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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
 
   
 FORM 10-Q 
   

xQUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended: September 30, 2018March 31, 2019
OR
¨TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from                      to                      
Commission File Number: 001-11590 
   
CHESAPEAKE UTILITIES CORPORATION
(Exact name of registrant as specified in its charter)
   

Delaware 51-0064146
(State or other jurisdiction
of incorporation or organization)
 
(I.R.S. Employer
Identification No.)
909 Silver Lake Boulevard, Dover, Delaware 19904
(Address of principal executive offices, including Zip Code)
(302) 734-6799
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each classTrading Symbol(s)Name of each exchange on which registered
Common Stock - par value per share $0.4867CPKNew York Stock Exchange, Inc.
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15 (d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  x    No  ¨ 

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).  Yes  x    No  ¨
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act.

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Large accelerated filer x  Accelerated filer ¨
    
Non-accelerated filer ¨  Smaller reporting company ¨
       
    Emerging growth company ¨



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If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.
¨
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).    Yes  ¨    No  x
Common Stock, par value $0.4867 — 16,378,54516,397,017 shares outstanding as of October 31, 2018.April 30, 2019.

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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
3529
   
    ITEM 3.
QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
5846
   
    ITEM 4.
CONTROLS AND PROCEDURES
5947
  
PART II—OTHER INFORMATION
6149
   
    ITEM 1.
LEGAL PROCEEDINGS
6149
   
    ITEM 1A.
RISK FACTORS
6149
   
    ITEM 2.
UNREGISTERED SALES OF EQUITY SECURITIES AND USE OF PROCEEDS
6149
   
    ITEM 3.
DEFAULTS UPON SENIOR SECURITIES
6149
   
    ITEM 5.
OTHER INFORMATION
6149
   
    ITEM 6.
EXHIBITS
6250
  
SIGNATURES
6351


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GLOSSARY OF DEFINITIONS
ARM: ARM Energy Management, LLC, a natural gas supply and supply management company servicing commercial and industrial customers in Western Pennsylvania, which sold certain natural gas marketing assets to PESCO in August 2017
ASC: Accounting Standards Codification issued by the FASB
Aspire Energy: Aspire Energy of Ohio, LLC, a wholly-owned subsidiary of Chesapeake Utilities
ASU: Accounting Standards Update issued by the FASB
AutoGas: Alliance AutoGas, a national consortium of companies, of which Sharp is a member, providing an industry-leading complete program for fleets interested in shifting from gasoline to clean-burning propane
CDD: Cooling degree-day, which is a measure of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is above 65 degrees Fahrenheit
Central Gas: Central Gas Company of Okeechobee, Incorporated, a propane distribution provider in Southeast Florida, which sold certain assets to Flo-gas in December 2017
CGC: Consumer Gas Cooperative, an Ohio natural gas cooperative
CGS: Community Gas Systems
Chesapeake or Chesapeake Utilities: Chesapeake Utilities Corporation, and its direct and indirect subsidiaries, as appropriate in the context of the disclosure
Chesapeake Pension Plan: A defined benefit pension plan sponsored by Chesapeake Utilities
Chesapeake Postretirement Plan: An unfunded postretirement health care and life insurance plan sponsored by Chesapeake Utilities
Chesapeake SERP: An unfunded supplemental executive retirement pension plan sponsored by Chesapeake Utilities
Chipola: Chipola Propane Gas Company, Inc., a propane distribution service provider in Northwest Florida, which sold certain assets to Flo-gas in August 2017
CHP: Combined heat and power plant
Columbia Gas: Columbia Gas of Ohio, an unaffiliated local distribution company based in Ohio
Company: Chesapeake Utilities Corporation, and its direct and indirect subsidiaries, as appropriate in the context of the disclosure
CP: Certificate of Public Convenience and Necessity
Credit Agreement: The Credit Agreement dated October 8, 2015, among Chesapeake Utilities and the Lenders related to the Revolver
Deferred Compensation Plan: A non-qualified, deferred compensation arrangement under which certain of our executives and members of the Board of Directors are able to defer payment of all or a part of certain specified types of compensation, including executive salaries and cash bonuses, executive performance shares, and directors’ retainers
Degree-Day: A degree-day is the measure of the variation in the weather based on the extent to which the average daily temperature (from 10:00 am to 10:00 am) falls above or below 65 degrees Fahrenheit
Delaware Division: Chesapeake Utilities' natural gas distribution operation serving customers in Delaware

Del-Mar Energy Pathway Project - A project for the construction of pipeline looping in Kent County, Delaware, and additional mainline extension in Sussex County, Delaware. The project also upgrades an existing pressure control facility, which includes a portion of mainline extension in Sussex County, Delaware, as well as in Somerset County, Maryland.
Delmarva Peninsula: A peninsula on the east coast of the United States of AmericaU. S. occupied by Delaware and portions of Maryland and Virginia

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DNREC: Delaware Department of Natural Resources and Environmental Control
Dt(s): Dekatherm(s), which is a natural gas unit of measurement that includes a standard measure for heating value
Dts/d: Dekatherms per day
Eastern Shore: Eastern Shore Natural Gas Company, a wholly-owned natural gas transmission subsidiary of Chesapeake Utilities
EGWIC: Eastern Gas & Water Investment Company, LLC, an affiliate of ESG
Eight Flags: Eight Flags Energy, LLC, a subsidiary of Chesapeake OnSight Services, LLC which owns and operates a CHP plant on Amelia Island, Florida, that supplies electricity to FPU and industrial steam to Rayonier
EPA: United States Environmental Protection Agency
ESG: Eastern Shore Gas Company and its affiliates
FASB: Financial Accounting Standards Board
FDEP: Florida Department of Environmental Protection
FERC: Federal Energy Regulatory Commission an independent agency of the United States government that regulates the interstate transmission of electricity, natural gas, and oil
FGT: Florida Gas Transmission Company
Flo-gas: Flo-gas Corporation, a wholly-owned subsidiary of FPU
FPL: Florida Power & Light Company, an unaffiliated electric company that supplies electricity to FPU
FPU: Florida Public Utilities Company, a wholly-owned subsidiary of Chesapeake Utilities
FPU Medical Plan: A separate unfunded postretirement medical plan for FPU sponsored by Chesapeake Utilities
FPU Pension Plan: A separate defined benefit pension plan for FPU sponsored by Chesapeake Utilities
GAAP: Accounting principles generally accepted in the United States of America
GRIP: The Gas Reliability Infrastructure Program
Gross Margin: a non-GAAP measure defined as operating revenues less the cost of sales. The Company's cost of sales includes purchased fuel cost for natural gas, pipeline replacement program in Florida pursuant to which we collect a surcharge from certainelectricity and propane and the cost of our customers to recover capitallabor spent on direct revenue-producing activities and other program-related costs associated with the replacement of qualifying distribution mainsexcludes depreciation, amortization and services
Gulf Power: Gulf Power Company, an unaffiliated electric company that supplies electricity to FPUaccretion
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 FahrenheitDegree-Day
Lenders:Marlin Gas Services: PNC, BankMarlin Gas Services, LLC, a newly created subsidiary of America N.A., Citizens Bank N.A., Royal BankChesapeake Utilities that acquired certain operating assets of Canada, and Wells Fargo Bank, National Association, which are collectively the lenders that entered into the Credit Agreement with Chesapeake UtilitiesMarlin Gas Transport, Inc.
MDE:Marlin Gas Transport: Maryland DepartmentMarlin Gas Transport, Inc.,a supplier of Environmentmobile compressed natural gas utility and pipeline solutions
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

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MTM: FairMark-to-Market (fair value (mark-to-market) accounting required for derivatives in accordance with ASC 815, Derivatives and Hedging
NOPR: Notice of Proposed Rulemakingaccounting)
NYL: New York Life Investors LLC, an institutional debt investment management firm, with which weChesapeake Utilities entered into the NYLa Shelf Agreement
NYL Shelf Agreement: An agreement entered into by Chesapeake Utilities and NYL in March 2017 pursuant to which Chesapeake Utilities may request that NYL purchase, through March 2, 2020, up to $100.0 million of unsecured senior debt at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance
NYL Shelf Notes: Unsecured senior promissory notes issuable under the NYL Shelf Agreement
OPT Service: Off Peak ≤ 30 or ≤ 90 Firm Transportation Service, a tariff associated with Eastern Shore's firm transportation service that allows Eastern Shore to not schedule service for up to 30 or 90 days during the peak months of November through April each year
OTC: Over-the-counter
Peninsula Pipeline: Peninsula Pipeline Company, Inc., a wholly-owned subsidiary of Chesapeake Utilities' wholly-owned Florida intrastate pipeline subsidiaryUtilities
PESCO: Peninsula Energy Services Company, Inc., a wholly-owned subsidiary of Chesapeake Utilities' wholly-owned natural gas marketing subsidiaryUtilities

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

Prudential: PGIM, Inc., formerly known as Prudential Investment Management Inc., an institutional investment management firm, with which we haveChesapeake Utilities has entered into the Prudentiala Shelf Agreement
Prudential and issued Shelf Agreement: An agreement entered into by Chesapeake Utilities and Prudential in October 2015 pursuant to which Chesapeake Utilities could request that Prudential purchase, through October 7, 2018, up to $150.0 million of Prudential Shelf Notes at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance, as subsequently amended in September 2018, pursuant to which we may request that Prudential purchase up to $150.0 million of our unsecured debt over a three-year period, expiring in August 2021
Prudential Shelf Notes: Unsecured senior promissory notes issuable under the Prudential Shelf Agreement
PSC: Public Service Commission, which is the state agency that regulates theutility rates andand/or services provided by Chesapeake Utilities’ natural gas and electric distribution operations in Delaware, Maryland and Florida and Peninsula Pipeline in Florida
Rayonier: Rayonier Performance Fibers, LLC, the company that owns the property on which Eight Flags' CHP plant is located, and a customercertain of the steam generated by the CHP plantour jurisdictions
Retirement Savings Plan: A qualified 401(k) retirement savings plan sponsored by Chesapeake Utilities
Revolver: Our unsecured revolving credit facility with the Lenders
ROU: Right of usecertain lenders
Sandpiper: Sandpiper Energy, Inc., Chesapeake Utilities'a 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 siteof Chesapeake Utilities
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., a wholly-owned subsidiary of Chesapeake Utilities' wholly-owned propane distribution subsidiaryUtilities
Shelf Agreement: An agreement entered into by Chesapeake Utilities and a counterparty pursuant to which Chesapeake Utilities may request that the counterparty purchase our unsecured senior debt with a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance
Shelf Notes: Unsecured senior promissory notes issuable under the Shelf Agreement executed with various counterparties
SICP: Chesapeake Utilities' 2013 Stock and Incentive Compensation Plan
TCJA: The Tax Cuts and Jobs Act of 2017, which is legislation passed by Congress and signed into law by the Presidentenacted 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

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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

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PART I—FINANCIAL INFORMATION
Item 1. Financial Statements
Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Income (Unaudited)
 
 Three Months Ended Nine Months Ended  Three Months Ended
 September 30, September 30,  March 31,
 2018 2017 2018 2017  2019 2018
(in thousands, except shares and per share data)             
Operating Revenues             
Regulated Energy $72,770
 $69,703
 $252,667
 $238,353
  $103,618
 $109,393
Unregulated Energy and other 67,509
 57,233
 263,632
 198,827
  123,998
 129,963
Total Operating Revenues 140,279
 126,936
 516,299
 437,180
  227,616
 239,356
Operating Expenses             
Regulated Energy cost of sales 21,501
 22,794
 89,741
 87,206
  36,516
 48,231
Unregulated Energy and other cost of sales 55,660
 44,066
 204,880
 145,325
  89,703
 99,826
Operations 32,821
 29,274
 101,804
 91,778
  37,144
 32,702
Maintenance 3,208
 2,737
 10,419
 9,370
  3,681
 3,593
Gain from a settlement —
 —
 (130) (130) 
Depreciation and amortization 10,633
 9,362
 30,176
 27,267
  11,074
 9,704
Other taxes 4,420
 4,071
 13,719
 12,572
  5,505
 4,894
Total Operating Expenses 128,243
 112,304
 450,609
 373,388
  183,623
 198,950
Operating Income 12,036
 14,632
 65,690
 63,792
  43,993
 40,406
Other expense, net (11) (154) (204) (1,855) 
Other income (expense), net (45) 68
Interest charges 4,430
 3,321
 11,976
 9,133
  5,710
 3,664
Income Before Income Taxes 7,595
 11,157
 53,510

52,804
  38,238
 36,810
Income taxes 2,057
 4,324
 14,731
 20,781
  9,574
 9,955
Net Income $5,538
 $6,833
 $38,779

$32,023
  $28,664
 $26,855
Weighted Average Common Shares Outstanding:             
Basic 16,378,545
 16,344,442
 16,366,608
 16,334,210
  16,384,927
 16,351,338
Diluted 16,428,439
 16,389,635
 16,416,255
 16,378,633
  16,432,852
 16,402,985
Earnings Per Share of Common Stock:             
Basic $0.34
 $0.42
 $2.37
 $1.96
  $1.75
 $1.64
Diluted $0.34
 $0.42
 $2.36
 $1.96
  $1.74
 $1.64
Cash Dividends Declared Per Share of Common Stock $0.3700
 $0.3250
 $1.0650
 $0.9550
 
The accompanying notes are an integral part of these financial statements.


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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
 
 Three Months Ended Nine Months Ended Three Months Ended
 September 30, September 30, March 31,
 2018 2017 2018 2017 2019 2018
(in thousands)            
Net Income $5,538
 $6,833
 $38,779
 $32,023
 $28,664
 $26,855
Other Comprehensive Income (Loss), net of tax:            
Employee Benefits, net of tax:            
Amortization of prior service cost, net of tax of $(5), $(8), $(16) and $(23), respectively (14) (11) (42) (35)
Net gain, net of tax of $38, $69, $118 and $212, respectively 100
 102
 317
 297
Amortization of prior service cost, net of tax of $(5) and $(5), respectively (14) (14)
Net gain, net of tax of $42 and $41, respectively 121
 108
Cash Flow Hedges, net of tax:            
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $257, $(15), $(70) and $(376), respectively 644
 (104) (83) (643)
Unrealized gain (loss) on commodity contract cash flow hedges, net of tax of $1,194 and $(756), respectively 2,982
 (1,788)
Total Other Comprehensive Income (Loss), net of tax 730
 (13) 192
 (381) 3,089
 (1,694)
Comprehensive Income $6,268
 $6,820
 $38,971
 $31,642
 $31,753
 $25,161
The accompanying notes are an integral part of these financial statements.

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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Assets September 30,
2018		 December 31,
2017		 March 31,
2019		 December 31,
2018
(in thousands, except shares and per share data)        
Property, Plant and Equipment        
Regulated Energy $1,242,840
 $1,073,736
 $1,346,221
 $1,297,416
Unregulated Energy 220,721
 210,682
 241,126
 237,682
Other businesses and eliminations 34,975
 27,699
 30,282
 34,585
Total property, plant and equipment 1,498,536
 1,312,117
 1,617,629
 1,569,683
Less: Accumulated depreciation and amortization (295,449) (270,599) (312,949) (294,295)
Plus: Construction work in progress 60,243
 84,509
 90,453
 108,584
Net property, plant and equipment 1,263,330
 1,126,027
 1,395,133
 1,383,972
Current Assets        
Cash and cash equivalents 6,215
 5,614
 7,975
 6,089
Trade and other receivables (less allowance for uncollectible accounts of $987 and $936, respectively) 52,660
 77,223
Trade and other receivables (less allowance for uncollectible accounts of $1,054 and $1,108, respectively) 74,098
 85,404
Accrued revenue 12,352
 22,279
 20,747
 27,499
Propane inventory, at average cost 7,444
 8,324
 6,865
 9,791
Other inventory, at average cost 4,786
 12,022
 8,122
 7,127
Regulatory assets 6,891
 10,930
 7,913
 4,796
Storage gas prepayments 6,989
 5,250
 1,327
 6,603
Income taxes receivable 8,725
 14,778
 9,059
 15,300
Prepaid expenses 9,775
 13,621
 7,192
 10,079
Derivative assets, at fair value 10,568
 1,286
 9,221
 13,165
Other current assets 2,557
 7,260
 1,121
 5,684
Total current assets 128,962
 178,587
 153,640
 191,537
Deferred Charges and Other Assets        
Goodwill 19,604
 19,604
 25,785
 25,837
Other intangible assets, net 4,073
 4,686
 5,909
 6,207
Investments, at fair value 7,951
 6,756
 7,509
 6,711
Operating lease right-of-use assets (refer to Note 15) 12,523
 —
Regulatory assets 76,343
 75,575
 77,101
 72,422
Other assets 5,293
 3,699
 5,197
 6,985
Total deferred charges and other assets 113,264
 110,320
 134,024
 118,162
Total Assets $1,505,556
 $1,414,934
 $1,682,797
 $1,693,671
 
The accompanying notes are an integral part of these financial statements.
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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Capitalization and Liabilities September 30,
2018		 December 31,
2017		 March 31,
2019		 December 31,
2018
(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
 7,980
 7,971
Additional paid-in capital 255,509
 253,470
 255,307
 255,651
Retained earnings 249,805
 229,141
 284,111
 261,530
Accumulated other comprehensive loss (4,987) (4,272) (3,739) (6,713)
Deferred compensation obligation 3,818
 3,395
 4,376
 3,854
Treasury stock (3,818) (3,395) (4,376) (3,854)
Total stockholders’ equity 508,298
 486,294
 543,659
 518,439
Long-term debt, net of current maturities 241,597
 197,395
 285,998
 316,020
Total capitalization 749,895
 683,689
 829,657
 834,459
Current Liabilities        
Current portion of long-term debt 9,613
 9,421
 71,509
 11,935
Short-term borrowing 268,293
 250,969
 276,393
 294,458
Accounts payable 60,228
 74,688
 75,277
 129,804
Customer deposits and refunds 34,887
 34,751
 29,710
 34,155
Accrued interest 3,969
 1,742
 4,505
 2,317
Dividends payable 6,060
 5,312
 6,067
 6,060
Accrued compensation 10,396
 13,112
 8,506
 13,923
Regulatory liabilities 9,099
 6,485
 15,085
 7,883
Derivative liabilities, at fair value 9,774
 6,247
 6,798
 14,871
Other accrued liabilities 14,819
 10,273
 14,719
 12,828
Total current liabilities 427,138
 413,000
 508,569
 528,234
Deferred Credits and Other Liabilities        
Deferred income taxes 146,814
 135,850
 160,912
 156,820
Regulatory liabilities 141,840
 140,978
 132,686
 135,039
Environmental liabilities 7,941
 8,263
 7,370
 7,638
Other pension and benefit costs 28,839
 29,699
 29,822
 28,513
Operating lease - liabilities (refer to Note 15) 10,873
 —
Deferred investment tax credits and other liabilities 3,089
 3,455
 2,908
 2,968
Total deferred credits and other liabilities 328,523
 318,245
 344,571
 330,978
Environmental and other commitments and contingencies (Notes 5 and 6) 
 
 
 
Total Capitalization and Liabilities $1,505,556
 $1,414,934
 $1,682,797
 $1,693,671
The accompanying notes are an integral part of these financial statements.

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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
 Nine Months Ended Three Months Ended
 September 30, March 31,
 2018 2017 2019 2018
(in thousands)        
Operating Activities        
Net income $38,779
 $32,023
 $28,664
 $26,855
Adjustments to reconcile net income to net cash provided by operating activities:        
Depreciation and amortization 30,176
 27,267
 11,074
 9,704
Depreciation and accretion included in other costs 6,464
 5,989
 2,135
 2,276
Deferred income taxes 11,047
 29,520
 3,430
 6,469
Realized loss (gain) on commodity contracts/sale of assets/investments 4,015
 (2,817)
Unrealized gain on investments/commodity contracts (427) (695)
Realized (gain) loss on commodity contracts/sale of assets/investments (363) 3,416
Unrealized (gain) loss on investments/commodity contracts (721) 44
Employee benefits and compensation 456
 1,212
 382
 228
Share-based compensation 2,535
 1,608
 487
 1,520
Other, net (35) (39) —
 (12)
Changes in assets and liabilities:        
Accounts receivable and accrued revenue 32,988
 12,912
 18,147
 9,649
Propane inventory, storage gas and other inventory 6,379
 (8,256) 7,207
 12,448
Regulatory assets/liabilities, net 3,899
 927
 3,121
 11,511
Prepaid expenses and other current assets (1,533) (2,860) 11,873
 8,095
Accounts payable and other accrued liabilities (9,590) 4,515
 (44,783) (26,932)
Income taxes receivable 6,053
 (3,810) 6,241
 8,741
Customer deposits and refunds 136
 3,255
 (4,445) 44
Accrued compensation (2,804) (2,030) (5,548) (7,731)
Other assets and liabilities, net (542) (349) 3,585
 347
Net cash provided by operating activities 127,996
 98,372
 40,486
 66,672
Investing Activities        
Property, plant and equipment expenditures (171,410) (130,137) (43,216) (63,116)
Proceeds from sales of assets 565
 601
 115
 193
Acquisitions, net of cash acquired —
 (11,707)
Environmental expenditures (322) (210) (268) (48)
Net cash used in investing activities (171,167) (141,453) (43,369) (62,971)
Financing Activities        
Common stock dividends (16,171) (14,780) (5,877) (5,147)
(Purchase) issuance of stock under the Dividend Reinvestment Plan (518) 254
Stock issuance —
 (10)
Issuance of stock under the Dividend Reinvestment Plan (183) (164)
Tax withholding payments related to net settled stock compensation (1,210) (692) (692) (719)
Change in cash overdrafts due to outstanding checks 712
 (3,013) 84
 2,352
Net borrowing (repayment) under line of credit agreements and short-term borrowing under the Revolver 16,612
 (3,760)
Proceeds from long-term debt and long-term borrowing under the Revolver 74,901
 69,800
Net repayment under line of credit agreements (18,149) (24,213)
Proceeds from long-term debt 30,000
 25,000
Repayment of long-term debt, long-term borrowing under the Revolver and capital lease obligation (30,554) (5,510) (414) (428)
Net cash provided in financing activities 43,772
 42,289
Net Increase (Decrease) in Cash and Cash Equivalents 601
 (792)
Net cash provided (used) by financing activities 4,769
 (3,319)
Net Increase in Cash and Cash Equivalents 1,886
 382
Cash and Cash Equivalents—Beginning of Period 5,614
 4,178
 6,089
 5,614
Cash and Cash Equivalents—End of Period $6,215
 $3,386
 $7,975
 $5,996
The accompanying notes are an integral part of these financial statements.
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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)
 
Common Stock (1)
            
Common Stock (1)
            
(in thousands, except shares and per share data)
Number  of
Shares(2)
 
Par
Value
 
Additional  Paid-In
Capital
 
Retained
Earnings
 
Accumulated  Other Comprehensive
Loss
 
Deferred
Compensation
 
Treasury
Stock
 Total
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, 201616,303,499
 $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 plan10,771
 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, 201716,344,442
 7,955
 253,470
 229,141
 (4,272) 3,395
 (3,395) 486,294
16,344,442
 $7,955
 $253,470
 $229,141
 $(4,272) $3,395
 $(3,395) $486,294
Net income—
 —
 —
 38,779
 —
 —
 —
 38,779
—
 —
 —
 26,855
 —
 —
 —
 26,855
Cumulative effect of the adoption of ASU 2014-09—
 —
 —
 (1,498) —
 —
 —
 (1,498)—
 —
 —
 (1,498) —
 —
 —
 (1,498)
Reclassification upon the adoption of ASU 2018-02—
 —
 —
 907
 (907) —
 —
 —
—
 —
 —
 907
 (907) —
 —
 —
Other comprehensive loss—
 —
 —
 —
 (1,694) —
 —
 (1,694)
Dividend declared ($.3250 per share)—
 —
 —
 (5,381) —
 —
 —
 (5,381)
Dividend reinvestment plan—
 —
 (1) —
 —
 —
 —
 (1)
Share-based compensation and tax benefit (3)(4)
19,350
 9
 657
 —
 —
 —
 —
 666
Treasury stock activities—
 —
 —
 —
 —
 178
 (178) —
Balance at March 31, 201816,363,792
 $7,964
 $254,126
 $250,024
 $(6,873) $3,573
 $(3,573) $505,241
               
Balance at December 31, 201816,378,545
 $7,971
 $255,651
 $261,530
 $(6,713) $3,854
 $(3,854) $518,439
Net income—
 —
 —
 28,664
 —
 —
 —
 28,664
Prior period reclassification—
 —
 —
 115
 (115) —
 —
 —
Other comprehensive income—
 —
 —
 —
 192
 —
 —
 192
—
 —
 —
 —
 3,089
 —
 —
 3,089
Dividend declared ($1.065 per share)—
 —
 —
 (17,524) —
 —
 —
 (17,524)
Dividend declared ($0.3700 per share)—
 —
 —
 (6,198) —
 —
 —
 (6,198)
Dividend reinvestment plan—
 —
 (2) —
 —
 —
 —
 (2)—
 —
 (1) —
 —
 —
 —
 (1)
Share-based compensation and tax benefit (3) (4)
34,103
 16
 2,041
 —
 —
 —
 —
 2,057
18,472
 9
 (343) —
 —
 —
 —
 (334)
Treasury stock activities—
 —
 —
 —
 —
 423
 (423) —
—
 —
 —
 —
 —
 522
 (522) —
Balance at September 30, 201816,378,545
 $7,971
 $255,509
 $249,805
 $(4,987) $3,818
 $(3,818) $508,298
Balance at March 31, 201916,397,017
 $7,980
 $255,307
 $284,111
 $(3,739) $4,376
 $(4,376) $543,659
 
(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)
(2)
Includes 96,622101,997 shares at March 31, 2019, 97,053 shares at December 31, 2018, 93,422 shares at March 31, 2018 and 90,961 shares at September 30, 2018 and December 31, 2017, respectively, held in a Rabbi Trust related to our Non-Qualified 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 ninethree months ended September 30,March 31, 2019 and 2018, and for the year ended December 31, 2017, we withheld 16,9187,635 and 10,26910,436 shares, respectively, for taxes.

