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

xFORM10-Q
☒QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended: September 30, 2017March 31, 2023
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)

Delaware51-0064146
(State or other jurisdiction

of incorporation or organization)
(I.R.S. Employer

Identification No.)
909 Silver Lake Boulevard,500 Energy Lane, Dover, Delaware 1990419901
(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 and posted on its corporate Web site, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files).  Yes  x☒    No  ¨☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company, or an emerging growth company. See definitions of “large accelerated filer,” “accelerated filer” andfiler,” “smaller reporting company”company,” and "emerging growth company" in Rule 12b-2 of the Exchange Act. (Check one):
Large accelerated filer☒Accelerated filer☐
Non-accelerated filer☐Smaller reporting company☐
Large accelerated filerxAccelerated filerEmerging growth company¨
Non-accelerated filer¨Smaller reporting 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$0.4867 — 16,344,44217,789,856 shares outstanding as of October 31, 2017.April 28, 2023.


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GLOSSARY OF DEFINITIONS

ARM: ARM Energy Management, LLC, aAdjusted Gross Margin: A non-GAAP measure calculated by deducting the purchased cost of natural gas, supplypropane and supply management company servicing commercialelectricity and industrial customersthe cost of labor spent on direct revenue-producing activities from operating revenues. The costs included in Western Pennsylvania, which soldAdjusted Gross Margin exclude depreciation and amortization and certain natural gas marketing assets to PESCOcosts presented in August 2017operations and maintenance expenses in accordance with regulatory requirements
ASC: Accounting Standards Codification
ASU: Accounting Standards Update
Aspire Energy: Aspire Energy of Ohio, LLC, a wholly-owned subsidiary of Chesapeake Utilities
Aspire Energy Express: Aspire Energy Express, LLC, a wholly-owned subsidiary of Chesapeake Utilities
ASU: Accounting Standards Update issued by the FASB
ATM: At-the-market
CARES Act: Coronavirus Aid, Relief, and Economic Security Act
CDC: U.S. Centers for Disease Control and Prevention
CDD: Cooling degree-day, which isDegree-Day
CFG: Central Florida Gas Company, a measuredivision 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 FahrenheitChesapeake Utilities
Chesapeake or Chesapeake Utilities: Chesapeake Utilities Corporation, and its directdivisions and indirect subsidiaries, as appropriate in the context of the disclosure
Chesapeake Pension Plan: A defined benefit pension plan sponsored by Chesapeake UtilitiesCHP: Combined Heat and Power Plant
Chesapeake Postretirement Plan: An unfunded postretirement health care and life insurance plan sponsored by Chesapeake Utilities
Chesapeake SERP: An unfunded supplemental executive retirement pension plan sponsored by Chesapeake Utilities
Chipola: Chipola Propane Gas Company, Inc., a propane distribution service provider in Northwest Florida, which sold certain assets to Flo-gas in August 2017
CIAC: Contributions from customers that are used to construct facilities
CGC: Consumer Gas Cooperative, an Ohio natural gas cooperative
CHP: 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 directdivisions and indirect subsidiaries, as appropriate in the context of the disclosure
CP: Certificate of Public Convenience and NecessityCOVID-19: An infectious disease caused by a coronavirus
Credit Agreement: The Credit Agreement dated October 8, 2015, among Chesapeake Utilities and the Lenders related to the RevolverCNG: Compressed natural gas
Deferred Compensation Plan: A non-qualified, deferred compensation arrangement under whichDavenport Energy: An entity from whom we acquired certain of our executives and members of the Board of Directors are able to defer payment of all or a part of certain specified types of compensation, including executive cash bonuses, executive performance shares, and directors’ retainerspropane operating assets in North Carolina.
Degree-Day: A degree-day is the measureDegree-day: 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 (CDD) or below (HDD) 65 degrees Fahrenheit
Delaware Division: Chesapeake Utilities' natural gas distribution operation serving customers in Delaware
Delmarva Peninsula: A peninsula on the east coast of the United States of AmericaU.S. occupied by Delaware and portions of Maryland and Virginia
DNREC: Delaware Department of Natural ResourcesDRIP: Dividend Reinvestment and Environmental ControlDirect Stock Purchase Plan
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

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Eight Flags: Eight Flags Energy, LLC, a wholly-owned subsidiary of Chesapeake OnSight Services, LLC, which owns and operates a CHP plant on Amelia Island, FloridaUtilities
EPA: United States Environmental Protection Agency
ESG: Eastern ShoreElkton Gas: Elkton Gas Company, a wholly-owned subsidiary of Chesapeake Utilities

ESG: Environmental, Social and its affiliatesGovernance

FASB: Financial Accounting Standards Board
FERC: Federal Energy Regulatory Commission an independent agency of the United States government that regulates the interstate transmission of electricity, natural gas, and oil
FDEP: Florida Department of Environmental Protection
FGT: Florida Gas Transmission Company
Flo-gas: Flo-gas Corporation, a wholly-owned subsidiaryFlorida OPC: The Office of FPUPublic Counsel, an agency established by the Florida legislature who advocates on behalf of Florida's utility consumers prior to actions or rule changes
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

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FPU Pension Plan: A separate defined benefit pension plan for FPU sponsored by Chesapeake Utilities
GAAP: Generally Accepted Accounting principles generally accepted inPrinciples
Gross Margin: a term under U.S. GAAP which is the United Statesexcess of Americasales over costs of goods sold
GRIP: TheGUARD: Gas Reliability Infrastructure Program,Utility Access and Replacement Directive a program to enhance the safety, reliability and accessibility of portions of the Company’s natural gas pipeline replacement programdistribution system in Florida pursuant to which we collect
Guernsey Power Station: Guernsey Power Station, LLC, a surcharge from certain of our customers to recover capital and other program-related costs associated with the replacement of qualifying distribution mains and servicespower generation facility in Guernsey County Ohio
Gulf Power: Gulf Power Company, an unaffiliated electric company that supplies electricity to FPU
Gulfstream: Gulfstream Natural Gas System, LLC, an unaffiliated pipeline network that supplies natural gas to FPU
HDD: Heating degree-day, which isDegree-Day
LNG: Liquefied Natural Gas
Marlin Gas Services: Marlin Gas Services, LLC, a measurewholly-owned subsidiary of the variation in weather based on the extent to which the daily average temperature (from 10:00 am to 10:00 am) is below 65 degrees Fahrenheit
JEA: The unaffiliated community-owned utility located in Jacksonville, Florida, formerly known as Jacksonville Electric Authority
Lenders: PNC, Bank of America N.A., Citizens Bank N.A., Royal Bank of Canada, and Wells Fargo Bank, National Association, which are collectively the lenders that entered into the Credit Agreement with Chesapeake Utilities
MDE: Maryland Department of Environment
MetLife: MetLife Investment Advisors, an institutional debt investment management firm, with which we entered intohave previously issued Senior Notes and which is a party to the current MetLife Shelf Agreement, as amended
MetLife Shelf Agreement: An agreement entered into by Chesapeake Utilities and MetLife in March 2017 pursuant to which Chesapeake Utilities may request that MetLife purchase, through March 2, 2020, up to $150.0 million of unsecured senior debt at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance
MGP: Manufactured gas plant, which is a site where coal was previously used to manufacture gaseous fuel for industrial, commercial and residential use
MWH: Megawatt hour, which isPeninsula Pipeline: Peninsula Pipeline Company, Inc., a unitwholly-owned subsidiary of measurement for electricityChesapeake Utilities
NYL: New York Life Investors LLC,Peoples Gas: Peoples Gas System, an Emera Incorporated subsidiary
Prudential: Prudential Investment Management Inc., an institutional debt investment management firm, with which weChesapeake Utilities entered into the NYLa previous Shelf Agreement and issued Shelf Notes
NYL PSC: Public Service Commission, which is the state agency that regulates utility rates and/or services in certain of our jurisdictions
Revolver: Our $400.0 million unsecured revolving credit facility with certain lenders
RNG: Renewable natural gas
Sandpiper Energy: Sandpiper Energy, Inc., a wholly-owned subsidiary of Chesapeake Utilities
SEC: 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
Shelf Agreement: An agreement entered into by Chesapeake Utilities and NYL in March 2017a counterparty pursuant to which Chesapeake Utilities may request that NYLthe counterparty purchase through March 2, 2020, up to $100.0 million ofour unsecured senior debt atwith a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance

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OPT ≤ 90 Service: Off Peak ≤ 90 Firm Transportation Service, a tariff associated with Eastern Shore's firm transportation service that enables Eastern Shore to forgo scheduling service for up to 90 days during the peak months of November through April each year
OTC: Over-the-counter
Peninsula Pipeline: Peninsula Pipeline Company, Inc., Chesapeake Utilities' wholly-owned Florida intrastate pipeline subsidiary
PESCO: Peninsula Energy Services Company, Inc., Chesapeake Utilities' wholly-owned natural gas marketing subsidiary
PNC: PNC Bank, National Association, the administrative agent and primary lender for our Revolver
Prudential: Prudential Investment Management Inc., an institutional investment management firm, with which we have entered into the Prudential Shelf Agreement
Prudential Shelf Agreement: An agreement entered into by Chesapeake Utilities and Prudential pursuant to which Chesapeake Utilities may request that Prudential purchase, through October 7, 2018, up to $150.0 million of Prudential Shelf Notes at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance
Prudential Shelf Notes:Unsecured senior promissory notes that we may request Prudential to purchaseissuable under the Prudential Shelf Agreement executed with various counterparties
PSC: Public Service Commission, which is the state agency that regulates the ratesSICP: 2013 Stock and services provided by Chesapeake Utilities’ natural gasIncentive Compensation Plan
SOFR: Secured Overnight Financing Rate, a secured interbank overnight interest rate established as an alternative to LIBOR
TCJA: Tax Cuts and electric distribution operations in Delaware, Maryland and Florida and Peninsula Pipeline in FloridaJobs Act enacted on December 22, 2017
RAP: Remedial Action Plan, which is a plan that outlines the procedures taken or being considered in removing contaminants from a MGP formerly owned by Chesapeake Utilities or FPUTETLP: Texas Eastern Transmission, LP, an interstate pipeline interconnected with Eastern Shore's pipeline
Retirement Savings Plan: Chesapeake Utilities' qualified 401(k) retirement savings plan
Revolver: Our unsecured revolving credit facility with the Lenders
Rights Plan: A plan designed to protect against abusive or coercive takeover attempts or tactics that are contrary to the best interests of Chesapeake Utilities' stockholders
Sandpiper: Sandpiper Energy, Inc., Chesapeake Utilities' wholly-owned subsidiary, which provides a tariff-based distribution service to customers in Worcester County, Maryland
Sanford Group: FPU and other responsible parties involved with the Sanford MGP site
SEC: Securities and Exchange Commission
Uncollateralized Senior Notes: Our unsecured long-term debt issued primarily to insurance companies on various dates
Sharp: Sharp Energy, Inc., Chesapeake Utilities' wholly-owned propane distribution subsidiaryU.S.: The United States of America
SICP: 2013 Stock and Incentive Compensation Plan

