had a carrying value of approximately $250.7 million. This compares to a fair value of approximately $250.3 million, using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At December 31, 2017, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of approximately $205.2 million, compared to the estimated fair value of approximately $215.4 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

- 31

Table of Contents


14.	Long-Term Debt

Our outstanding long-term debt is shown below:



	June 30,			December 31,
(in thousands)	2018			2017
FPU secured first mortgage bonds ⁽¹⁾:
9.08% bond, due June 1, 2022	$	7,984		$	7,982
Uncollateralized senior notes:
5.50% note, due October 12, 2020	6,000			6,000
5.93% note, due October 31, 2023	16,500			18,000
5.68% note, due June 30, 2026	23,200			26,100
6.43% note, due May 2, 2028	7,000			7,000
3.73% note, due December 16, 2028	20,000			20,000
3.88% note, due May 15, 2029	50,000			50,000
3.25% note, due April 30, 2032	70,000			70,000
3.48% note, due May 31, 2038	50,000			—
Promissory notes	26			97
Capital lease obligation	1,351			2,070
Less: debt issuance costs	(488		)	(433		)
Total long-term debt	251,573			206,816
Less: current maturities	(9,977		)	(9,421		)
Total long-term debt, net of current maturities	$	241,596		$	197,395

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

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

Shelf Agreements

In October 2015, we entered into the $150.0 million Prudential Shelf Agreement, under which we may request that Prudential purchase up to $150.0 million of our unsecured senior debt. As of June 30, 2018, we have issued $70.0 million of 3.25% Prudential Shelf Notes.

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

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

As of June 30, 2018, we have $230.0 million of additional potential borrowing capacity under the Prudential and MetLife Shelf Agreements. The Prudential Shelf Agreement and the NYL Shelf Agreement set forth certain business covenants to which we are subject when any note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.

- 32

Table of Contents

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

Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K for the year ended December 31, 2017, including the audited consolidated financial statements and notes thereto.

Safe Harbor for Forward-Looking Statements

We make statements in this Quarterly Report on Form 10-Q that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of the Private Securities Litigation Reform Act of 1995. One can typically identify forward-looking statements by the use of forward-looking words, such as “project,” “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “continue,” “potential,” “forecast” or other similar words, or future or conditional verbs such as “may,” “will,” “should,” “would” or “could.” These statements represent our intentions, plans, expectations, assumptions and beliefs about future financial performance, business strategy, projected plans and objectives of the Company. Forward-looking statements speak only as of the date they are made or as of the date indicated and we do not undertake any obligation to update forward-looking statements as a result of new information, future events or otherwise. These statements are subject to many risks, uncertainties and other important factors that could cause actual future results to differ materially from those expressed in the forward-looking statements. In addition to the risk factors described under Item 1A, Risk Factors in our 2017 Annual Report on Form 10-K, such factors include, but are not limited to:


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


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


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


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


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


•	changes in environmental and other laws and regulations to which we are subject and environmental conditions of property that we now, or may in the future, own or operate;


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


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


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


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


•	customers' preferred energy sources;


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


•	the effect of competition on our businesses;


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


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


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


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


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


•	the capital-intensive nature of our regulated energy businesses;


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


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


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


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


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


•	the timing and success of technological improvements; and

- 33

Table of Contents


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

Introduction

We are a diversified energy company engaged, directly or through our operating divisions and subsidiaries, in regulated and unregulated energy businesses. These businesses center around energy distribution, energy transmission, energy generation, propane delivery and other energy services.

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

The key elements of this strategy include:


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


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


•	providing new services in our current service territories;


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


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


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

The following discussions and those later in the document on operating income and segment results include the use of the term “gross margin," which is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased cost of natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities, and excludes depreciation, amortization and accretion. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. We believe that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by us under our allowed rates for regulated energy operations and under our competitive pricing structures for unregulated energy operations. Our management uses gross margin in measuring our business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.

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

- 34

Table of Contents

Results of Operations for the Three and Six Months ended June 30, 2018

Overview

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

Operational Highlights

Our net income for the quarter ended June 30, 2018 was $6.4 million, or $0.39 per share. This represents an increase of $341,000, or $0.02 per share, compared to net income of $6.0 million, or $0.37 per share, reported for the same quarter in 2017. Operating income decreased by $813,000 for the three months ended June 30, 2018, compared to the same period in the prior year, as margin increased by $6.9 million, or 11.3 percent, but was offset by a $1.0 million increase in depreciation, amortization and property taxes and a $6.6 million increase in other operating expenses. The decrease in operating income primarily reflected the impact of the TCJA on margins generated by our regulated energy businesses. During the second quarter, we refunded or reserved for future refunds $2.3 million in margin, which represents a pass-through to regulated energy customers of the $2.3 million benefit from lower Federal income taxes during the quarter. Excluding the estimated customer refunds reserved or refunded during the second quarter of 2018 associated with the TCJA, gross margin and operating income increased by $9.1 million, or 15.1 percent, and $1.5 million, or 10.5 percent, respectively, compared to the same period in the prior year. The decrease in the Federal income tax rate positively impacted earnings in our unregulated energy businesses.



	Three Months Ended
	June 30,						Increase
	2018			2017			(decrease)
(in thousands except per share)
Business Segment:
Regulated Energy segment	$	14,304		$	14,086		$	218
Unregulated Energy segment	490			2			488
Other businesses and eliminations	(1,546		)	(27		)	(1,519		)
Operating Income	$	13,248		$	14,061		$	(813	)
Other expense, net	(262		)	(1,002		)	740
Interest charges	3,881			3,073			808
Pre-tax Income	9,105			9,986			(881		)
Income taxes	2,718			3,940			(1,222		)
Net Income	$	6,387		$	6,046		$	341
Earnings Per Share of Common Stock
Basic	$	0.39		$	0.37		$	0.02
Diluted	$	0.39		$	0.37		$	0.02

- 35

Table of Contents

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



(in thousands, except per share data)	Pre-tax Income			Net Income			Earnings Per Share
Second Quarter of 2017 Reported Results	$	9,986		$	6,046		$	0.37
Adjusting for unusual items:
One-time separation expenses associated with a former executive	(1,548		)	(1,421		)	(0.09		)
Absence of Xeron expenses, including 2017 wind-down expenses	173			122			0.01
	(1,375		)	(1,299		)	(0.08		)

Increased Gross Margins:
Implementation of Eastern Shore settled rates* ⁽¹⁾	2,365			1,659			0.10
TCJA impact - refunds and reserves for future refunds to ratepayers⁽²⁾	(2,284		)	(1,602		)	(0.10		)
Service expansions*	1,652			1,158			0.07
Natural gas growth (including customer and consumption growth but excluding service expansions)	1,575			1,105			0.07
Return to normal weather	1,108			778			0.05
Nonrecurring margin increase at PESCO	1,092			766			0.05
Incremental margin from PESCO operations	592			415			0.03
Unregulated Energy growth excluding PESCO	503			353			0.02
Florida electric reliability/modernization program*	352			247			0.02
GRIP*	306			215			0.01
	7,261			5,094			0.32