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

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NOTES TO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)
 
1.    Summary of Accounting Policies
Basis of Presentation
References in this document to the “Company,” “Chesapeake Utilities,” “we,” “us” and “our” are intended to mean Chesapeake Utilities Corporation, its divisions and/or its subsidiaries, as appropriate in the context of the disclosure.
The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2017.2018. 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, ChipolaMarlin Gas Transport and Central Gas AssetOhl Fuel Oil Acquisitions
In August 2017, PESCO acquired certain natural gas marketing assets of ARM. The acquired assets complemented PESCO’s existing asset portfolio and expanded our regional footprint and retail demand in a market where we had existing pipeline capacity and wholesale liquidity.  We accounted for the purchase of these assets as a business combination and initially recorded goodwill of $6.8 million within our Unregulated Energy segment. In connection with the acquisition, we initially recorded a contingent consideration liability of $2.5 million, based on our preliminary analysis projecting that the acquired business would achieve at least a certain gross margin target in 2018. During the second quarter ofDecember 2018, we identified certain known information as of the acquisition date that was not considered in our original analysis and would have resulted in no contingent consideration liability being initially recorded. Therefore, we reversed the originally-recorded contingent liability and reduced goodwill by $2.5 million. We similarly revised the condensed consolidated balance sheet as of December 31, 2017. These revisions are considered immaterial to our condensed consolidated financial statements. The need for a contingent consideration liability will be re-evaluated in the final reporting period in 2018. However, our current assessment is that no contingent consideration will be paid.

In August 2017, Flo-gasMarlin Gas Services acquired certain operating assets of Chipola,Marlin Gas Transport. The acquisition will enable us to offer solutions to supply interruption scenarios and tailor other alternatives where pipeline supplies are unavailable or inadequate to meet customer requirements.
In December 2018, Sharp acquired certain propane operating assets and customers of R. F. Ohl Fuel Oil, Inc. ("Ohl"), which provided propane distribution service to approximately 8002,500 residential and commercial customers in Bay, Calhoun, Gadsden, Jackson, Liberty, and Washington Counties, Florida.Pennsylvania.

In December 2017, Flo-gas acquired certainWe accounted for the purchases of the operating assets of CentralMarlin Gas Transport and Ohl, which provides propane distribution servicetotaled approximately $18.4 million, as business combinations within our Unregulated Energy segment. Goodwill of $4.8 million, related to approximately 325 residentialthe Marlin Gas Transport acquisition, and commercial customers in Glades, Highlands, Martin, Okeechobee, and St. Lucie Counties, Florida.

The revenue and net income from$1.5 million, associated with the Ohl acquisition, were initially recorded at the close of these acquisitions, which were included in our condensed consolidated statements of income for the three and nine months ended September 30, 2018, were not material.transactions. The acquisition accounting amounts recorded in conjunction with the ARM and Chipolathese acquisitions are now final although the amounts associated with the Central Gas acquisition are preliminary and subject to adjustment based on additional valuations performed during the measurement period. Due to the timing of these acquisitions, the revenue and net income from these acquisitions in 2018 were immaterial. For the quarter ended March 31, 2019, these acquisitions generated the following operating revenue and income:
 Three Months Ended March 31, 2019
 Operating Revenue Operating Income
(in thousands)   
Marlin Gas Services$2,434
 $1,375
Ohl$822
 $273

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

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

The following highlights the impact of the adoption of ASC 606 on our condensed consolidated income statements for the three and nine months ended September 30, 2018 and condensed consolidated balance sheet as of September 30, 2018:
  Three Months Ended 
 September 30, 2018		 Nine Months Ended 
 September 30, 2018
Income statement As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower) As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower)
(in thousands)            
Regulated Energy operating revenues $72,770
 $72,879
 $(109) $252,667
 $253,659
 $(992)
Regulated Energy cost of sales 21,501
 21,512
 (11) 89,741
 90,454
 (713)
Depreciation and amortization 10,633
 10,629
 4
 30,176
 30,150
 26
Income before income taxes 7,595
 7,697
 (102) 53,510
 53,815
 (305)
Income taxes 2,057
 2,086
 (29) 14,731
 14,819
 (88)
Net income 5,538
 5,611
 (73) 38,779
 38,996
 (217)
  As of September 30, 2018
Balance sheet As Reported Without Adoption of ASC 606 Effect of Change Higher (Lower)
(in thousands)      
Assets      
Accrued revenues $12,352
 $13,658
 $(1,306)
Other assets $5,293
 $5,702
 $(409)
      
Capitalization     
Retained earnings $249,805
 $251,520
 $(1,715)
       
The primary impact of the adoption of ASC 606 on our income statement was the delayed recognition of approximately $305,000 in revenue in the first nine months of 2018 to future years and a cumulative adjustment that decreased retained earnings and other assets by $1.7 million at September 30, 2018, associated with a long-term firm transmission contract with an industrial customer.
Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost and Net Periodic Post Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and should not be included operating expenses. The update allows for capitalization of the service cost component when applicable. We adopted ASU 2017-07 on January 1, 2018 and applied the changes in the presentation of the service cost and other components of net benefit costs, retrospectively. Aside from changes in presentation, implementation of this standard did not have a material impact on our financial position or results of operations.
Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain transactions are classified in the statement of cash flows. We adopted ASU 2016-15 on January 1, 2018. Implementation of this new standard did not have a material impact on our condensed consolidated statement of cash flows.
Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scopeof ModificationAccounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) change because of a change in the terms or conditions of the award. We adopted
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ASU 2017-09, prospectively, on January 1, 2018. Implementation of this new standard did not have a material impact on our financial position or results of operations.
Income Statement - Reporting Comprehensive Income (ASC 220) - In February 2018, the FASB issued ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income, which allows a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the TCJA. We adopted ASU 2018-02 on January 1, 2018, and reclassified stranded tax effects from accumulated other comprehensive loss related to our employee benefit plans and commodity contract cash flows hedges. Implementation of this new standard did not have a material impact on our financial position and results of operations. See Note 8, Stockholders' Equity, for additional information.
Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument that is included in the assessment of hedge effectiveness to be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges and eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. ASU 2017-12 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We adopted ASU 2017-12 effective July 1, 2018, with no material impact on our financial statements. See Note 12, Derivative Instruments, for additional information with respect to the disclosures required by ASU 2017-12.
Recent Accounting Standards Yet to be Adopted
Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which requires lessees to recognize leases on the balance sheet and disclose key information about leasing arrangements. The standard establishes a ROUright of use model that requires a lessee to recognize a ROUright of use asset and lease liability for all leases with a term greater than 12 months. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASC 842 was subsequently amended by ASU No. 2018-01, Land Easement Practical Expedient for Transition to Topic 842; ASU No. 2018-10, Codification Improvements to Topic 842, Leases; and ASU No. 2018-11, Targeted Improvements; and ASU No. 2019-01, Codification Improvements. We adopted ASU 2016-02 will be effective for our annual and interim financial statements, beginning January 1, 2019, although early adoption is permitted. We expect to adopt ASU 2016-02 effectivethe related amendments on January 1, 2019, and useused the modified retrospectiveoptional transition approach tomethod for all existing leases.
The optional transition method enables us to adopt the new standard permits companiesas of the beginning of the period of adoption and does not require restatement of prior period financial information. As a result, prior period financial information has not been recast and continues to elect severalbe reported under the accounting guidance that was effective during those periods.
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At adoption, we elected the following practical expedients. We expect to elect:expedients: (1) the ‘package of practical expedients,’ pursuant to which we dodid not need to reassess our prior conclusions about lease identification, lease classification and initial direct costs, and (2) the ‘use-of-hindsight’ practical expedient, which allowsallowed us to use hindsight in assessing impairment of our existing land easements. We also intendeasements, (3) creation of an accounting policy for short-term leases resulting in lease payments being recorded as an expense on a straight-line basis over the lease term, and (4) to aggregate allnot separate lease and non-lease components for all leases.
See Note 15, Leases, for additional information with respect to the impact of the adoption of the lease componentsaccounting guidance and the disclosures required by ASU 2016-02 and the related amendments.

Compensation - Stock Compensation (ASC 718) - In June 2018, the FASB issued ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting, which they relate.
The most significant effectexpands the scope of ASC 842 will be recognitionTopic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. We adopted ASU 2018-07 on January 1, 2019. Implementation of ROU assets and lease liabilitiesthis new standard did not have a material impact on our balance sheet for our operating leases and providing significant new disclosures about our leasing activities. We currently expect that upon adoption, we will recognize lease liabilities ranging from $4.0 millionfinancial position or results of operations.
Recent Accounting Standards Yet to $5.0 million, with corresponding ROU of the same amount based on the present value of the remaining minimum rental payments for existing operating leases.be Adopted
Intangibles-Goodwill (ASC 350) - In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment, which simplifies how an entity is required to test goodwill for impairment by eliminating Step 2 from the goodwill impairment test. ASU 2017-04 will be effective for our annual and interim financial statements beginning January 1, 2020, although early adoption is permitted. The amendments included in this ASU are to be applied prospectively. We believe that implementation of this new standard will not have a material impact on our financial position or results of operations.
Compensation - Stock Compensation (ASC 718) - In June 2018, the FASB issued ASU 2018-07, Improvements to Nonemployee Share-Based Payment Accounting, which expands the scope of Topic 718 to include share-based payment transactions for acquiring goods and services from nonemployees. ASU 2018-07 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We believe that implementation of this new standard will not have a material impact on our financial position or results of operations.
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Fair Value Measurement (ASC 820) - In August 2018, the FASB issued ASU 2018-13, Disclosure Framework - Changes to the Disclosure Requirements for Fair Value Measurement, which removes, modifies and adds certain disclosure requirements on fair value measurements in ASC 820. ASU 2018-13 will be effective for our annual and interim financial statements beginning January 1, 2020 and, since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.
Compensation - Retirement Benefits - Defined Benefit Plans - General (ASC 715-20) - In August 2018, the FASB issued ASU 2018-14, Disclosure Framework - Changes to the Disclosure Requirements for Defined Benefit Plans, which removes, clarifies and adds certain disclosure requirements in ASC 715-20 related to defined benefit pension and other postretirement plans. ASU 2018-14 will be effective for our annual and interim financial statements, on a retrospective basis, beginning January 1, 2021 and, since the changes only impact disclosures, will not have a material impact on our financial position or results of operations.

2.Calculation of Earnings Per Share

 Three Months Ended Nine Months Ended Three Months Ended
 September 30, September 30, March 31,
 2018 2017 2018 2017 2019 2018
(in thousands, except shares and per share data)            
Calculation of Basic Earnings Per Share:            
            
Net Income $5,538
 $6,833
 $38,779
 $32,023
 $28,664
 $26,855
Weighted average shares outstanding 16,378,545
 16,344,442
 16,366,608
 16,334,210
 16,384,927
 16,351,338
Basic Earnings Per Share $0.34
 $0.42
 $2.37
 $1.96
 $1.75
 $1.64
            
Calculation of Diluted Earnings Per Share:            
Reconciliation of Numerator:            
Net Income $5,538
 $6,833
 $38,779
 $32,023
 $28,664
 $26,855
Reconciliation of Denominator:            
Weighted shares outstanding—Basic 16,378,545
 16,344,442
 16,366,608
 16,334,210
 16,384,927
 16,351,338
Effect of dilutive securities—Share-based compensation 49,894
 45,193
 49,647
 44,423
 47,925
 51,647
Adjusted denominator—Diluted 16,428,439
 16,389,635
 16,416,255
 16,378,633
 16,432,852
 16,402,985
Diluted Earnings Per Share $0.34
 $0.42
 $2.36
 $1.96
 $1.74
 $1.64
 

3.     Revenue Recognition

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

The following table displays our revenue by major source based on product and service type for the three months ended September 30,March 31, 2019 and 2018:
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 Three months ended March 31, 2019 Three Months Ended March 31, 2018
(in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total Regulated Energy Unregulated Energy Other and Eliminations Total Regulated Energy Unregulated Energy Other and Eliminations Total
Energy distribution                        
Delaware natural gas division $27,549
 $—
 $—
 $27,549
 $32,072
 $—
 $—
 $32,072
Florida natural gas division $6,282
 $—
 $—
 $6,282
 7,900
 —
 —
 7,900
 5,864
 —
 —
 5,864
Delaware natural gas division 7,010
 —
 —
 7,010
FPU electric distribution 23,830
 —
 —
 23,830
 14,378
 —
 —
 14,378
 18,741
 —
 —
 18,741
FPU natural gas distribution 17,390
 —
 —
 17,390
 23,786
 —
 —
 23,786
 23,213
 —
 —
 23,213
Maryland natural gas division 2,463
 —
 —
 2,463
 10,047
 —
 —
 10,047
 10,672
 —
 —
 10,672
Sandpiper 3,561
 —
 —
 3,561
Sandpiper natural gas/propane operations 7,082
 —
 —
 7,082
 8,964
 —
 —
 8,964
Total energy distribution 60,536
 —
 —
 60,536
 90,742
 —
 —
 90,742
 99,526

—

—

99,526
       
       
        
Energy transmission       
       
        
Aspire Energy —
 5,750
 —
 5,750
 —
 13,470
 —
 13,470
 —
 12,077
 —
 12,077
Eastern Shore 16,189
 —
 —
 16,189
 19,056
 —
 —
 19,056
 15,597
 —
 —
 15,597
Peninsula Pipeline 3,404
 —
 —
 3,404
 3,565
 —
 —
 3,565
 2,098
 —
 —
 2,098
Total energy transmission 19,593
 5,750
 —
 25,343
 22,621
 13,470
 —
 36,091

17,695

12,077

—

29,772
                        
Energy generation       
       
        
Eight Flags —
 4,044
 —
 4,044
 —
 4,142
 —
 4,142
 —
 4,378
 —
 4,378
       
       
        
Propane delivery        
Delmarva Peninsula propane delivery —
 13,172
 —
 13,172
Florida propane delivery —
 4,166
 —
 4,166
Total propane delivery —
 17,338
 —
 17,338
Propane operations                
Propane delivery operations —
 46,125
 —
 46,125
 —
 52,104
 —
 52,104
                        
Energy services                        
PESCO —
 51,619
 —
 51,619
Marlin Gas Services —
 2,434
 —
 2,434
 —
 —
 —
 —
PESCO - Natural Gas Marketing —
 77,022
 —
 77,022
   81,559
 —
 81,559
Total energy services —
 79,456
 —
 79,456
 —
 81,559
 —
 81,559
                        
Other and eliminations       
       
        
Eliminations (7,359) (3,185) (8,668) (19,212) (9,745) (5,496) (14,236) (29,477) (7,828) (5,245) (15,598) (28,671)
Other —
 476
 135
 611
 —
 405
 132
 537
 —
 494
 194
 688
Total other and eliminations (7,359) (2,709) (8,533) (18,601) (9,745) (5,091) (14,104) (28,940) (7,828) (4,751) (15,404) (27,983)
                        
Total operating revenues (1)
 $72,770

$76,042

$(8,533)
$140,279
 $103,618

$138,102

$(14,104)
$227,616
 $109,393
 $145,367
 $(15,404) $239,356
(1) IncludesTotal operating revenues for the three months ended March 31, 2019, include other revenue (revenues from sources other than contracts with customers) of $546,000$121,000 and $91,000$84,000 for our Regulated and Unregulated Energy segments, respectively.respectively and $(589,000) and $73,000 for our Regulated and Unregulated Energy segments, respectively, for the three months ended March 31, 2018. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper and late fees.














Contract balances
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The following table displays our revenue by major source based on product and service type for the nine months ended September 30, 2018:
(in thousands) Regulated Energy Unregulated Energy Other and Eliminations Total
Energy distribution        
Florida natural gas division $18,462
 $—
 $—
 $18,462
Delaware natural gas division 50,963
 —
 —
 50,963
FPU electric distribution 60,933
 —
 —
 60,933
FPU natural gas distribution 58,885
 —
 —
 58,885
Maryland natural gas division 17,136
 —
 —
 17,136
Sandpiper 16,892
 —
 —
 16,892
Total energy distribution 223,271
 —
 —
 223,271
         
Energy transmission        
Aspire Energy —
 23,682
 —
 23,682
Eastern Shore 46,289
 —
 —
 46,289
Peninsula Pipeline 8,469
 —
 —
 8,469
Total energy transmission 54,758
 23,682
 —
 78,440
         
Energy generation        
Eight Flags —
 12,652
 —
 12,652
         
Propane delivery        
Delmarva Peninsula propane delivery —
 73,907
 —
 73,907
Florida propane delivery —
 15,741
 —
 15,741
Total propane delivery —
 89,648
 —
 89,648
         
Energy services        
PESCO —
 181,976
 —
 181,976
         
Other and eliminations        
Eliminations (25,362) (11,679) (34,643) (71,684)
Other —
 1,475
 521
 1,996
Total other and eliminations (25,362) (10,204) (34,122) (69,688)
         
Total operating revenues (1)
 $252,667

$297,754

$(34,122)
$516,299
(1) Includes other revenue (revenues from sources other than contracts with customers) of $(399,000) and $246,000 for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.

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

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

Peninsula Pipeline is engaged in natural gas intrastate transmission to third-party customers and certain affiliates in the State of Florida. Our performance obligation is satisfied over time as the natural gas is transported to customers. We recognize revenue based on rates approved by the Florida PSC and the capacity used or reserved. We accrue unbilled revenues for transportation services provided and not yet billed at the end of an accounting period.

Unregulated Energy segment
Revenues generated from the Unregulated Energy segment are not subject to any federal, state, or local pricing regulations. Aspire Energy primarily sources gas from hundreds of conventional producers and performs gathering and processing functions to maintain the quality and reliability of its gas for its wholesale customers. Aspire Energy's performance obligation is satisfied over time as natural gas is delivered to its customers. Aspire Energy recognizes revenue based on the deliveries of natural gas at contractually agreed upon rates (which are based upon an established monthly index price and a monthly operating fee, as applicable). For natural gas customers, we accrue unbilled revenues for natural gas that has been delivered, but not yet billed, at the end of an accounting period to the extent that billing and delivery do not coincide with the end of the accounting period.
Eight Flags' CHP plant, which is located on land leased from Rayonier, produces three sources of energy: electricity, steam and heated water. Rayonier purchases the steam (unfired and fired) and heated water, which is used in Rayonier’s production facility. Our electric distribution operation purchases the electricity generated by the CHP plant for distribution to its customers. Eight Flags' performance obligation is satisfied over time as deliveries of heated water, steam and electricity occur. Eight Flags recognizes revenues over time based on the amount of heated water, steam and electricity generated and delivered to its customers.
For our propane delivery operations, we recognize revenue based upon customer type and service offered. Generally, for propane bulk delivery customers (customers without meters) and wholesale sales, our performance obligation is satisfied when we deliver propane to the customers' locations (point-in-time basis). We recognize revenue from these customers based on the number of gallons delivered and the price per gallon at the point-in-time of delivery. For our propane delivery customers with meters, we satisfy our performance obligation over time when we deliver propane to customers. We recognize revenue over time based on the amount of propane consumed and the applicable price per unit. For propane delivery metered customers, we accrue unbilled revenues for propane that has been delivered, but not yet billed, at the end of an accounting period to the extent that billing and delivery do not coincide with the end of the accounting period.
PESCO provides natural gas supply and asset management services to customers (including affiliates of Chesapeake Utilities) located primarily in Florida, the Delmarva Peninsula, and the Appalachian Basin. PESCO's performance obligation is satisfied over time as natural gas is delivered to its customers. PESCO recognizes revenue over time based on customer meter readings, on a monthly basis. We accrue unbilled revenues for natural gas that has been delivered, but not yet billed, at the end of an accounting period to the extent that billing and delivery do not coincide with the end of the accounting period.
Contract balances
The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our condensed consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 20172018 and September 30, 2018March 31, 2019 were as follows:
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 Trade Receivables Contract Assets (Non-current) Contract Liabilities (Current) Trade Receivables Contract Assets (Non-current) Contract Liabilities (Current)
(in thousands)            
Balance at 12/31/2017 $74,962
 $1,270
 $407
Balance at 9/30/2018 50,937
 2,331
 583
Balance at 12/31/2018 $83,214
 $2,614
 $480
Balance at 3/31/2019 72,162
 3,004
 305
Increase (decrease) $(24,025) $1,061
 $176
 $(11,052) $390
 $(175)
Our trade receivables are included in trade and other receivables in the condensed consolidated balance sheets. Our non-current contract assets are included in other assets in the condensed consolidated balance sheet and relate to operations and maintenance costs incurred by Eight Flags that have not yet been recovered through rates for the sale of electricity to our electric distribution operation pursuant to a long-term service agreement.

At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. At September 30, 2018March 31, 2019 and December 31, 2017,2018, we had a contract liability of $583,000$305,000 and $407,000,$480,000, respectively, which was included in other accrued liabilities in the condensed consolidated balance sheet, and which relates to non-refundable prepaid fixed fees for our Delmarva Peninsula propane delivery operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the three and nine months ended September 30,March 31, 2019 and 2018, we recognized revenue of $48,000$287,000 and $384,000,$251,000, 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. OurRemaining performance obligations under our
Our businesses have long-term fixed fee contracts with customers in which revenues are recognized as performance obligations are satisfied over time. As a practical expedient, we do not disclose information aboutthe contract term. Revenue for these businesses for the remaining or unsatisfied, performance obligations for these long-term contracts since the revenueat March 31, 2019 are expected to be recognized corresponds to the amount we have the right to invoice.as follows:

(in thousands)2019 2020 2021 2022 2023 2024 2025 and thereafter
Eastern Shore and Peninsula Pipeline$28,754
 $36,791
 $33,510
 $26,566
 $21,146
 $18,969
 $193,651
Natural gas distribution operations2,999
 3,587
 3,358
 3,320
 2,924
 2,910
 27,916
PESCO - Natural Gas Marketing4,435
 4,585
 1,706
 22
 —
 —
 —
FPU electric distribution223
 297
 297
 109
 —
 —
 —
Total revenue contracts with remaining performance obligations$36,411
 $45,260
 $38,871
 $30,017
 $24,070
 $21,879
 $221,567