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,
 2017 2016 2017 2016 20232022
(in thousands, except shares and per share data)         (in thousands, except shares and per share data)  
Operating Revenues         Operating Revenues
Regulated Energy $69,703
 $70,019
 $238,353
 $226,630
 Regulated Energy$142,270 $127,891 
Unregulated Energy and other 57,233
 38,329
 198,827
 130,356
 Unregulated Energy and other75,859 94,989 
Total Operating Revenues 126,936
 108,348
 437,180
 356,986
 Total Operating Revenues218,129 222,880 
Operating Expenses         Operating Expenses
Regulated Energy cost of sales 22,794
 24,644
 87,206
 81,184
 
Unregulated Energy and other cost of sales 44,066
 28,183
 145,325
 85,142
 
Natural gas and electric costsNatural gas and electric costs55,288 45,442 
Propane and natural gas costsPropane and natural gas costs33,301 51,739 
Operations 29,667
 30,126
 92,990
 85,370
 Operations44,767 42,793 
Maintenance 2,737
 3,542
 9,370
 8,925
 Maintenance5,104 4,264 
Gain from a settlement —
 —
 (130) (130) 
Depreciation and amortization 9,362
 8,209
 27,267
 23,493
 Depreciation and amortization17,183 16,977 
Other taxes 4,071
 3,488
 12,572
 10,725
 Other taxes7,571 6,800 
Total Operating Expenses 112,697
 98,192
 374,600
 294,709
 Total Operating Expenses163,214 168,015 
Operating Income 14,239
 10,156
 62,580
 62,277
 Operating Income54,915 54,865 
Other income (expense), net 239
 (28) (643) (68) 
Other income, netOther income, net276 913 
Interest charges 3,321
 2,722
 9,133
 7,996
 Interest charges7,232 5,339 
Income Before Income Taxes 11,157
 7,406
 52,804

54,213
 Income Before Income Taxes47,959 50,439 
Income taxes 4,324
 2,990
 20,781
 21,401
 
Income TaxesIncome Taxes11,615 13,506 
Net Income $6,833
 $4,416
 $32,023

$32,812
 Net Income$36,344 $36,933 
Weighted Average Common Shares Outstanding:         Weighted Average Common Shares Outstanding:
Basic 16,344,442
 15,372,413
 16,334,210
 15,324,932
 Basic17,759,896 17,678,060 
Diluted 16,389,635
 15,412,783
 16,378,633
 15,365,955
 Diluted17,831,772 17,761,119 
Earnings Per Share of Common Stock:         Earnings Per Share of Common Stock:
Basic $0.42
 $0.29
 $1.96
 $2.14
 Basic$2.05 $2.09 
Diluted $0.42
 $0.29
 $1.96
 $2.14
 Diluted$2.04 $2.08 
Cash Dividends Declared Per Share of Common Stock $0.3250
 $0.3050
 $0.9550
 $0.8975
 
The accompanying notes are an integral part of these condensed consolidated financial statements.





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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Comprehensive Income (Unaudited)
 
 Three Months Ended Nine Months EndedThree Months Ended
 September 30, September 30,March 31,
 2017 2016 2017 201620232022
(in thousands)        (in thousands)
Net Income $6,833
 $4,416
 $32,023
 $32,812
Net Income$36,344 $36,933 
Other Comprehensive (Loss) Income, net of tax:        
Other Comprehensive Income (Loss), net of tax:Other Comprehensive Income (Loss), net of tax:
Employee Benefits, net of tax:        Employee Benefits, net of tax:
Amortization of prior service cost, net of tax of $(8), $(8), $(23) and $(23), respectively (11) (12) (35) (37)
Net gain, net of tax of $69, $66, $212 and $200, respectively 102
 100
 297
 300
Reclassifications of amortization of prior service credit and actuarial loss, net of tax of $3 and $6, respectivelyReclassifications of amortization of prior service credit and actuarial loss, net of tax of $3 and $6, respectively10 18 
Cash Flow Hedges, net of tax:        Cash Flow Hedges, net of tax:
Unrealized (loss)/gain on commodity contract cash flow hedges, net of tax of $(15), $38, $(376) and $360, respectively (104) 51
 (643) 548
Total Other Comprehensive (Loss) Income (13) 139
 (381) 811
Net gain on commodity contract cash flow hedges, net of tax of $7 and $937, respectivelyNet gain on commodity contract cash flow hedges, net of tax of $7 and $937, respectively22 2,498 
Reclassifications of net (gain) on commodity contract cash flow hedges, net of tax $(166) and $(752), respectivelyReclassifications of net (gain) on commodity contract cash flow hedges, net of tax $(166) and $(752), respectively(440)(1,969)
Net (loss) on interest rate swap cash flow hedges, net of tax of $(52) and $0, respectivelyNet (loss) on interest rate swap cash flow hedges, net of tax of $(52) and $0, respectively(148)— 
Reclassifications of net (gain) on interest rate swap cash flow hedges, net of tax of $(17) and $0, respectivelyReclassifications of net (gain) on interest rate swap cash flow hedges, net of tax of $(17) and $0, respectively(48)— 
Total Other Comprehensive Income (Loss), net of taxTotal Other Comprehensive Income (Loss), net of tax(604)547 
Comprehensive Income $6,820
 $4,555
 $31,642
 $33,623
Comprehensive Income$35,740 $37,480 
The accompanying notes are an integral part of these condensed consolidated financial statements.



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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Assets September 30,
2017		 December 31,
2016		AssetsMarch 31,
2023		December 31,
2022
(in thousands, except shares and per share data)    (in thousands, except shares and per share data)  
Property, Plant and Equipment    Property, Plant and Equipment
Regulated Energy $1,050,332
 $957,681
Regulated Energy$1,835,261 $1,802,999 
Unregulated Energy 207,331
 196,800
Unregulated Energy395,052 393,215 
Other businesses and eliminations 26,061
 21,114
Other businesses and eliminations29,695 29,890 
Total property, plant and equipment 1,283,724
 1,175,595
Total property, plant and equipment2,260,008 2,226,104 
Less: Accumulated depreciation and amortization (267,138) (245,207)Less: Accumulated depreciation and amortization(476,407)(462,926)
Plus: Construction work in progress 69,053
 56,276
Plus: Construction work in progress53,094 47,295 
Net property, plant and equipment 1,085,639
 986,664
Net property, plant and equipment1,836,695 1,810,473 
Current Assets    Current Assets
Cash and cash equivalents 3,386
 4,178
Cash and cash equivalents3,065 6,204 
Accounts receivable (less allowance for uncollectible accounts of $912 and $909, respectively) 52,775
 62,803
Trade and other receivablesTrade and other receivables65,130 65,758 
Less: Allowance for credit lossesLess: Allowance for credit losses(2,820)(2,877)
Trade and other receivables, netTrade and other receivables, net62,310 62,881 
Accrued revenue 14,307
 16,986
Accrued revenue24,135 29,206 
Propane inventory, at average cost 5,226
 6,457
Propane inventory, at average cost8,505 9,365 
Other inventory, at average cost 12,711
 4,576
Other inventory, at average cost17,520 16,896 
Regulatory assets 9,761
 7,694
Regulatory assets27,874 41,439 
Storage gas prepayments 6,876
 5,484
Storage gas prepayments1,228 6,364 
Income taxes receivable 26,741
 22,888
Income taxes receivable— 2,541 
Prepaid expenses 10,899
 6,792
Prepaid expenses12,990 15,865 
Derivative assets, at fair value 1,526
 823
Derivative assets, at fair value1,248 2,787 
Other current assets 4,797
 2,470
Other current assets629 428 
Total current assets 149,005
 141,151
Total current assets159,504 193,976 
Deferred Charges and Other Assets    Deferred Charges and Other Assets
Goodwill 21,944
 15,070
Goodwill46,213 46,213 
Other intangible assets, net 4,608
 1,843
Other intangible assets, net17,412 17,859 
Investments, at fair value 6,380
 4,902
Investments, at fair value10,866 10,576 
Derivative assets, at fair valueDerivative assets, at fair value898 982 
Operating lease right-of-use assetsOperating lease right-of-use assets14,272 14,421 
Regulatory assets 75,793
 76,803
Regulatory assets99,379 108,214 
Receivables and other deferred charges 3,381
 2,786
Receivables and other deferred charges12,312 12,323 
Total deferred charges and other assets 112,106
 101,404
Total deferred charges and other assets201,352 210,588 
Total Assets $1,346,750
 $1,229,219
Total Assets$2,197,551 $2,215,037 
 
The accompanying notes are an integral part of these condensed consolidated financial statements.