Decreased (Increased) Other Operating Expenses:
Higher outside services and facilities maintenance costs ⁽³⁾	(1,602		)	(1,124		)	(0.07		)
Higher payroll expense (increased staffing and annual salary increases) ⁽³⁾	(1,534		)	(1,076		)	(0.07		)
Higher depreciation, asset removal and property tax costs due to new capital investments ⁽³⁾	(848		)	(595		)	(0.04		)
Higher incentive compensation costs (based on period-over-period results) ⁽³⁾	(811		)	(569		)	(0.03		)
Incremental operating expenses for PESCO	(764		)	(536		)	(0.03		)
Higher benefit and other employee-related expenses ⁽³⁾	(365		)	(256		)	(0.02		)
	(5,924		)	(4,156		)	(0.26		)

Interest charges	(808		)	(567		)	(0.03		)
Income taxes - including TCJA impact - decreased effective tax rate	—			1,295			0.08
Net other changes	(35		)	(26		)	(0.01		)
	(843		)	702			0.04

Second Quarter of 2018 Reported Results	$	9,105		$	6,387		$	0.39

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

⁽²⁾ "TCJA impact - refunds and reserves for future refunds to ratepayers" represents the amounts that have already been refunded to customers or reserves established for future refunds to customers in the second quarter of 2018 as a result of lower taxes due to the TCJA. Refunds made to customers are offset by the corresponding decrease in federal income taxes and are expected to have no net impact on net income.

⁽³⁾Excluding incremental operating expenses at PESCO.

*See the Major Projects and Initiatives table.

- 36

Table of Contents

Our net income for the six months ended June 30, 2018 was $33.2 million, or $2.03 per share. This represents an increase of $8.0 million, or $0.49 per share, compared to net income of $25.2 million, or $1.54 per share, reported for the same period in 2017. Operating income increased by $4.5 million for the six months ended June 30, 2018, compared to the same period in the prior year. This increase was driven by a $14.0 million, or 9.7 percent, increase in gross margin, which was partially offset by a $2.2 million increase in depreciation, amortization and property taxes and a $5.7 million increase in other operating expenses. Excluding the estimated customer refunds reserved or refunded to customers for the six months ended June 30, 2018 associated with the TCJA, gross margin and operating income increased by $19.4 million, or 13.4 percent, and $9.9 million, or 20.2 percent, respectively, compared to the same period in the prior year. The decrease in the Federal income tax rate positively impacted earnings in our unregulated energy businesses.



	Six Months Ended
	June 30,						Increase
	2018			2017			(decrease)
(in thousands except per share)
Business Segment:
Regulated Energy segment	$	41,015		$	37,481		$	3,534
Unregulated Energy segment	14,174			11,577			2,597
Other businesses and eliminations	(1,535		)	102			(1,637		)
Operating Income	$	53,654		$	49,160		$	4,494
Other expense, net	(194		)	(1,703		)	1,509
Interest charges	7,545			5,811			1,734
Pre-tax Income	45,915			41,646			4,269
Income taxes	12,674			16,456			(3,782		)
Net Income	$	33,241		$	25,190		$	8,051
Earnings Per Share of Common Stock
Basic	$	2.03		$	1.54		$	0.49
Diluted	$	2.03		$	1.54		$	0.49

- 37

Table of Contents

Key variances, between the six months ended 2018 and the six months ended 2017, included:



(in thousands, except per share data)	Pre-tax Income			Net Income			Earnings Per Share
Six Months Ended June 30, 2017 Reported Results	$	41,646		$	25,190		$	1.54
Adjusting for unusual items:
One-time separation expenses associated with a former executive	(1,548		)	(1,421		)	(0.09		)
Absence of Xeron expenses, including 2017 wind-down expenses	870			630			0.04
	(678		)	(791		)	(0.05		)

Increased Gross Margins:
TCJA impact - refunds and reserves for future refunds to ratepayers⁽²⁾	(5,421		)	(3,925		)	(0.24		)
Return to normal weather	5,159			3,735			0.23
Implementation of Eastern Shore settled rates* ⁽¹⁾	5,095			3,689			0.22
Natural gas growth (including customer and consumption growth but excluding service expansions)	3,342			2,420			0.15
Service expansions*	2,316			1,677			0.10
Unregulated Energy growth excluding PESCO	2,044			1,480			0.09
Nonrecurring margin decrease at PESCO	(863		)	(625		)	(0.04		)
Florida electric reliability/modernization program*	767			555			0.03
GRIP*	602			436			0.03
Incremental margin from PESCO operations	255			185			0.01
	13,296			9,627			0.58

Decreased (Increased) Other Operating Expenses:
Higher payroll expense (increased staffing and annual salary increases) ⁽³⁾	(2,395		)	(1,734		)	(0.11		)
Higher depreciation, asset removal and property tax costs due to new capital investments ⁽³⁾	(1,949		)	(1,411		)	(0.09		)
Incremental operating expenses for PESCO	(1,715		)	(1,242		)	(0.08		)
Higher facilities maintenance costs ⁽³⁾	(1,554		)	(1,125		)	(0.07		)
Lower regulatory and outside services costs ⁽³⁾	1,298			940			0.06
Higher incentive compensation costs (based on period-over-period results) ⁽³⁾	(1,187		)	(859		)	(0.05		)
	(7,502		)	(5,431		)	(0.34		)

Interest charges	(1,734		)	(1,255		)	(0.08		)
Income taxes - including TCJA impact - decreased effective tax rate	—			5,262			0.32
Net other changes	887			639			0.06
	(847		)	4,646			0.30

Six Months Ended June 30, 2018 Reported Results	$	45,915		$	33,241		$	2.03

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

⁽²⁾ "TCJA impact - refunds and reserves for future refunds to ratepayers" represents amounts that have already been refunded to customers or reserves established for future refunds to customers in the first six months of 2018 as a result of lower taxes due to the TCJA. Refunds made to customers are offset by the corresponding decrease in federal income taxes and are expected to have no net impact on net income.

⁽³⁾Excluding incremental operating expenses at PESCO.

*See the Major Projects and Initiatives table.