4.Rates and Other Regulatory Activities

Our natural gas and electric distribution operations in Delaware, Maryland and Florida are subject to regulation by their respective PSC; Eastern Shore, our natural gas transmission subsidiary, is subject to regulation by the FERC; and Peninsula Pipeline, our intrastate pipeline subsidiary, is subject to regulation by the Florida PSC. Chesapeake Utilities' Florida natural gas distribution division and FPU’s natural gas and electric distribution operations continue to be subject to regulation, as separate entities, by the Florida PSC.
Delaware
Effect of the TCJA on customers:Customers: The Delaware PSC issued an order requiring all rate-regulated utilities to file estimates of the impact of the TCJA on their cost of service for the most recent test year available (including new rate schedules). The order also required utilities to propose procedures for changing rates to reflect those impacts on or before MarchOn January 31, 2018. Our Delaware Division filed the requisite reports with2019, the Delaware PSC on March 30, 2018. Subsequently,approved the as-filed Delaware Division filed an updated reportDelivery Service Rates reflecting the impact of the TCJATCJA.  The new rates went into effect March 1, 2019, and we will have to complete refunds retroactive to February 2018, by June 30, 2019.  The order also provided for a line item billing credit that went into effect on May 31, 2018. If, after reviewingApril 1, 2019, for 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 impactsreturn of the excess accumulated deferred income taxes ("ADIT").  Additional information on the TCJA on our operations and existing rates.
In addition, on February 1, 2018, the Delaware PSC issued an order requiring Delaware rate-regulated public utilities to accrue regulatory liabilities reflecting the impacts of changesimpact is included in the federal corporate income tax laws. In compliance withtable at the Delaware PSC order, we have established a regulatory liability to reflect the estimated impactsend of the changes in the federal corporate income tax rate. We believe that the reduction in rates charged by our Delaware Division because of the lower federal income taxes resulting from the TCJA will not have a material effect on our financial position or results of operations, because the reduction will be offset by an equal reduction in income tax expense.this Note 4, Rates and Other Regulatory Activities.
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Underserved Area Rates: In December 2017, we filed an application requesting authorization to utilize existing expansion area tariff rates to serve customers located outside of the current Sussex County, Delaware expansion area boundaries that cannot be economically served under the regular tariff rates. In June 2018, we reached a settlement agreement with the relevant parties, which allows us to utilize higher rates for areas outside of our existing expansion area. The Delaware PSC unanimously approved the settlement at its public meeting on July 10, 2018. The new rate schedule became effective on August 1, 2018.
CGS:Weather Normalization Adjustment: In June 2018,January 2019, we filed with the Delaware PSC an application requesting approval of the acquisition and subsequent conversion of propane to implement a weather normalization adjustment. The proposed weather normalization adjustment will provide either a billing credit (during colder than normal weather) or surcharge (during warmer than normal weather) designed to produce natural gas bills for certain CGS located within our territory. We requested the establishmentcustomers that reflect normal temperatures. The weather normalization adjustment will ensure we do not over or under-collect Delaware PSC authorized levels of regulatory accounting treatment and valuation of the acquisition of certain CGS, approval of a methodologydistribution revenues due to set new distribution rates for CGS customers and approval of a new system-wide tariff rate that will recover CGS conversion costs.weather variability. The Delaware PSC has not reached a decision as of the date of this filing.
Maryland Division and Sandpiper
Effect of the TCJA on customers: The Maryland PSC issued an order requiring all Maryland public utilities with rates explicitly grossed-up for income taxeson March 19, 2019 to trackopen a docket and formally review the impacts of the TCJA, beginning January 1, 2018. The order required utilities to: (a) apply regulatory accounting treatment, which includes the use of regulatory assets and liabilities, for all impacts of the TCJA; (b) file an explanation of the expected effects of the TCJA on their expenses and revenues; and (c) explain when and how they expect to pass on to their customers the net results of those effects. We established a regulatory liability to reflect the impacts of the changes in the federal corporate income tax rate in compliance with the Maryland PSC’s order and made compliance filings that included preliminary estimates of the annual impact of the change in the statutory federal income tax rate. In April 2018, the Maryland PSC ordered both the Maryland Division and Sandpiper to implement reduced rates effective May 1, 2018, reflecting the impact of the TCJA. We implemented a one-time bill credit for the regulatory liability established for the refunds and issued the refunds to customers in July 2018. We submitted an informational filing to the Maryland PSC within the requisite 60 days of completing the refund payments. Additionally, if in the future the Maryland Division or Sandpiper identify any additional tax savings, we must submit an additional filing to the Maryland PSC in order to return those savings to customers as soon as possible. We believe that the reduction in rates charged by our Maryland Division and Sandpiper because of the lower federal income taxes resulting from the TCJA will not have a material effect on our financial position or results of operations, because the reduction is offset by an equal reduction in income tax expense.case.
Florida
Florida Electric Reliability/Modernization Pilot Program: In July 2017, our Florida electric operations filed a petition with the Florida PSC requesting approval to include $15.2 million of certain capital project expenditures in its rate base and to adjust its base rates accordingly. These expenditures are designed to improve the stability and safety of the electric system, while enhancing the capability of our electrical grid. An interconnection project with FPL, which enables us to mitigate fuel costs for our electric customers, was included in the $15.2 million capital project expenditures. In December 2017, the Florida PSC approved this petition, effective January 1, 2018. The settlement agreement prescribed the methodology for adjusting the new rates based on the lower federal income tax rate and the process and methodology regarding the refund of deferred income taxes, reclassified as a regulatory liability, as a result of the TCJA. We have established a regulatory liability to reflect the impacts of the changes in the federal corporate income tax rate in compliance with the settlement agreement.
Electric Limited Proceeding-Storm Recovery: In February 2018, our Florida electric operationsFPU 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 the storm reserve to its pre-storm level of $1.5 million. As a result of these hurricanes and tropical storms, our Florida electric operation’sFPU’s storm reserve was depleted and, is currently at the time of this filing, had a deficit of $779,000. We have requestedThis matter went to hearing in December 2018 and was subsequently approved at the March 5, 2019 Agenda with the Final Order issued on March 25, 2019. FPU received approval ofto begin a surcharge of $1.82$1.54 per 1,000 kilowatt per hour on customer bills for two years beginning in April 2019, to recover storm-related costs and replenish storm-related costs. This matter is scheduled for review at the Florida PSC’s meetingstorm reserve.
Hurricane Michael: In October 2018, Hurricane Michael passed through FPU's electric distribution operation's service territory in Northwest Florida. The hurricane caused widespread and severe damage to FPU's infrastructure resulting in 100 percent of its customers losing electrical service. FPU, after exerting extraordinary hurricane restoration efforts, restored service to those customers who were able to accept it. FPU expended more than $65.0 million to restore service, which has been recorded as new plant and equipment or charged against FPU’s storm reserve. In conjunction with the hurricane-related expenditures, we executed two 13-month unsecured term loans as temporary financing, each in the fourth quarteramount of 2018.$30 million. The interest cost associated with these loans is LIBOR plus 75 points. One of the term loans was executed in December 2018; the other was executed in January 2019. While there is a short-term negative impact, the storm is not expected to have a significant impact going forward, assuming reasonable regulatory treatment. We have begun preparing the necessary regulatory filings to seek recovery of the costs incurred, including the financing costs for the temporary debt issued to fund the new plant and equipment.
Effect of the TCJA on customers:Customers: The Office of Public Counsel filed a petition requesting that the Florida PSC establish a general docket to investigate and adjust rates for all investor-owned utilities related to the passage of the TCJA. The Florida PSC issued a Memorandum with a recommendation that, if utilities do not agree to a January 1, 2018 effective date, then the effective date should beIn February 6, 2018. On January 30, 2018, the Florida PSC scheduled informal meetings between its staffopened dockets to consider the impacts associated with the TCJA. In May 2018, FPU’s natural gas divisions filed petitions and interested persons to discusssupporting testimony regarding the impactdisposition of the related impacts of the TCJA. Hearings for Florida’s electric utilities are tentatively scheduled foron this matter took place in November 2018, and the first quarter of 2019, and hearings for the natural gas utilities are tentatively scheduled for the fourth quarter of 2018.
In December 2017,staff's recommendation was approved by the Florida PSC at the February 5, 2019 Agenda. Final orders were issued an order regardingon February 25, 2019. Staff’s recommendations are summarized in the limited proceeding for our Florida electric operations, which prescribestable at the applicability, timingend of this Note 4, Rates and treatment of the impacts of the TCJA, as discussed above. Other Regulatory Activities.
Imbalance Petition: In June, our
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Florida natural gas operationsFebruary 2019, FPU filed petitions and testimony in support of the disposition of the impacts created by the TCJA. We believe that the reduction in rates charged by our Florida electric and natural gas operations because of the lower federal income taxes resulting from the TCJA will not have a material effect on our financial position or results of operations, because the reduction is offset by an equal reduction in income tax expense.

In October 18, 2018, our electric distribution operation reached a settlement agreement with the Office of Public Counsel. This settlement agreement was filed for approvalpetition, with the Florida PSC, on October 19, 2018to modify the pool manager cash out tiers and hearing inrespective cash out rates. With this action is expected to be held in December 2018. This agreement proposes that our electric distribution operation will flow benefit associated withpetition, FPU further facilitates consistency across the TCJA back to its customers through a combination of reductions toFlorida business units and eliminates the fuel cost recovery rate, base rates, as well as application to the storm reserve over the next several years.

Eastern Shore
2017 Expansion Project: In May 2016, the FERC approved Eastern Shore's request to initiate the pre-filing review process for its 2017 Expansion Project. The 2017 Expansion Project's facilities include approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgrades to existing metering facilities in Lancaster County, Pennsylvania; installation of an additional compressor unit at Eastern Shore’s existing Daleville compressor station in Chester County, Pennsylvania; and approximately 17 miles of new mainline extension and two pressure control stations in Sussex County, Delaware. Eastern Shore entered into precedent agreements with seven existing customers, including three affiliates of Chesapeake Utilities, for a total of 61,162 Dts/d of additional firm natural gas transportation service on Eastern Shore’s pipeline system with an additional 52,500 Dts/d of firm transportation service at certain Eastern Shore receipt facilities.
In October 2017, the FERC issued a CP authorizing Eastern Shore to construct the expansion facilities. The estimated cost of the 2017 Expansion Project is approximately $117.0 million. Eastern Shore submitted its Implementation Plan in October 2017, addressing the actions Eastern Shore will undertake to meet the environmental conditions set forth in the FERC's order.
In December 2017, the TETLP interconnect upgrade was placed into service. In June 2018, the Fair Hill Loop in Chester County, Pennsylvania and Cecil County, Maryland was placed into service. With the exception of some minor facilities, the remaining segments of the 2017 Expansion Project are expected to be placed into service in various phases during the fourth quarter of 2018.
2017 Rate Case Filing: In January 2017, Eastern Shore filed a base rate proceeding with the FERC, as requiredunintentional arbitrage opportunity created by the terms of its 2012 rate case settlement agreement. Eastern Shore based its proposed rates on the mainline cost of service of approximately $60.0 million resulting in an overall requested annual revenue increase of approximately $18.9 million andtariff. The petition does not have a requested rate of return on common equity of 13.75 percent. In March 2017, the FERC issued an order suspending the tariff ratesfinancial impact for the usual five-month period.
In August 2017, Eastern Shore implemented new rates, subject to refund, based on the outcome of the rate proceeding.  Eastern Shore recorded incremental revenue of approximately $3.7 million for the year ended December 31, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates pending FERC approval of the settlement and refunds to customers according to the terms of the settlement agreement. The FERC approved the settlement agreement in February 2018,FPU, and it became final in March 2018. Exclusive of the TCJA impact, base rates would have increased, on an annual basis,will benefit customers by approximately $9.8 million.
Effect of the TCJA on customers: In March 2018, Eastern Shore filed with the FERC its revised base rates, reflecting the change in its federal corporate income tax rate. These adjusted base rates became effective April 1, 2018 and will generate approximately $6.6 million in incremental margin, on an annual basis. Any excess accumulated deferred income tax balances will flow back to customers over the period determined in the next rate case, absent any transition rule included in the TCJA or other statutes or rules that would govern the flow-back period. In April 2018, Eastern Shore refunded to its customers, with interest, the difference between the proposed rates and the settlement rates. The refund to customers also reflected the difference in rates due to the impact of the TCJA.
In March 2018, the FERC issued a NOPR that proposed a process to determine which natural gas pipelines may be collecting unjust and unreasonable rates in light of the recent reduction in the corporate income tax rate in the TCJA and changes to the FERC’s income tax allowance policies following the United Airlines, Inc. v. FERC decision. The NOPR proposed requiring interstate natural gas pipelines to provide an informational filing to allow the FERC to evaluate the impact of the TCJA on the pipelines’ revenue requirement. In April 2018, Eastern Shore filed comments in this proceeding requesting confirmation that Eastern Shore is not required to provide an informational filing because it has already implemented lower rates in accordance with the settlement agreement in its 2017 rate caselowering costs. This petition was approved by the FERC. In July 2018,Florida PSC at the FERC issued a final rule, which largely adoptedApril 2, 2019 Agenda.
Maryland Division and Sandpiper
There were no material regulatory matters during the process proposed in the NOPR, requiring all interstate natural gas companies to file an informational filing for the purpose of evaluating the impact of the TCJA and the Unitedquarter.
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Airlines, Inc. v. FERC decision on interstate natural gas pipelines’ revenue requirements. The final rule provides that an individual pipeline has the option to request a waiver if the pre-March 2018 settlement justifies not adjusting its rates at this time. In September 2018, Eastern Shore requested that the FERC grant it a waiver of the requirement. In October 2018, the FERC issued an order granting the waiver.
Del-Mar Energy Pathway Project: In September 2018, Eastern Shore filed a Certificate Application forwith the FERC, requesting authorization to construct and operate the Del-Mar Energy Pathway project, with the FERC. The proposed project wouldwhich will provide an additional 14,300 Dts/d of capacityfirm service to four customers. Facilities to be constructed include six miles of pipeline looping in Delaware,Delaware; 13 miles of new mainline extension in Sussex County, Delaware and Somerset County, Maryland as well asMaryland; and new pressure control and delivery stations in these counties. The benefits of this project includeinclude: (i) furtheradditional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and (ii) first extension of Eastern Shore’s pipeline system, for the first time, into Somerset County, Maryland. During the fourth quarter of 2018, the FERC held a full project area scoping meeting in Sussex County, Delaware and issued a Notice of Schedule for Environmental Review. The Environmental Assessment for the Del-Mar Energy Pathway project was issued on April 1, 2019. As of the date of this filing, final FERC authorization was still pending.




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Summary TCJA Table

The following table summarizes the TCJA impact on our regulated businesses:
Regulatory Liabilities related to ADIT
Operation and Regulatory JurisdictionAmount (in thousands)StatusStatus of Customer Rate impact related to lower federal corporate income tax rate
Eastern Shore (FERC)$34,190Will be addressed in Eastern Shore's next rate case filingImplemented one-time bill credit (totaling $900,000) in April 2018 - Customer rates adjusted in April, 2018
Delaware Division (Delaware PSC)$13,082PSC approved amortization of ADIT in January 2019Customer rates adjusted March 1, 2019. One-time bill credit to be implemented during the second quarter of 2019
Maryland Division (Maryland PSC)$4,171PSC approved amortization of ADIT in May 2018Implemented one-time bill credit (totaling $365,000) in July 2018 - Customer rates adjusted effective May 1, 2018
Sandpiper Energy (Maryland PSC)$3,803PSC approved amortization of ADIT in May 2018Implemented one-time bill credit (totaling $608,000) in July 2018 - Customer rates adjusted effective May 1, 2018
Chesapeake Florida Gas Division/Central Florida Gas (Florida PSC)$8,346PSC issued order authorizing amortization and retention of net ADIT liability by the Company on February 25, 2019
PSC Staff recommendation issued on January 24, 2019; final order was issued on February 25, 2019; No one-time bill credit or adjustment in rates will be applied; the tax savings arising from the TCJA rate reduction will be retained by the Company

FPU Natural Gas (includes FPU, Fort Meade, and Indiantown) (Florida PSC)$19,478
Same treatment on a net basis as Chesapeake Florida Gas Division (above)

Same treatment on a net basis as Chesapeake Florida Gas Division (above)

FPU Electric (Florida PSC)$5,950In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and ratesTCJA benefit will flow back to its customers through a combination of reductions to the fuel cost recovery rate, base rates, as well as application to the storm reserve over the next several years
 
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. ThoseWe have received approval for recovery of clean-up costs in rates for sites are located in Salisbury, Maryland; Seaford, Delaware; and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We are also in discussions with the MDEMaryland Department of Environment ("MDE") regarding another former MGP site located in Cambridge, Maryland.
As of September 30,March 31, 2019 and December 31, 2018, we had approximately $9.4$8.9 million and $9.1 million, respectively, in environmental liabilities related to FPU’s MGP sites in Key West, Pensacola, Sanford and West Palm Beach. FPU has approval to recover, from insurance and from customers through customer rates, up to $14.0 million of its environmental costs related to its MGP sites. As of September 30,March 31, 2019 and December 31, 2018, we havehad recovered approximately $11.4$11.6 million and $11.5 million, respectively, leaving approximately $2.6$2.4 million and $2.5 million, respectively, in regulatory assets for future recovery of environmental costs from FPU’s customers.
Environmental liabilities for our MGP sites are recorded on an undiscounted basis based on the estimate of future costs provided by independent consultants. We continue to expect that all costs related to environmental remediation and related activities, including any potential future remediation costs for which we do not currently have approval for regulatory recovery, will be recoverable from customers through rates.
The following is a summary of our remediation status and estimated costs to implement clean-up of our key MGP sites:
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JurisdictionMGP Site (Jurisdiction)Status
Estimated Cost to Clean up
Recovery
(Expect to Recover through Rates with Customers)
FloridaWest Palm Beach (Florida)Remedial actions approved by the FDEPFlorida Department of Environmental Protection 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 2018.2019.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
FloridaSanford (Florida)In March 2018, the EPAUnited States Environmental Protection Agency ("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 It is unlikely that FPU will incur any significant future costs associated with the site.
FloridaWinter Haven (Florida)Remediation is ongoing.Not expected to exceed $425,000, which includes costs of implementing institutional controls at the site.Yes
DelawareSeaford (Delaware)SeafordProposed plan for implementationConducted investigations of on-site and off-site impacts in the vicinity of the site, from 2014 through 2018, and submitted the findings to Delaware Department of Natural Resources and Environmental Control ("DNREC") in a March 2019 report. An interim action involving air-sparging/vapor extraction to mitigate on-site impact will be implemented, after the Work Plan has been submitted and approved by the DNREC in July 2017. Site assessment is ongoing.DNREC.Between $273,000 and $465,000.Yes
MarylandCambridge (Maryland)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, ourOur Delmarva Peninsula natural gas distribution operations entered intohave 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 EGWICEastern Gas & Water Investment Company, LLC ("EGWIC") to purchase propane over a six-year term ending inthrough May 2019. Sandpiper's current annual commitment is approximately 1.8 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices. Sandpiper's remaining commitment at March 31, 2019 was approximately 288,000 gallons. Sandpiper has entered into an agreement with EGWIC to purchase any remaining assets at the end of the lease term and will transfer them to Sharp.
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 inthrough May 2019. Sharp's current annualremaining commitment isas of March 31, 2019 was approximately 1.8 million288,000 gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement.
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EGWIC.
Chesapeake Utilities' Florida Division has firm transportation service contracts with FGTFlorida Gas Transmission Company ("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.
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FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with FPLFlorida Power & Light Company requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If FPU fails to meet this ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 2two times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of September 30, 2018,March 31, 2019, FPU was in compliance with all of the requirements of its fuel supply contracts.
Eight Flags provides electricity and steam generation services through its CHP plant located on Amelia Island, Florida. In June 2016, Eight Flags began selling power generated from the CHP plant to FPU pursuant to a 20-year power purchase agreement for distribution to our electric customers. In July 2016, Eight Flags also started selling steam, pursuant to a separate 20-year contract, to Rayonier, the landowner on which the CHP plant is located. The CHP plant is powered by natural gas transported by FPU through its distribution system and Peninsula Pipeline through its intrastate pipeline.

Corporate Guarantees
We have issued corporate guarantees to certain vendors of our subsidiaries, primarily PESCO. These corporate guarantees provide for the payment of natural gas purchases in the event that PESCO defaults. PESCO has never defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred. The aggregate amount guaranteed at September 30, 2018March 31, 2019 was approximately $73.9$77.3 million, with the guarantees expiring on various dates through September 2019.December 2020.
Chesapeake Utilities also guarantees the payment of FPU’s first mortgage bonds. The maximum exposure under this guarantee is the outstanding principal plus accrued interest balances. The outstanding principal balances of FPU’s first mortgage bonds approximate their carrying values (see Note 14, Long-Term Debt, for further details).
Letters of Credit
As of September 30, 2018,March 31, 2019, we have issued letters of credit totaling approximately $5.0$7.0 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.March 2020. There have been no draws on these letters of credit as of September 30, 2018.March 31, 2019. We do not anticipate that the counterparties will draw upon these letters of credit, and we expect that the letters of creditthey will be renewed to the extent necessary in the future.
Other
We are involved in certain other legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental agencies concerning rates. In the opinion of management, the ultimate disposition of these proceedings will not have a material effect on our consolidated financial position, results of operations or cash flows.

7.Segment Information
We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker (our Chief Executive Officer) in order to make decisions about resources and to assess performance.
Our operations are comprised of two reportable segments:
Regulated Energy. Includes energy distribution and transmission services (natural gas distribution, natural gas transmission and electric distribution operations). All operations in this segment are regulated, as to their rates
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and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.
Unregulated Energy. Includes energy transmission, energy generation propane delivery, and other energy services (propane distribution, the(the operations of our Eight Flags' CHP plant, as well asplant), propane operations, the new mobile compressed natural gas utility and pipeline solutions subsidiary, and other energy services (natural gas marketing gathering, processing, transportation and supply)related services). 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”,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.
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The following table presents financial information about our reportable segments:
 Three Months Ended Nine Months Ended Three Months Ended
 September 30, September 30, March 31,
 2018 2017 2018 2017 2019 2018
(in thousands)            
Operating Revenues, Unaffiliated Customers            
Regulated Energy segment $69,697
 $67,257
 $243,382
 $232,519
Unregulated Energy segment and other businesses 70,582
 59,679
 272,917
 204,661
Regulated Energy $100,739
 $105,954
Unregulated Energy 126,877
 133,402
Total operating revenues, unaffiliated customers $140,279
 $126,936
 $516,299
 $437,180
 $227,616
 $239,356
Intersegment Revenues (1)
            
Regulated Energy segment $3,073
 $2,446
 $9,285
 $5,834
Unregulated Energy segment 5,460
 5,009
 24,837
 15,801
Regulated Energy $2,879
 $3,439
Unregulated Energy 11,225
 11,965
Other businesses 135
 194
 521
 581
 132
 194
Total intersegment revenues $8,668
 $7,649
 $34,643
 $22,216
 $14,236
 $15,598
Operating Income            
Regulated Energy segment $15,915
 $15,523
 $56,930
 $53,004
Unregulated Energy segment (3,933) (951) 10,241
 10,626
Regulated Energy $29,741
 $26,711
Unregulated Energy 15,127
 13,684
Other businesses and eliminations 54
 60
 (1,481) 162
 (875) 11
Total operating income 12,036
 14,632
 65,690
 63,792
Other expense, net (11) (154) (204) (1,855)
Operating income 43,993
 40,406
Other income (expense), net (45) 68
Interest charges 4,430
 3,321
 11,976
 9,133
 5,710
 3,664
Income before Income Taxes 7,595
 11,157
 53,510

52,804
 38,238
 36,810
Income taxes 2,057
 4,324
 14,731
 20,781
 9,574
 9,955
Net Income $5,538
 $6,833
 $38,779

$32,023
 $28,664
 $26,855
 
(1)
(1)All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.
All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.
(in thousands) September 30, 2018 December 31, 2017 March 31, 2019 December 31, 2018
Identifiable Assets        
Regulated Energy segment $1,223,537
 $1,121,673
 $1,343,061
 $1,345,805
Unregulated Energy segment 244,390
 259,041
 296,836
 306,045
Other businesses and eliminations 37,629
 34,220
 42,900
 41,821
Total identifiable assets $1,505,556
 $1,414,934
 $1,682,797
 $1,693,671

Our operations are entirely domestic.

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8.Stockholder's Equity
Preferred Stock
We had 2,000,000 authorized and unissued shares of preferred stock, $0.01 par value per share, as of September 30, 2018 and December 31, 2017. Shares of preferred stock may be issued from time to time, by authorization of our Board of Directors and without the necessity of further action or authorization by stockholders, in one or more series and with such voting powers, designations, preferences and relative, participating, optional or other special rights and qualifications as the Board of Directors may, in its discretion, determine.
Accumulated Other Comprehensive Loss
Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements, call options and natural gas swaps and futures contracts, designated as commodity contracts cash flow hedges, are the components of our accumulated other comprehensive loss. During the first quarter of 2018, we elected early adoption of ASU 2018-02, Reclassification of Certain Tax Effects from Accumulated Other Comprehensive Income. Accordingly, we reclassified stranded tax effects resulting from the TCJA from accumulated other comprehensive loss to retained earnings, related to our employee benefit plans and commodity contracts cash flow hedges.
The following tables present the changes in the balance of accumulated other comprehensive (loss)/income as of September 30, 2018March 31, 2019 and 2017.2018. All amounts except the stranded tax reclassification are presented net of tax.

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

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  Defined Benefit Commodity  
  Pension and Contracts  
  Postretirement Cash Flow  
  Plan Items Hedges Total
(in thousands)      
As of December 31, 2016 $(5,360) $482
 $(4,878)
Other comprehensive (loss)/income before reclassifications (9) 322
 313
Amounts reclassified from accumulated other comprehensive income/(loss) 271
 (965) (694)
Net prior-period other comprehensive income/(loss) 262
 (643) (381)
As of September 30, 2017 $(5,098) $(161) $(5,259)
  Defined Benefit Commodity  
  Pension and Contracts  
  Postretirement Cash Flow  
  Plan Items Hedges Total
(in thousands)      
As of December 31, 2018 $(5,928) $(785) $(6,713)
Other comprehensive income before reclassifications —
 3,021
 3,021
Amounts reclassified from accumulated other comprehensive income/(loss) 107
 (39) 68
Net current-period other comprehensive income 107
 2,982
 3,089
Prior-year reclassification —
 (115) (115)
As of March 31, 2019 $(5,821) $2,082
 $(3,739)
(in thousands)      
As of December 31, 2017 $(4,743) $471
 $(4,272)
Other comprehensive loss before reclassifications —
 (2,232) (2,232)
Amounts reclassified from accumulated other comprehensive income/(loss) 94
 444
 538
Net prior-period other comprehensive income/(loss) 94
 (1,788) (1,694)
Stranded tax reclassification to retained earnings (1,022) 115
 (907)
As of March 31, 2018 $(5,671) $(1,202) $(6,873)
The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, 2018March 31, 2019 and 2017.2018. Deferred gains or losses for our commodity contracts cash flow hedges are recognized in earnings upon settlement.
 Three Months Ended Nine Months Ended Three Months Ended
 September 30, September 30, March 31,
 2018 2017 2018 2017 2019 2018
(in thousands)            
Amortization of defined benefit pension and postretirement plan items:            
Prior service credit (1)
 $19
 $19
 $58
 $58
 $19
 $19
Net loss(1)
 (138) (171) (435) (509) (163) (149)
Total before income taxes (119)
(152) (377)
(451) (144)
(130)
Income tax benefit 33
 61
 102
 180
 37
 36
Net of tax $(86) $(91) $(275)
$(271) $(107) $(94)
        
Gains and losses on commodity contracts cash flow hedges:            
Propane swap agreements (2)
 $(276) $198
 $(921) $663
 $606
 $(464)
Natural gas swaps (2)
 123
 1
 (358) 1
 11
 (450)
Natural gas futures (2)
 (308) (852) (171) 929
 (573) 298
Total before income taxes (461) (653) (1,450)
1,593
 44
 (616)
Income tax benefit (expense) 129
 248
 407
 (628) (5) 172
Net of tax (332) (405)
(1,043) 965
 39
 (444)
Total reclassifications for the period $(418) $(496)
$(1,318) $694
 $(68) $(538)
(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 condensed consolidated statements of income. The income tax benefit is included in income tax expense in the accompanying condensed consolidated statements of income.