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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Balance Sheets (Unaudited)
 
Capitalization and Liabilities September 30,
2017		 December 31,
2016		Capitalization and LiabilitiesMarch 31,
2023		December 31,
2022
(in thousands, except shares and per share data)    (in thousands, except shares and per share data)  
Capitalization    Capitalization
Stockholders’ equity    Stockholders’ equity
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding $—
 $—
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding$— $— 
Common stock, par value $0.4867 per share (authorized 25,000,000 shares) 7,955
 7,935
Common stock, par value $0.4867 per share (authorized 50,000,000 shares)Common stock, par value $0.4867 per share (authorized 50,000,000 shares)8,659 8,635 
Additional paid-in capital 252,722
 250,967
Additional paid-in capital379,703 380,036 
Retained earnings 208,402
 192,062
Retained earnings472,209 445,509 
Accumulated other comprehensive loss (5,259) (4,878)
Accumulated other comprehensive income (loss)Accumulated other comprehensive income (loss)(1,983)(1,379)
Deferred compensation obligation 3,366
 2,416
Deferred compensation obligation8,816 7,060 
Treasury stock (3,366) (2,416)Treasury stock(8,816)(7,060)
Total stockholders’ equity 463,820
 446,086
Total stockholders’ equity858,588 832,801 
Long-term debt, net of current maturities 201,248
 136,954
Long-term debt, net of current maturities656,284 578,388 
Total capitalization 665,068
 583,040
Total capitalization1,514,872 1,411,189 
Current Liabilities    Current Liabilities
Current portion of long-term debt 12,136
 12,099
Current portion of long-term debt21,489 21,483 
Short-term borrowing 203,098
 209,871
Short-term borrowing94,079 202,157 
Accounts payable 53,284
 56,935
Accounts payable38,193 61,496 
Customer deposits and refunds 32,493
 29,238
Customer deposits and refunds36,676 37,152 
Accrued interest 3,361
 1,312
Accrued interest4,849 3,349 
Dividends payable 5,312
 4,973
Dividends payable9,518 9,492 
Accrued compensation 8,544
 10,496
Accrued compensation6,350 14,660 
Regulatory liabilities 5,338
 1,291
Regulatory liabilities10,556 5,031 
Income taxes payableIncome taxes payable7,554 — 
Derivative liabilities, at fair value 1,732
 773
Derivative liabilities, at fair value798 585 
Other accrued liabilities 13,972
 7,063
Other accrued liabilities16,717 13,618 
Total current liabilities 339,270
 334,051
Total current liabilities246,779 369,023 
Deferred Credits and Other Liabilities    Deferred Credits and Other Liabilities
Deferred income taxes 252,273
 222,894
Deferred income taxes258,399 256,167 
Regulatory liabilities 42,915
 43,064
Regulatory liabilities143,642 142,989 
Environmental liabilities 8,382
 8,592
Environmental liabilities2,530 3,272 
Other pension and benefit costs 32,059
 32,828
Other pension and benefit costs17,190 16,965 
Derivative liabilities, at fair valueDerivative liabilities, at fair value636 1,630 
Operating lease - liabilitiesOperating lease - liabilities12,110 12,392 
Deferred investment tax credits and other liabilities 6,783
 4,750
Deferred investment tax credits and other liabilities1,393 1,410 
Total deferred credits and other liabilities 342,412
 312,128
Total deferred credits and other liabilities435,900 434,825 
Environmental and other commitments and contingencies (Note 4 and 5) 
 
Environmental and other commitments and contingencies (Notes 6 and 7)Environmental and other commitments and contingencies (Notes 6 and 7)
Total Capitalization and Liabilities $1,346,750
 $1,229,219
Total Capitalization and Liabilities$2,197,551 $2,215,037 
The accompanying notes are an integral part of these condensed consolidated financial statements.



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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Cash Flows (Unaudited)
 Nine Months EndedThree Months Ended
 September 30,March 31,
 2017 201620232022
(in thousands)    (in thousands)  
Operating Activities    Operating Activities
Net income $32,023
 $32,812
Net income$36,344 $36,933 
Adjustments to reconcile net income to net cash provided by operating activities:    Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization 27,267
 23,493
Depreciation and amortization17,183 16,977 
Depreciation and accretion included in other costs 5,989
 5,357
Depreciation and accretion included in other costs2,834 2,744 
Deferred income taxes 29,520
 12,004
Deferred income taxes2,453 7,398 
Realized gain on commodity contracts/sale of assets/investments (2,817) (405)
Unrealized gain on investments/commodity contracts (695) (243)
Realized gain on commodity contracts and sale of assetsRealized gain on commodity contracts and sale of assets(284)(4,274)
Unrealized loss (gain) on investments/commodity contractsUnrealized loss (gain) on investments/commodity contracts(551)541 
Employee benefits and compensation 1,212
 1,217
Employee benefits and compensation119 (260)
Share-based compensation 1,608
 1,887
Share-based compensation2,408 2,213 
Other, net (39) 42
Changes in assets and liabilities:    Changes in assets and liabilities:
Accounts receivable and accrued revenue 12,912
 (3,835)Accounts receivable and accrued revenue5,641 7,532 
Propane inventory, storage gas and other inventory (8,256) (2,179)Propane inventory, storage gas and other inventory5,373 4,031 
Regulatory assets/liabilities, net 927
 (3,326)Regulatory assets/liabilities, net24,607 5,774 
Prepaid expenses and other current assets (2,860) 485
Prepaid expenses and other current assets3,985 6,626 
Accounts payable and other accrued liabilities 4,515
 7,187
Accounts payable and other accrued liabilities(21,166)(12,918)
Income taxes (payable) receivable (3,810) 14,897
Income taxes receivable/payableIncome taxes receivable/payable10,095 6,134 
Customer deposits and refunds 3,255
 (314)Customer deposits and refunds(476)(3,114)
Accrued compensation (2,030) (2,293)Accrued compensation(8,436)(6,392)
Other assets and liabilities, net (349) (1,053)Other assets and liabilities, net1,538 (825)
Net cash provided by operating activities 98,372
 85,733
Net cash provided by operating activities81,667 69,120 
Investing Activities    Investing Activities
Property, plant and equipment expenditures (130,137) (109,589)Property, plant and equipment expenditures(42,418)(29,887)
Proceeds from sales of assets 601
 119
Acquisitions, net of cash acquired (11,707) —
Proceeds from sale of assetsProceeds from sale of assets506 219 
Environmental expenditures (210) (260)Environmental expenditures(742)(267)
Net cash used in investing activities (141,453) (109,730)Net cash used in investing activities(42,654)(29,935)
Financing Activities    Financing Activities
Common stock dividends (14,780) (12,964)Common stock dividends(9,492)(8,274)
Issuance of stock for Dividend Reinvestment Plan 254
 600
Stock issuance (10) 57,306
Issuance of stock under the Dividend Reinvestment Plan, net of offering feesIssuance of stock under the Dividend Reinvestment Plan, net of offering fees— 3,242 
Tax withholding payments related to net settled stock compensation (692) (770)Tax withholding payments related to net settled stock compensation(2,455)(2,838)
Change in cash overdrafts due to outstanding checks (3,013) 2,466
Change in cash overdrafts due to outstanding checks(323)1,223 
Net repayment under line of credit agreements (3,760) (21,379)
Proceeds from issuance of long-term debt 69,800
 —
Repayment of long-term debt and capital lease obligation (5,510) (2,581)
Net cash provided by financing activities 42,289
 22,678
Net Decrease in Cash and Cash Equivalents (792) (1,319)
Net repayments under line of credit agreementsNet repayments under line of credit agreements(107,755)(82,008)
Proceeds from long-term debt, net of offering feesProceeds from long-term debt, net of offering fees79,840 49,915 
Repayment of long-term debtRepayment of long-term debt(1,967)(213)
Net cash used in financing activitiesNet cash used in financing activities(42,152)(38,953)
Net Increase (Decrease) in Cash and Cash EquivalentsNet Increase (Decrease) in Cash and Cash Equivalents(3,139)232 
Cash and Cash Equivalents—Beginning of Period 4,178
 2,855
Cash and Cash Equivalents—Beginning of Period6,204 4,976 
Cash and Cash Equivalents—End of Period $3,386
 $1,536
Cash and Cash Equivalents—End of Period$3,065 $5,208 
The accompanying notes are an integral part of these condensed consolidated financial statements.

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Chesapeake Utilities Corporation and Subsidiaries
Condensed Consolidated Statements of Stockholders’ Equity (Unaudited)
 
 
Common Stock (1)
            
(in thousands, except shares and per share data)
Number  of
Shares(2)
 
Par
Value
 
Additional  Paid-In
Capital
 
Retained
Earnings
 
Accumulated  Other Comprehensive
Loss
 
Deferred
Compensation
 
Treasury
Stock
 
Total (2)
Balance at December 31, 201515,270,659
 $7,432
 $190,311
 $166,235
 $(5,840) $1,883
 $(1,883) $358,138
Net income—
 —
 —
 44,675
 —
 —
 —
 44,675
Other comprehensive income—
 —
 —
 —
 962
 —
 —
 962
Dividend declared ($1.2025 per share)—
 —
 —
 (18,848) —
 —
 —
 (18,848)
Retirement savings plan and dividend reinvestment plan36,253
 17
 2,225
 —
 —
 —
 —
 2,242
Stock issuance (3)
960,488
 467
 56,893
 —
 —
 —
 —
 57,360
Share-based compensation and tax benefit (4) (5)
36,099
 19
 1,538
 —
 —
 —
 —
 1,557
Treasury stock activities—
 —
 —
 —
 —
 533
 (533) —
Balance at December 31, 201616,303,499
 7,935
 250,967
 192,062
 (4,878) 2,416
 (2,416) 446,086
Net income—
 —
 —
 32,023
 —
 —
 —
 32,023
Other comprehensive loss—
 —
 —
 —
 (381) —
 —
 (381)
Dividend declared ($0.9550 per share)—
 —
 —
 (15,683) —
 —
 —
 (15,683)
Dividend reinvestment plan10,771
 5
 731
 —
 —
 —
 —
 736
Stock issuance—
 —
 (10) —
 —
 —
 —
 (10)
Share-based compensation and tax benefit (4) (5)
30,172
 15
 1,034
 —
 —
 —
 —
 1,049
Treasury stock activities—
 —
 —
 —
 —
 950
 (950) —
Balance at September 30, 201716,344,442
 $7,955
 $252,722
 $208,402
 $(5,259) $3,366
 $(3,366) $463,820
 