- 38

Table of Contents

Summary of Key Factors

Recently Completed and Ongoing Major Projects and Initiatives

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



	Gross Margin for the Period
	Three Months Ended				Six Months Ended				Year Ended		Estimate for
	June 30,				June 30,				December 31,		Fiscal
in thousands	2018		2017		2018		2017		2017		2018		2019
Florida GRIP	$	3,647	$	3,341	$	7,211	$	6,609	$	13,454	$	14,287	$	14,370
Eastern Shore Rate Case ⁽¹⁾	2,365		—		5,095		—		3,693		9,800		9,800
Florida Electric Reliability/Modernization Pilot Program ⁽¹⁾	352		—		767		—		94		1,558		1,558
New Smyrna Beach, Florida Project ⁽¹⁾	352		—		704		—		235		1,409		1,409
2017 Eastern Shore System Expansion Project - including interim services ⁽¹⁾	859		—		1,995		—		433		8,101		15,799
Northwest Florida Expansion Project ⁽¹⁾	870		—		870		—		—		3,484		6,500
(Palm Beach County) Belvedere, Florida Project ⁽¹⁾	—		—		—		—		—		635		1,131
Total	$	8,445	$	3,341	$	16,642	$	6,609	$	17,909	$	39,274	$	50,567

^{(1 )} Gross margin amount included in this table has not been adjusted to reflect the impact of the TCJA. The refunds and rate reductions implemented have been or will be offset by lower federal income taxes due to the TCJA.

Ongoing Growth Initiatives

GRIP

GRIP is a natural gas pipe replacement program approved by the Florida PSC that allows automatic recovery, through regulated rates, of capital and other program-related costs, inclusive of a return on investment, associated with the replacement of mains and services. Since the program's inception in August 2012, we have invested $120.1 million to replace 250 miles of qualifying distribution mains, including $6.4 million during the first six months of 2018. The increased investments in GRIP generated additional gross margin of $306,000 and $602,000 for the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017.

Regulatory Proceedings

Eastern Shore Rate Case

Eastern Shore's rate case settlement agreement became final on April 1, 2018. The final agreement increases Eastern Shore's operating income by $6.6 million, which consists of $9.8 million in additional margin from base rates offset by $3.2 million in lower Federal income taxes resulting from the TCJA. For the three and six months ended June 30, 2018, Eastern Shore recognized incremental gross margin of approximately $2.4 million and $5.1 million, respectively. As of June 30, 2018, Eastern Shore refunded its customers a total of $1.7 million related to the decrease in federal income taxes as a result of the TCJA. The settlement rates were effective January 1, 2018.

Florida Electric Reliability/Modernization Pilot Program

In December 2017, the Florida PSC approved a $1.6 million annualized rate increase, effective January 2018, for the recovery of a limited number of investments and costs related to reliability, safety and modernization for FPU's electric distribution system. This increase will continue through at least the last billing cycle of December 2019. For the three and six months ended June 30, 2018, additional margin of $352,000 and $767,000, respectively, was generated.

Major Projects and Initiatives Currently Underway

New Smyrna Beach, Florida Project

In the fourth quarter of 2017, we commenced construction of a 14-mile gas transmission pipeline to provide additional capacity to serve current and planned customer growth in the New Smyrna Beach service area. The project was partially placed into service at the end of 2017 and is expected to be fully in service in September 2018. For the three and six months ended June 30, 2018, the project generated incremental gross margin of approximately $352,000 and $704,000, respectively.

- 39

Table of Contents

2017 Eastern Shore System Expansion Project

In November 2017, Eastern Shore began construction of a $117.0 million system expansion that will increase its capacity by 26 percent once completed. We have invested $89.6 million through June 30, 2018 and expect to invest approximately $24.8 million during the remainder of 2018 to substantially complete the project. The first phase of the project was placed into service in December 2017, and generated $859,000 and $2.0 million in incremental gross margin, including margin from interim services, during the three and six months ended June 30, 2018, respectively. With the exception of some minor facilities, the remaining segments are scheduled to be completed and begin generating margin during the second half of 2018. The project is expected to produce approximately $15.8 million in gross margin in its first full year of service.

Northwest Florida Expansion Project

Peninsula Pipeline has completed construction of transmission lines and the Florida natural gas division has completed construction of lateral distribution lines to serve two large customers and other customers close to these facilities. This is our first expansion of natural gas service into Northwest Florida. The project was placed into service in May 2018 and generated incremental gross margin of $870,000 for the three and six months ended June 30, 2018. The estimated annual gross margin from this project is $6.5 million.

(Palm Beach County) Belvedere, Florida Project

Peninsula Pipeline is constructing a pipeline to bring gas directly to our natural gas distribution system in West Palm Beach, Florida. We expect to complete this project by the end of the third quarter of 2018. Estimated annual gross margin associated with the project is approximately $1.1 million.

Other major factors influencing gross margin

Weather and Consumption

Gross margin increased by $1.1 million and $5.2 million in the three and six months ended June 30, 2018, respectively, as a result of colder temperatures, compared to the extremely warm temperatures experienced during the same period in 2017. While temperatures during the first half of 2018 were colder than 2017, they were still warmer than normal, as shown in the table below. We estimate that we would have generated an additional $2.4 million in gross margin if temperatures for the six months ended June 30, 2018 had been normal. The following table summarizes HDD and CDD variances from the 10-year average HDD/CDD ("Normal") for the three and six months ended June 30, 2018 and 2017.

HDD and CDD Information



	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2018		2017		Variance		2018		2017		Variance
Delmarva
Actual HDD	424		288		136		2,719		2,246		473
10-Year Average HDD ("Delmarva Normal")	423		429		(6	)	2,785		2,783		2
Variance from Delmarva Normal	1		(141	)			(66	)	(537	)
Florida
Actual HDD	17		13		4		507		298		209
10-Year Average HDD ("Florida Normal")	16		19		(3	)	533		555		(22	)
Variance from Florida Normal	1		(6	)			(26	)	(257	)
Ohio
Actual HDD	662		508		154		3,652		2,992		660
10-Year Average HDD ("Ohio Normal")	614		637		(23	)	3,683		3,774		(91	)
Variance from Ohio Normal	48		(129	)			(31	)	(782	)
Florida
Actual CDD	952		935		17		1,091		1,080		11
10-Year Average CDD ("Florida CDD Normal")	969		955		14		1,058		1,037		21
Variance from Florida CDD Normal	(17	)	(20	)			33		43

- 40

Table of Contents

Natural Gas Distribution Customer and Consumption Growth

The Company's natural gas distribution operations generated $1.6 million and $3.3 million of additional margin for the three and six months ended June 30, 2018, respectively. The breakdown of the increased margin is as follows:



	Three Months Ended		Six Months Ended
In thousands	June 30, 2018		June 30, 2018
Customer growth:
Residential	$	351	$	864
Commercial and industrial excluding new service in Northwest Florida	303		604
New service in Northwest Florida	276		305
Total customer growth	930		1,773

Volume growth:
Residential	151		855
Commercial and industrial	387		1,026
Other - including unbilled revenue	107		(312		)
Total volume growth	645		1,569

Total natural gas distribution growth	$	1,575	$	3,342

Customer growth for the Company's Delmarva Peninsula and Florida natural gas distribution operations generated $930,000 and $1.8 million in additional gross margin for the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017. The additional margin was generated from an approximately 3.8 percent increase in the average number of residential customers as well as growth in commercial and industrial customers on the Delmarva Peninsula in the second quarter and first six months of 2018, compared to the corresponding periods in 2017. Residential customer growth on the Delaware Peninsula has averaged 3.0 percent over the past five years. The Company's Florida natural gas distribution operations generated additional gross margin for the three and six months ended June 30, 2018, due to growth in all customer classes and new service to customers in Northwest Florida.