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9.Employee Benefit Plans
Net periodic benefit costs for our pension and post-retirement benefits plans for the three and nine months ended September 30,March 31, 2019 and 2018 and 2017 are set forth in the following tables:
  Chesapeake
Pension Plan		 FPU
Pension Plan		 Chesapeake SERP Chesapeake
Postretirement
Plan		 FPU
Medical
Plan
For the Three Months Ended September 30, 2018 2017 2018 2017 2018 2017 2018 2017 2018 2017
(in thousands)                    
Interest cost $94
 $103
 $570
 $623
 $21
 $22
 $10
 $11
 $12
 $13
Expected return on plan assets (131) (127) (770) (699) —
 —
 —
 —
 —
 —
Amortization of prior service credit —
 —
 —
 —
 —
 —
 (19) (19) —
 —
Amortization of net loss 82
 107
 86
 131
 25
 22
 15
 17
 —
 —
Net periodic cost (benefit) (1)
 45
 83
 (114) 55
 46
 44
 6
 9
 12
 13
Amortization of pre-merger regulatory asset —
 —
 191
 191
 —
 —
 —
 —
 2
 2
Total periodic cost $45
 $83
 $77
 $246
 $46
 $44
 $6
 $9

$14
 $15

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

(1)As a result of our adoption of ASU 2017-07 on January 1, 2018, the "other than service" cost components of net periodic costs have been recorded or reclassified to other income (expense), net in the condensed consolidated statements of income.
  Chesapeake
Pension Plan		 FPU
Pension Plan		 Chesapeake SERP Chesapeake
Postretirement
Plan		 FPU
Medical
Plan
For the Three Months Ended March 31, 2019 2018 2019 2018 2019 2018 2019 2018 2019 2018
(in thousands)                    
Interest cost $105
 $97
 $615
 $592
 $21
 $21
 $10
 $10
 $12
 $12
Expected return on plan assets (127) (138) (693) (774) —
 —
 —
 —
 —
 —
Amortization of prior service credit —
 —
 —
 —
 —
 —
 (19) (19) —
 —
Amortization of net loss 101
 88
 129
 109
 26
 25
 12
 15
 —
 —
Net periodic cost (benefit) 79
 47
 51
 (73) 47
 46
 3
 6
 12
 12
Amortization of pre-merger regulatory asset —
 —
 190
 191
 —
 —
 —
 —
 2
 2
Total periodic cost $79
 $47
 $241
 $118
 $47
 $46
 $3
 $6

$14
 $14

We expect to record pension and postretirement benefit costs of approximately $856,000$1.3 million for 2018.2019. Included in these costs is approximately $769,000$543,000 related to continued amortization of the FPU pension regulatory asset, which represents the portion attributable to FPU’s regulated energy operations for the changes in funded status that occurred, but were not recognized, as part of net periodic benefit costs prior to the FPU merger in 2009. This was deferred as a regulatory asset by FPU prior to the merger, to be recovered through rates pursuant to a previous order by the Florida PSC. The unamortized balance of this regulatory asset was approximately $749,000$351,000 and approximately $1.3 million$543,000 at September 30, 2018March 31, 2019 and December 31, 2017,2018, respectively. The other than service cost components of the net periodic costs have been recorded or reclassified to other income (expense), net in the condensed consolidated statements of income.

Pursuant to a Florida PSC order, FPU continues to record, as a regulatory asset, a portion of the unrecognized pension and postretirement benefit costs related to its regulated operations after the FPU merger. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake Utilities' operations is recorded to accumulated other comprehensive loss.
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The following tables present the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three months ended September 30, 2018March 31, 2019 and 2017:2018:
 
For the Three Months Ended September 30, 2018 Chesapeake
Pension
Plan		 FPU
Pension
Plan		 Chesapeake SERP Chesapeake
Postretirement
Plan		 FPU
Medical
Plan		 Total
(in thousands)            
Prior service credit $—
 $—
 $—
 $(19) $—
 $(19)
Net loss 82
 86
 25
 15
 —
 208
Total recognized in net periodic benefit cost 82
 86
 25
 (4) —
 189
Recognized from accumulated other comprehensive loss (1)
 82
 16
 25
 (4) —
 119
Recognized from regulatory asset —
 70
 —
 —
 —
 70
Total $82
 $86
 $25
 $(4) $—
 $189

For the Three Months Ended September 30, 2017 Chesapeake
Pension
Plan		 FPU
Pension
Plan		 Chesapeake SERP Chesapeake
Postretirement
Plan		 FPU
Medical
Plan		 Total
(in thousands)            
Prior service credit $—
 $—
 $—
 $(19) $—
 $(19)
Net loss 107
 131
 22
 17
 —
 277
Total recognized in net periodic benefit cost 107
 131
 22
 (2) —
 258
Recognized from accumulated other comprehensive loss (1)
 107
 25
 22
 (2) —
 152
Recognized from regulatory asset —
 106
 —
 —
 —
 106
Total $107
 $131
 $22

$(2)
$—

$258

For the Nine Months Ended September 30, 2018 
Chesapeake
Pension
Plan
 
FPU
Pension
Plan
 Chesapeake SERP 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
 Total
For the Three Months Ended March 31, 2019 Chesapeake
Pension
Plan		 FPU
Pension
Plan		 Chesapeake SERP Chesapeake
Postretirement
Plan		 FPU
Medical
Plan		 Total
(in thousands)                        
Prior service credit $—
 $—
 $—
 $(58) $—
 $(58) $—
 $—
 $—
 $(19) $—
 $(19)
Net loss 258
 302
 75
 45
 —
 680
 101
 129
 26
 12
 —
 268
Total recognized in net periodic benefit cost 258
 302
 75
 (13) —
 622
 101
 129
 26
 (7) —
 249
Recognized from accumulated other comprehensive loss (1)
 258
 57
 75
 (13) —
 377
 101
 24
 26
 (7) —
 144
Recognized from regulatory asset —
 245
 —
 —
 —
 245
 —
 105
 —
 —
 —
 105
Total $258
 $302
 $75
 $(13) $—
 $622
 $101
 $129
 $26
 $(7) $—
 $249

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

$(4)
$—

$218

(1) See Note 8, Stockholder's Equity.
During the three and nine months ended September 30, 2018,March 31, 2019, we contributed approximately $235,000 and $433,000, respectively,$33,000 to the Chesapeake Pension Plan and approximately $123,000 and $971,000, respectively,$233,000 to the FPU Pension Plan. We expect to contribute a total of approximately $359,000$163,000 and approximately $1.5$1.2 million to the Chesapeake Pension Plan and FPU Pension Plan, respectively, during 2018,2019, which represents the minimum annual contribution payments required.
The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three and nine months ended September 30, 2018,March 31, 2019, were approximately $38,000 and $113,000, respectively.$38,000. We expect to pay total cash benefits of approximately $151,000$383,000 under the Chesapeake SERP in 2018.2019. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for ninethe three months ended September 30, 2018,March 31, 2019, were approximately $15,000 and no cash benefits were paid for medical claims during the third quarter of 2018.$1,000. We estimate that approximately $97,000$96,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2018.2019. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and nine months ended September 30, 2018,March 31, 2019, were approximately $9,000 and $33,000, respectively.$6,000. We estimate that approximately $88,000$94,000 will be paid for such benefits under the FPU Medical Plan in 2018.2019.

10.Investments
The investment balances at September 30, 2018March 31, 2019 and December 31, 2017,2018, consisted of the following:
    
(in thousands)September 30,
2018		 December 31,
2017		March 31,
2019		 December 31,
2018
Rabbi trust (associated with the Deferred Compensation Plan)$7,929
 $6,734
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)$7,484
 $6,689
Investments in equity securities22
 22
25
 22
Total$7,951
 6,756
$7,509
 $6,711
We classify these investments as trading securities and report them at their fair value. For the three months ended September 30,March 31, 2019 and 2018, and 2017, we recorded a net unrealized gain of approximately $313,000$727,000 and $261,000, respectively, in other expense, net in the condensed consolidated statements of income related to these investments. For the nine months ended September 30, 2018 and 2017, we recorded a net unrealized gainloss of approximately $426,000 and $694,000,$44,000, 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 condensed consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust.
 
11.Share-Based Compensation
Our non-employee directors and key employees are granted share-based awards through our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares awarded, using the estimated fair value of each share on the date it was granted and the number of shares to be issued at the end of the service period.
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The table below presents the amounts included in net income related to share-based compensation expense for the three and nine months ended September 30, 2018March 31, 2019 and 2017:2018:
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 Three Months Ended Nine Months Ended Three Months Ended
 September 30, September 30, March 31,
 2018 2017 2018 2017 2019 2018
(in thousands)            
Awards to non-employee directors $135
 $134
 $404
 $406
 $149
 $135
Awards to key employees 153
 662
 2,728
 1,202
 338
 1,385
Total compensation expense 288
 796
 3,132
 1,608
 487
 1,520
Less: tax benefit (79) (320) (858) (647) (127) (416)
Share-based compensation amounts included in net income $209
 $476
 $2,274
 $961
 $360
 $1,104
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.date of the grant. 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.period of one year. 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 summaryOur former President and Chief Executive Officer, Michael P. McMasters, retired on December 31, 2018 and continued as a member of the Board of Directors beginning January 1, 2019. Mr. McMasters received a pro-rated grant of 276 shares of common stock activityunder the SICP for awards toservice as a non-employee directors fordirector from January 1, 2019 through the nine months ended September 30, 2018:
  Number of Shares 
Weighted Average
Fair Value
Outstanding—December 31, 2017 —
 $—
Granted 7,128
 $75.70
Vested (7,128) $75.70
Outstanding—September 30, 2018 —
 $—
2019 Annual Meeting of Stockholders. These shares were issued and vested in January 2019 at a weighted average fair value of $75.70.
At September 30, 2018,March 31, 2019, there was approximately $315,000$52,000 of unrecognized compensation expense related to these awards.shares granted to non-employee directors. This expense will be recognized over the directors' remaining service periodsperiod 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 ninethree months ended September 30, 2018:March 31, 2019: 
  Number of Shares 
Weighted Average
Fair Value
Outstanding—December 31, 2017 132,642
 $59.31
Granted 49,494
 $67.76
Vested (29,786) $47.39
Vested - Accelerated pursuant to separation agreement (1)
 (16,676) $75.78
Expired (3,933) $49.66
Outstanding—September 30, 2018 131,741
 $67.43

(1)Includes 2,569 shares that were forfeited.
  Number of Shares 
Weighted Average
Fair Value
Outstanding—December 31, 2018 131,741
 $67.24
Granted 45,016
 $91.19
Vested (25,831) $67.08
Expired (15,086) $69.28
Outstanding—March 31, 2019 135,840
 $74.05
In February 2018,2019, our Board of Directors granted awards of 49,49445,016 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, 2020.2021. All of these stock awards are earned based upon the successful achievement of long-term financial results, which comprise market-based and performance-based conditions or targets. The fair value of each performance-
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basedperformance-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 2018,2019, 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 in February 2019 for the performance period ended December 31, 2017,2018, remitted the cash to the appropriate taxing authorities, and paid the balance of such awarded shares to each such executive officer. We withheld 10,4367,635 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.$692,000.
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
Table 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.Contents

At September 30, 2018,March 31, 2019, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $11.1$12.4 million. At September 30, 2018,March 31, 2019, there was approximately $2.6$4.3 million of unrecognized compensation cost related to these awards, which is expected to be recognized as expense from 20182019 through 2020.2021.
Stock Options
We did not have any stock options outstanding at September 30,March 31, 2019 or 2018, or 2017, nor were any stock options issued during these periods.

12.Derivative Instruments

We use derivative and non-derivative contracts to manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane. Our natural gas, electric and propane distribution operations have entered into agreements with suppliers to purchase natural gas, electricity and propane for resale to our customers. Aspire Energy has entered into contracts with producers to secure natural gas to meet its obligations. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and normal sales” and are accounted for on an accrual basis. OurBoth our propane distribution and natural gas marketing operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. As of September 30, 2018,March 31, 2019, our natural gas and electric distribution operations did not have any outstanding derivative contracts.
We adopted ASU 2017-12 as of July 1, 2018. See Note 1, Summary of Accounting Policies, under the heading "FASB Statements and Other Authoritative Pronouncements" for additional details.
Volume of Derivative Activity
As of September 30, 2018,March 31, 2019, the volume of our open commodity derivative contracts were as follows:
Business unit Commodity Quantity hedged (in millions) Designation Longest Expiration date of hedge
PESCO Natural gas (Dts) 22.121.7 Cash flows hedges MarchDecember 2022
PESCO Natural gas (Dts) 1.13.8 Not designated January 2020
SharpPropane (gallons)4.4Cash flows hedgesJuneMarch 2021
Sharp Propane (gallons) 0.35.4 Fair valueCash flows hedges March 2019June 2021
PESCO entered into natural gas futures contracts associated with the purchase and sale of natural gas to specific customers. We designated and accounted for them as cash flow hedges. The change in fair value of the natural gas futures contracts is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $570,000$2.1 million from accumulated other comprehensive loss to earnings during the next 12-month period ending September 30, 2019.
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March 31, 2020.
Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes expected to be purchased during the heating season. Under the futures and swap agreements, Sharp will receive the difference betweenbetween: (i) the index prices (Mont Belvieu prices in August 2018 through June 2021), and (ii) the per gallon propane swap prices, to the extent the index prices exceed the contracted prices. If the index prices are lower than the swap prices, Sharp will pay the difference. We designated and accounted for propane swaps as cash flows hedges. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $392,000$503,000 from accumulated other comprehensive income (loss) to earnings during the next 12-month period ending September 30, 2019.
Sharp paid a total of $28,000 to purchase a put option to protect against a decline in propane prices and related potential inventory losses associated volumes of propane for its propane price cap program during the upcoming heating season. We will exercise the put option if propane prices fall below specified strike price(s) per gallon in December 2018 to March 2019. If exercised, we will receive the difference between the market price and the strike price during those months. We accounted for the put option as a fair value hedge. The premium paid by Sharp is amortized and recorded in earnings over the duration of the put option and recorded in the same line item as the hedged item. The change in the fair value of the put option is recorded in derivative assets and or derivative liability and later recognized in cost of sales.

31, 2020.
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 condensed consolidated balance sheets. The following table summarizes the accounts receivable and payable on a gross and net basis at September 30, 2018March 31, 2019 and December 31, 2017:2018:
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 At September 30, 2018 At March 31, 2019
(in thousands) Gross amounts Amounts offset Net amounts Gross amounts Amounts offset Net amounts
Accounts receivable $7,042
 $1,158
 $5,884
 $8,832
 $3,264
 $5,568
Accounts payable $11,264
 $1,158
 $10,106
 $15,906
 $3,264
 $12,642
 At December 31, 2017 At December 31, 2018
(in thousands) Gross amounts Amounts offset Net amounts Gross amounts Amounts offset Net amounts
Accounts receivable $8,283
 $2,391
 $5,892
 $12,368
 $3,834
 $8,534
Accounts payable $16,643
 $2,391
 $14,252
 $24,741
 $3,834
 $20,907
Broker Margin
Futures exchanges have contract specific margin requirements that require the posting of cash or cash equivalents relating to traded contracts. Margin requirements consist of initial margin that is posted upon the initiation of a position, maintenance margin that is usually expressed as a percent of initial margin, and variation margin that fluctuates based on the daily MTM relative to maintenance margin requirements. We maintain separate broker margin accounts for Sharp and PESCO. The balances are as follows:

(in thousands)Balance Sheet Location At September 30, 2018 At December 31, 2017Balance Sheet Location At March 31, 2019 At December 31, 2018
SharpOther Current Liabilities $18
 $—
PESCOOther Current Assets $2,060
 $6,300
Other Current Assets $(335) $2,810
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Financial Statements Presentation

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

The fair values of the derivative contracts recorded in the condensed consolidated balance sheets as of September 30, 2018March 31, 2019 and December 31, 2017,2018, are as follows: 
 Asset Derivatives Asset Derivatives
   Fair Value As Of   Fair Value As Of
(in thousands) Balance Sheet Location September 30, 2018 December 31, 2017 Balance Sheet Location March 31, 2019 December 31, 2018
Derivatives not designated as hedging instruments        
Propane swap agreements Derivative assets, at fair value $—
 $13
Natural gas futures contracts Derivative assets, at fair value 1,841
 —
 Derivative assets, at fair value $2,122
 $4,024
Derivatives designated as fair value hedges        
Propane put options Derivative assets, at fair value 19
 —
 Derivative assets, at fair value —
 71
Derivatives designated as cash flow hedges        
Natural gas futures contracts Derivative assets, at fair value 8,114
 92
 Derivative assets, at fair value 7,055
 9,059
Propane swap agreements Derivative assets, at fair value 594
 1,181
 Derivative assets, at fair value 44
 11
Total asset derivatives $10,568
 $1,286
 $9,221
 $13,165
 
  Liability Derivatives
    Fair Value As Of
(in thousands) Balance Sheet Location September 30, 2018 December 31, 2017
Derivatives not designated as hedging instruments      
Natural gas futures contracts Derivative liabilities, at fair value $1,602
 $5,776
Derivatives designated as cash flow hedges      
Natural gas futures contracts Derivative liabilities, at fair value 8,168
 469
Natural gas swap contracts Derivative liabilities, at fair value —
 2
Propane swap agreements Derivative liabilities, at fair value 4
 —
Total liability derivatives   $9,774
 $6,247
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  Liability Derivatives
    Fair Value As Of
(in thousands) Balance Sheet Location March 31, 2019 December 31, 2018
Derivatives not designated as hedging instruments      
Natural gas futures contracts Derivative liabilities, at fair value $2,638
 $4,562
Derivatives designated as cash flow hedges      
Natural gas futures contracts Derivative liabilities, at fair value 3,533
 8,705
Propane swap agreements Derivative liabilities, at fair value 627
 1,604
Total liability derivatives   $6,798
 $14,871
The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows: 
   Amount of Gain (Loss) on Derivatives:   Amount of Gain (Loss) on Derivatives:
 Location of Gain For the Three Months Ended September 30, For the Nine Months Ended September 30, Location of Gain For the Three Months Ended March 31,
(in thousands) (Loss) on Derivatives 2018 2017 2018 2017 (Loss) on Derivatives 2019 2018
Derivatives not designated as hedging instruments                
Realized gain on forward contracts and options (1)
 Revenue $—
 $—
 $—
 $112
Natural gas futures contracts Cost of sales 197
 286
 (2,766) 907
 Cost of sales $(22) $(2,835)
Propane swap agreements Cost of sales —
 15
 (13) 11
 Cost of sales —
 (9)
Natural gas swap contracts Cost of sales —
 1
 —
 1
Derivatives designated as fair value hedges        
Put /Call option (2)
 Cost of sales —
 —
 —
 (9)
Derivatives designated as cash flow hedges            
Propane swap agreements Cost of sales (276) 198
 (921) 663
 Cost of sales 606
 (464)
Propane swap agreements Other comprehensive income (loss) 296
 1,590
 (590) 814
 Other comprehensive income (loss) 1,009
 (992)
Natural gas futures contracts Cost of sales (308) (852) (171) 929
 Cost of sales (573) 298
Natural gas swap contracts Cost of sales 123
 1
 (358) 1
 Cost of sales 11
 (450)
Natural gas swap contracts Other comprehensive income (loss) (25) (413) 563
 (413) Other comprehensive income (loss) 3,226
 (1,617)
Natural gas futures contracts Other comprehensive income (loss) 630
 (1,296) (241) (1,420) Other comprehensive income (loss) (59) 65
Total $637
 $(470) $(4,497) $1,596
 $4,198
 $(6,004)

(1)
All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our condensed consolidated statements of income.
(2)
As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this put option effectively changed the value of propane inventory on the condensed consolidated balance sheets.
As of September 30, 2018,March 31, 2019, the following amounts were recorded in the condensed consolidated balance sheets related to fair value hedges:
(in thousands) Carrying Amount of Hedged ItemCumulative Adjustment Included in Carrying Amount of Hedged Item Carrying Amount of Hedged ItemCumulative Adjustment Included in Carrying Amount of Hedged Item
Balance Sheet Location of Hedged Items At September 30, 2018At December 31, 2017At September 30, 2018At December 31, 2017 At March 31, 2019At December 31, 2018At March 31, 2019At December 31, 2018
Inventory $290
$—
$—
$—
 $6
$212
$—
$—
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13.Fair Value of Financial Instruments
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are the following:
Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;
Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and
Level 3: Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity).
Fair Value HierarchyDescription of Fair Value LevelFair Value Technique Utilized
Level 1Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities
Investments - equity securities - The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.

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

Level 2Quoted 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
Derivative assets and liabilities - The fair values of forward contracts are measured using market transactions in either the listed or over-the-counter 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 over-the-counter markets.
Level 3Prices 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)
Investments - guaranteed income fund - The fair values of these investments are recorded at the contract value, which approximates their fair value.


Financial Assets and Liabilities Measured at Fair Value
The following table summarizestables summarize our financial assets and liabilities that are measured at fair value on a recurring basis and the fair value measurements, by level, within the fair value hierarchy as of September 30, 2018March 31, 2019 and December 31, 2017:2018:
   Fair Value Measurements Using:   Fair Value Measurements Using:
As of September 30, 2018 Fair Value 
Quoted Prices in
Active Markets
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
As of March 31, 2019 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
 $—
 $—
 $25
 $25
 $—
 $—
Investments—guaranteed income fund 679
 —
 —
 679
 695
 —
 —
 695
Investments—mutual funds and other 7,250
 7,250
 —
 —
 6,789
 6,789
 —
 —
Total investments 7,951
 7,272

—

679
 7,509
 6,814

—

695
Derivative assets 10,568
 —
 10,568
 —
 9,221
 —
 9,221
 —
Total assets $18,519

$7,272

$10,568

$679
 $16,730

$6,814

$9,221

$695
Liabilities:                
Derivative liabilities $9,774
 $—
 $9,774
 $—
 $6,798
 $—
 $6,798
 $—
 
    Fair Value Measurements Using:
As of December 31, 2017 Fair Value 
Quoted Prices in
Active Markets
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
(in thousands)        
Assets:        
Investments—equity securities $22
 $22
 $—
 $—
Investments—guaranteed income fund 648
 —
 —
 648
Investments—mutual funds and other 6,086
 6,086
 —
 —
Total investments 6,756
 6,108

—

648
Derivative assets 1,286
 —
 1,286
 —
Total assets $8,042

$6,108

$1,286

$648
Liabilities:        
Derivative liabilities $6,247
 $—
 $6,247
 $—

The following valuation techniques were used to measure the fair value of assets and liabilities in the tables above:
Level 1 Fair Value Measurements:
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Investments - equity securities — The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.
Investments - mutual funds and other — The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares.
Level 2 Fair Value Measurements:
Derivative assets and liabilities — The fair values of forward contracts are measured using market transactions in either the listed or OTC markets. The fair value of the propane put/call options, swap agreements and natural gas futures contracts are measured using market transactions for similar assets and liabilities in either the listed or OTC markets.
Level 3 Fair Value Measurements:
Investments - guaranteed income fund — The fair values of these investments are recorded at the contract value, which approximates their fair value.
    Fair Value Measurements Using:
As of December 31, 2018 Fair Value 
Quoted Prices in
Active Markets
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
(in thousands)        
Assets:        
Investments—equity securities $22
 $22
 $—
 $—
Investments—guaranteed income fund 686
 —
 —
 686
Investments—mutual funds and other 6,003
 6,003
 —
 —
Total investments 6,711
 6,025

—

686
Derivative assets 13,165
 —
 13,165
 —
Total assets $19,876

$6,025

$13,165

$686
Liabilities:        
Derivative liabilities $14,871
 $—
 $14,871
 $—
The following table sets forth the summary of the changes in the fair value of Level 3 investments for the ninethree months ended September 30, 2018March 31, 2019 and 2017:2018:
     
Nine Months Ended 
 September 30,		Three Months Ended 
 March 31,
2018 20172019 2018
(in thousands)      
Beginning Balance$648
 $561
$686
 $648
Purchases and adjustments64
 76
6
 (48)
Transfers(29) —
Distribution(12) (2)
Investment income8
 7
3
 2
Ending Balance$679
 $642
$695
 $602

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

At September 30, 2018,March 31, 2019, there were no non-financial assets or liabilities required to be reported at fair value. We review our non-financial assets for impairment at least on an annual basis, as required.
Other Financial Assets and Liabilities
Financial assets with carrying values approximating fair value include cash and cash equivalents and accounts receivable. Financial liabilities with carrying values approximating fair value include accounts payable and other accrued liabilities and short-term debt. The fair value of cash and cash equivalents is measured using the comparable value in the active market and approximates its carrying value (Level 1 measurement). The fair value of short-term debt approximates the carrying value due to its short maturities and because interest rates approximate current market rates (Level 3 measurement).
At September 30, 2018March 31, 2019, long-term debt includingwhich includes current maturities but excluding aexcludes capital lease obligation,obligations, had a carrying value of approximately $250.7 million. This compares$357.2 million, compared to athe estimated fair value of approximately $248.9$361.3 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, 2017,2018, long-term debt, includingwhich includes the current maturities but excludingexcludes a capital lease obligation, had a carrying value of approximately $205.2$327.2 million, compared to the estimateda fair value of approximately $215.4$323.8 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

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14.Long-Term Debt
Our outstanding long-term debt is shown below: 
 September 30, December 31, March 31, December 31,
(in thousands) 2018 2017 2019 2018
FPU secured first mortgage bonds (1) :
        
9.08% bond, due June 1, 2022 $7,985
 $7,982
 $7,987
 $7,986
Uncollateralized senior notes:        
5.50% note, due October 12, 2020 6,000
 6,000
 4,000
 4,000
5.93% note, due October 31, 2023 16,500
 18,000
 15,000
 15,000
5.68% note, due June 30, 2026 23,200
 26,100
 23,200
 23,200
6.43% note, due May 2, 2028 7,000
 7,000
 7,000
 7,000
3.73% note, due December 16, 2028 20,000
 20,000
 20,000
 20,000
3.88% note, due May 15, 2029 50,000
 50,000
 50,000
 50,000
3.25% note, due April 30, 2032 70,000
 70,000
 70,000
 70,000
3.48% note, due May 31, 2038 50,000
 —
 50,000
 50,000
3.58% note, due November 30, 2038 50,000
 50,000
Term Note due January 21, 2020 30,000
 30,000
Term Note due February 28, 2020
 30,000
 —
Promissory notes 26
 97
 —
 26
Capital lease obligation 987
 2,070
Finance lease obligation 909
 1,310
Less: debt issuance costs (488) (433) (589) (567)
Total long-term debt 251,210
 206,816
 357,507
 327,955
Less: current maturities (9,613) (9,421) (71,509) (11,935)
Total long-term debt, net of current maturities $241,597

$197,395
 $285,998

$316,020
(1) FPU secured first mortgage bonds are guaranteed by Chesapeake Utilities.