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
Income (Loss)		Deferred
Compensation		Treasury
Stock		Total
Balance at December 31, 202117,655,410 $8,593 $371,162 $393,072 $1,303 $7,240 $(7,240)$774,130 
Net income— — — 36,933 — — — 36,933 
Other comprehensive income— — — — 547 — — 547 
Dividends declared ($0.480 per share)— — — (8,661)— — — (8,661)
Issuance under various plans (5)
24,960 12 3,410 — — — — 3,422 
Share-based compensation and tax benefit (3) (4)
39,018 19 (878)— — — — (859)
Treasury stock activities— — — — — (763)763 — 
Balance at March 31, 202217,719,388 $8,624 $373,694 $421,344 $1,850 $6,477 $(6,477)$805,512 
Balance at December 31, 202217,741,418 $8,635 $380,036 $445,509 $(1,379)$7,060 $(7,060)$832,801 
Net income— — — 36,344 — — — 36,344 
Other comprehensive loss— — — — (604)— — (604)
Dividends declared ($0.535 per share)— — — (9,644)— — — (9,644)
Issuance under various plans (5)
— — (11)— — — — (11)
Share-based compensation and tax benefit (3) (4)
48,438 24 (322)— — — — (298)
Treasury stock activities— — — — — 1,756 (1,756)— 
Balance at March 31, 202317,789,856 $8,659 $379,703 $472,209 $(1,983)$8,816 $(8,816)$858,588 
 

(1)2,000,000 shares of preferred stock at $0.01 par value have been authorized. No shares have been issued or are outstanding; accordingly, no information has been included in the statements of stockholders’ equity.    
(1)
2,000,000 shares of preferred stock at $0.01 par value have been authorized. None has been issued or is outstanding; accordingly, no information has been included in the statements of stockholders’ equity.
(2)
Includes 90,588 and 76,745 shares at September 30, 2017 and December 31, 2016, respectively, held in a Rabbi Trust related to our Deferred Compensation Plan.
(3)
On September 22, 2016, we completed a public offering of 960,488 shares of our common stock at a price per share of $62.26. The net proceeds from the sale of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million.
(4)
Includes amounts for shares issued for Directors’ compensation.
(5)
The shares issued under the SICP are net of shares withheld for employee taxes. For the nine months ended September 30, 2017, and for the year ended December 31, 2016, we withheld 10,269 and 12,031 shares, respectively, for taxes.

(2)Includes 109,687, 108,143, 107,518, and 116,238 shares at March 31, 2023, December 31, 2022, March 31, 2022 and December 31, 2021, 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 three months ended March 31, 2023 and 2022, we withheld 19,859 and 21,832 shares, respectively, for employee taxes.
(5)Can include shares issued under the Retirement Savings Plan, DRIP and ATM equity issuances.

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


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NOTESTO CONDENSED CONSOLIDATED FINANCIAL STATEMENTS (UNAUDITED)NAUDITED)

1.    Summary of Accounting Policies

Basis of Presentation

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

The accompanying unaudited condensed consolidated financial statements have been prepared in compliance with the rules and regulations of the SEC and GAAP. In accordance with these rules and regulations, certain information and disclosures normally required for audited financial statements have been condensed or omitted. These financial statements should be read in conjunction with the consolidated financial statements and notes thereto, included in our latest Annual Report on Form 10-K for the year ended December 31, 2016.2022. In the opinion of management, these financial statements reflect normal recurringall adjustments that are necessary for a fair presentation of our results of operations, financial position and cash flows for the interim periods presented.

Where necessary to improve comparability, prior period amounts have been changed to conform to current period presentation.

Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is highest due to colder temperatures.
We reclassified certain amounts in the condensed consolidated statement of cash flows for the nine months ended September 30, 2016
FASB Statements and Other Authoritative Pronouncements

Recent Accounting Standards
There are no pending or recently effective accounting standards which have had, or are expected to conformhave, a material impact to the current year’s presentation. These reclassifications are considered immaterial to the overall presentation of our condensed consolidated financial statements.statements or disclosures.

2.    Calculation of Earnings Per Share
Three Months Ended
March 31,
20232022
(in thousands, except shares and per share data)  
Calculation of Basic Earnings Per Share:
Net Income$36,344 $36,933 
Weighted average shares outstanding17,759,896 17,678,060 
Basic Earnings Per Share$2.05 $2.09 
Calculation of Diluted Earnings Per Share:
Net Income$36,344 $36,933 
Reconciliation of Denominator:
Weighted shares outstanding—Basic17,759,896 17,678,060 
Effect of dilutive securities—Share-based compensation71,876 83,059 
Adjusted denominator—Diluted17,831,772 17,761,119 
Diluted Earnings Per Share$2.04 $2.08 

3.     Acquisitions

Acquisition of Davenport Energy
In August 2017, PESCOJune 2022, Sharp acquired certain natural gas marketing assets of ARM. We have accounted for the purchase of these assets as a business combination. The acquired assets complement PESCO’s current asset portfolio and will expand our regional footprint and retail demand in a market where we have existing pipeline capacity and wholesale liquidity. In connection with the acquisition, we recorded a contingent liability of $2.5 million, which represents the expected payment of contingent consideration to ARM. The payment, which is expected to be paid in 2019, is contingent upon the achievement of certain gross margin targets during the 2018 calendar year. The recorded liability is based upon our most recent gross margin projections for the acquired business and is subject to change based on actual performance or changes in our gross margin projections.

In August 2017, Flo-gas acquired certainpropane operating assets of Chipola,Davenport Energy's Siler City, North Carolina propane division for approximately $2.0 million. Through this acquisition, we expanded our operating footprint further into North Carolina, where customers are served by Sharp Energy’s Diversified Energy division. Sharp added

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approximately 850 customers, along with distribution of approximately 0.4 million gallons of propane annually. We recorded $1.5 million in property plant and equipment, $0.5 million in goodwill, and immaterial amounts associated with customer relationships and non-compete agreements, all of which provides propane distribution service to approximately 800 residential and commercial customers in Jackson, Calhoun, Gadsden, Liberty, Bay and Washington Counties, Florida.
The revenue and netare deductible for income from these acquisitions that we included in our condensed consolidated statements of income for the three and nine months ended September 30, 2017, were not material.tax purposes. The amounts recorded in conjunction with our acquisitionsthe acquisition are preliminary, and subject to adjustment based on additional valuations performed duringcontractual provisions and finalization prior to the measurement period.

FASB Statements and Other Authoritative Pronouncements
Recently Adopted Accounting Standards
Inventory (ASC 330) - In July 2015,first anniversary of the FASB issued ASU 2015-11, Simplifying the Measurement of Inventory. Under this guidance, inventories are required to be measured at the lower of cost or net realizable value. Net realizable value represents the estimated selling price less coststransaction closing. The financial results associated with completion, disposal and transportation.this acquisition are included within our propane distribution operations within our Unregulated Energy segment.

Acquisition of Planet Found Energy Development
In October 2022, we acquired Planet Found Energy Development, LLC ("Planet Found") for $9.5 million. In connection with this acquisition, we recorded a $0.9 million liability which is subject to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. We adopted ASU 2015-11 on January 1, 2017, onaccounted for this acquisition as a prospective basis. Adoption of this standard did not have a material impact onbusiness combination within our financial position or results of operations.
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Recent Accounting Standards Yet to be Adopted
Revenue from Contracts with Customers (ASC 606) - In May 2014, the FASB issued ASU 2014-09, Revenue from Contracts with Customers. This standard provides a single comprehensive revenue recognition model for all contracts with customers to improve comparability within industries, as well as across industries and capital markets. The standard contains principles that entities will apply to determine the measurement of revenue and when it is recognized. The underlying principle is that an entity will recognize revenue to depict the transfer of goods or services to customers at an amount that the entity expects to be entitled toUnregulated Energy segment beginning in exchange for those goods or services. The guidance also requires a number of disclosures regarding the nature, amount, timing, and uncertainty of revenue and the related cash flows. In March 2016, FASB issued ASU 2016-08, Principal versus Agent Considerations (Reporting Revenue Gross versus Net), to clarify the implementation guidance on principal versus agent considerations. For public entities, this standard is effective for interim and annual financial statements issued beginning January 1, 2018.
We have completed our evaluation of our revenue sources and will continue assessing the impact on our financial position, results of operations and cash flows during the fourth quarter of 2017. 2022. Planet Found's farm scale anaerobic digestion pilot system and technology produces biogas from 1,200 tons of poultry litter annually, which can be used to create renewable energy in the form of electricity or upgraded to renewable natural gas. The transaction will accelerate our efforts in converting poultry waste to renewable, sustainable energy while simultaneously improving the local environments in our service territories. The operating revenues and operating income of Planet Found were not material to our consolidated results for the three months ended March 31, 2023.

In tandem,connection with this acquisition, we have developedrecorded $4.4 million in intangible assets associated primarily with intellectual property and documented accounting policiesnon-compete agreements, $4.0 million in property plant and position papers,equipment, $1.1 million in goodwill, and less than $0.1 million in working capital, all of which are intended to meet the requirements of this new revenue recognition standard. We have also completed our plan to update our internal controls. In the third quarter of 2017, we began providing additional training to our employees and implementing system and process changes that are associateddeductible for income tax purposes. The amounts recorded in conjunction with the adoptionacquisition are preliminary, and subject to adjustment based on contractual provisions and finalization prior to the first anniversary of the standard. transaction closing.