The Company's Delmarva Peninsula and Florida natural gas distribution operations generated $645,000 and $1.6 million in additional gross margin for the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017 from higher sales to residential and commercial customers.

Propane Operations

The Company’s Florida and Delmarva Peninsula propane operations generated $1.6 million and $5.7 million in incremental margin for the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017. A return to more normal temperatures accounted for $806,000 and $2.9 million of the margin increase during the three and six months ended June 30, 2018, respectively. The balance of the increase reflects increased customer consumption driven by growth and other factors, higher sales and revenues from service contracts and increased wholesale sales activities.

PESCO

For the three and six months ended June 30, 2018, PESCO recorded a series of adjustments, MTM gains and recognized extraordinary costs, which impacted reported results. Excluding the impact of these items, PESCO's gross margin increased by $592,000 and $255,000, during the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017. The total of the adjustments increased gross margin by $1.1 million and reduced gross margin by $863,000 for the three and six months ended June 30, 2018, respectively, compared to the same periods in 2017. The following table summarizes the changes in PESCO’S year-over-year margin for the three and six months ended June 30, 2018:

- 41

Table of Contents



	Three Months Ended		Six Months Ended
	June 30, 2018		June 30, 2018
(in thousands)
Three and Six Months Ended June 30, 2017 Reported Results	$	921	$	4,389
Incremental Margin from Growth and ARM Acquisition in 2017	592		255
Nonrecurring Margin factors - non-renewal of Supply Agreement, MTM and Other Adjustments	1,092		(863		)
2018 Margin	$	2,605	$	3,781

The following table compares the margin, operating expenses and operating income from PESCO for the three and six months ended June 30, 2018 and 2017:



	Three Months Ended						Six Months Ended
	June 30,						June 30,
in thousands	2018			2017			2018			2017
Total Gross Margin	$	2,606		$	921		$	3,781		$	4,389
Operating Expense	(1,918		)	(1,154		)	(3,857		)	(2,143		)
Operating Income/(Loss)	$	688		$	(233	)	$	(76	)	$	2,246

Operating income for PESCO improved to $688,000 for the three months ended June 30, 2018, from a loss of $233,000 during the same period in the prior year. The improvement reflects the benefit of several nonrecurring margin adjustments in the business, growth in margins from existing operations as well as the addition of margin from the business purchased from ARM during the third quarter of 2017. This was partially offset by a $764,000 increase in operating expenses, including $262,000 associated with the ARM margins previously mentioned, as well as $501,000 in increased staffing, infrastructure and risk management system costs to ensure the profitable future growth of this business.

For the six months ended June 30, 2018, PESCO reported an operating loss of $76,000, compared to income of $2.2 million during the same period in the prior year. The decline primarily reflects increased expenses incurred to build out the staff, infrastructure and risk management systems necessary for the success of this business, as well as the impact of several nonrecurring margin adjustments, largely during the first quarter of 2018.

Xeron

Xeron's operations were wound down during the second quarter of 2017. Operating income for the three and six months ended June 30, 2018, improved by $173,000 and $870,000, respectively, due to the absence of wind-down expenses and the absence of operating losses for Xeron in 2018.

- 42

Table of Contents

Regulated Energy Segment

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



	Three Months Ended
	June 30,				Increase
	2018		2017		(decrease)
(in thousands)
Revenue	$	70,504	$	70,996	$	(492	)
Cost of sales	20,010		24,167		(4,157		)
Gross margin	50,494		46,829		3,665
Operations & maintenance	25,022		22,407		2,615
Depreciation & amortization	7,620		7,142		478
Other taxes	3,548		3,194		354
Other operating expenses	36,190		32,743		3,447
Operating income	$	14,304	$	14,086	$	218

Operating income for the Regulated Energy segment for the three months ended June 30, 2018 was $14.3 million, an increase of $218,000 compared to the same period in 2017. The increased operating income resulted from increased gross margin of $3.7 million, offset by a $3.4 million increase in operating expenses.

Excluding the impact of the customer refunds and reserves for future refunds of approximately $2.3 million for lower income taxes due to the TCJA, gross margin and operating income for the three months ended June 30, 2018 increased by $5.9 million and $2.5 million, or 12.7 percent and 17.8 percent, respectively.

Gross Margin

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



(in thousands)	Margin Impact
Implementation of Eastern Shore settled rates	$	2,365
Service expansions	1,652
Natural gas growth (including customer and consumption growth but excluding service expansions)	1,575
Return to more normal weather	359
Florida electric reliability/modernization program	352
Florida GRIP	306
Other	(660		)
Total	5,949
TCJA impact - refunds and reserves for future refunds to ratepayers^*	(2,284		)
Quarter-over-quarter increase in gross margin	$	3,665

*As a result of the TCJA, an estimated amount of $2.3 million was reserved or refunded to customers during the second quarter of 2018 to reflect the impact of lower tax rates on our regulated businesses. In some jurisdictions, we have paid refunds to customers, while in other jurisdictions, we have established reserves until final agreements are approved and changes are made to customer rates. The reserves and lower customer rates are equal to the estimated reduction in Federal income taxes due to the TCJA and have no material impact on after-tax earnings from the Regulated Energy segment

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

Implementation of Eastern Shore Settled Rates

Eastern Shore generated additional gross margin of $2.4 million from the implementation of new rates as a result of its rate case filing. See Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.

- 43

Table of Contents

Service Expansions

We generated additional gross margin of $1.7 million primarily from the following natural gas service expansions:


•	$1.2 million generated by Peninsula Pipeline from the New Smyrna Beach and Northwest Pipeline Expansion Projects; and

•

$859,000 from Eastern Shore's services, including those provided on an interim basis, to industrial customers in Delaware in conjunction with a portion of Eastern Shore's 2017 Expansion Project that was placed in service in December 2017, and $223,000 in additional margin as a result of an increase in rates from service provided to an industrial customer, partially offset by the absence of short-term contracts totaling $544,000 that were replaced by long-term service agreements.

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

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


•	$645,000 from higher sales on the Delmarva Peninsula and in Florida that were not driven by weather;


•	$560,000 from Florida natural gas customer growth, due primarily to an increase in residential and commercial customers served as well as expansion to Northwest Florida; and


•	$371,000 from a 3.8 percent increase in the average number of residential customers served by the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers served.