Term Notes
In JanuaryDecember 2018, we borrowed an additional $25.0issued a $30.0 million under the Revolver, which we classified as long-term debt due to the statedunsecured term note through PNC Bank N.A. with maturity date of October 8,January 21, 2020. The interest rate at March 31, 2019 and December 31, 2018 was 3.24% and 3.23%, respectively, which equals one month LIBOR rate plus 75 basis points. In May 2018,January 2019, we utilizedissued a portion$30.0 million unsecured term note through Branch Banking and Trust Company, with a maturity date of February 28, 2020. The interest rate at March 31, 2019 was 3.24%, which equals the proceeds fromone month LIBOR rate plus 75 basis points. As of March 31, 2019, these term notes totaling $60.0 million are included in the issuance of $50.0 million of 3.48% Series A notes to repay the $25.0 millioncurrent maturities of long-term debt borrowed under the Revolver. For additional information regarding the issuance of the Series A notes, see "Shelf Agreements" below.debt.
Shelf Agreements
In October 2015, weWe have entered into the $150.0 millionShelf Agreements with Prudential, Shelf Agreement, under which we may request that Prudential purchase up to $150.0 million of our unsecured senior debt. Prudential is under no obligation to purchase any unsecured senior debt. As of September 30, 2018, we had issued $70.0 million of 3.25% Prudential Shelf Notes. In September 2018, we amended the Prudential Shelf Agreement, pursuant to which we may request that Prudential purchase up to $150.0 million of our unsecured debt over a three-year period which expires in August 2021. Following this amendment, in September 2018, Prudential accepted our request to purchase $100 million of Shelf Notes on or before August 20, 2019. The new Prudential Shelf Notes will bear interest at the rate of 3.98% and have a maturity date not to exceed 20 years from the date of issuance. The proceeds received from the issuance of these Prudential Shelf Notes will be used to reduce short-term borrowings under the Revolver, lines of credit and/or to fund capital expenditures.
In March 2017, we entered into the MetLife Shelf Agreement and the NYL Shelf Agreement, under which we may request that MetLife and NYL, through March 2, 2020, purchase up to $150.0 million of Met Life Shelf Notes and $100.0 million NYL Shelf Notes, respectively. The unsecured senior debt would have a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance. MetLife and NYLwhom are under no obligation to purchase any unsecured senior debt. We entered into the Prudential Shelf Agreement, totaling $150.0 million, in October 2015, and we issued $70.0 million of 3.25% unsecured debt in April 2017. The Prudential Shelf Agreement was then amended in September 2018 to increase the borrowing capacity back up to $150.0 million, and Prudential accepted our request to purchase our unsecured debt of $100.0 million at an 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 issued3.98% on or before NovemberAugust 20, 2018. The proceeds received from2019. We entered into 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.Agreement, totaling $100.0 million, in March 2017, and we issued unsecured debt totaling $100.0 million during 2018. The NYL Shelf Agreement has been fully utilized.
was amended in November 2018 to add incremental borrowing capacity of $50.0 million. As of September 30, 2018,March 31, 2019, we have $200.0 million of additional potential borrowing capacity (after excluding existing unfunded commitments)had not requested that MetLife purchase unsecured senior debt under the Prudential Shelf Agreement ($50.0 million) and MetLife Shelf Agreement, ($150.0 million).which we entered into in March 2017. The Prudentialfollowing table summarizes the borrowing information under our Shelf Agreement and the NYLAgreements at March 31, 2019:
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  Total Borrowing Capacity Less: Amount of Debt Issued Less: Unfunded Commitments Remaining Borrowing Capacity
(in thousands)        
Shelf Agreement        
Prudential Shelf Agreement $220,000
 $(70,000) $(100,000) $50,000
MetLife Shelf Agreement 150,000
 —
 —
 150,000
NYL Shelf Agreement 150,000
 (100,000) —
 50,000
Total $520,000
 $(170,000) $(100,000) $250,000
The Shelf AgreementAgreements or Shelf Notes set forth certain business covenants to which we are subject when any note is outstanding, including covenants that limit or restrict our ability, and the ability of our
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subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.

15.Leases
We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These leases have been entered into to better enable us to conduct our business operations in the regions in which we operate. Office space is leased to provide adequate workspace for all our employees in several locations throughout the Mid-Atlantic, Mid-West and in Florida. We lease land at various locations throughout our service territories to enable us to inject natural gas into underground storage and distribution systems, for bulk storage capacity, for our propane operations and for storage of equipment used in repairs and maintenance of our infrastructure. We lease natural gas compressors to ensure timely and reliable transportation of natural gas to our customers. Additionally, we lease a pipeline to deliver natural gas to an industrial customer in Polk County, Florida. We lease warehouses to store equipment and materials used in repairs and maintenance for our businesses.
Some of our leases are subject to annual changes in the Consumer Price Index (“CPI”). While lease liabilities are not re-measured as a result of changes to the CPI, changes to the CPI are treated as variable lease payments and recognized in the period in which the obligation for those payments was incurred. A 100-basis-point increase in CPI would have resulted in immaterial additional annual lease costs.

Most of our leases include options to renew, with renewal terms that can extend the lease term from one to 25 years or more. The exercise of lease renewal options is at our sole discretion. The amounts disclosed in our condensed consolidated balance sheet at March 31, 2019, pertaining to the right of use assets and lease liabilities, are measured based on our current expectations of exercising our available renewal options.

Our existing leases are not subject to any restrictions or covenants which preclude our ability to pay dividends, obtain financing or enter into additional leases.

We utilize our incremental borrowing rate, as the basis to calculate the present value of future lease payments, at lease commencement. Our incremental borrowing rate represents the rate that we would have to pay to borrow funds on a collateralized basis over a similar term and in a similar economic environment.

Leases with an initial term of 12 months or less are not recorded on our balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term.

We have elected not to separate non-lease components from all classes of our existing leases. Non-lease components have been accounted for as part of the single lease component to which they are related.
As of March 31, 2019, we have not entered into any leases, which have not yet commenced, that would entitle us to significant rights or create additional obligations. The following table presents information related to our total lease cost included in our condensed consolidated statements of income:
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    Three Months Ended
    March 31,
( in thousands) Classification 2019 2018
Operating lease cost (1)
 Operations expense $635
 $1,107
Finance lease cost      
Amortization of lease assets Depreciation and amortization  401
 358
Interest on lease liabilities Interest expense 4
 17
Net lease cost   $1,040
 $1,482
(1) Includes short-term leases and variable lease costs, which are immaterial

The following table presents the balance and classifications of our right of use assets and lease liabilities included in our consolidated balance sheet at March 31, 2019:
(in thousands) Balance sheet classification Amount
Assets    
Operating lease assets Operating lease right-of-use assets $12,523
Finance lease assets Property, plant and equipment 1,839
Total lease assets   $14,362
Liabilities    
Current    
Operating lease liabilities Other accrued liabilities $1,642
Finance lease liabilities Current portion of long-term debt 909
Noncurrent    
Operating lease liabilities Other liabilities 10,873
Finance lease liabilities Long-term debt —
Total lease liabilities   $13,424

The following table presents our weighted-average remaining lease terms and weighted-average discount rates for our operating and financing leases at March 31, 2019:
At March 31, 2019
Weighted-average remaining lease term (in years)
Operating leases9.32
Finance leases0.17
Weighted-average discount rate
Operating leases3.8%
Finance leases3.5%
The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our condensed consolidated statements of cash flows as of March 31, 2019 and March 31, 2018:
  Three Months Ended
  March 31,
(in thousands) 2019 2018
Operating cash flows from operating leases $537
 $1,018
Operating cash flows from finance leases 4
 17
Financing cash flows from finance leases 401
 358

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The following table presents the future undiscounted maturities of our operating and financing leases at March 31, 2019 and for each of the next five years and thereafter:
(in thousands) 
Operating 
Leases (1)
 Finance Leases Total
Remainder of 2019 $1,539
 $910
 $2,449
2020 2,045
 —
 2,045
2021 1,765
 —
 1,765
2022 1,659
 —
 1,659
2023 1,669
 —
 1,669
2024 1,431
 —
 1,431
Thereafter 4,860
 —
 4,860
Total lease payments $14,968
 $910
 $15,878
Less: Interest 2,453
 1
 2,454
Present value of lease liabilities $12,515
 $909
 13,424
(1)Operating lease payments include $3.8 million related to options to extend lease terms that are reasonably certain of being exercised.
The following table presents future minimum lease payments for our operating leases at December 31, 2018 under ASC 840 and is being presented for comparative purposes:
Year(s) 2019 2020 2021 2022 2023 Thereafter Total
(in thousands)              
Expected payments $2,349 $1,998 $1,761 $1,689 $1,642 $5,398 $14,837

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K for the year ended December 31, 2017,2018, 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 20172018 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 related 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;
projects and 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• the economy in our service territories or markets, the nation, and worldwide, including the impact of economic conditions including any potential effects arising from terrorist attacks and any hostilities(which we do not control) on demand for electricity, natural gas, propane or other external factors over which we have no control;fuels;
long-term global climate change, which• risks related to cyber-attacks or cyber-terrorism that could adversely affect customer demanddisrupt our business operations or cause extreme weather conditions that disrupt the Company's operations;result in failure of information technology systems;
• 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, establishing and inmaintaining key supply sources; and 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 a merger, acquisition or divestiture plans;of assets or businesses and the related regulatory or other limitations imposed as a result of a merger, acquisition or divestiture; andconditions associated with 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 Protectionhealth care legislation and Affordable Care Act;regulation;
• the ability to continue to hire, train and retain appropriately qualified personnel; and
• the effect of accounting pronouncements issued periodically by accounting standard-setting bodies;bodies.

Introduction
We are an energy delivery company engaged in the timingdistribution of natural gas, propane and successelectricity; the transmission of technological improvements;natural gas; the generation of electricity and steam, and in providing related services to our customers.
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risks related to cyber-attacks or cyber-terrorism that could disrupt our business operations or result in failure of information technology systems.

Introduction
We are a diversified energy company engaged, directly or through our operating divisions and subsidiaries, in regulated and unregulated energy businesses. These businesses center around energy distribution, energy transmission, energy generation, propane delivery and other energy services.
Our strategy is focused on growing earnings from a stable utility foundation and investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. We are focused on identifying and developing opportunities across the energy value chain, with emphasis on midstream and downstream investments that are accretive to earnings per share and consistent with our long-term growth strategy.
The key elements of this strategy include:
executing a capital investment program in pursuit of growth opportunities that generate returns equal to or greater than our cost of capital;
expanding our energy distribution and transmission businesses organically as well as into new geographic areas;
providing new services in our current service territories;
expanding our footprint in potential growth markets through strategic acquisitions;
entering new unregulated energy markets and business lines that will complement our existing operating units and growth strategy while capitalizing on opportunities across the energy value chain; and
differentiating the Company as a full-service energy supplier/partner/provider through a customer-centric model.
Our strategy is to consistently produce industry-leading total shareholder returns by profitably investing capital into opportunities that leverage our skills and expertise in energy distribution and transmission to achieve high levels of service and growth. The key elements of our strategy include:
•
capital investment in growth opportunities that generate our target returns;
•
expanding our energy distribution and transmission operations within our existing service areas as well as into new geographic areas;
•
providing new services in our current service areas;
•
expanding our footprint in potential growth markets through strategic acquisitions;
•
entering new energy markets and businesses that complement our existing operations and growth strategy; and
•
operating as a customer-centric full-service energy supplier/partner/provider of safe and reliable service.
Our employees strive to build meaningful connections that generate opportunities to grow our businesses, develop new markets, and enrich the communities in which we live, work and serve.

Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is normally highest due to colder temperatures.
The following discussions and those later in the document on operating income and segment results include the use of the term “gross margin," which is determined by deducting the cost of sales from operating revenue. Cost of sales includes the purchased cost of natural gas, electricity and propane and the cost of labor spent on direct revenue-producing activities, and excludes depreciation, amortization and accretion. Gross margin should not be considered an alternative to operating income or net income, which are determined in accordance with GAAP. We believe that gross margin, although a non-GAAP measure, is useful and meaningful to investors as a basis for making investment decisions. It provides investors with information that demonstrates the profitability achieved by us under our allowed rates for regulated energy operations and under our competitive pricing structures for unregulated energy operations. Our management uses gross margin in measuring our business units’ performance and has historically analyzed and reported gross margin information publicly. Other companies may calculate gross margin in a different manner.
Unless otherwise noted, earningsEarnings per share information is presented on a diluted basis.basis, unless otherwise noted.


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Results of Operations for the Three and Nine Months ended September 30, 2018March 31, 2019
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 deliveryoperations and other energy services. These services include: natural gas distribution, transmission, supply, gathering, processing and marketing; electric distribution and generation; propane distribution;operations; steam generation; and other energy-related services.
Operational Highlights
Our net income for the quarter ended September 30, 2018March 31, 2019 was $5.5$28.7 million, or $0.34$1.74 per share. This represents a decreasean increase of $1.3$1.8 million, or $0.08$0.10 per share, compared to net income of $6.8$26.9 million, or $0.42$1.64 per share, reported for the same quarter in 2017.2018. Operating income decreasedincreased by $2.6$3.6 million for the three months ended September 30, 2018,March 31, 2019, compared to the same period in the prior year, as margin increased by $3.0$10.1 million, or 5.111.1 percent, and was offset by a $1.5$1.8 million increase in growth-related depreciation, amortization and property taxes and a $4.1$4.7 million increase in other operating expenses. DuringIn addition, a final order by the third quarter, we refunded $2.0 million in margin, which represents a pass-throughFlorida PSC allowing us to regulated energy customers of the $2.0 million benefit fromretain TCJA tax savings associated with lower federal income taxestax rates resulted in the reversal, during the quarter. Excluding the estimatedfirst quarter of 2019, of $1.3 million in reserves for customer refunds duringrecorded in 2018.
Our net income for the third quarter was impacted by an increase in interest charges of 2018 associated with the TCJA, gross margin increased by $5.0$2.0 million, or 8.4 percent, and operating income decreased by $603,000, or 4.1 percent, compared to the same period in 2018. The increase was attributable primarily to an increase of $980,000 in interest on higher levels of short-term borrowings, and an increase of $742,000 in interest on long-term debt, largely as a result of the prior year. The decreaseissuance of the NYL Shelf Notes in May and November 2018 and term notes issued in December 2018 and January 2019 to finance the federal income tax rate positively impacted earnings in our unregulated energy businesses.restoration of service to customers who lost service due to the impact of Hurricane Michael.
 Three Months Ended   Three Months Ended  
 September 30, Increase March 31, Increase
 2018 2017 (decrease) 2019 2018 (decrease)
(in thousands except per share)            
Business Segment:            
Regulated Energy segment $15,915
 $15,523
 $392
 $29,741
 $26,711
 $3,030
Unregulated Energy segment (3,933) (951) (2,982) 15,127
 13,684
 1,443
Other businesses and eliminations 54
 60
 (6) (875) 11
 (886)
Operating Income $12,036
 $14,632
 $(2,596) $43,993
 $40,406
 $3,587
Other expense, net (11) (154) 143
Other expense income (expense), net (45) 68
 (113)
Interest charges 4,430
 3,321
 1,109
 5,710
 3,664
 2,046
Pre-tax Income 7,595
 11,157
 (3,562) 38,238
 36,810
 1,428
Income taxes 2,057
 4,324
 (2,267) 9,574
 9,955
 (381)
Net Income $5,538
 $6,833
 $(1,295) $28,664
 $26,855
 $1,809
Earnings Per Share of Common Stock            
Basic $0.34
 $0.42
 $(0.08) $1.75
 $1.64
 $0.11
Diluted $0.34
 $0.42
 $(0.08) $1.74
 $1.64
 $0.10
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Key variances, between the thirdfirst quarter of 2019 and the first quarter of 2018, and the third quarter of 2017, included: 

(in thousands, except per share data) Pre-tax
Income		 Net
Income		 Earnings
Per Share
Third Quarter of 2017 Reported Results $11,157
 $6,833
 $0.42
       
Increased (Decreased) Gross Margins:      
Eastern Shore and Peninsula Pipeline service expansions* 3,616
 2,636
 0.16
Pass-through of lower taxes to regulated energy customers(1)
 (1,993) (1,454) (0.09)
Implementation of Eastern Shore settled rates* (2)
 1,161
 847
 0.05
Natural gas growth (including customer and consumption growth, but excluding service expansions) 734
 535
 0.03
PESCO results (decrease primarily due to imbalance adjustments)
 (629) (459) (0.03)
Retail margins per gallon (469) (342) (0.02)
Florida electric reliability/modernization program* 464
 339
 0.02
Unregulated energy customer consumption (374) (273) (0.02)
GRIP* 329
 240
 0.01
  2,839
 2,069
 0.11
       
 Decreased (Increased) Other Operating Expenses:      
Outside services and facilities maintenance costs (3)
 (1,532) (1,117) (0.07)
Depreciation, asset removal and property tax costs due to new capital investments (3)
 (1,447) (1,055) (0.06)
Benefits and other employee-related expenses (3)
 (758) (553) (0.03)
Payroll expense (increased staffing and annual salary increases) (3)
 (754) (550) (0.03)
Operating expenses to increase staffing, infrastructure and risk management systems necessary to support growth for PESCO (452) (330) (0.02)
Early termination of facility lease due to consolidation of operations facilities(3)
 (423) (309) (0.02)
  (5,366) (3,914) (0.23)
       
Interest charges (1,109) (809) (0.04)
Income taxes - including TCJA impact - decreased effective tax rate for regulated energy —
 1,454
 0.09
Income taxes - including TCJA impact - change in effective tax rate for unregulated energy and other operations —
 (151) (0.01)
Net other changes 74
 56
 —
  (1,035) 550
 0.04
       
Third Quarter of 2018 Reported Results $7,595
 $5,538
 $0.34
(1)"Pass-through of lower taxes to regulated customers" represents the amounts that have already been refunded to customers or reserves established for future refunds and/or reduced rates to customers in the third quarter of 2018 as a result of lower taxes due to the TCJA. Refunds made to customers are offset by the corresponding decrease in federal income taxes and are expected to have no net impact on net income.
(2) Excluding amounts refunded to customers associated with the TCJA, which are broken out separately and discussed in footnote 1.
(3) Excluding incremental operating expenses at PESCO.

(in thousands, except per share data) Pre-tax
Income		 Net
Income		 Earnings
Per Share
First Quarter of 2018 Reported Results $36,810
 $26,855
 $1.64
       
Adjusting for Unusual Items:      
Net impact of PESCO's MTM activity (5,591) (4,088) (0.24)
Impact of weather on customer consumption (2,523) (1,891) (0.12)
2018 retained tax savings for certain Florida natural gas operations 1,321
 990
 0.06
  (6,793) (4,989) (0.30)
       
Increased (Decreased) Gross Margins:      
Absence of the 2018 Bomb Cyclone and capacity constraints cost for PESCO 5,545
 4,157
 0.25
Eastern Shore and Peninsula Pipeline service expansions* 4,266
 3,198
 0.19
Margin contribution from Marlin Gas Services and Ohl (assets acquired in December 2018)* 2,805
 2,103
 0.13
Natural gas distribution - customer growth (excluding service expansions) 1,451
 1,088
 0.06
Higher propane retail margins per gallon 1,259
 944
 0.06
Unregulated Energy customers' consumption growth 879
 659
 0.04
Aspire Energy rate increases 779
 584
 0.04
Other margin for PESCO operations 731
 548
 0.03
Natural gas distribution - change in customer consumption (non-weather) (485) (364) (0.02)
Lower wholesale propane margins and sales (453) (340) (0.02)
Conversion of Sandpiper customers to natural gas 382
 287
 0.02
Florida GRIP* 223
 167
 0.01
  17,382
 13,031
 0.79
       
 Decreased (Increased) Other Operating Expenses:      
Depreciation, asset removal and property tax costs due to growth investments (1,560) (1,169) (0.07)
Incentive compensation costs (based on timing and period-over-period results) (1,931) (1,448) (0.09)
Operating expenses for Marlin Gas Services and Ohl (assets acquired in December 2018) (1,157) (867) (0.05)
Benefits and other employee-related expenses (732) (549) (0.03)
Payroll expense (increased staffing and annual salary increases) (673) (504) (0.03)
Operating expenses to support growth for PESCO (431) (323) (0.02)
  (6,484) (4,860) (0.29)
       
Interest charges (2,046) (1,534) (0.09)
Change in effective tax rate —
 768
 0.05
Net other changes (631) (607) (0.06)
  (2,677) (1,373) (0.10)
       
First Quarter of 2019 Reported Results $38,238
 $28,664
 $1.74
*See the Major Projects and Initiatives table.