4.     Revenue Recognition
We planrecognize 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 utilizecustomers. We exclude sales taxes and other similar taxes from the modified retrospective transition method upon adoptiontransaction price. Typically, our customers pay for the goods and/or services we provide in the month following the satisfaction of this standard.our performance obligation. The following table displays our revenue by major source based on product and service type for the three months ended March 31, 2023 and 2022:
Based

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Three Months Ended March 31, 2023Three Months Ended March 31, 2022
(in thousands)Regulated EnergyUnregulated EnergyOther and EliminationsTotalRegulated EnergyUnregulated EnergyOther and EliminationsTotal
Energy distribution
Delaware natural gas division$36,907 $— $— $36,907 $34,481 $— $— $34,481 
Florida natural gas distribution (1)
46,358 — — 46,358 40,286 — — 40,286 
FPU electric distribution22,737 — — 22,737 19,089 — — 19,089 
Maryland natural gas division12,263 — — 12,263 10,464 — — 10,464 
Sandpiper natural gas/propane operations7,082 — — 7,082 7,636 — — 7,636 
Elkton Gas4,141 — — 4,141 3,366 — — 3,366 
Total energy distribution129,488 — — 129,488 115,322 — — 115,322 
Energy transmission
Aspire Energy— 13,954 — 13,954 — 18,036 — 18,036 
Aspire Energy Express364 — — 364 263 — — 263 
Eastern Shore20,670 — — 20,670 20,321 — — 20,321 
Peninsula Pipeline6,911 — — 6,911 6,772 — — 6,772 
Total energy transmission27,945 13,954 — 41,899 27,356 18,036 — 45,392 
Energy generation
Eight Flags— 5,300 — 5,300 — 5,539 — 5,539 
Propane operations
Propane delivery operations— 59,980 — 59,980 — 75,606 — 75,606 
Compressed Natural Gas Services
Marlin Gas Services— 4,001 — 4,001 — 2,209 — 2,209 
Other and eliminations
Eliminations(15,163)(69)(7,352)(22,584)(14,787)(98)(6,435)(21,320)
Other— — 45 45 — — 132 132 
Total other and eliminations(15,163)(69)(7,307)(22,539)(14,787)(98)(6,303)(21,188)
Total operating revenues (2)
$142,270 $83,166 $(7,307)$218,129 $127,891 $101,292 $(6,303)$222,880 
(1) In accordance with the Florida PSC approval of our natural gas base rate proceeding, effective March 1, 2023, our natural gas distribution businesses in Florida (FPU, FPU-Indiantown division, FPU-Fort Meade division and Chesapeake Utilities' CFG division, collectively, “Florida natural gas distribution businesses”) have been consolidated for rate-making purposes and amounts above are now being presented on a consolidated basis consistent with the final rate order.
(2)Total operating revenues for the three months ended March 31, 2023 include other revenue (revenues from sources other than contracts with customers) of $0.6 million and $0.1 million for our current assessment, we believe thatRegulated and Unregulated Energy segments, respectively and $0.1 million for both our Regulated and Unregulated Energy segments, respectively, for the implementationthree months ended March 31, 2022. The sources of this new standard will not have a material impact onother revenues include revenue from alternative revenue programs related to revenue normalization for the amountMaryland division and Sandpiper Energy and late fees.


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Contract Balances
The timing of revenue recognition, except for one long-termcustomer 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 for which we will delayassets, and contract liabilities as of March 31, 2023 and December 31, 2022 were as follows:
Trade ReceivablesContract Assets (Current)Contract Assets (Non-current)Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2022$61,687 $18 $4,321 $983 
Balance at 3/31/202358,514 18 4,174 682 
Decrease$(3,173)$— $(147)$(301)
Our trade receivables are included in trade and other receivables in the recognition of revenue of approximately $407,000condensed consolidated balance sheets. Our current contract assets are included in 2018. Since weother current assets in the condensed consolidated balance sheet. Our non-current contract assets are included in other assets in the condensed consolidated balance sheet and primarily relate to operations and maintenance costs incurred by Eight Flags that have not yet finalized our assessment, we will continue to monitor and subsequently disclose future identified material impacts, if any, in our annual report on Form 10-Kbeen recovered through rates for the year ended December 31, 2017. In addition, the AICPA Power and Utilities Industry Task Force is addressing issues specificsale of electricity to our industry, including CIAC,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. Contract liabilities are included in other accrued liabilities in the condensed consolidated balance sheets and has concluded that CIACrelate to non-refundable prepaid fixed fees for our Mid-Atlantic and North Carolina propane delivery operation's retail offerings. Our performance obligation is outsidesatisfied over the term of the scoperespective customer retail program on a ratable basis. For the three months ended March 31, 2023 and 2022, we recognized revenue of this standard; accordingly, our Regulated Energy segment accounting$0.2 million and $0.4 million, respectively.

Remaining Performance Obligations
Our businesses have long-term fixed fee contracts with customers in which revenues are recognized when performance obligations are satisfied over the contract term. Revenue for CIAC will not change as a result of ASC 606.
Leases (ASC 842) - In February 2016, the FASB issued ASU 2016-02, Leases, which provides updated guidance regarding accounting for leases. This update requires a lessee to recognize a lease liability and a lease asset for all leases, including operating leases, with a term greater than 12 months on its balance sheet. The update also expands the required quantitative and qualitative disclosures surrounding leases. ASU 2016-02 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted.
We have assessed all of our leases and have concluded that a majority of our operating leases would continue to fall within the category of operating leases; however, we may have some leases that qualifythese businesses for the short-term lease exception. We will record the right to use of assets and the lease liability related to the operating leases, but we do not believe that this will have a material impact on our financial position, results of operations and cash flows. During the fourth quarter of 2017, we intend to quantify the overall impact that may result from early adoption of the standard and implementation of the overall process. This guidance will be applied using the modified retrospective transition method for leases existingremaining performance obligations, at or entered into after, the beginning of the earliest comparative period presented in the financial statements.
Statement of Cash Flows (ASC 230) - In August 2016, the FASB issued ASU 2016-15, Classification of Certain Cash Receipts and Cash Payments, which clarifies how certain transactionsMarch 31, 2023, are classified in the statement of cash flows. ASU 2016-15 will be effective for our annual and interim financial statements beginning January 1, 2018, although early adoption is permitted. We believe that the implementation of this new standard will not have a material impact on our statement of cash flows.
Intangibles-Goodwill (ASC 350) - In January 2017, the FASB issued ASU 2017-04, Simplifying the Test for Goodwill Impairment, which simplifies how 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 areexpected to be applied prospectively. We believe that the implementation of this new standard will not have a material impact on our financial position or results of operations.recognized as follows:
Compensation-Retirement Benefits (ASC 715) - In March 2017, the FASB issued ASU 2017-07, Improving the Presentation of Net Periodic Pension Cost
(in thousands)2023202420252026202720282029 and thereafter
Eastern Shore and Peninsula Pipeline$29,497 $37,006 $30,613 $27,138 $24,163 $23,398 $188,498 
Natural gas distribution operations5,474 7,115 6,757 6,527 5,942 4,742 28,371 
FPU electric distribution489 652 275 275 275 275 — 
Total revenue contracts with remaining performance obligations$35,460 $44,773 $37,645 $33,940 $30,380 $28,415 $216,869 


5.     Rates and Net Periodic Post Retirement Benefit Cost. Under this guidance, employers are required to report the service cost component in the same line item or items as other compensation costs arising from services rendered by the pertinent employees during the period. The other components of net benefit costs are required to be presented in the income statement separately from the service cost component and outside a subtotal of income from operations. The update allows for capitalization of the service cost component when applicable. ASU 2017-07 will be effective for our annual and interim financial statements beginning January 1, 2018, although early adoption is permitted. The presentation of the service cost and other components in this update are to be applied retrospectively, and theOther Regulatory Activities
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capitalization of the service cost is to be applied prospectively on or after the effective date. Aside from changes in presentation, we believe that the implementation of this new standard will not have a material impact on our financial position or results of operations.
Compensation - Stock Compensation (ASC 718) - In May 2017, the FASB issued ASU 2017-09, Scopeof ModificationAccounting, to clarify when to account for a change in the terms or conditions of a share-based payment award as a modification. Under this guidance, modification accounting is required only if the fair value, the vesting conditions or the award classification (equity or liability) changes as a result of a change in the terms or conditions of the award. The guidance is effective for our annual financial statements beginning January 1, 2018, although early adoption is permitted. The amendments included in this standard are to be applied prospectively. We believe that the implementation of this new standard will not have a material impact on our financial position or results of operations.
Derivatives and Hedging (ASC 815) - In August 2017, the FASB issued ASU 2017-12, Targeted Improvements to Accounting for Hedging Activities, to better align an entity’s risk management activities and financial reporting for hedging relationships through changes to both the designation and measurement guidance for qualifying hedging relationships and the presentation of hedge results. Among other changes to hedge designation, ASU 2017-12 expands the risks that can be designated as hedged risks in cash flow hedges to include cash flow variability from contractually specified components of forecasted purchases or sales of non-financial assets. ASU 2017-12 requires the entire change in fair value of a hedging instrument included in the assessment of hedge effectiveness be presented in the same income statement line that is used to present the earnings effects of the hedged item for fair value hedges and in other comprehensive income for cash flow hedges. For disclosures, ASU 2017-12 requires a tabular presentation of the income statement effect of fair value and cash flow hedges, and it eliminates the requirement to disclose the ineffective portion of the change in fair value of hedging instruments. ASU 2017-12 will be effective for our annual and interim financial statements beginning January 1, 2019, although early adoption is permitted. We are evaluating the effect of this standard on our future financial position and results of operations.

2.Calculation of Earnings Per Share

  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
(in thousands, except shares and per share data)        
Calculation of Basic Earnings Per Share:        
         
Net Income $6,833
 $4,416
 $32,023
 $32,812
Weighted average shares outstanding 16,344,442
 15,372,413
 16,334,210
 15,324,932
Basic Earnings Per Share $0.42
 $0.29
 $1.96
 $2.14
         
Calculation of Diluted Earnings Per Share:        
Reconciliation of Numerator:        
Net Income $6,833
 $4,416
 $32,023
 $32,812
Reconciliation of Denominator:        
Weighted shares outstanding—Basic 16,344,442
 15,372,413
 16,334,210
 15,324,932
Effect of dilutive securities—Share-based compensation 45,193
 40,370
 44,423
 41,023
Adjusted denominator—Diluted 16,389,635
 15,412,783
 16,378,633
 15,365,955
Diluted Earnings Per Share $0.42
 $0.29
 $1.96
 $2.14

3.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 and Aspire Energy Express, our intrastate pipeline subsidiary, issubsidiaries, are subject to regulation (excluding cost of service) by the Florida PSC. Chesapeake Utilities' Florida natural gas distribution divisionPSC and FPU’s natural gasPublic Utilities Commission of Ohio, respectively.

Delaware

Refer to the below discussion pertaining to the COVID-19 impact and electric distribution operations continue to be subject to regulation, as separate entities, by the Florida PSC.Customer Information System Regulatory Asset Petition.