Return to More Normal Weather

Temperatures during the second quarter of 2018 were nearly normal, compared to 32.9 percent warmer than normal weather during the second quarter of 2017. Comparatively colder weather during the second quarter of 2018 increased usage and generated $359,000 in additional margin.

Florida Electric Reliability/Modernization Program

Gross margin increased by $352,000, due primarily to the rates that went into effect in January 2018. See Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.

GRIP

Increased investment in GRIP generated additional gross margin of $306,000 for the three months ended June 30, 2018, compared to the same period in 2017.

Impact of the TCJA on customer rates

The adjustment to customer rates, because of the implementation of the TCJA, decreased gross margin by $2.3 million due to refunds paid to customers and the establishment of reserves for future refunds and/or rate reductions to customers. The decrease in gross margin was offset by a $2.3 million reduction in Federal income taxes.

Other Operating Expenses

Other operating expenses increased by $3.4 million. The significant factors contributing to the increase in other operating expenses included:


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


•	$1.0 million in higher staffing costs for additional personnel to support growth, including the largest project to date in our history, Eastern Shore's 2017 System Expansion Project;


•	$722,000 in higher depreciation, asset removal and property tax costs associated with recent capital investments; and


•	$384,000 in higher incentive compensation costs due to improved period-over-period results.

- 44

Table of Contents

For the six months ended June 30, 2018, compared to the six months ended June 30, 2017:



	Six Months Ended
	June 30,				Increase
	2018		2017		(decrease)
(in thousands)
Revenue	$	179,897	$	168,650	$	11,247
Cost of sales	68,241		64,411		3,830
Gross margin	111,656		104,239		7,417
Operations & maintenance	48,169		45,987		2,182
Depreciation & amortization	15,136		14,027		1,109
Other taxes	7,336		6,744		592
Other operating expenses	70,641		66,758		3,883
Operating income	$	41,015	$	37,481	$	3,534

Operating income for the Regulated Energy segment for the six months ended June 30, 2018 was $41.0 million, an increase of $3.5 million compared to the same period in 2017. The increased operating income resulted from increased gross margin of $7.4 million, offset by an increase in operating expenses of $3.9 million.

Excluding the impact of refunds to customers and reserves for future refunds of approximately $5.4 million for lower income taxes due to the TCJA, gross margin and operating income increased by $12.8 million and $9.0 million, or 12.3 percent and 24.0 percent, respectively.

Gross Margin

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



(in thousands)	Margin Impact
Implementation of Eastern Shore settled rates	$	5,095
Natural gas growth (including customer and consumption growth but excluding service expansions)	3,342
Service expansions	2,316
Return to more normal weather	1,314
Florida electric reliability/modernization program	767
Florida GRIP	602
Other	(598		)
Total	12,838
TCJA impact - refunds and reserves for future refunds to ratepayers^*	(5,421		)
Period-over-Period increase in gross margin	$	7,417

*As a result of the TCJA, an estimated $5.4 million was reserved or refunded to customers during the first half of 2018 to reflect the impact of lower tax rates on the Company's regulated businesses. In some jurisdictions, the Company has paid refunds to customers, while in other jurisdictions, the Company has established reserves until final agreements are approved and changes are made to customer rates. The reserves and lower customer rates are equal to the estimated reduction in Federal income taxes due to the TCJA and have no material impact on after-tax earnings from the Regulated Energy segment

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

Implementation of Eastern Shore's Settled Rates

Eastern Shore generated additional gross margin of $5.1 million from the implementation of new rates as a result of its rate case filing. See Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.

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

Increased gross margin of $3.3 million from natural gas growth and consumption (excluding service expansions) was generated primarily from the following:


•	$1.6 million from higher sales on the Delmarva Peninsula and in Florida that were not driven by weather;

- 45

Table of Contents


•	$889,000 from Florida natural gas customer growth, due primarily to an increase in residential and commercial customers served; and


•	$885,000 from a 3.7 percent increase in the average number of residential customers served by the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers served.

Service Expansions

We generated additional gross margin of $2.3 million primarily from the following natural gas service expansions:

•

$2.0 million from Eastern Shore's services, including those provided on an interim basis, to industrial customers in Delaware in conjunction with a portion of Eastern Shore's 2017 Expansion Project that was placed in service in December 2017, and $447,000 in additional margin as a result of an increase in rates from service provided to an industrial customer, partially offset by the absence of short-term contracts totaling $1.2 million that were replaced by long-term service agreements; and


•	$1.6 million generated by Peninsula Pipeline from the New Smyrna Beach and Northwest Pipeline Expansion Projects.

Return to More Normal Weather

Temperatures during the first six months of 2018 were 1.8 percent warmer than normal compared to 22.2 percent warmer than normal weather during the first six months of 2017. Comparatively colder weather during the first six months of 2018 increased usage and generated $1.3 million in additional margin.

Florida Electric Reliability/Modernization Program

Gross margin increased by $767,000, due primarily to the rates that went into effect in January 2018. See Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.

GRIP

Increased investment in GRIP generated additional gross margin of $602,000 for the six months ended June 30, 2018, compared to the same period in 2017.

Impact of the TCJA on customer rates

The adjustment to customer rates, because of the implementation of the TCJA, decreased gross margin by $5.4 million due to refunds and reserves for future refunds to customers. The decrease in gross margin was offset by a reduction in Federal income taxes.

Other Operating Expenses

Other operating expenses increased by $3.9 million. The significant factors contributing to the increase in other operating expenses included:


•	$1.7 million in higher depreciation, asset removal and property tax costs associated with recent capital investments;


•	$1.4 million in higher staffing costs for additional personnel to support growth, including the largest project to date in the Company's history, Eastern Shore's 2017 System Expansion Project;


•	$1.1 million in higher facilities and maintenance costs to maintain system integrity; and


•	$592,000 in higher incentive compensation costs as a result of improved period-over-period results; offset by


•	$1.1 million in lower regulatory and outside services costs due to the absence of rate case filings in 2018.

- 46

Table of Contents

Unregulated Energy Segment

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



	Three Months Ended
	June 30,				Increase
	2018		2017		(decrease)
(in thousands)
Revenue	$	76,345	$	63,049	$	13,296
Cost of sales	59,430		49,313		10,117
Gross margin	16,915		13,736		3,179
Operations & maintenance	13,406		11,047		2,359
Depreciation & amortization	2,198		1,929		269
Other taxes	821		758		63
Total operating expenses	16,425		13,734		2,691
Operating income	$	490	$	2	$	488

Operating income for the Unregulated Energy segment for the three months ended June 30, 2018 was $490,000, compared to operating income of $2,000 for the same period in 2017. The increase in operating income of $488,000 was due to an increase in gross margin of $3.2 million, offset by a $2.7 million increase in operating expenses.