Our net income for the nine months ended September 30, 2018 was $38.8 million, or $2.36 per share. This represents an increase of $6.8 million, or $0.40 per share, compared to net income of $32.0 million, or $1.96 per share, reported for the same period in 2017. Operating income increased by $1.9 million for the nine months ended September 30, 2018, compared to the same
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period in the prior year. This increase was driven by a $17.0 million, or 8.3 percent, increase in gross margin, which was offset by a $3.7 million increase in depreciation, amortization and property taxes and an $11.4 million increase in other operating expenses. Excluding the estimated customer refunds reserved or refunded to regulated customers for the nine months ended September 30, 2018, associated with the TCJA, gross margin and operating income increased by $24.6 million, or 12.0 percent, and $9.4 million, or 14.8 percent, respectively, compared to the same period in the prior year. The decrease in the federal income tax rate positively impacted earnings in our unregulated energy businesses.
  Nine Months Ended  
  September 30, Increase
  2018 2017 (decrease)
(in thousands except per share)      
Business Segment:      
Regulated Energy segment $56,930
 $53,004
 $3,926
Unregulated Energy segment 10,241
 10,626
 (385)
Other businesses and eliminations (1,481) 162
 (1,643)
Operating Income $65,690
 $63,792
 $1,898
Other expense, net (204) (1,855) 1,651
Interest charges 11,976
 9,133
 2,843
Pre-tax Income 53,510
 52,804
 706
Income taxes 14,731
 20,781
 (6,050)
Net Income $38,779
 $32,023
 $6,756
Earnings Per Share of Common Stock      
Basic $2.37
 $1.96
 $0.41
Diluted $2.36
 $1.96
 $0.40
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Key variances, between the nine months ended 2018 and the nine months ended 2017, included:
(in thousands, except per share data) Pre-tax
Income		 Net
Income		 Earnings
Per Share
Nine Months Ended September 30, 2017 Reported Results $52,804
 $32,023
 $1.96
Adjusting for unusual items:      
One-time separation expenses associated with a former executive (1,548) (1,421) (0.09)
Absence of Xeron expenses, including 2017 wind-down expenses 829
 601
 0.04
  (719) (820) (0.05)
Increased (Decreased) Gross Margins:      
Pass-through of lower taxes to regulated energy customers(1)
 (7,530) (5,457) (0.33)
Implementation of Eastern Shore settled rates* (2)
 6,256
 4,534
 0.28
Eastern Shore and Peninsula Pipeline service expansions* 5,966
 4,323
 0.26
Return to normal weather 5,342
 3,872
 0.24
Natural gas growth (including customer and consumption growth, but excluding service expansions) 4,098
 2,970
 0.18
Unregulated energy growth excluding PESCO 1,704
 1,234
 0.08
Florida electric reliability/modernization program* 1,231
 892
 0.05
GRIP* 931
 675
 0.04
Non-recurring margin decrease at PESCO (863) (626) (0.04)
Margin from PESCO operations (373) (271) (0.02)
  16,762
 12,146
 0.74
 Decreased (Increased) Other Operating Expenses:      
Depreciation, asset removal and property tax costs due to new capital investments (3)
 (3,401) (2,465) (0.15)
Payroll expense (increased staffing and annual salary increases)(3)
 (3,287) (2,382) (0.15)
Facilities maintenance costs (3)
 (2,275) (1,649) (0.10)
Operating expenses to increase staffing, infrastructure and risk management systems necessary to support growth for PESCO
 (2,167) (1,571) (0.10)
Incentive compensation costs (based on period-over-period results)(3)
 (1,046) (758) (0.05)
Vehicle, credit collections, other taxes, sales and advertising costs (3)
 (1,010) (732) (0.04)
Benefits and other employee-related expenses (3)
 (749) (543) (0.03)
Regulatory costs (3)
 536
 389
 0.02
Early termination of facility lease due to consolidation of operations facilities(3)
 (423) (306) (0.02)
  (13,822) (10,017) (0.62)
       
Interest charges (2,843) (2,060) (0.13)
Income taxes - including TCJA impact - decreased effective tax rate for regulated energy —
 5,457
 0.33
Income taxes - including TCJA impact - decreased effective tax rate for unregulated energy and other operations   1,087
 0.07
Net other changes 1,328
 963
 0.06
  (1,515) 5,447
 0.33
Nine Months Ended September 30, 2018 Reported Results $53,510
 $38,779
 $2.36
(1) "Pass-through of lower taxes to regulated customers" represents the amounts that have already been refunded to customers or reserves established for future refunds and/or reduced rates to customers in the third quarter of 2018 as a result of lower taxes due to the TCJA. Refunds made to customers are offset by the corresponding decrease in federal income taxes and are expected to have no net impact on net income.
(2) Excluding amounts refunded to regulated customers associated with the TCJA, which are broken out separately and discussed in footnote 1.
(3) Excluding incremental operating expenses at PESCO.
*See the Major Projects and Initiatives table.
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Summary of Key Factors
Recently Completed and Ongoing Major Projects and InitiativesInitiatives
We constantly seek and develop additional projects and initiatives in order to increase shareholder value and serve our existing and new customers. The following table represents the major projects recently completed and currently underway. In the future, we will add new projects to this table as such projects are initiated.
 Gross Margin for the Period
 Three Months Ended Nine Months Ended Year Ended Estimate for
 September 30, September 30, December 31, Fiscal
in thousands2018 2017 2018 2017 2017 2018 2019
Florida GRIP$3,722
 $3,393
 $10,933
 $10,002
 $13,454
 $14,287
 $14,370
Eastern Shore Rate Case (1)
2,181
 1,020
 7,276
 1,020
 3,693
 9,800
 9,800
Florida Electric Reliability/Modernization Pilot Program (1)
464
 —
 1,231
 —
 94
 1,558
 1,558
New Smyrna Beach, Florida Project (1)
352
 —
 1,056
 —
 235
 1,409
 1,409
2017 Eastern Shore System Expansion Project - including interim services (1)
2,409
 —
 4,439
 —
 433
 8,009
 15,773
Northwest Florida Expansion Project (1)
1,307
 —
 2,177
 —
 —
 3,484
 6,500
(Palm Beach County) Belvedere, Florida Project (1)
—
 —
 —
 —
 —
 —
 2,023
Total$10,435
 $4,413
 $27,112
 $11,022
 $17,909
 $38,547
 $51,433
 Gross Margin for the Period
 Three Months Ended Year Ended Estimate for
 March 31, December 31, Fiscal
in thousands2019 2018 2018 2019 2020
Florida GRIP (1)
$3,565
 $3,342
 $13,323
 $14,204
 $15,565
2017 Eastern Shore System Expansion Project - including interim services4,800
 2,263
 9,238
 16,183
 15,799
Tax benefit retained by certain Florida entities(2)
2,115
 —
 —
 3,199
 1,879
Northwest Florida Expansion1,307
 —
 3,485
 6,500
 6,500
Western Palm Beach County, Florida Expansion161
 —
 54
 605
 4,711
Marlin Gas Services2,329
 —
 110
 5,100
 6,000
Ohl propane acquisition (rolled into Sharp)476
 —
 —
 1,200
 1,236
Del-Mar Energy Pathway Project - including interim services165
 —
 —
 725
 3,039
Total$14,918
 $5,605
 $26,210
 $47,716
 $54,729
(1 )Gross margin amount included in this table has not(1) All periods shown have been adjusted to reflect the impactlower customer rates as a result of the TCJA. The refunds and rate reductions implemented were or will be,Lower customer rates are offset by lowerthe corresponding decrease in federal income taxestax expense and have no negative impact on net income.
(2) The amount disclosed for the first quarter of 2019 includes tax savings of $1.3 million for the year ended December 31, 2018, due to an order by the TCJA.Florida PSC allowing reversal of a TCJA refund reserve, recorded in 2018, which increased gross margin for the quarter by that amount.

Ongoing Growth Initiatives
GRIP
Florida GRIP is a natural gas pipe replacement program approved by the Florida PSC that allows automatic recovery, through regulated rates, of capital and other program-related costs inclusive of a return on investment, associated with the replacement of mains and services. Since the program's inception in August 2012, we have invested $123.4$131.4 million of capital expenditures to replace 261268 miles of qualifying distribution mains, including $9.5$4.1 million during the first ninethree months of 2018. The increased investments in2019. GRIP generated additional gross margin of $329,000 and $931,000$223,000 for the three and nine months ended September 30, 2018, respectively,March 31, 2019 compared to the same periodsperiod in 2017.2018.
Regulatory ProceedingsMajor Projects and Initiatives Currently Underway
2017 Eastern Shore System Expansion Project
Eastern Shore Rate Case
Eastern Shore's rate case settlement agreement became final on April 1, 2018, with settlement rates effective January 1,has substantially completed the construction of a system expansion project that has increased its capacity by 26 percent. A few remaining segments are expected to be placed into service in various phases during the second quarter of 2019. The project generated $2.5 million in incremental gross margin during the three months ended March 31, 2019, compared to the same period in 2018. The final agreement increases Eastern Shore's operating income by $6.6project is expected to produce gross margin of approximately $16.2 million representing $9.8this year; $15.8 million annually, through 2022; and $13.2 million annually thereafter.
Northwest Florida Expansion Project
In May 2018, Peninsula Pipeline completed construction of transmission lines, and our Florida natural gas division completed construction of lateral distribution lines, to serve customers in additional margin from base rates offset by $3.2 million in lower federal income tax expense for Eastern Shore resulting from the TCJA. For the three and nine months ended September 30, 2018, Eastern Shore recognizedNorthwest Florida. The project generated incremental gross margin of approximately $1.2$1.3 million for the three months ended March 31, 2019. The estimated annual gross margin from this project is $6.5 million, with the opportunity for additional margin as the remaining capacity is sold.
Western Palm Beach County Belvedere, Florida Project
Peninsula Pipeline is constructing four transmission lines to bring natural gas to our distribution system in West Palm Beach, Florida. The first phase of this project was placed into service in December 2018 and $6.3 million, respectively. As of September 30, 2018, Eastern Shore has provided rate reductionsgenerated $161,000 in additional gross margin for the three months ended March 31, 2019. We expect to its customers totaling approximately $2.5 million related tocomplete the decrease in federal income taxes as a resultremainder of the TCJA.

Florida Electric Reliability/Modernization Pilot Program
In December 2017,project in phases through early 2020, and we estimate that the Florida PSC approved a $1.6 million annualized rate increase, effective January 2018, for the recovery of a limited number of investments and costs related to reliability, safety and modernization for our Florida electric distribution system. This increaseproject will continue through at least the last billing cycle of December 2019. For the three and nine months ended September 30, 2018, additionalgenerate gross margin of $464,000$605,000 in 2019 and $1.2approximately $4.7 million respectively, was generated.



in future years once fully in service.


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Major Projects and Initiatives Currently Underway
New Smyrna Beach, Florida ProjectMarlin Gas Services
In the fourth quarterDecember 2018, Marlin Gas Services, our newly created subsidiary, acquired certain operating assets of 2017, we commenced constructionMarlin Gas Transport, a supplier of a 14-milemobile compressed natural gas transmissionutility and pipeline solutions. The acquisition will allow us to serve currentoffer solutions to supply interruption scenarios and plannedprovide other unique applications where pipeline supplies are unavailable or inadequate to meet customer growth in the New Smyrna Beach service area. The project was partially placed into service at the endrequirements. Marlin Gas Services generated $2.3 million of 2017 and is expected to be fully in service during the fourth quarter of 2018. Forincremental gross margin for the three and nine months ended September 30, 2018, the project generated incrementalMarch 31, 2019. We estimate that this acquisition will generate additional annual gross margin of approximately $352,000$5.1 million in 2019 and $1.1$6.0 million respectively, and is expected to generate $1.4 million of annual gross margin beginning in fiscal year 2019.annually thereafter.
2017 Eastern Shore System Expansion ProjectOhl Propane Acquisition
In November 2017, Eastern Shore began constructionDecember 2018, Sharp acquired certain propane customers and operating assets of a $117.0 million system expansion that will increase its capacity by 26 percent once completed. WeOhl. Located between two of Sharp's existing districts, Ohl provided propane distribution service to approximately 2,500 residential and commercial customers in Pennsylvania. The customers and assets acquired from Ohl have invested $103.3 million through September 30, 2018 and expect to substantially complete the project during the remainderbeen assimilated into Sharp. The operations acquired from Ohl generated $476,000 of 2018. The first phase of the project was placed into service in December 2017. Additional segments of the project were placed into service over the first nine months of 2018. The project generated $2.4 million and $4.4 million in incremental gross margin including margin from interim services, duringfor the three and nine months ended September 30, 2018, respectively. The project is expected to produce approximately $15.8 million annually in gross margin through 2022 and $13.2 million annually in gross margin thereafter.

Northwest Florida Expansion Project
In our first expansion of natural gas service into Northwest Florida, Peninsula Pipeline has completed construction of transmission lines and the Florida natural gas division has completed construction of lateral distribution lines to serve several customers. The project was placed into service in May 2018 and generated incrementalMarch 31, 2019. We estimate that this acquisition will generate additional gross margin of $1.3 million and $2.2approximately $1.2 million for Sharp in 2019, with the three and nine months ended September 30, 2018, respectively. The estimated annual gross margin from this project is $6.5 million.
(Palm Beach County) Belvedere, Florida Project
Peninsula Pipeline is constructing a transmission line to bring natural gas to our natural gas distribution systempotential for additional growth in West Palm Beach, Florida. We expect to complete this project by mid-2019 and estimate that the annual gross margin associated with this project will be approximately $2.0 million.

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

Future Projects Not Included in the Table Above

years.
Del-Mar Energy Pathway Project
In September 2018, Eastern Shore filed with thefor FERC a CPauthorization to construct the Del-Mar Energy Pathway project. The proposed project willto provide an additional 14,300 Dts/ddekatherms per day of capacity to four customers. The benefits of this project include additional natural gas transmission pipeline infrastructure in eastern Sussex County, Delaware, and the initial extension of Eastern Shore’s pipeline system into Somerset County, Maryland. Interim services in advance of this project generated $165,000 for the three months ended March 31, 2019. The estimated annual gross margin from this project is approximately $725,000 in 2019, $3.0 million in 2020, $4.6 million in 2021 and $5.1 million.million annually thereafter. Eastern Shore anticipates that this project will be fully in-service by mid-2021, contingent upon FERC issuing authorization for the project by August 2019.
Regulatory Initiatives
Florida Tax Savings Related to TCJA
In the first quarter of 2019, the Florida PSC issued orders authorizing certain of our natural gas distribution operations to retain a portion of the tax savings associated with the lower federal tax rates resulting from the TCJA. We expect these savings to continue in future years.
Other major factors influencing gross margin

Weather and Consumption
Weather did not haveconditions accounted for a material impact on results for$2.5 million decrease in gross margin during the three months ended September 30, 2018. For the nine months ended September 30, 2018, colder temperaturesfirst quarter of 2019 compared to the prior year contributed $5.3same period in 2018.  While period-over-period heating degree-days ("HDD") were essentially flat on the Delmarva Peninsula, extreme conditions during the 2018 "Bomb Cyclone" drove weather-related consumption in the first quarter of 2018 compared to the same period in 2019.  The decrease in consumption on the Delmarva Peninsula accounted for $1.1 million in incrementallower first quarter 2019 gross margin. While temperatures duringmargin for the propane operations and $310,000 for the natural gas distribution operations.  Weather in Florida was approximately 26 percent warmer in the first nine monthsquarter of 2019, compared to the same period in 2018, were colder than the first nine monthsand reduced consumption by propane, electric and natural gas distribution customers which resulted in decreased margin of 2017, they were still warmer than normal, as shown in the table below. We estimate that we would have generated an additional $2.2 million in gross margin if temperatures for the nine months ended September 30, 2018 had been normal.approximately $951,000.  The following table summarizes HDD and CDDcooling degree-day (“CDD”) variances from the 10-year average HDD/CDD ("Normal") for the three and nine months ended September 30, 2018March 31, 2019 and 2017.2018.

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HDD and CDD Information
Three Months Ended   Nine Months Ended  Three Months Ended  
September 30,   September 30,  March 31,  
2018 2017 Variance 2018 2017 Variance2019 2018 Variance
Delmarva                
Actual HDD10
 16
 (6) 2,729
 2,262
 467
2,322
 2,295
 27
10-Year Average HDD ("Delmarva Normal")61
 61
 —
 2,846
 2,850
 (4)
Variance from Delmarva Normal(51) (45)   (117) (588)  
10-Year Average HDD ("Normal")2,362
 2,354
 8
Variance from Normal(40) (59)  
Florida                
Actual HDD—
 —
 —
 507
 298
 209
361
 490
 (129)
10-Year Average HDD ("Florida Normal")—
 —
 —
 533
 555
 (22)
Variance from Florida Normal—
 —
 
 (26) (257) 
10-Year Average HDD ("Normal")518
 517
 1
Variance from Normal(157) (27) 
Ohio    
     
    
Actual HDD
55
 80
 (25) 3,707
 3,070
 637
2,996
 2,991
 5
10-Year Average HDD ("Ohio Normal")91
 92
 (1) 3,774
 3,866
 (92)
Variance from Ohio Normal(36) (12)   (67) (796)  
10-Year Average HDD ("Normal")3,045
 3,069
 (24)
Variance from Normal(49) (78)  
Florida                
Actual CDD1,613
 1,526
 87
 2,704
 2,606
 98
134
 139
 (5)
10-Year Average CDD ("Florida CDD Normal")1,535
 1,542
 (7) 2,593
 2,579
 14
Variance from Florida CDD Normal78
 (16)   111
 27
  
10-Year Average CDD ("Normal")97
 89
 8
Variance from Normal37
 50
  
Natural Gas Distribution Customer and ConsumptionMargin Growth
TheNew customer growth in the Company's natural gas distribution operations generated $734,000 and $4.1$1.5 million of additional margin, which was partially offset by $485,000 in lower margin due to fewer volumes sold to commercial and industrial customers in Florida and at Sandpiper. The details for the three and nine months ended September 30, 2018, respectively. The breakdown ofMarch 31, 2019 are provided in the increased margin is as follows:following table:
 Three Months Ended Nine Months Ended Three Months Ended
(in thousands) September 30, 2018 September 30, 2018 March 31, 2019
Customer growth:    
Customer Growth:  
Residential $309
 $1,171
 $637
Commercial and industrial, excluding new service in Northwest Florida 283
 927
 529
New service in Northwest Florida 305
 652
 285
Total customer growth 897
 2,750
    
Volume growth:    
Total Customer Growth 1,451
Non-Weather Change in Customer Consumption:  
Residential (239) 613
 (89)
Commercial and industrial 57
 1,030
 (396)
Other - including unbilled revenue 19
 (295)
Total volume growth (163) 1,348
    
Total natural gas distribution growth $734
 $4,098
Total Decline in Customer Consumption (485)
Total (or net) Increase in Natural Gas Distribution Margin $966

The additional margin from new customers reflects an increase of approximately 3.9 percent in the average number of residential customers served on the Delmarva Peninsula, approximately 3.2 percent growth in new residential customers served in Florida, new service to customers in Northwest Florida, as well as an increase in the number of commercial and industrial customers served.
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Customer growth for our Delmarva Peninsula and Florida natural gas distribution operations generated $897,000 and $2.8 million in additional gross margin for the three and nine months ended September 30, 2018, respectively, compared to the same periods in 2017.The additional margin was generated from an approximately 3.9 percent and 3.8 percent increase in the average number of residential customers for the three and nine months ended September 30, 2018, respectively, as well as growth in commercial and industrial customers on the Delmarva Peninsula in the third quarter and first nine months of 2018, compared to the corresponding periods in 2017. Residential customer growth on the Delmarva Peninsula has averaged 3.0 percent over the past five years. Our Florida natural gas distribution operations generated additional gross margin for the three and nine months ended September 30, 2018, due to growth in all customer classes and new service to customers in Northwest Florida.

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

Propane Operations
Gross margin generated by our propane operations decreasedincreased by $834,000$305,000 during the three months ended September 30, 2018,March 31, 2019, compared to the same period in 2017, as a result of lower retail margins per gallon and2018. The following table summarizes the timing ofyear-over-year changes in gross margin for the propane deliveries to customers. Customer consumptionbusiness for our Florida propane operations was higherthe quarter ended March 31, 2019:
 Three Months Ended
 March 31, 2019
(in thousands) 
Decrease in customer consumption due to warmer weather$(1,307)
Increased retail margins per gallon1,259
Customer growth, increased sales volumes (non-weather-related) and other factors482
Ohl acquisition (assets acquired in December 2018)476
Lower wholesale propane margins and sales(453)
Other(152)
2019 Change in gross margin by our propane operations$305
Aspire Energy
Gross margin generated by Aspire Energy increased by $796,000 during the third quarter of 2017 due to the impact of Hurricane Irma.

For the ninethree months ended September 30, 2018, propane operations generated $4.9 million in incremental marginMarch 31, 2019, compared to the same period in 2017. More normal temperatures accounted for $2.9 million of the margin increase during the nine months ended September 30, 2018. The balanceincrease reflects $779,000 of the increase reflected increased customerrate increases and $397,000 of consumption growth, continued expansion of AutoGas through the addition of new customers and other factors, higher sales and revenues from service contracts and increased wholesale sales activities.

offset by a $380,000 decrease in gross margin due to various factors.
PESCO
PESCO's gross margin for the three and nine months ended September 30, 2018March 31, 2019 was lowerhigher by $629,000 and $1.2 million,$685,000 compared to the same periodsperiod in 2017, respectively.2018. The following table summarizes the changes in PESCO’S year-over-yearPESCO’s quarter-over-quarter margin for the three and nine months ended September 30, 2018:March 31, 2019:
 Three Months Ended Nine Months Ended
 September 30, 2018 September 30, 2018
(in thousands)   
2017 Gross margin$1,360
 $5,749
Imbalance positions and true up(493) (493)
Margin changes from growth and the acquisition of certain assets from ARM in 2017(136) 119
Non-recurring margin factors - change in gross margin contribution from various asset management agreements, MTM impact, Bomb Cyclone impact and other adjustments
—
 (863)
2018 Gross Margin$731
 $4,512
 Three Months Ended
(in thousands)March 31, 2019
Net impact of PESCO's MTM activity$(5,591)
Net impact of extraordinary costs associated with the 2018 Bomb Cyclone for the Mid-Atlantic wholesale portfolio (1)
3,284
Mid-Atlantic retail portfolio loss due to pipeline capacity constraints in the first quarter of 2018 (1)
2,261
Other margin for PESCO operations (net)731
2019 Change in PESCO gross margin$685

(1)The 2018 Bomb Cyclone refers to the high-intensity winter storms in early January 2018 that impacted the Mid-Atlantic region and had a residual impact on our businesses through the month of February 2018.   The exceedingly high demand and associated impacts on pipeline capacity and gas supply in the Mid-Atlantic region created significant, unusual costs for PESCO. While such concerted impacts are not expected to occur frequently, our management revisited and refined its risk management strategies and implemented additional controls.
PESCO generated an operating loss of $1.1 million$510,000 for the three months ended September 30, 2018,March 31, 2019, compared to aan operating loss of $63,000$764,000 during the prior year period. The improvement in the quarter-over-quarter decreased results reflect lowerreflects higher gross margin growth, accompaniedpartially offset by a $452,000$431,000 increase in planned operating expenses as a result offor increased staffing, infrastructure and risk management system costs as PESCO executes itsresources to support continued execution of PESCO's growth strategy.

ForImpact of Hurricane Michael
In October 2018, Hurricane Michael passed through FPU's electric distribution operation's service territory in Northwest Florida. The hurricane caused widespread and severe damage to FPU's infrastructure, resulting in 100 percent of its Northwest Florida customers losing electrical service. FPU, after exerting extraordinary hurricane restoration efforts, restored service to those customers who were able to accept it. Through March 31, 2019, FPU has spent approximately $65.0 million to restore service, which has been recorded as new plant and equipment or charged against FPU’s accumulated depreciation and storm reserve. In conjunction with the nine months ended September 30, 2018, PESCO reported an operating loss of $1.2 million, compared to operating income of $2.2 million during the prior year period. The year-over-year operating loss primarily reflects increased expenses incurred for the reasons discussedhurricane-related expenditures, we executed two 13-month unsecured term loans as temporary financing, each in the paragraph above, $596,000amount of $30.0 million. The interest cost associated with these loans is LIBOR plus 75 basis points. One term loan was executed in additional expenses relatedDecember 2018; the other was executed in January 2019. The storm did not have a material impact on the margin from these operations, as services were restored to a majority of our customers. Pending the acquisitionoutcome of certain assets from ARM, as well as the impact of several non-recurring margin adjustments, largely duringregulatory filings associated with the storm, our results for the first quarter included higher interest expense of 2018.


Table$435,000, or $326,000 on an after-tax basis, associated with the intermediate term loans discussed above. We are in the process of Contents


Xeron
Xeron's operations were wound down duringpreparing the second quarternecessary regulatory filings to seek recovery of 2017. Operating income for the nine months ended September 30, 2018, improved by $829,000, compared tocosts incurred, including the prior year period due to the absence of Xeron's 2017 wind-down expenses and operating losses.


associated interest costs.
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Regulated Energy Segment

For the quarter ended September 30, 2018,March 31, 2019, compared to the quarter ended September 30, 2017:March 31, 2018:

 Three Months Ended   Three Months Ended  
 September 30, Increase March 31, Increase
 2018 2017 (decrease) 2019 2018 (decrease)
(in thousands)            
Revenue $72,770
 $69,703
 $3,067
 $103,618
 $109,393
 $(5,775)
Cost of sales 21,501
 22,794
 (1,293) 36,516
 48,231
 (11,715)
Gross margin 51,269
 46,909
 4,360
 67,102
 61,162
 5,940
Operations & maintenance 23,376
 20,794
 2,582
 24,548
 23,147
 1,401
Depreciation & amortization 8,405
 7,338
 1,067
 8,446
 7,516
 930
Other taxes 3,573
 3,254
 319
 4,367
 3,788
 579
Other operating expenses 35,354
 31,386
 3,968
 37,361
 34,451
 2,910
Operating income $15,915
 $15,523
 $392
 $29,741
 $26,711
 $3,030
Operating income for the Regulated Energy segment for the three months ended September 30, 2018March 31, 2019 was $15.9$29.7 million, an increase of $392,000$3.0 million compared to the same period in 2017.2018. The increased operating income resulted from increased gross margin of $4.4$5.9 million, offset by $1.5 million in higher depreciation and taxes and a $4.0$1.4 million increase in operating expenses.
On February 25, 2019, the Florida PSC issued a final order regarding the treatment of TCJA impact, allowing us to retain the savings associated with lower federal tax rates for certain of our natural gas distribution operations. As a result, $1.3 million in reserves for customer refunds, recorded in 2018, were reversed in 2019. Excluding the impact of the customer refunds and reserves for future refunds and/ or rate reductions of approximately $2.0 million for lower income taxes due to the TCJA,reversal, gross margin and operating income for the three months ended September 30, 2018March 31, 2019 increased by $6.4$4.6 million and $2.4$1.7 million, or 13.57.6 percent and 15.46.4 percent, respectively.
Gross Margin
Items contributing to the quarter-over-quarter increase in gross margin are listed in the following table:
(in thousands)Margin Impact
Eastern Shore and Peninsula Pipeline service expansions$3,616
Implementation of Eastern Shore settled rates1,161
Natural gas growth (including customer and consumption growth, but excluding service expansions)734
Florida electric reliability/modernization program464
Florida GRIP329
Other49
Total6,353
Pass-through to regulated customers of lower taxes as a result of the TCJA*(1,993)
Quarter-over-quarter increase in gross margin$4,360
(in thousands)Margin Impact
Eastern Shore and Peninsula Pipeline service expansions$4,266
Natural gas distribution - customer growth (excluding service expansions)1,451
2018 retained tax savings for certain Florida natural gas distribution operations1,321
Impact of weather on customer consumption (primarily in Florida)(1,093)
Natural gas distribution - change in customer consumption (non-weather)(485)
Conversion of Sandpiper customers to natural gas382
Florida GRIP223
Other immaterial variances(125)
Quarter-over-quarter increase in gross margin$5,940
*AsThe following is a resultnarrative discussion of the TCJAsignificant items in the foregoing table, which we believe is necessary to understand the information disclosed in the table.
Eastern Shore and ensuing directivesPeninsula Pipeline Service Expansions
We generated additional gross margin of $4.3 million, primarily from the following natural gas service expansions:
$2.5 million from Eastern Shore's services in conjunction with its 2017 Expansion Project.
$1.5 million generated by federalPeninsula Pipeline from the Belvedere Pipeline and state regulatory commissions, we reserved or refundedNorthwest Pipeline Expansion Projects.