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Maryland
Delaware
Rate Case Filing:Customer Information System Regulatory Asset Petition:In December 2015,July 2022, we filed a joint petition for our natural gas divisions in Maryland (Maryland Division, Sandpiper, and Elkton Gas) for the approval to establish a regulatory asset for non-capitalizable expenses related to the initial development and implementation of our new Customer Information System ("CIS") system. The petition was approved by the Maryland PSC in August 2022.A similar petition for our Florida Regulated Energy businesses was filed during the same time frame and was initially denied. The Florida PSC subsequently approved capitalization of these expenses. Additionally, our Delaware Division has the ability to defer these costs as a regulatory asset. We have completed the system selection process and the CIS implementation began during the first quarter of 2023.

Ocean City Maryland Reinforcement: In March 2022, we filed an applicationa Section 7(f) - Request for Service Area Determination with the FERC regarding plans to extend our natural gas facilities across the Delaware/Maryland state line from Sussex County, Delaware, to Worcester County, Maryland, to provide a secondary feed to Sandpiper Energy. The FERC approved the Section 7(f) request on August 29, 2022. The project will increase the reliability of the existing distribution system in those areas while also expanding infrastructure to serve new customers. Construction has been initiated with estimated completion in the first half of 2023.

Florida

Wildlight Expansion: In August 2022, Peninsula Pipeline and FPU filed a joint petition with the Florida PSC for a base rate increase and certain other changesapproval of its Transportation Service Agreement associated with the Wildlight planned community located in Nassau County, Florida. The project enables us to its tariff.meet the significant growing demand for service in Yulee, Florida. The Delaware Division, Delaware PSC Staff,agreement will enable us to construct the Divisionproject during the build-out of the Public Advocatecommunity, and other intervenors met and reached a settlement agreement in November 2016. The termscharge the reservation rate as each phase of the settlement agreement included an annual increase of $2.3 million in base rates. The order became final in December 2016, and the new rates became effective January 1, 2017. Amounts collected through interim rates in excessproject goes into service. Construction of the respective portionpipeline facilities will occur in two separate phases. Phase one consists of three extensions with associated facilities, and a gas injection interconnect with associated facilities. Phase two will consist of two additional pipeline extensions. The various phases of the $2.3 million increaseproject commenced in the first quarter of 2023, with construction on the overall project continuing through December 31, 2016 were accrued as of that date. In January 2017, we filed our proposed refund plan with the Delaware PSC and subsequently issued refunds to customers in March 2017.
Maryland
There were no material rates and other regulatory activities for our Maryland division during the period.
Sandpiper
There were no material rates and other regulatory activities for Sandpiper during the period.
Florida
Cost Recovery for the Electric Interconnect Project: In September 2015, FPU’s electric division filed to recover the cost of the proposed Florida Power & Light Company interconnect project through FPU's annual Fuel and Purchased Power Cost Recovery Clause filing.2025. The interconnect project would enable FPU's electric division to negotiate a new power purchase agreement to mitigate fuel costs for its Northeast division. FPU's proposalpetition was approved by the Florida PSC at its Agenda Conference held in December 2015. November 2022.

Natural Gas Rate Case: In January 2016, however, the Office of Public CounselMay 2022, our natural gas distribution businesses in Florida filed an appeal of the Florida PSC's decisiona consolidated natural gas rate case with the Florida Supreme Court.PSC. The application included a request for the following: (i) permanent rate relief of approximately $24.1 million, effective January 1, 2023, (ii) a depreciation study also submitted with filing; (iii) authorization to make certain changes to tariffs to include the consolidation of rates and rate structure across the businesses and to unify the Florida Supreme Court reversednatural gas distribution businesses under FPU; (iv) authorization to retain the acquisition adjustment recorded at the time of the FPU merger in our revenue requirement; and (v) authorization to establish an environmental remediation surcharge for the purposes of addressing future expected remediation costs for FPU MGP sites. In August 2022, interim rates were approved by the Florida PSC decision in the amount of approximately $7.7 million on an annualized basis, effective for all meter readings in September 2022. The discovery process and subsequent hearings were concluded during the fourth quarter of 2022 and briefs were submitted during the same quarter of 2022. In January 2023, the Florida PSC approved the application for consolidation and permanent rate relief of approximately $17.2 million on an annual basis. Actual rates in connection with the rate relief were approved by the Florida PSC in February 2023 with an effective date of March 2017, after consideration1, 2023.

Beachside Pipeline Extension: In June 2021, Peninsula Pipeline and Florida City Gas entered into a Transportation Service Agreement for an incremental 10,176 Dts/d of firm service in Indian River County, Florida, to support Florida City Gas’ growth along the parties' legal briefs and oral arguments.Indian River's barrier island. As a result, FPU excluded the recoverypart of these coststhis agreement, Peninsula Pipeline constructed 11.3 miles of pipeline from its 2018 Fuel and Purchased Power Cost Recovery Clause and included the costs for recoveryexisting pipeline in the limited proceeding filing described below.Sebastian, Florida area, traveling east under the Intercoastal Waterway and southward on the barrier island. The project was placed in-service during April 2023.
Surcharge Associated with Modernization of Electric Distribution System Project:
St.Cloud / Twin Lakes Expansion: In February 2017, FPU’s electric divisionJuly 2022, Peninsula Pipeline filed a petition with the Florida PSC requestingfor approval of its Transportation Service Agreement with FPU, for an additional 2,400 Dt/d of firm service in the St. Cloud, Florida area. As part of this agreement, Peninsula Pipeline will construct a temporary surcharge mechanismpipeline extension and regulator station for FPU. The extension will be used to recover costs and generate an appropriate return on investment associated with an essentialsupport new incremental load due to growth in the area, including providing service, most immediately, to the residential development, Twin Lakes. The expansion will also improve reliability and modernization project for its electricprovide operational benefits to FPU's existing distribution system. We requested approval to invest approximately $59.8 million, over a five-year period, associated withsystem in the modernization project. In February 2017,area, supporting future growth. The petition was approved by the Office of Public Counsel intervened in this petition. The Florida PSC requested that FPU file a limited proceedingon October 4, 2022.We expect this expansion to include these investmentsbe in base rates insteadservice by the second quarter of seeking2023.


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Storm Protection Plan:In 2020, the Florida PSC implemented the Storm Protection Plan ("SPP") and Storm Protection Plan Cost Recovery Clause ("SPPCRC") rules, which require electric utilities to petition the Florida PSC for approval of a temporary surcharge. In April 2017, FPU voluntarily withdrew its petitionTransmission and subsequentlyDistribution Storm Protection Plan that covers the utility’s immediate 10-year planning period with updates to the plan at least every 3 years. The SPPCRC rules allow the utility to file for recovery of associated costs for the SPP. Our Florida electric distribution operation’s SPP plan was filed during the limited proceeding describedfirst quarter of 2022 and approved in the next paragraph.fourth quarter of 2022 with modifications, by the Florida PSC. Rates associated with this initiative were effective in January 2023.
Electric Limited Proceeding:
Lake Wales Pipeline Acquisition: In July 2017, FPU’s electric divisionFebruary 2022, Peninsula Pipeline filed a petition with the Florida PSC requestingfor approval to include $15.2 million of certain capital project expendituresits Transportation Service Agreement with FPU for an additional 9,000 Dt/d of firm service in its rate base and to adjust its base rates accordingly. These expenditures are designed to improve the stability and safetyLake Wales, Florida area. Approval of the electric system while enhancingagreement by the capabilityFlorida PSC will enable Peninsula Pipeline to begin executing on the acquisition of FPU’s grid. Includedan existing pipeline in the $15.2 million is the interconnection project with Florida Power & Light Company, which enables FPU to mitigate fuel costs for its electric customers. This petition is scheduled for the Florida PSC's December 2017 Agenda.
Northwest Florida Expansion Project: Peninsula Pipeline and FPU's natural gas division are constructing a pipeline in Escambia County, Florida that will interconnect with FGT's pipeline. The project consists of 33 miles of 12-inch transmission line from the FGT interconnectarea that will be operated by Peninsula Pipeline and 8 miles of 8-inch lateral distribution lines that will be operated by Chesapeake Utilities' Floridautilized to serve our current natural gas division. We have entered into agreementscustomers as well as new customers. The Commission approved the petition in April 2023.

GUARD: In February 2023, FPU filed a petition with the Florida PSC for approval of the GUARD program. GUARD is a proposed ten-year program to serve two large customersenhance the safety, reliability and are marketing to other customers close to the facilities.

New Smyrna Beach, Florida Project: Peninsula Pipeline is constructing a pipeline in Volusia County, Florida that will interconnect with FGT's pipeline. The project consistsaccessibility of 14 milesportions of transmission line from the FGT interconnect that will be operated by Peninsula Pipeline and will serve FPUour natural gas distribution customers.system. FPU has identified various categories of eligible projects to be included in GUARD, which includes the relocation of mains and service lines located in rear easements and other difficult to access areas to the front of the street; the replacement of problematic distribution mains, service lines and M&R equipment; and system reliability projects. The petition is currently under review by the Florida PSC.

Eastern Shore
White Oak Mainline
Southern Expansion Project:In July 2016, Eastern Shore received FERC authorization to construct, own and operate certain expansion facilities designed to provide 45,000 Dts/d of firm transportation service to an electric power generator in Kent County, Delaware ("White Oak Mainline Project"). Eastern Shore constructed approximately 5.4 miles of 16-inch diameter pipeline looping in Chester County, Pennsylvania and increased compression capability at Eastern Shore’s existing Delaware City compressor station in New Castle County, Delaware. At the end of March 2017, the entire project was placed into service. The total cost to complete the project was approximately $42.0 million.
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System Reliability Project: In September 2016, the FERC approved Eastern Shore's application to construct, own and operate approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware, and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. Eastern Shore further proposed to reinforce critical points on its pipeline system. Previously, in July 2016, the FERC granted Eastern Shore’s pre-determination of rolled-in rate treatment absent any significant change in circumstances.
As of June 2017, the entire project was placed into service. The total cost to complete the project was approximately $38.0 million. We began to recover the project's costs in August 2017, coinciding with the proposed effectiveness of new rates, subject to refund, pending final resolution of the base rate case described below.
2017 Expansion Project: In May 2016,January 2022, Eastern Shore submitted a request toprior notice filing with the FERC pursuant to initiate the pre-filing reviewblanket certificate procedures, for Eastern Shore's 2017 expansion project (the “2017 Expansion Project”). The 2017 Expansion Project's facilities include approximately 23 miles of pipeline looping in Pennsylvania, Maryland and Delaware; upgradesregarding its proposal to existing metering facilities in Lancaster County, Pennsylvania; installation ofinstall an additional compressor unit and related facilities at Eastern Shore’s existing DalevilleShore's compressor station in Chester County, Pennsylvania; approximately 17 miles of new mainline extension and two pressure control stations inBridgeville, Sussex County, Delaware. In May 2016, the FERC approved Eastern Shore’s request to commence the pre-filing review process.The project will enable Eastern Shore entered into Precedent Agreements with seven existing customers, including three affiliates of Chesapeake Utilities, for a total of 61,162 Dts/d ofto provide additional firm natural gas transportation service to an existing shipper on Eastern Shore’sits pipeline system with an additional 52,500 Dts/dsystem. The project obtained FERC approval in December 2022, and is under construction, estimated to go into service in the fourth quarter of firm transportation service at certain Eastern Shore receipt facilities.2023.