Gross Margin

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



(in thousands)	Margin Impact
PESCO	$	1,684
Propane delivery operations - additional customer consumption - weather	806
Propane delivery operations - increased margin driven by growth and other factors	536
Aspire Energy - increased margins largely due to higher commodity pricing on natural gas liquid sales	207
Other	(54		)
Quarter-over-quarter increase in gross margin	$	3,179

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

PESCO

For the three months ended June 30, 2018, PESCO's gross margin increased by $1.7 million compared to the same period in 2017. Higher second quarter 2018 margin from PESCO resulted from the following:



(in thousands)	Margin Impact
Nonrecurring margin increase associated with the Southeast portfolio	$	642
Nonrecurring annual imbalance settlement from 2017 customer Supply Agreement	451
Additional margin associated with the acquisition of the Midwest portfolio in the third quarter of 2017	325
Incremental margin from growth	266
Total Incremental Margin from PESCO for the Second Quarter of 2018	$	1,684

Propane delivery operations - additional customer consumption - weather

Gross margin increased by $806,000, due primarily to increased deliveries of propane as a result of colder temperatures in the three months ended June 30, 2018, compared to the same period in 2017.

- 47

Table of Contents

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

Gross margin increased by $536,000, due primarily to increased sales of propane as a result of growth in customers and other factors.

Aspire Energy - increased margin due to changes in natural gas liquids commodity prices

Gross margin increased by $207,000, as a result of higher commodity pricing on natural gas liquid sales, compared to the same period in 2017.

Other Operating Expenses

Other operating expenses increased by $2.7 million. The significant components of the increase in other operating expenses included:


•	$764,000 in higher expenses as a result of increased staffing, infrastructure and risk management system costs to ensure the profitable future growth of PESCO;


•	$515,000 in higher staffing and associated costs for additional personnel to support growth and increased deliveries driven by the colder weather in the second quarter of 2018, compared to the same period in 2017;


•	$475,000 in higher outside services associated primarily with growth and ongoing compliance activities;


•	$427,000 in higher incentive compensation costs as a result of improved period-over-period results;


•	$173,000 in higher benefits and employee-related costs (since we self-insure for healthcare, benefits costs fluctuate depending upon filed claims); and


•	$131,000 in higher depreciation expense.

For the six months ended June 30, 2018, compared to the six months ended June 30, 2017:



	Six Months Ended
	June 30,				Increase
	2018		2017		(decrease)
(in thousands)
Revenue	$	221,712	$	155,774	$	65,938
Cost of sales	174,496		115,219		59,277
Gross margin	47,216		40,555		6,661
Operations & maintenance	26,766		23,426		3,340
Depreciation & amortization	4,364		3,833		531
Other taxes	1,912		1,719		193
Total operating expenses	33,042		28,978		4,064
Operating income	$	14,174	$	11,577	$	2,597

Operating income for the Unregulated Energy segment for the six months ended June 30, 2018 was $14.2 million, compared to operating income of $11.6 million for same period in 2017. The $2.6 million increase in operating income was due to an increase in gross margin of $6.7 million, offset by a $4.1 million increase in operating expenses.

Gross Margin

- 48

Table of Contents

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



(in thousands)	Margin Impact
Propane delivery operations - additional customer consumption - weather	2,923
Propane delivery operations - increased margin driven by growth and other factors	1,789
Aspire Energy - customer consumption - weather	921
PESCO	(608		)
Aspire Energy - increased margin driven by growth and other factors	585
Growth in wholesale propane margins and sales	333
Other	718
Period-over-period increase in gross margin	$	6,661

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

Propane delivery operations - additional customer consumption - weather

Gross margin increased by $2.9 million, due primarily to increased propane deliveries as a result of colder temperatures in the six months ended June 30, 2018, compared to the same period in 2017.

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

Gross margin increased by $1.8 million, due primarily to increased propane sales as a result of customer growth and other factors.

Aspire Energy - customer consumption - weather

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

PESCO

For the six months ended June 30, 2018, PESCO's gross margin decreased by $608,000 compared to the same period in 2017. Lower gross margin for the six months ended June 30, 2018 from PESCO resulted from the following:



(in thousands)	Margin Impact
Reversal of unrealized MTM loss recorded in the fourth quarter of 2017	$	5,713
Nonrecurring margin and annual imbalance settlement from 2017 customer Supply Agreement	(1,673		)
Net impact of extraordinary costs associated with the 2018 Bomb Cyclone for the Mid-Atlantic wholesale portfolio ⁽¹⁾	(3,284		)
Loss for the Mid-Atlantic retail portfolio caused by pipeline capacity constraints in January and warm weather in February 2018 ⁽¹⁾	(2,261		)
Nonrecurring margin increase associated with the Southeast portfolio	642
Additional margin associated with the acquisition of the Midwest portfolio in the third quarter of 2017	273
Other	(18		)
Total Change in Gross Margin for PESCO for the six months ended June 30, 2018	$	(608	)

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

Aspire Energy - increased margin driven by growth and other factors

Gross margin increased by $585,000, due to customer growth, increased deliveries of natural gas because of an upgrade of pipeline pressure and improved margins on natural gas liquid sales.

Wholesale Propane Margins

Gross margin increased by $333,000, due to a higher margin per gallon and an increase in volume delivered for the Delmarva Peninsula propane distribution operations.

- 49

Table of Contents

Other Operating Expenses

Other operating expenses increased by $4.1 million. The significant components of the increase in other operating expenses included:


•	$1.7 million in higher expenses as a result of increased staffing, infrastructure and risk management system costs to ensure the profitable future growth of PESCO;


•	$996,000 in higher staffing and associated costs for additional personnel to support growth and increased deliveries driven by the colder weather in the first six months of 2018, compared to the same period in 2017;


•	$646,000 in higher expenses, including vehicle fuel costs, sales and advertising, taxes other than income taxes and credit collections costs;


•	$594,000 in higher incentive compensation costs as a result of improved period-over-period results;


•	$443,000 in higher maintenance costs as a result of ongoing compliance activities;


•	$266,000 in higher depreciation and amortization expense due to increased investments; offset by


•	the absence of $870,000 in 2017 Xeron wind-down expenses.

OTHER EXPENSE, NET

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

Other expense, net, which includes non-operating investment income (expense), interest income, late fees charged to customers, gains or losses from the sale of assets and pension and other benefits expense, decreased by $740,000 in the second quarter of 2018, compared to the same period in 2017, due partly to the recognition of Xeron lease termination expenses in 2017.

For the six months ended June 30, 2018 compared to the six months ended June 30, 2017

Other expense, net, which includes non-operating investment income (expense), interest income, late fees charged to customers, gains or losses from the sale of assets and pension and other benefits expense, decreased by $1.5 million for the first six months of 2018, compared to the same period in 2017, due partly to the recognition of Xeron lease termination expenses in 2017.