Natural Gas Customer Growth
We generated additional gross margin of $1.5 million from natural gas customer growth. Gross margin increased by $748,000 in Florida and $703,000 on the Delmarva Peninsula.

2018 retained tax savings for Florida natural gas operations
We generated additional gross margin of $1.3 million, due to a final order from the Florida PSC allowing us to retain the tax savings associated with TCJA. Pursuant to the order, refund reserves recorded by our Florida natural gas businesses in 2018, were reversed in 2019. See Note 4, Rates and Other Regulatory Activities, for additional information.
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Impact of Weather on Customer Consumption
Gross margin decreased by $1.1 million, as weather in Florida was approximately 26 percent warmer in the first quarter of 2019, compared to the same period in 2018. This reduced consumption by Florida electric and natural gas distribution customers, decreasing gross margin by approximately $784,000. Our Delmarva natural gas operations experienced a decrease in margin of our regulated businesses an estimated $2.0 million$310,000, reflecting the absence, during the first quarter of 2019, of the much higher consumption experienced during the first quarter of 2018 due to the extreme Bomb Cyclone weather conditions.

Consumption Changes (non-weather)
Gross margin decreased by $485,000 due to non-weather-related decreases in customer sales volumes in Florida and on the Delmarva Peninsula.

Sandpiper's margin from natural gas conversions
Gross margin increased by $382,000, due primarily to continuing conversion of the Sandpiper system from propane service to natural gas service.

Florida GRIP
Continued investment in the Florida GRIP generated additional gross margin of $223,000 for the three months ended September 30, 2018. In some jurisdictions, we have paid refunds to customers, while in other jurisdictions, we have established reserves until agreements are approved and changes are made to customer rates. The reserves and lower customer rates are equalMarch 31, 2019, compared to the estimated reductionsame period in federal2018.

Other Operating Expenses
Items contributing to the quarter-over-quarter increase in operating expenses are listed in the following table:
(in thousands)Other Operating Expenses
Depreciation, amortization and property taxes primarily associated with recent growth projects$1,375
Incentive compensation costs (based on timing and period-over-period results)653
Outside services, facilities and maintenance costs(609)
Payroll expense (increased staffing and annual salary increases)608
Benefits and other employee-related expenses(1)
551
Other immaterial variances332
Quarter-over-quarter increase in other operating expenses$2,910
(1) Since we self-insure for healthcare costs, benefits costs fluctuate depending upon filed claims.

Unregulated Energy Segment

For the quarter ended March 31, 2019, compared to the quarter ended March 31, 2018:
  Three Months Ended  
  March 31, Increase
  2019 2018 (decrease)
(in thousands)      
Revenue $138,102
 $145,367
 $(7,265)
Cost of sales 103,700
 115,066
 (11,366)
Gross margin 34,402
 30,301
 4,101
Operations & maintenance 15,555
 13,359
 2,196
Depreciation & amortization 2,611
 2,167
 444
Other taxes 1,109
 1,091
 18
Total operating expenses 19,275
 16,617
 2,658
Operating income $15,127
 $13,684
 $1,443

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The Unregulated Energy segment had operating income taxesof $15.1 million and $13.7 million for the three months ended March 31, 2019 and 2018, respectively. The increased operating income of approximately $1.4 million was due to an increase in gross margin of $4.1 million, partially offset by a $2.7 million increase in operating expenses.
Unregulated Energy, excluding PESCO
     Increase
For the Three Months Ended March 31,2019 2018 (decrease)
(in thousands)     
Gross margin$32,542
 $29,126
 $3,416
Depreciation, amortization and property taxes2,792
 2,357
 435
Other operating expenses14,113
 12,321
 1,792
Operating Income$15,637
 $14,448
 $1,189
Gross Margin
Items contributing to the TCJA and have no material impact on after-tax earnings fromquarter-over-quarter increase in gross margin are listed in the Regulated Energy segment.following table:
(in thousands) Margin Impact
Marlin Gas Services (acquired assets of Marlin Gas Transport in December 2018) $2,329
Propane Operations  
Decrease in weather-related customer consumption due to the absence of the 2018 Bomb Cyclone (1,307)
Increased retail margins per gallon 1,259
Customer growth, increased sales volumes (non-weather-related) and other factors 482
Ohl acquisition (assets acquired in December 2018) 476
Lower wholesale propane margins and sales (453)
Aspire Energy  
Rate increases 779
Increased customer consumption 397
Other immaterial variances (546)
Quarter-over-quarter increase in gross margin $3,416
The following is a narrative discussion of the significant items in the foregoing table, which we believe is necessary to understand the information disclosed in the table.

Service ExpansionsMarlin Gas Services
We generated additionalGross margin increased by $2.3 million as a result of the acquisition of certain assets of Marlin Gas Transport in December 2018.

Propane Operations - Decreased Customer Consumption - (Weather)
While HDDs were essentially flat period-over-period on the Delmarva Peninsula, extreme conditions during the January 2018 "Bomb Cyclone" drove weather-related consumption in the first quarter of 2018 compared to the same period in 2019, and which reduced gross margin by $1.1 million for the Delmarva propane operations.  Weather in Florida was approximately 26 percent warmer in the first quarter of $3.62019 reducing consumption by propane distribution customers and decreasing gross margin by approximately $167,000, compared to the same period in 2018. 

Propane Operations - Increased Retail Margins Per Gallon
Gross margin increased by $1.3 million, due to lower propane costs during the first quarter of 2019, compared to the same period in 2018. Our retail pricing strategy, guided by local market conditions, further increased margins in the first quarter of 2019. These market conditions, which include competition with other propane suppliers, as well as the availability and price of alternative energy sources, may fluctuate based on changes in demand, supply and other energy commodity prices.

Aspire Energy - Increased Margin Driven by Changes in Rates
Gross margin increased by $779,000, due primarily fromto changes in customer rates on various dates during 2018.

Aspire Energy - Increased Margin Driven by Growth in Customer Consumption
Gross margin increased by $397,000, due to an increase in customer consumption during the following natural gas service expansions:
$2.4 million from Eastern Shore's services, including those providedfirst quarter of 2019, compared to customers on an interim basis,the same period in conjunction with portions of Eastern Shore's 2017 Expansion Project that were placed in service in December 2017 and July 2018, partially offset by the absence of short-term contracts totaling $343,000 that were replaced by long-term service agreements; and
$1.7 million generated by Peninsula Pipeline from the New Smyrna Beach and Northwest Pipeline Expansion Projects.2018.
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Implementation of Eastern Shore Settled Rates
Eastern Shore generated additional gross margin of $1.2 million from the implementation of new rates as a result of its rate case filing. See Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.
Natural Gas Growth (including customer and consumption growth but excluding service expansions)
Increased gross margin of $734,000 from natural gas growth and consumption (excluding service expansions) was generated primarily from the following:
$591,000 from Florida natural gas customer growth, due primarily to an increase in residential and commercial customers served as well as expansion to Northwest Florida;
$307,000 from a 3.9 percent increase in the average number of residential customers served by the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers served; offset by
$165,000 from lower sales on the Delmarva Peninsula and absence of the positive impact on consumption growth in Florida in the third quarter of 2017.

Florida Electric Reliability/Modernization Program
Gross margin increased by $464,000, due primarily to the rates that went into effect in January 2018. See Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.
GRIP
Increased investment in GRIP generated additional gross margin of $329,000 for the three months ended September 30, 2018, compared to the same period in 2017.
Impact of the TCJA on Customer Rates
Adjustments to customer rates, because of the implementation of the TCJA, decreased gross margin by $2.0 million due to refunds paid to customers and the establishment of reserves for future refunds and/or rate reductions to customers. The decrease in gross margin was offset by a $2.0 million reduction in federal income taxes.
Other Operating Expenses
Other operating expenses increased by $4.0 million. The significant factors contributing to the increase in other operating expenses included:
$1.2 million in higher costs related to outside services to support growth and facilities and maintenance costs to maintain system integrity;
$1.3 million in higher depreciation, asset removal and property tax costs associated with recent capital investments;
$530,000 in higher benefits and other employee-related expenses (since we self-insure for health care costs, benefits costs fluctuate depending upon filed claims);
$446,000 in higher payroll expense for additional personnel to support growth, including Eastern Shore's 2017 System Expansion Project, which is our largest project to date; and
$323,000 in early lease termination fees for our former service center, which service center moved to our newly constructed “Energy Lane Campus” in Dover, Delaware during the third quarter of 2018.


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

  Nine Months Ended  
  September 30, Increase
  2018 2017 (decrease)
(in thousands)      
Revenue $252,667
 $238,353
 $14,314
Cost of sales 89,741
 87,206
 2,535
Gross margin 162,926
 151,147
 11,779
Operations & maintenance 71,546
 66,780
 4,766
Depreciation & amortization 23,541
 21,365
 2,176
Other taxes 10,909
 9,998
 911
Other operating expenses 105,996
 98,143
 7,853
Operating income $56,930
 $53,004
 $3,926
Operating income for the Regulated Energy segment for the nine months ended September 30, 2018 was $56.9 million, an increase of $3.9 million compared to the same period in 2017. The increased operating income resulted from increased gross margin of $11.8 million, offset by an increase in operating expenses of $7.9 million.
Excluding the impact of refunds to customers and reserves for future refunds and/or rate reductions of approximately $7.5 million for lower income taxes due to the TCJA, gross margin and operating income increased by $19.3 million and $11.4 million, or 12.8 percent and 21.6 percent, respectively.
Gross Margin
Items contributing to the period-over-period increase in gross margin are listed in the following table:
(in thousands)Margin Impact
Implementation of Eastern Shore settled rates$6,256
Eastern Shore and Peninsula Pipeline service expansions5,966
Natural gas growth (including customer and consumption growth but excluding service expansions)4,098
Return to more normal weather1,498
Florida electric reliability/modernization program1,231
Florida GRIP931
Other(671)
Total19,309
Pass-through to regulated customers of lower taxes as a result of the TCJA*(7,530)
Period-over-Period increase in gross margin$11,779
*As a result of the TCJA, and ensuing directives by federal and state regulatory commissions, we reserved or refunded to customers of our regulated businesses an estimated $7.5 million during the first nine months of 2018. In some jurisdictions, we have paid refunds to customers, while in other jurisdictions, we have established reserves until agreements are approved and changes are made to customer rates. The reserves and lower customer rates are equal to the estimated reduction in federal income taxes due to the TCJA and have no material impact on after-tax earnings from the Regulated Energy segment.

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

Implementation of Eastern Shore's Settled Rates
Eastern Shore generated additional gross margin of $6.3 million from the implementation of new rates as a result of its rate case filing. See Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.
Service Expansions
We generated additional gross margin of $6.0 million primarily from the following natural gas service expansions:
$4.4 million from Eastern Shore's services, including those provided to customers on an interim basis, in conjunction with portions of Eastern Shore's 2017 Expansion Project that were placed in service in December 2017 and July 2018;
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$446,000 in additional margin as a result of an increase in rates from service provided to an industrial customer, partially offset by the absence of short-term contracts totaling $1.6 million that were replaced by long-term service agreements; and
$3.2 million generated by Peninsula Pipeline from the New Smyrna Beach and Northwest Pipeline Expansion Projects.
Natural Gas Growth (including customer and consumption growth but excluding service expansions)
Increased gross margin of $4.1 million from natural gas growth and consumption (excluding service expansions) was generated primarily from the following:
$1.5 million from Florida natural gas customer growth, due primarily to an increase in residential and commercial customers served;
$1.3 million from higher sales on the Delmarva Peninsula and in Florida that were not driven by weather; and
$1.2 million from a 3.8 percent increase in the average number of residential customers served by the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers served.
Return to More Normal Weather
Temperatures during the first nine months of 2018 were 2.9 percent warmer than normal, compared to 22.6 percent warmer than normal during the first nine months of 2017. Comparatively colder weather during the first nine months of 2018 increased usage and generated $1.5 million in additional margin.
Florida Electric Reliability/Modernization Program
Gross margin increased by $1.2 million, due primarily to the rates that went into effect in January 2018. See Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.
GRIP
Increased investment in GRIP generated additional gross margin of $931,000 for the nine months ended September 30, 2018, compared to the same period in 2017.
Impact of the TCJA on Customer Rates
Adjustments to customer rates, because of the implementation of the TCJA, decreased gross margin by $7.5 million due to refunds and reserves for future refunds and/or rate reductions to customers. The decrease in gross margin was offset by a reduction in federal income taxes.
Other Operating Expenses
Other operating expenses increased by $7.9 million. The significant factors contributing to the increase in other operating expenses included:
$3.0 million in higher depreciation, asset removal and property tax costs associated with recent capital investments;
$1.9 million in higher payroll expenses for additional personnel to support growth, including Eastern Shore's 2017 System Expansion Project, our largest project to date;
$1.5 million in higher facilities and maintenance costs to maintain system integrity;
$401,000 in higher incentive compensation costs as a result of improved period-over-period results;
$356,000 in higher vehicle, credit collections, other taxes, sales and advertising costs;
$323,000 in early lease termination fees for our former service center, which service center moved to our newly constructed “Energy Lane Campus” in Dover, Delaware during the third quarter; and
$307,000 in higher benefit and other employee-related expenses (since we self-insure for health care costs, benefits costs fluctuate depending upon filed claims); offset by
$536,000 in lower regulatory costs due to the absence of rate case filings in 2018.

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Unregulated Energy Segment

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

The Unregulated Energy segment had an operating loss of $3.9 million for the three months ended September 30, 2018 compared to an operating loss of $951,000 for the same period in 2017. The increased operating loss of approximately $3.0 million was due to a decrease in gross margin of $1.3 million, accompanied by a $1.6 million increase in operating expenses.
Gross Margin
Items contributing to the quarter-over-quarter decrease in gross margin are listed in the following table:
(in thousands) Margin Impact
PESCO $(629)
Propane retail operations - decreased margins driven by lower prices per gallon (469)
Unregulated Energy customer consumption decrease (374)
Other 133
Quarter-over-quarter decrease in gross margin $(1,339)

The following is a narrative discussion of the significant items in the foregoing table, which we believe is necessary to understand the information disclosed in the table.
PESCO
For the three months ended September 30, 2018, PESCO's gross margin decreased by $629,000 compared to the same period in 2017. Reduced third quarter 2018 margin from PESCO primarily resulted from the timing and true-up of various imbalance positions with pipelines.
Propane Retail Operations - Decreased Prices Per Gallon
Gross margin decreased by $469,000for the three months ended September 30, 2018, mainly driven by lower prices per retail gallon as these businesses responded to current market conditions.
Unregulated Energy customer consumption decrease
Gross margin decreased by $374,000, due primarily to decreased sales of propane resulting from timing of propane deliveries to customers. Propane deliveries in Florida during the third quarter of 2017 were positively impacted by Hurricane Irma.
Other Operating Expenses
Other operating expenses increased by $1.6 million in the third quarter of 2018. The significant components of the increase in other operating expenses included:
$452,000 in higher expenses as a result of increased staffing, infrastructure and risk management system costs to ensure the appropriate infrastructure is in place as PESCO executes its growth strategy;
$308,000 in higher staffing and associated costs for additional personnel to support growth;
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$275,000 in higher outside services associated primarily with growth and ongoing compliance activities;
$228,000 in higher benefits and employee-related costs (since we self-insure for health care costs, benefits costs fluctuate depending upon filed claims);
$176,000 in higher incentive compensation costs as a result of improved period-over-period results for most of the unregulated energy business; and
$144,000 in higher depreciation, amortization and property tax expense.

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

Operating income for the Unregulated Energy segment for the nine months ended September 30, 2018 was $10.2 million, compared to operating income of $10.6 million for same period in 2017. The $385,000 decrease in operating income in the nine months ended September 30, 2018 was due to an increase in gross margin of $5.3 million, offset by a $5.7 million increase in operating expenses.
Gross Margin
Items contributing to the period-over-period increase in gross margin are listed in the following table:
(in thousands) Margin Impact
Propane delivery operations - additional customer consumption - (weather) 2,923
Propane delivery operations - increased margin driven by growth and other factors 1,552
PESCO (1,236)
Aspire Energy - customer consumption - (weather) 921
Aspire Energy - increased margin driven by growth and other factors 592
Growth in wholesale propane margins and sales 255
Other 315
Period-over-period increase in gross margin $5,322

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

Propane Delivery Operations - Additional Customer Consumption - (Weather)
Gross margin increased by $2.9 million, due primarily to increased propane deliveries in the Mid-Atlantic region as a result of colder temperatures during the nine months ended September 30, 2018, compared to the same period in 2017.

Propane Delivery Operations - Increased Margin Driven by Growth and Other Factors
Gross margin increased by $1.6 million,$482,000, due primarily to increased propane sales as a result of customer growth in customers and other factors in Florida and in the Mid-Atlantic region.

Propane Operations - Ohl Acquisition
Gross margin increased by $476,000 as a result of the acquisition of R.F. Ohl in December 2018, which was rolled into Sharp.

Wholesale Propane Margins
Gross margin decreased by $453,000 in 2019 due to a lower margin per gallon and a decrease in volumes delivered for the Mid-Atlantic propane operations.
Other Operating Expenses
Other operating expenses increased by $2.2 million in the first quarter of 2019. The significant components of the increase in other operating expenses included:
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(in thousands)Other Operating Expenses
Operating expenses associated with operating Marlin Gas Services and Ohl (Asset acquisitions in December 2018)$1,157
Incentive compensation costs (based on timing and period-over-period results)466
Outside services and facilities maintenance costs286
Depreciation, asset removal and property tax costs due to new capital investments187
Benefits and other employee-related expenses(1)
133
Other immaterial variances(2)
Quarter-over-quarter increase in other operating expenses$2,227

(1)
Since the Company self-insures for healthcare costs, benefits costs fluctuate depending upon filed claims.

PESCO
     Increase
For the Three Months Ended March 31,2019 2018 (decrease)
(in thousands)     
Gross margin$1,860
 $1,175
 $685
Depreciation, amortization and property taxes147
 148
 (1)
Other operating expenses2,223
 1,791
 432
Operating Income$(510) $(764) $254

For the ninethree months ended September 30, 2018,March 31, 2019, PESCO's gross margin decreasedincreased by $1.2 million$685,000 compared to the same period in 2017. Lower2018. Higher gross margin from PESCO for the ninethree months ended September 30, 2018 from PESCOMarch 31, 2019 resulted from the following:

(in thousands)Margin Impact
Reversal of unrealized MTM loss recorded in the fourth quarter of 2017$5,713
Net impact of extraordinary costs associated with the 2018 Bomb Cyclone for the Mid-Atlantic wholesale portfolio (1)
(3,284)
Loss for the Mid-Atlantic retail portfolio caused by pipeline capacity constraints in January and warm weather in February 2018 (1)
(2,261)
Non-recurring margin and annual imbalance settlement from 2017 customer Supply Agreement(1,673)
Non-recurring margin increase associated with the Southeast portfolio642
Other(373)
Total Change in Gross Margin for PESCO for the nine months ended September 30, 2018$(1,236)
(in thousands)Margin Impact
Net impact of PESCO's MTM activity$(5,591)
Net impact of extraordinary costs associated with the 2018 Bomb Cyclone for the Mid-Atlantic wholesale portfolio (1)
3,284
Mid-Atlantic retail portfolio loss due to pipeline capacity constraints in the first quarter of 2018 (1)
2,261
Other margin for PESCO operations (net)731
Quarter-over-quarter increase in gross margin for PESCO$685
(1) The 2018 Bomb Cyclone refers to the high-intensity winter storms in early January 2018 that impacted the Company's Mid-Atlantic service territoryregion and which had a residual impact on the Company'sour businesses through the month of February.   The exceedingly high demand and associated impacts on pipeline capacity and gas supply in the Delmarva PeninsulaMid-Atlantic region created significant, unusual costs for PESCO. While such concerted impacts will recur infrequently, the Company'sare not expected to occur frequently, our management revisited and refined its risk management strategies and implemented additional controls.

Aspire Energy - Customer Consumption (Weather)
Gross margin increased by $921,000, as a result of increased natural gas deliveries, due primarily to colder temperatures during the nine months ended September 30, 2018, compared to the same period in 2017.

Aspire Energy - Customer Consumption (Growth and Other Factors)
Gross margin increased by $592,000, in the nine months ended September 30, 2018, due primarily to increased sales as a result of customer consumption growth and other factors.

Wholesale Propane Margins
Gross margin increased by $255,000, in the nine months ended September 30, 2018 due to a higher margin per gallon and an increase in volume delivered for the Mid-Atlantic propane distribution operations.
Other Operating Expenses
Other operating expenses increased by $5.7 million in the nine months ended September 30, 2018. The significant components of the increase in other operating expenses included:
$2.2 million in higher expenses as a result of increased staffing, infrastructure and risk management system costs to ensure the appropriate infrastructure is in place as PESCO executes its growth strategy;
$1.4 million in higher staffing and associated costs for additional personnel to support growth and increased deliveries driven by the colder weather during the nine months ended September 30, 2018, compared to the same period in 2017;
$706,000 in higher maintenance costs as a result of ongoing compliance activities;
$654,000 in higher expenses, including vehicle fuel costs, sales and advertising, taxes other than income taxes and credit collections costs;
$645,000 in higher incentive compensation costs as a result of improved period-over-period results for many of the unregulated energy businesses;
$442,000 in higher benefits and employee-related costs (since we self-insure for health care costs, benefits costs fluctuate depending upon filed claims); and
$410,000 in higher depreciation, amortization and property tax expense due to increased investments; offset by
the absence of $829,000 in 2017 Xeron wind-down expenses.

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Operating expenses increased by $432,000, reflecting increased staffing, infrastructure and risk management systems necessary to support growth. Overall, PESCO’s quarter-over-quarter performance improved by $254,000.

OTHER EXPENSE,INCOME (EXPENSE), NET
For the quarter ended September 30, 2018March 31, 2019 compared to the quarter ended September 30, 2017March 31, 2018
Other expense,income (expense), net, which includes non-operating investment income (expense), interest income, late fees charged to customers, gains or losses from the sale of assets and pension and other benefits expense, decreased by $143,000$113,000 in the thirdfirst quarter of 2018,2019, compared to the same period in 2017, due to gain from the sale of assets within our unregulated businesses in the third quarter of 2017.
For the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017
Other expense, net, which includes non-operating investment income (expense), interest income, late fees charged to customers, gains or losses from the sale of assets and pension and other benefits expense, decreased by $1.7 million for the first three quarters of 2018, compared to the same period in 2017, due partly to the recognition of Xeron lease termination expenses in 2017.2018.
INTEREST CHARGES
For the quarter ended September 30, 2018March 31, 2019 compared to the quarter ended September 30, 2017March 31, 2018
Interest charges for the three months ended September 30, 2018March 31, 2019 increased by $1.1$2.0 million, compared to the same period in 2017,2018, attributable primarily to an increase of $953,000$980,000 in interest on higher levels of short-term borrowings, and an increase of $277,000$742,000 in interest on long-term debt, largely as a result of the issuance of the NYL Shelf Notes (Series A) in May 2018.
Forand November 2018 and term notes issued in December 2018 and January 2019 to finance the nine months ended September 30, 2018 comparedrestoration of service to customers who lost service due to the nine months ended September 30, 2017
Interest charges for the nine months ended September 30, 2018 increased by $2.8 million, compared to the same period in 2017, attributable primarily to an increaseimpact of $2.3 million in interest on higher short-term borrowings, and an increase of $1.1 million in interest on long-term debt, largely as a result of the issuance of the Prudential Shelf Notes in April 2017 and the issuance of the NYL Shelf Notes (Series A) in May 2018.
Hurricane Michael.
INCOME TAXES
For the quarter ended September 30, 2018March 31, 2019 compared to the quarter ended September 30, 2017March 31, 2018
Income tax expense was $2.1$9.6 million for the three months ended September 30, 2018,March 31, 2019, compared to $4.3$10.0 million in the same period in 2017.2018. The decrease in income tax expense was due primarilyattributed to the impactamortization of the TCJA in the third quarter of 2018.deferred taxes gross up associated with TCJA. Our effective income tax rate was 27.125.0 percent and 39.527.0 percent, for the three months ended September 30,March 31, 2019 and 2018, and 2017, respectively.

For the nine months ended September 30, 2018 compared to the nine months ended September 30, 2017
Income tax expense was $14.7 million for the nine months ended September 30, 2018, compared to $20.8 million in the same period in 2017. The decrease in income tax expense was due primarily to the impact of the TCJA in the first nine months of 2018. Our effective income tax rate was 27.5 percent and 39.5 percent for the nine months ended September 30, 2018 and 2017, respectively.