Capital Cost Surcharge: In December 2016,2022, Eastern Shore submitted an application for a CP seeking authorization to construct the expansion facilities. Six of Eastern Shore's existing customers timely intervened to become parties. In February and March 2017, Eastern Shore submitted responses to the FERC staff's data requests.
In October 2017, FERC issued a CP authorizing Eastern Shore to construct and operate the proposed 2017 Expansion Project. The estimated cost of the 2017 Expansion Project is approximately $115.0 million
Eastern Shore is preparing its implementation plan, which will be filedfiling with the FERC addressingregarding a capital cost surcharge to recover capital costs associated with the actionsreplacement of existing Eastern Shore will undertake to meet the Environmental Conditions set forthfacilities as a result of mandated highway relocation projects as well as compliance with a Pipeline and Hazardous Materials Safety Administration ("PHMSA") regulation. The capital cost surcharge mechanism was approved in the FERC's order. Eastern Shore anticipates placing certain facilities into service by the end of the year and completing the entire project in 2018.
2017 Rate Case Filing: Shore’s last rate case. In January 2017, Eastern Shore filed a base rate proceedingconjunction with the FERC, as required byfiling of this surcharge, a cumulative adjustment to the terms of its 2012 rate case settlement agreement. Eastern Shore's proposed rates were based on the mainline cost of service of approximately $60.0 million resulting in an overall requested revenue increase of approximately $18.9 million and a requested rate of return on common equity of 13.75 percent.existing surcharge to reflect additional depreciation was included. The filing includes incremental rates for the White Oak Lateral Project and White Oak Mainline Expansion Project, which benefits a single customer. Eastern Shore also proposed to revise its depreciation rates and negative salvage rate based on the results of independent, third-party depreciation and negative salvage value studies. In March 2017, the FERC issued an order suspendingapproving the tariffsurcharge as filed on December 19, 2022. The combined revised surcharge became effective January 1, 2023.

COVID-19 Impact

In March 2020, the CDC declared a national emergency due to the rapidly growing outbreak of COVID-19. In response to this declaration and the rapid spread of COVID-19 within the United States, federal, state and local governments throughout the country imposed varying degrees of restrictions on social and commercial activity to promote social distancing in an effort to slow the spread of the illness. These restrictions significantly impacted economic conditions in the United States in 2020 and continued to impact economic conditions, to a lesser extent, through 2021 and 2022. Chesapeake Utilities is considered an “essential business,” which allowed us to continue operational activities and construction projects with appropriate safety precautions and personal protective equipment, while being mindful of the social distancing restrictions that were in place.

In response to the COVID-19 pandemic and related restrictions, we experienced reduced consumption of energy largely in the commercial and industrial sectors, higher bad debt expenses and incremental expenses associated with COVID-19, including expenditures associated with personal protective equipment and premium pay for field personnel. The additional operating expenses we incurred supported the ongoing delivery of our essential services during the height of the pandemic. In April and May 2020, we were authorized by the Maryland and Delaware PSCs, respectively, to record regulatory assets for COVID-19 related costs which offered us the ability to seek recovery of those costs. In July 2021, the Florida PSC issued an order that approved incremental expenses we incurred due to COVID-19. The order allowed us to establish a regulatory asset in a total amount of $2.1 million as of June 30, 2021 for natural gas and electric distribution operations. The regulatory asset is being amortized over two years and is

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recovered through the Purchased Gas Adjustment and Swing Service mechanisms for our natural gas distribution businesses and through the Fuel Purchased Power Cost Recovery clause for our electric division. As of March 31, 2023 and December 31, 2022, our total COVID-19 regulatory asset balance was $1.0 million and $1.2 million, respectively.

In 2021 and 2022, restrictions were gradually lifted as vaccines became widely available in the United States. The various state of emergencies associated with the COVID-19 pandemic that were previously declared in our service territories have been terminated and we have adjusted our operating practices accordingly to ensure the safety of our operations and will take the necessary actions to comply with the CDC, and the Occupational Safety and Health Administration, as new developments may occur.

Summary TCJA Table
Customer rates for the usual five-month period.
On August 1, 2017, Eastern Shore implemented new rates, subject to refund based upon the outcome of the rate proceeding.  Eastern Shore recorded incremental revenue of approximately $1.0 million for the three and nine months ended September 30, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generatedour regulated businesses were adjusted, as approved by the new rates untilregulators, prior to 2020 with the exception of Elkton Gas, which implemented a one-time bill credit in May 2020. The following table summarizes the regulatory liabilities related to accumulated deferred taxes ("ADIT") associated with TCJA for our regulated businesses as of March 31, 2023 and December 31, 2022:

Amount (in thousands)
Operation and Regulatory JurisdictionMarch 31, 2023December 31, 2022Status
Eastern Shore (FERC)$34,190$34,190Will be addressed in Eastern Shore's next rate case filing.
Chesapeake Delaware natural gas division (Delaware PSC)$12,182$12,230PSC approved amortization of ADIT in January 2019.
Chesapeake Maryland natural gas division (Maryland PSC)$3,674$3,703PSC approved amortization of ADIT in May 2018.
Sandpiper Energy (Maryland PSC)$3,570$3,597PSC approved amortization of ADIT in May 2018.
Florida natural gas distribution (Florida PSC) (1)
$26,999$27,179PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.
FPU electric division (Florida PSC)$4,934$4,993In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.
Elkton Gas (Maryland PSC)$1,051$1,059PSC approved amortization of ADIT in March 2018.
(1) In accordance with the Florida PSC approval of our natural gas base rate case is resolved. Settlement discussions continue amongproceeding, effective March 1, 2023, our natural gas distribution businesses in Florida have been consolidated for rate-making purposes and amounts above are now being presented on a consolidated basis consistent with the other parties to the case.final rate order.

4.


6. Environmental Commitments and Contingencies

We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These laws and regulations require us to remove or remediate, at current and former operating sites, the effect on the environment of the disposal or release of specified substances.
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MGP Sites
We have participated in the investigation, assessment or remediation of, and have exposures at, seven former MGP sites. ThoseWe have received approval for recovery of clean-up costs in rates for sites are located in Salisbury, Maryland,Maryland; Seaford, DelawareDelaware; and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida. We have also been in discussions with the MDE regarding another former MGP site located in Cambridge, Maryland.

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As of September 30, 2017,March 31, 2023 and December 31, 2022, we had approximately $9.7$3.5 million and $4.3 million, respectively, in environmental liabilities related to the former MGP sites. As of March 31, 2023 and December 31, 2022, we have cumulative regulatory assets of $0.5 million and $0.8 million, respectively, for future recovery of environmental costs for customers. Specific to FPU’s four MGP sites in Florida, which include the Key West, Pensacola, Sanford and West Palm Beach, sites. FPU has approval to recover, from insurance and from customers through customer rates, up to $14.0 million of its environmental costs related to its MGP sites. Approximately $10.9The total $14.0 million has beenwas fully recovered as of September 30, 2017, leaving approximately $3.1 million in regulatory assets for future recovery of environmental costs from FPU’s customers.March 31, 2023.
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.
Remediation is ongoing for the MGPs in Winter Haven and Key West in Florida and in Seaford, Delaware and the remaining clean-up costs are estimated to be between $0.3 million to $0.9 million for these three sites. The followingEnvironmental Protection Agency has approved a "site-wide ready for anticipated use" status for the Sanford, Florida MGP site, which is the final step before delisting a summarysite. The remaining remediation expenses for the Sanford MGP site are immaterial.
The remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of our remediation statusWest Palm Beach Florida site. Similar remedial actions have been initiated on the site's west parcel, and estimated costsconstruction of active remedial systems are expected to implement clean-up of our MGP sites:be completed later in 2023.



JurisdictionMGP SiteStatusCost to Clean upRecovery through Rates
FloridaWest Palm BeachRemedial actions approved by FDEP have been implemented on the east parcel of the site. Similar remedial actions expected to be implemented on other remaining portions.Between $4.5 million to $15.4 million, including costs associated with the relocation of FPU’s operations at this site, which is necessary to implement the remedial plan, and any potential costs associated with future redevelopment of the propertiesYes
FloridaSanford
In January 2007, FPU and the Sanford group signed a Third Participation Agreement. FPU's share of remediation costs under the Third Participation Agreement is set at five percent of a maximum of $13.0 million, or $650,000, which has been paid to an escrow account.7.     Other Commitments and Contingencies