INTEREST CHARGES

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

Interest charges for the three months ended June 30, 2018 increased by $808,000, compared to the same period in 2017, attributable primarily to an increase of $804,000 in interest on higher short-term borrowings, and an increase of $273,000 in interest on long-term debt, largely as a result of the issuance of the NYL Shelf Notes (Series A) in May 2018.

For the six months ended June 30, 2018 compared to the six months ended June 30, 2017

Interest charges for the six months ended June 30, 2018 increased by $1.7 million, compared to the same period in 2017, attributable primarily to an increase of $1.4 million in interest on higher short-term borrowings, and an increase of $804,000 in interest on long-term debt, largely as a result of the issuance of the Prudential Shelf Notes in April 2017 and the issuance of the NYL Shelf Notes (Series A) in May 2018.

INCOME TAXES

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

Income tax expense was $2.7 million for the three months ended June 30, 2018, compared to $3.9 million in the same period in 2017. The decrease in income tax expense was due primarily to the impact of the TCJA in the second quarter of 2018. Our effective income tax rate was 29.9 percent and 39.5 percent, for the three months ended June 30, 2018 and 2017, respectively.

For the six months ended June 30, 2018 compared to the six months ended June 30, 2017

Income tax expense was $12.7 million for the six months ended June 30, 2018, compared to $16.5 million in the same period in 2017. The decrease in income tax expense was due primarily to the impact of the TCJA in the first six months of 2018. Our effective income tax rate was 27.6 percent and 39.5 percent for the six months ended June 30, 2018 and 2017, respectively.

- 50

Table of Contents

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 with our target capital structure.

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

Capital expenditures for investments in new or acquired plant and equipment are our largest capital requirements. Our capital expenditures were $134.7 million for the six months ended June 30, 2018.

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



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

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

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

- 51

Table of Contents

Capital Structure

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

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



	June 30, 2018				December 31, 2017
(in thousands)
Long-term debt, net of current maturities	$	241,596	32	%	$	197,395	29	%
Stockholders’ equity	507,986		68	%	486,294		71	%
Total capitalization, excluding short-term debt	$	749,582	100	%	$	683,689	100	%

	June 30, 2018				December 31, 2017
(in thousands)
Short-term debt	$	235,288	24	%	$	250,969	26	%
Long-term debt, including current maturities	251,573		25	%	206,816		22	%
Stockholders’ equity	507,986		51	%	486,294		52	%
Total capitalization, including short-term debt	$	994,847	100	%	$	944,079	100	%

Included in the long-term debt balances at June 30, 2018 and December 31, 2017, was a capital lease obligation associated with Sandpiper's capacity, supply and operating agreement (at June 30, 2018, zero excluding current maturities and $1.4 million including current maturities and, at December 31, 2017, $620,000 excluding current maturities and $2.1 million including current maturities). At the closing of the ESG acquisition in May 2013, Sandpiper entered into this agreement, which has a six-year term ending in May 2019. The capacity portion of this agreement is accounted for as a capital lease.

Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. From time to time, we may go below the lower end of the target range as we seek to align, as much as feasible, any long-term debt or equity issuance(s) with the commencement of service, and associated earnings, for larger revenue generating capital projects. In addition, the exact timing of any long-term debt or equity issuance(s) will be based on market conditions.

Shelf Agreements

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

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

- 52

Table of Contents

Short-term Borrowings

Our outstanding short-term borrowings at June 30, 2018 and December 31, 2017 were $235.3 million and $251.0 million at weighted average interest rates of 2.98 percent and 2.42 percent, respectively. Our current short-term borrowing limit, authorized by our Board of Directors, is $350.0 million.

We utilize bank lines of credit to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of the capital expenditure program. As of June 30, 2018, we had five unsecured bank credit facilities with four financial institutions totaling $220.0 million in available credit. In addition, since October 2015, we have $150.0 million of additional short-term debt capacity available under the Revolver. The terms of the Revolver are described in further detail below. None of the unsecured bank lines of credit requires compensating balances.

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

Cash Flows

The following table provides a summary of our operating, investing and financing cash flows for the six months ended June 30, 2018 and 2017:



	Six Months Ended
	June 30,
	2018			2017
(in thousands)
Net cash provided by (used in):
Operating activities	$	108,352		$	96,370
Investing activities	(126,661		)	(88,577		)
Financing activities	17,207			(9,552		)
Net decrease in cash and cash equivalents	(1,102		)	(1,759		)
Cash and cash equivalents—beginning of period	5,614			4,178
Cash and cash equivalents—end of period	$	4,512		$	2,419

Cash Flows Provided By Operating Activities

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

During the six months ended June 30, 2018 and 2017, net cash provided by operating activities was $108.4 million and $96.4 million, respectively, resulting in an increase in cash flows of $12.0 million. Significant operating activities generating the cash flows change were as follows:


•	Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities decreased cash flows by $20.5 million, due primarily to the timing of the receipt of customer payments as well as the timing of payments to vendors.


•	Net income, adjusted for reconciling activities, increased cash flows by $8.2 million, due primarily to the higher performance during the period.


•	Net cash flows from changes in propane inventories increased by approximately $12.4 million as a result of higher use of propane, which decreased our inventory levels.

- 53

Table of Contents


•	Changes in net regulatory assets and liabilities increased cash flows by $6.8 million, due primarily to the change in fuel costs collected through the various cost recovery mechanisms.


•	Changes in net prepaid expenses and other current assets, customer deposits and refunds increased cash flows by $5.2 million.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $126.7 million and $88.6 million during the six months ended June 30, 2018 and 2017, respectively, resulting in a decrease in cash flows of $38.1 million. Cash paid for capital expenditures increased by $38.2 million to $126.8 million for the first six months of 2018, compared to $88.6 million for the same period in 2017.

Cash Flows Provided (Used) by Financing Activities

Net cash provided by financing activities totaled $17.2 million during the six months ended June 30, 2018 compared to net cash of $9.6 million used in financing activities during the prior year period resulting in an increase in cash flows of $26.8 million. The increase in net cash provided by financing activities resulted primarily from the following:


•	Increased cash flows from lower repayments of short-term borrowing of $45.6 million under our line of credit arrangements;

•

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


•	Increased cash flows of $3.0 million as a result of changes in cash overdrafts; partially offset by


•	Higher repayment of long-term debt of $25.0 million during the six months ended June 30, 2018, compared to the same period in 2017.

Off-Balance Sheet Arrangements

We have issued corporate guarantees to certain vendors of our subsidiaries, primarily PESCO. These corporate guarantees provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. These subsidiaries have never defaulted on their obligations to pay their suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at June 30, 2018 was $72.5 million, with the guarantees expiring on various dates through June 2019.