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FINANCIAL POSITION, 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 $176.1$33.8 million for the ninethree months ended September 30, 2018.March 31, 2019.
We originally budgeted $181.6The following table shows the 2019 capital expenditure budget of $168.2 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:line:
20182019
(dollars in thousands)  
Regulated Energy:  
Natural gas distribution$65,594
$64,143
Natural gas transmission110,813
66,787
Electric distribution8,930
5,949
Total Regulated Energy185,337
136,879
Unregulated Energy:  
Propane distribution13,359
11,870
Energy transmission8,345
Other unregulated energy7,413
1,416
Total Unregulated Energy20,772
21,631
Other:  
Corporate and other businesses10,289
9,705
Total Other10,289
9,705
Total 2018 Budgeted Capital Expenditures$216,398
Total 2019 Budgeted Capital Expenditures$168,215

The 2019 budget, excluding acquisitions, includes: Eastern Shore's 2017 Expansion Project and Del-Mar Energy Pathway Project, Florida's Palm Beach County Western Expansion and other potential pipeline projects, continued expenditures under Florida GRIP, further expansions of our natural gas distribution and transmission systems, continued natural gas infrastructure improvement activities, information technology systems, new buildings and facilities, and other strategic initiatives and investments.
The capital expenditure projection is subject to continuous review and modification. Actual capital requirements may vary from the above estimates due to a number of factors, including changing economic conditions, customer growth in existing areas, regulation, new growth or acquisition opportunities and availability of capital. Historically, actual capital expenditures have typically lagged behind the budgeted amounts.
The timing of capital expenditures can vary based on delays in regulatory approvals, securing environmental approvals and other permits. The regulatory application and approval process has lengthened in the past few years, and we expect this trend to continue.

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Capital Structure
We are committed to maintaining a sound capital structure and strong credit ratings to provide the financial flexibility needed to access capital markets when required. This commitment, along with adequate and timely rate relief for our regulated energy operations, is intended to ensure our ability to attract capital from outside sources at a reasonable cost. We believe that the achievement of these objectivescost, which will provide benefits tobenefit our customers, creditors, employees and investors.stockholders.
The following table presents our capitalization, excluding and including short-term borrowings, as of September 30, 2018March 31, 2019 and December 31, 2017:2018:

 September 30, 2018 December 31, 2017 March 31, 2019 December 31, 2018
(in thousands)                
Long-term debt, net of current maturities $241,597
 32% $197,395
 29% $285,998
 34% $316,020
 38%
Stockholders’ equity 508,298
 68% 486,294
 71% 543,659
 66% 518,439
 62%
Total capitalization, excluding short-term debt $749,895
 100% $683,689
 100% $829,657
 100% $834,459
 100%
                
 September 30, 2018 December 31, 2017 March 31, 2019 December 31, 2018
(in thousands)                
Short-term debt $268,293
 26% $250,969
 26% $276,393
 24% $294,458
 26%
Long-term debt, including current maturities 251,210
 24% 206,816
 22% 357,507
 30% 327,955
 29%
Stockholders’ equity 508,298
 50% 486,294
 52% 543,659
 46% 518,439
 45%
Total capitalization, including short-term debt $1,027,801
 100% $944,079
 100% $1,177,559
 100% $1,140,852
 100%
Included in the long-term debt balances at September 30, 2018March 31, 2019 and December 31, 2017, was2018, were finance lease obligations for Sandpiper and Sharp. Sandpiper entered into a capital lease obligation associated with Sandpiper's capacity, supply and operating agreement (at September 30, 2018, zero excluding current maturities and $1.0 million including current maturities and, at December 31, 2017, $620,000 excluding current maturities and $2.1 million including current maturities). At the closing of the ESG acquisition in May 2013, Sandpiper entered into this agreement, which has a six-year term endingexpires in May 2019. The capacity portion of this agreement is accounted for as a capitalfinance lease. At March 31, 2019 and December 31, 2018, the remaining balance of $249,000 and $620,000, respectively, was included in current maturities.
Sharp had previously entered into an agreement to rent property in Anne Arundel County, Maryland, which it subsequently acquired in April 2019 (at March 31, 2019, $660,000 of current maturities and at December 31, 2018, $690,000 of current maturities).
Our target ratio of equity to total capitalization, ratio, including short-term borrowings, is between 50 and 60 percent. From timeIncluding the funds expended specifically related to time, we may go below the lower endimpact of Hurricane Michael, our equity to total capitalization ratio, including short-term borrowings, was 46.0 percent as of March 31, 2019. Excluding the target range as we seekfunds expended for Hurricane Michael restoration activities, our equity to total capitalization ratio, including short-term borrowings, would have been approximately 49 percent. The Company seeks to align permanent financing with the in-service dates of its capital projects. The Company may utilize more temporary short-term debt when the financing cost is attractive as much as feasible, anya bridge to the permanent long-term financing.
Term Notes
In December 2018, we issued a $30.0 million unsecured term note through PNC Bank N.A. with maturity of January 21, 2020. The interest rate at March 31, 2019 and December 31, 2018 was 3.24% and 3.23%, respectively, which equals one month LIBOR rate plus 75 basis points. In January 2019, we issued a $30.0 million unsecured term note through Branch Banking and Trust Company, with maturity of February 28, 2020. The interest rate at March 31, 2019 was 3.24% which equals one month LIBOR rate plus 75 basis points. These term notes totaling $60.0 million are included in the current maturities of long-term debt or equity issuance(s) with the commencementas 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.March 31, 2019.
Shelf Agreements
In October 2015, weWe have entered into the $150.0 millionShelf Agreements with Prudential, Shelf Agreement, under which we may request that Prudential purchase up to $150.0 million of our unsecured senior debt. Prudential is under no obligation to purchase any unsecured senior debt. As of September 30, 2018, we have issued $70.0 million of 3.25% Prudential Shelf Notes. In September 2018, we amended the Prudential Shelf Agreement, pursuant to which we may request that Prudential purchase up to $150.0 million of our unsecured debt over a three year period which expires in August 2021. Following this amendment, in September 2018, Prudential accepted our request to purchase $100.0 million of Shelf Notes on or before August 20, 2019. The new Prudential Shelf Notes will bear interest at the rate of 3.98% and have a maturity date not to exceed 20 years from the date of issuance. The proceeds received from the issuance of these Prudential Shelf Notes will be used to reduce short-term borrowings under our Revolver, lines of credit and/or to fund capital expenditures.
In March 2017, we entered into the MetLife Shelf Agreement and the NYL Shelf Agreement, under which we may request that MetLife and NYL through March 2, 2020, purchase up to $150.0 million of Met Life Shelf Notes and $100.0 million NYL Shelf Notes, respectively. The unsecured senior debt would have a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance. MetLife and NYLwho 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 beshelf notes was used to reduce borrowings under the Revolver and/or lines of credit and/or to fund capital expenditures. We entered into the Prudential Shelf Agreement, totaling $150.0 million, in October 2015, and we issued $70.0 million of 3.25% unsecured debt in April 2017. The Prudential Shelf Agreement was then amended in September 2018 to increase the borrowing capacity back up to $150.0 million, and Prudential accepted our request to purchase our unsecured debt of $100.0 million at an interest rate of 3.98% on or before August 20, 2019. We entered into the NYL Shelf Agreement, totaling $100.0 million, in March 2017, and we issued unsecured debt totaling $100.0 million during 2018. The NYL Shelf Agreement has been fully utilized.
was amended in November 2018 to add incremental borrowing capacity of $50.0 million. As of September 30, 2018,March 31, 2019, we have $200.0 million of additional potential borrowing capacity (after excluding existing unfunded commitments)had not requested that MetLife purchase unsecured senior debt under the Prudential Shelf Agreement ($50.0 million) and MetLife Shelf Agreement, ($150.0 million).which we entered into in March 2017. The Prudentialfollowing table summarizes our shelf agreements borrowing information at March 31, 2019:
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  Total Borrowing Capacity Less: Amount of Debt Issued Less: Unfunded Commitments Remaining Borrowing Capacity
(in thousands)        
Shelf Agreement        
Prudential Shelf Agreement $220,000
 $(70,000) $(100,000) $50,000
MetLife Shelf Agreement 150,000
 —
 —
 150,000
NYL Shelf Agreement 150,000
 (100,000) —
 50,000
Total $520,000
 $(170,000) $(100,000) $250,000
The Shelf Agreement and the NYLAgreements or Shelf AgreementNotes set forth certain business covenants to which we are subject when any note is
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outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.
Short-term Borrowings
Our outstanding short-term borrowings at September 30, 2018March 31, 2019 and December 31, 20172018 were $268.3$276.4 million and $251.0$294.5 million at weighted average interest rates of 3.123.75 percent and 2.423.44 percent, respectively. Our current short-term borrowing limit, authorized by our Board of Directors, is $350.0$370.0 million.
We utilize bank lines of credit to provide funds for our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of the capital expenditure program. As of September 30, 2018,March 31, 2019, we had five unsecured bank credit facilities with four financial institutions totaling $220.0 million in available credit. In addition, we have a $150.0 million of additionalRevolver under which borrowings can be designated as short-term debt capacity available under the Revolver.debt. The terms of the Revolver are described in further detaildescribed below. None of the unsecured bank lines of credit requires compensating balances.
The $150.0 million Revolver is available through October 8, 2020 which was recently extended by two years and is subject to the terms and conditions set forth in the credit agreement among us and the lenders related to the Revolver ("Credit Agreement.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%0.25 percent 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'lenders' approval. We may also request the Lenderslenders to increase the Revolver to $200.0 million, with any increase at the sole discretion of each Lender.lender.
Cash Flows
The following table provides a summary of our operating, investing and financing cash flows for the ninethree months ended September 30, 2018March 31, 2019 and 2017:2018:
 
 Nine Months Ended Three Months Ended
 September 30, March 31,
 2018 2017 2019 2018
(in thousands)        
Net cash provided by (used in):        
Operating activities $127,996
 $98,372
 $40,486
 $66,672
Investing activities (171,167) (141,453) (43,369) (62,971)
Financing activities 43,772
 42,289
 4,769
 (3,319)
Net increase (decrease) in cash and cash equivalents 601
 (792)
Net increase in cash and cash equivalents 1,886
 382
Cash and cash equivalents—beginning of period 5,614
 4,178
 6,089
 5,614
Cash and cash equivalents—end of period $6,215
 $3,386
 $7,975
 $5,996


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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 ninethree months ended September 30,March 31, 2019 and 2018, and 2017, net cash provided by operating activities was $128.0$40.5 million and $98.4$66.7 million, respectively, resulting in an increasea decrease in cash flows of $29.6$26.2 million. Significant operating activities generating the cash flows change were as follows:
Net cash flows from changes in propane inventory, storage gas and other inventories increased by approximately $14.6 million due primarily to higher levels of our inventory during 2017.
Changes in net regulatory assets and liabilities increased cash flows by $3.0 million, due primarily to the change in fuel costs collected through the various cost recovery mechanisms.
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Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities decreased cash flows by $6.0$9.4 million, due primarily higher to the timing of theand receipt of customer payments from increased revenue as well as the timing of payments to vendors.payments.
Changes in net prepaid expensesregulatory assets and other current assets, customer deposits and refundsliabilities decreased cash flows by $1.8 million.$8.4 million, due primarily to the change in fuel costs collected through the various cost recovery mechanisms.
Net cash flows from changes in propane inventory, storage gas and other inventories decreased by approximately $5.2 million due primarily to lower levels of our inventory during 2018.
Net income, adjusted for reconciling activities, decreased cash flows by $1.1$5.4 million, primarily due to the absence of deferred tax assets pertaining to the availability and utilization of bonus depreciation during the first nine months 2018, offset by an increase in net income and higher non-cash adjustments for depreciation and amortization related to increased investing activities and adjustments for realized gains on investments.activities.
Cash Flows Used in Investing Activities
Net cash used in investing activities totaled $171.2$43.4 million and $141.5$63.0 million during the ninethree months ended September 30,March 31, 2019 and 2018, and 2017, respectively, resulting in a decreasean increase in cash flows of $29.7$19.6 million. Cash paid for capital expenditures including acquisitions increaseddecreased by $41.3$19.9 million to $171.4$43.2 million for the first ninethree months of 2018,2019, compared to $130.1$63.1 million for the same period in 2017.2018.
Cash Flows Provided by Financing Activities
Net cash provided by financing activities totaled $43.8$4.8 million during the ninethree months ended September 30, 2018March 31, 2019 compared to net cash of $42.3$3.3 million provided byused in financing activities during the prior year period resulting in an increase in cash flows of $1.5$8.1 million. The increase in net cash provided by financing activities resulted primarily from the following:
Increased cash flows of $5.0 million as a result of $30.0 million in proceeds from a term note issued in January 2019. During the three months ended March 31, 2018, we received $25.0 million in proceeds from the Revolver, which was advanced on a long-term basis.
Increased cash flows from lower repayments of short-term borrowing of $20.4$6.1 million under our line of credit arrangements;arrangements.
Receipt of $74.9 million in net cash proceeds from the Revolver and the issuance of the NYL Shelf Notes (Series A) in January and May 2018, respectively, which increased cash flow by $5.1 million during the nine months ended September 30, 2018, compared to the same period in 2017. For the nine months ended September 30, 2017, we received $69.8 million in net proceeds from the issuance of the Prudential Shelf Notes; and
IncreasedDecreased cash flows of $3.7$2.3 million as a result of changes in cash overdrafts; partially offset byoverdrafts and;
Higher repayment
Cash dividends of long-term debt of $25.0$5.9 million paid during the ninethree months ended September 30, 2018,March 31, 2019, compared to $5.1 million for the same period in 2017.three months ended March 31, 2018.
Off-Balance Sheet Arrangements
We have issued corporate guarantees to certain vendors of our subsidiaries primarily PESCO. These corporate guaranteesthat provide for the payment of propane and natural gas purchases in the event of the respective subsidiary’s default. These subsidiaries have never defaulted on their obligations to pay their suppliers. The liabilities for these purchases are recorded in our financial statements when incurred. The aggregate amount guaranteed at September 30, 2018March 31, 2019 was $73.9$77.3 million, with the guarantees expiring on various dates through September 2019.December 2020.
We have issued letters of credit totaling $5.0$7.0 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, the payment of natural gas purchases for PESCO, and to our current and previous primary insurance carriers. These letters of credit have varyingcarriers with expiration dates extending through December 2019.March 2020. There have beenwere no draws on these letters of credit as of September 30, 2018.March 31, 2019. We do not anticipate that the letters of credit will be drawn upon by the counterparties, and we expect that theythe letters of credit 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.





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Contractual Obligations
There has been no material change in the contractual obligations presented in our 20172018 Annual Report on Form 10-K, except for long-term debt and commodity purchase obligations entered into in the ordinary course of our business. The following table summarizes long-term debt and commodity purchase contract obligations at September 30, 2018:March 31, 2019:
 
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 Payments Due by Period Payments Due by Period
 Less than 1 year 1 - 3 years 3 - 5 years More than 5 years Total Less than 1 year 1 - 3 years 3 - 5 years More than 5 years Total
(in thousands)                    
Long-term debt(1)
 $8,626
 $31,200
 $38,700
 $172,200
 $250,726
 $70,600
 $29,200
 $45,700
 $211,700
 $357,200
Purchase obligations - Commodity (2)
 95,964
 22,335
 28
 —
 118,327
 112,947
 34,384
 13,483
 11,762
 172,576
Total $104,590
 $53,535
 $38,728
 $172,200
 $369,053
 $183,547
 $63,584
 $59,183
 $223,462
 $529,776
 
(1)
(1) Excludes finance lease obligation, debt issuance costs and an unamortized discount of $307,000.
(2) In addition to the obligations noted above, we have agreements with commodity suppliers that have provisions with no minimum purchase requirements. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts allow the suppliers to reduce the amounts available in the winter season if we do not purchase specified amounts during the summer season. Under these contracts, the commodity prices will fluctuate as market prices fluctuate.
Excludes capital lease obligation, debt issuance costs and an unamortized discount of $484,000.
(2)
In addition to the obligations noted above, we have agreements with commodity suppliers that have provisions with no minimum purchase requirements. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts allow the suppliers to reduce the amounts available in the winter season if we do not purchase specified amounts during the summer season. Under these contracts, the commodity prices will fluctuate as market prices fluctuate.
Rates and Regulatory Matters
Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by the respective state PSC; Eastern Shore is subject to regulation by the FERC; and Peninsula Pipeline is subject to regulation by the Florida PSC. At September 30, 2018,March 31, 2019, we were involved in regulatory matters in each of the jurisdictions in which we operate. Our significant regulatory matters are fully described in Note 4, Rates and Other Regulatory Activities, to the condensed consolidated financial statements in this Quarterly Report on Form 10-Q.
Recent Authoritative Pronouncements on Financial Reporting and Accounting
Recent accounting developments applicable to us and their impact on our financial position, results of operations and cash flows are described in Note 1, Summary of Accounting Policies, to the condensed consolidated financial statements in this Quarterly Report on Form 10-Q.
Item 3. Quantitative and Qualitative Disclosures about Market Risk
INTEREST RATE RISK
Long-term debt is subject to potential losses based on changes in interest rates. Our long-term debt at September 30, 2018,March 31, 2019, 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-gasOur propane operations are exposed to commodity price risk as a result of the competitive nature of retail pricing offered to our customers. In order to mitigate this risk, we utilize propane storage activities and forward contracts for supply.
We can store up to approximately 7.07 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.
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Aspire Energy is exposed to commodity price risk, primarily during the winter season, to the extent we are not successful in balancing our natural gas purchases and sales and have to secure natural gas from alternative sources at higher spot prices. In order to mitigate this risk, we procure firm capacity that meets our estimated volume requirements and we continue to seek out new producers in order to fulfill our natural gas purchase requirements.
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PESCO is a party to natural gas swap and futures contracts. These contracts, which provide PESCO withus 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 ofprocure natural gas forand deliver it to its customers.
PESCO is subject to commodity price risk on its open positions to the extent that market prices for natural gas liquids and natural gas deviate from fixed contract settlement prices. Market risk associated with the trading of futures and forward contracts is monitored daily for compliance with our Risk Management Policy, which includes volumetric limits for open positions. To manage exposures to changing market prices, open positions are marked up or down to market prices and reviewed daily by our oversight officials. In addition, the Risk Management Committee reviews periodic reports on markets, approves any exceptions to the Risk Management Policy (within limits established by the Board of Directors) and authorizes the use of any new types of contracts.
The following table reflects the changes in the fair market value of financial derivatives contracts related to natural gas and propane purchases and sales from December 31, 20172018 to September 30, 2018:March 31, 2019:
(in thousands)Balance at December 31, 2017 Increase (Decrease) in Fair Market Value Less Amounts Settled  Balance at September 30, 2018Balance at December 31, 2018 Increase (Decrease) in Fair Market Value Less Amounts Settled  Balance at March 31, 2019
PESCO$(6,153) $15,293
 $(8,954) $186
$(184) $3,807
 $(617) $3,006
Sharp1,192
 (1,237) 654
 609
(1,522) 354
 585
 (583)
Total$(4,961) $14,056
 $(8,300) $795
$(1,706) $4,161
 $(32) $2,423
There were no changes in methods of valuations during the ninethree months ended September 30, 2018.March 31, 2019.
The following is a summary of fair market value of financial derivatives as of September 30, 2018,March 31, 2019, by method of valuation and by maturity for each fiscal year period.
(in thousands)2018 2019 2020 2021 2022 Total Fair Value2019 2020 2021 2022 Total Fair Value
Price based on ICE - PESCO$482
 $(1,285) $1,027
 $(35) $(3) $186
$18
 $2,091
 $848
 $49
 $3,006
Price based on Mont Belvieu - Sharp117
 346
 132
 14
 —
 609
(386) (161) (36) —
 (583)
Total$599
 $(939) $1,159
 $(21) $(3) $795
$(368) $1,930
 $812
 $49
 $2,423
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.

INFLATION
Inflation affects the cost of supply, labor, products and services required for operations, maintenance and capital improvements. To help cope with the effects of inflation on our capital investments and returns, we periodically seek rate increases from regulatory commissions for our regulated operations and closely monitor the returns of our unregulated energy business operations. To compensate for fluctuations in propane gas prices, we adjust propane sales prices to the extent allowed by the market.

Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The Chief Executive Officer and Chief Financial Officer of Chesapeake Utilities, with the participation of other Company officials, have evaluated our “disclosure controls and procedures” (as such term is defined under Rules 13a-15(e) and 15d-15(e), promulgated under the Securities Exchange Act of 1934, as amended) as of September 30, 2018.March 31, 2019. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2018.March 31, 2019.
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Changes in Internal Control over Financial Reporting
Beginning January 1, 2018,2019, we adopted ASU 2014-09,2016-02, Revenue from Contracts with Customers. Leases. The impacts of the adoption are discussed in detail in Note 1, Summary of Accounting Policies, and Note 3, Revenue Recognition,15, Leases, 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 thatleases, which were not material to our internal controls over financial reporting. These included the development of new policies based onfor the five-step model provided in the new revenue standard, enhanced contract review requirements,identification of leases and other ongoing monitoring activities. These controls were designed to provide assurance, at a reasonable level, of the fair presentation of our condensed consolidated financial statements and related disclosures. During the quarter ended September 30, 2018,March 31, 2019, there
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was no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.

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PART II—OTHER INFORMATION
Item 1. Legal Proceedings
As disclosed in Note 6, Other Commitments and Contingencies, of the condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we are involved in certain legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental or regulatory agencies concerning rates and other regulatory actions. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on our condensed consolidated financial position, results of operations or cash flows.
 
Item 1A. Risk Factors
Our business, operations, and financial condition are subject to various risks and uncertainties. The risk factors described in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K, for the year ended December 31, 2017,2018, should be carefully considered, together with the other information contained or incorporated by reference in this Quarterly Report on Form 10-Q and in our other filings with the SEC in connection with evaluating Chesapeake Utilities, our business and the forward-looking statements contained in this Quarterly Report on Form 10-Q. Additional risks and uncertainties not known to us at present, or that we currently deem immaterial, also may affect Chesapeake Utilities. The occurrence of any of these known or unknown risks could have a material adverse impact on our business, financial condition and results of operations.
 
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds 
  
Total
Number of
Shares
 
Average
Price Paid
 
Total Number of Shares
Purchased as Part of
Publicly Announced Plans
 
Maximum Number of
Shares That May Yet Be
Purchased Under the Plans
Period Purchased per Share 
or Programs (2)
 
or Programs (2)
July 1, 2018
through July 31, 2018 (1)
 417
 $85.25
 —
 —
August 1, 2018
through August 31, 2018		 —
 $—
 —
 —
September 1, 2018
through September 30, 2018		 —
 $—
 —
 —
Total 417
 $85.25
 —
 —
  
Total
Number of
Shares
 
Average
Price Paid
 
Total Number of Shares
Purchased as Part of
Publicly Announced Plans
 
Maximum Number of
Shares That May Yet Be
Purchased Under the Plans
Period Purchased per Share 
or Programs (2)
 
or Programs (2)
January 1, 2019
through January 31, 2019 (1)
 388
 $81.65
 —
 —
February 1, 2019
through February 28, 2019		 —
 $—
 —
 —
March 1, 2019
through March 31, 2019		 —
 $—
 —
 —
Total 388
 $81.65
 —
 —
 
(1)
Chesapeake Utilities purchased shares of common stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain directors and senior executives under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Item 8 under the heading “Notes to the Consolidated Financial Statements—Note 16, Employee Benefit Plans” in our latest Annual Report on Form 10-K for the year ended December 31, 2017. During the quarter ended September 30, 2018, 417 shares were purchased through the reinvestment of dividends on deferred stock units.
(2)
Except for the purposes described in Footnote (1) Chesapeake Utilities purchased shares of common stock on the open market for the purpose of reinvesting the dividend on shares held in the Rabbi Trust accounts for certain directors and senior executives under the Non-Qualified Deferred Compensation Plan. The Non-Qualified Deferred Compensation Plan is discussed in detail in Item 8 under the heading “Notes to the Consolidated Financial Statements—Note 9, Employee Benefit Plans” in our latest Annual Report on Form 10-K for the year ended December 31, 2018. During the quarter ended March 31, 2019, 388 shares were purchased through the reinvestment of dividends on deferred stock units.
(2) Except for the purposes described in Footnote (1), Chesapeake Utilities has no publicly announced plans or programs to repurchase its shares.


Item 3. Defaults upon Senior Securities
None.
 
Item 5. Other Information

None.

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Item 6.Exhibits
 
   
4.1†10.1* Form of
Term Note Agreement dated September 14, 2018, amongissued by Chesapeake Utilities Corporation as issuer,in favor of Branch Banking and certain note holders relating to the private placement of Chesapeake Utilities Corporation’s 3.98% Senior Notes due 2039.Trust Company on January 31, 2019.
   
10.1†10.2* First Amendment to Private Shelf
Term Loan Credit Agreement, dated September 14, 2018,January 31, 2019, by and between Chesapeake Utilities Corporation and PGIM, Inc. formerly known as Prudential Investment Management, Inc.,Branch Banking and other purchasers that may become a party thereto.Trust Company.
   
31.1*  
Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
   
31.2*  
Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Rule 13a-14(a) under the Securities Exchange Act of 1934.
   
32.1*  
Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350.
   
32.2*  
Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350.
   
101.INS*  XBRL Instance Document.
  
101.SCH*  XBRL Taxonomy Extension Schema Document.
  
101.CAL*  XBRL Taxonomy Extension Calculation Linkbase Document.
  
101.DEF*  XBRL Taxonomy Extension Definition Linkbase Document.
  
101.LAB*  XBRL Taxonomy Extension Label Linkbase Document.
  
101.PRE*  XBRL Taxonomy Extension Presentation Linkbase Document.

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

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.
 
CHESAPEAKE UTILITIES CORPORATION
 
/S/ BETH W. COOPER
Beth W. Cooper
SeniorExecutive Vice President, and Chief Financial Officer, and Assistant Corporate Secretary
Date: November 9, 2018May 8, 2019


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