We have issued letters of credit totaling $5.0 million related to the electric transmission services for FPU's northwest electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, and to our current and previous primary insurance carrier. These letters of credit have varying expiration dates through December 2019. There have been no draws on these letters of credit as of June 30, 2018. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that they will be renewed to the extent necessary in the future. Additional information is presented in Note 6, Other Commitments and Contingencies in the condensed consolidated financial statements.

Contractual Obligations

There has been no material change in the contractual obligations presented in our 2017 Annual Report on Form 10-K, except for long-term debt and commodity purchase obligations entered into in the ordinary course of our business. The following table summarizes long-term debt and commodity purchase contract obligations at June 30, 2018:



	Payments Due by Period
	Less than 1 year		1 - 3 years		3 - 5 years		More than 5 years		Total
(in thousands)
Long-term debt⁽¹⁾	$	8,626	$	31,200	$	38,700	$	172,200	$	250,726
Purchase obligations - Commodity ⁽²⁾	116,416		39,752		77		—		156,245
Total	$	125,042	$	70,952	$	38,777	$	172,200	$	406,971


⁽¹⁾	Excludes capital lease obligation, debt issuance costs and an unamortized discount of $847,000.

- 54

Table of Contents

⁽²⁾

In addition to the obligations noted above, we have agreements with commodity suppliers that have provisions with no minimum purchase requirements. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts allow the suppliers to reduce the amounts available in the winter season if we do not purchase specified amounts during the summer season. Under these contracts, the commodity prices will fluctuate as market prices fluctuate.

Rates and Regulatory Matters

Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by the respective state PSC; Eastern Shore is subject to regulation by the FERC; and Peninsula Pipeline is subject to regulation by the Florida PSC. At June 30, 2018, we were involved in regulatory matters in each of the jurisdictions in which we operate. Our significant regulatory matters are fully described in Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements in this Quarterly Report on Form 10-Q.

Recent Authoritative Pronouncements on Financial Reporting and Accounting

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

Item 3. Quantitative and Qualitative Disclosures about Market Risk

INTEREST RATE RISK

Long-term debt is subject to potential losses based on changes in interest rates. Our long-term debt at June 30, 2018, consists of fixed-rate Senior Notes and $8.0 million of fixed-rate secured debt. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowings based in part on the fluctuation in interest rates. Additional information about our long-term debt is disclosed in Note 14, Long-term Debt, in the condensed consolidated financial statements.

COMMODITY PRICE RISK

Regulated Energy Segment

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

Unregulated Energy Segment

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

We can store up to approximately 6.9 million gallons of propane (including leased storage and rail cars) during the winter season to meet our customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline, particularly if we utilize fixed price forward contracts for supply. To mitigate the risk of propane commodity price fluctuations on the inventory valuation, we have adopted a Risk Management Policy that allows our propane distribution operation to enter into fair value hedges, cash flow hedges or other economic hedges of our inventory.

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

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

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

- 55

Table of Contents

The following table reflects the changes in the fair market value of financial derivatives contracts related to natural gas and propane purchases and sales from December 31, 2017 to June 30, 2018:



(in thousands)	Balance at December 31, 2017			Increase (Decrease) in Fair Market Value			Less Amounts Settled			Balance at June 30, 2018
PESCO	$	(6,153	)	$	14,607		$	(9,099	)	$	(645	)
Sharp	1,192			(1,553		)	655			294
Total	$	(4,961	)	$	13,054		$	(8,444	)	$	(351	)

There were no changes in methods of valuations during the six months ended June 30, 2018.

The following is a summary of fair market value of financial derivatives as of June 30, 2018, by method of valuation and by maturity for each fiscal year period.



(in thousands)	2018			2019			2020			2021			2022		Total Fair Value
Price based on ICE - PESCO	$	(750	)	$	(541	)	$	972		$	(329	)	$	3	$	(645	)
Price based on Mont Belvieu - Sharp	244			65			(8		)	(7		)	—		294
Total	$	(506	)	$	(476	)	$	964		$	(336	)	$	3	$	(351	)

WHOLESALE CREDIT RISK

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

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The Chief Executive Officer and Chief Financial Officer of Chesapeake Utilities, with the participation of other Company officials, have evaluated our “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e), promulgated under the Securities Exchange Act of 1934, as amended) as of June 30, 2018. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of June 30, 2018.

Changes in Internal Control over Financial Reporting

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

- 56

Table of Contents

PART II—OTHER INFORMATION

Item 1. Legal Proceedings

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

Item 1A. Risk Factors

Our business, operations, and financial condition are subject to various risks and uncertainties. The risk factors described in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K, for the year ended December 31, 2017, should be carefully considered, together with the other information contained or incorporated by reference in this Quarterly Report on Form 10-Q and in our other filings with the SEC in connection with evaluating Chesapeake Utilities, our business and the forward-looking statements contained in this Quarterly Report on Form 10-Q. Additional risks and uncertainties not known to us at present, or that we currently deem immaterial, also may affect Chesapeake Utilities. The occurrence of any of these known or unknown risks could have a material adverse impact on our business, financial condition and results of operations.

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



	Total Number of Shares	Average Price Paid		Total Number of Shares Purchased as Part of Publicly Announced Plans	Maximum Number of Shares That May Yet Be Purchased Under the Plans
Period	Purchased	per Share		or Programs ⁽²⁾	or Programs ⁽²⁾
April 1, 2018 through April 30, 2018 ⁽¹⁾	406	$	73.05	—	—
May 1, 2018 through May 31, 2018	—	$	—	—	—
June 1, 2018 through June 30, 2018	—	$	—	—	—
Total	406	$	73.05	—	—

⁽¹⁾

Chesapeake Utilities purchased shares of common stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain directors and senior executives under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Item 8 under the heading “Notes to the Consolidated Financial Statements—Note 16, Employee Benefit Plans” in our latest Annual Report on Form 10-K for the year ended December 31, 2017. During the quarter ended June 30, 2018, 406 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.

- 57

Table of Contents


Item 6.	Exhibits




10.1		Separation Agreement and Release, effective as of June 7, 2018, by and between Chesapeake Utilities Corporation and Elaine B. Bittner, which was filed as Exhibit 10.1 to the Current Report on Form 8-K filed with the Securities and Exchange Commission on June 8, 2018, and is incorporated herein by reference thereto.

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

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

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

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

101.INS*		XBRL Instance Document.

101.SCH*		XBRL Taxonomy Extension Schema Document.

101.CAL*		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF*		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB*		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE*		XBRL Taxonomy Extension Presentation Linkbase Document.

*Filed herewith

- 58

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: August 9, 2018

- 59

Chesapeake Utilities - 10-Q quarterly report FY2018 Q2

What is the market capitalization of a company?

DISCLAIMER

Contact

Links