The EPA issued a preliminary close-out report in December 2014. Groundwater monitoring and statutory five-year reviews to ensure performance of the approved remedy will continue on this site.
FPU's remaining remediation expenses, including attorneys' fees and costs, are estimated to be approximately $24,000Yes
FloridaWinter HavenRemediation is ongoing.Not expected to exceed $425,000, which includes costs of implementing institutional controls at the siteYes
DelawareSeafordProposed plan for implementation approved by DNREC in July 2017.$273,000 to $465,000Yes
MarylandCambridgeCurrently in discussions with MDEUnable to estimateN/A
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5.Other Commitments and Contingencies
Natural Gas, Electric and Propane Supply
We have entered into contractual commitments to purchase natural gas, electricity and propane from various suppliers. The contracts have various expiration dates. In 2017,March 2023, our Delmarva Peninsula natural gas distribution operations entered into asset management agreements with PESCOa third party to manage a portion of their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2017,2023 and each has a three-year term, expiring onexpire in March 31, 2020. Previously, the Delaware PSC approved PESCO to serve as an asset manager.2026.
In May 2013, Sandpiper entered into a capacity, supply and operating agreement with EGWIC to purchase propane over a six-year term ending in May 2019. Sandpiper's current annual commitment is estimated at approximately 2.8 million gallons. Sandpiper has the option to enter into either a fixed per-gallon price for some or all of the propane purchases or a market-based price utilizing one of two local propane pricing indices.
Also in May 2013, Sharp entered into a separate supply and operating agreement with EGWIC. Under this agreement, Sharp has a commitment to supply propane to EGWIC over a six-year term ending in May 2019. Sharp's current annual commitment is estimated at approximately 2.8 million gallons. The agreement between Sharp and EGWIC is separate from the agreement between Sandpiper and EGWIC, and neither agreement permits the parties to set off the rights and obligations specified in one agreement against those specified in the other agreement.
Chesapeake Utilities'Our Florida natural gas distribution division hasoperations and Eight Flags have separate asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity. These agreements are for a 10-year term that commenced in November 2020 and expire in October 2030.
Additionally, our Florida natural gas distribution operations have firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties, including PESCO.parties. 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. To date, Chesapeake Utilities has not been required to make a payment resulting from this contingency.
FPU’s electric fuel supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with JEAFlorida Power & Light Company requires FPU to comply with the following ratiosmeet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months: (a) total liabilitiesmonths. If FPU fails to tangible net worth less than 3.75 times and (b) a fixed charge coveragemeet this ratio, greater than 1.5 times. If either ratio is not met by FPU, it has 30 days to cure the default ormust provide an irrevocable letter of credit ifor pay all amounts outstanding under the default is not cured.agreement within five business days. FPU’s electric fuel supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of 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, 2017,March 31, 2023, FPU was in compliance with all of the requirements of its fuel supply contracts.
Eight Flags provides electricity and steam generation services through its CHP plant located on Amelia Island, Florida. In June 2016, Eight Flags began selling power generated from the CHP plant to FPU pursuant to a 20-year power purchase agreement for distribution to its retailour electric customers. In July 2016, Eight Flags also started selling steam, an industrial customer that ownspursuant to a separate 20-year contract, to the propertylandowner on which the CHP plant is located pursuant to a separate 20-year contract.located. The CHP plant is powered by natural gas transported by FPU through its distribution system and Peninsula Pipeline through its intrastate pipeline.


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Corporate Guarantees
We have issuedThe Board of Directors has authorized us to issue corporate guarantees to certain vendorssecuring obligations of our subsidiaries primarily PESCO. These corporateand to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees provide for the paymentand letters of propane and natural gas purchases in the event that PESCO defaults. PESCO has never defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded when incurred.credit as of March 31, 2023 was $20.0 million. The aggregate amount guaranteed related to our subsidiaries at September 30, 2017March 31, 2023 was approximately $71.9$14.2 million with the guarantees expiring on various dates through September 2018.
Chesapeake Utilities alsoMarch 30, 2024. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose 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 13, Long-Term Debt, for further details).
Letters of Creditat March 31, 2023 was $4.0 million.
As of September 30, 2017,March 31, 2023, we have issued letters of credit totaling approximately $5.8 million related to the electric transmission services for FPU's electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, the capacity agreement between NEXUS and toAspire, and our current and previous primary insurance carriers. These letters of credit have various expiration dates through June 2018. ThereOctober 25, 2023 and to date, none have been no draws on these letters of credit as of September 30, 2017.used. We do not anticipate that the counterparties will draw upon these letters of credit, will be drawn upon by the counterparties, and we expect that the letters of 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.

8.    Segment Information
6.Segment Information
We use the management approach to identify operating segments. We organize our business around differences in regulatory environment and/or products or services, and the operating results of each segment are regularly reviewed by the chief operating decision maker, (ourour Chief Executive Officer)Officer, in order to make decisions about resources and to assess performance. The segments
Our operations are evaluated based on their pre-tax operating income. Our operationsentirely domestic and are comprised of two reportable segments:
•Regulated Energy. The Regulated Energy segment includes naturalIncludes energy distribution and transmission services (natural gas distribution, natural gas transmission and electric distribution operations.operations). All operations in this segment are regulated, as to their rates and services, by the PSC having jurisdiction in each operating territory or by the FERC in the case of Eastern Shore.
•Unregulated Energy. The Unregulated Energy segment includes Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane distribution as well asoperations, mobile compressed natural gas marketing, gathering, processing, transportationdistribution and supply.pipeline solutions operations, and project development activities related to our sustainable energy initiatives. 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. These operations are unregulated as to their rates and services. Effective June 2016, this segment includes electricity and steam generation through Eight Flags' CHP plant. Through March 2017, this segment also included the

The remainder of our operations of Xeron, our propane and crude oil trading subsidiary that began winding down operations at the end of the first quarter of 2017.
Other operations areis presented as “Other businesses and eliminations,” which consistconsists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations.

Our operations are entirely domestic.

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The following table presents financial information about our reportable segments:

15
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
(in thousands)        
Operating Revenues, Unaffiliated Customers        
Regulated Energy segment $67,257
 $68,899
 $232,519
 $224,382
Unregulated Energy segment and other businesses 59,679
 39,449
 204,661
 132,604
Total operating revenues, unaffiliated customers $126,936
 $108,348
 $437,180
 $356,986
Intersegment Revenues (1)
        
Regulated Energy segment $2,446
 $1,120
 $5,834
 $2,248
Unregulated Energy segment 5,009
 2,593
 15,801
 3,759
Other businesses 194
 240
 581
 705
Total intersegment revenues $7,649
 $3,953
 $22,216
 $6,712
Operating Income        
Regulated Energy segment $15,168
 $13,115
 $51,915
 $52,660
Unregulated Energy segment (989) (3,080) 10,504
 9,267
Other businesses and eliminations 60
 121
 161
 350
Total operating income 14,239
 10,156
 62,580
 62,277
Other income (expense), net 239
 (28) (643) (68)
Interest charges 3,321
 2,722
 9,133
 7,996
Income before Income Taxes 11,157
 7,406
 52,804

54,213
Income taxes 4,324
 2,990
 20,781
 21,401
Net Income $6,833
 $4,416
 $32,023

$32,812
(1)
All significant intersegment revenues are billed at market rates and have been eliminated from consolidated operating revenues.
(in thousands) September 30, 2017 December 31, 2016
Identifiable Assets    
Regulated Energy segment $1,084,961
 $986,752
Unregulated Energy segment 233,785
 226,368
Other businesses and eliminations 28,004
 16,099
Total identifiable assets $1,346,750
 $1,229,219

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7.Stockholder's Equity
Preferred Stock
Three Months Ended
March 31,
20232022
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy$141,621 $124,058 
Unregulated Energy76,508 98,822 
Total operating revenues, unaffiliated customers$218,129 $222,880 
Intersegment Revenues (1)
Regulated Energy$649 $3,833 
Unregulated Energy6,657 1,996 
Other businesses45 606 
Total intersegment revenues$7,351 $6,435 
Operating Income
Regulated Energy$37,625 $34,681 
Unregulated Energy17,245 20,046 
Other businesses and eliminations45 138 
Operating income54,915 54,865 
Other income, net276 913 
Interest charges7,232 5,339 
Income Before Income Taxes47,959 50,439 
Income Taxes11,615 13,506 
Net Income$36,344 $36,933 
We had 2,000,000 authorized(1)All significant intersegment revenues are billed at market rates and unissued shareshave been eliminated from consolidated operating revenues.

(in thousands)March 31, 2023December 31, 2022
Identifiable Assets
Regulated Energy segment$1,713,149 $1,716,255 
Unregulated Energy segment441,261 463,239 
Other businesses and eliminations43,141 35,543 
Total Identifiable Assets$2,197,551 $2,215,037 




16
Table of preferred stock, $0.01 par value per share, as of September 30, 2017 and December 31, 2016. Shares of preferred stock may be issued from time to time, by authorization of our Board of Directors and without the necessity of further action or authorization by stockholders, in one or more series and with such voting powers, designations, preferences and relative, participating, optional or other special rights and qualifications as the Board of Directors may, in its discretion, determine.Contents


9.    Stockholders' Equity
Common Stock Public OfferingIssuances
In September 2016,
We maintain an effective shelf registration statement with the SEC for the issuance of shares under our DRIP and ATM programs. Depending on our capital needs and subject to market conditions, in addition to other possible debt and equity offerings, we completed a public offeringmay issue additional shares under the direct stock purchase component of 960,488the DRIP. Under our current ATM equity program we may issue and sell shares of our common stock at a publicup to an aggregate offering price of $75.0 million through June 2023. In 2022, we issued less than 0.1 million shares at an average price per share of $62.26. The$136.26 and received net proceeds of $4.5 million under the DRIP. In the first three months of 2023, there were no issuances under the DRIP.

We use the net proceeds from the saleour share issuances, after fees, for general corporate purposes, including, but not limited to, financing of common stock, after deducting underwriting commissions and expenses, were approximately $57.4 million, which were added to our general funds and used primarily to repay a portioncapital expenditures, repayment of our short-term debt, under unsecured lines of credit.financing acquisitions, investing in subsidiaries, and general working capital purposes.
Stockholders' Rights
Pursuant to authority granted under Delaware law and our Certificate of Incorporation, our Board of Directors previously declared a dividend of one preferred stock purchase right (each, a "Right," and, collectively, the "Rights") for each outstanding share of our common stock held of record on September 3, 1999, as adjusted for our stock split in September of 2014, and for additional shares of common stock issued since that time. The description and terms of the Rights are set forth in the Rights Plan. Unless exercised, the Rights trade with our common stock and are evidenced by the common stock certificate. In general, each Right will become exercisable and trade independently from our common stock upon a person or entity acquiring a beneficial ownership of 15 percent or more of our outstanding common stock.
Each Right, if it becomes exercisable, initially entitles the holder to purchase one fiftieth of a share of our Series A Participating Cumulative Preferred Stock, par value $0.01 per share, at a price of $70 per unit, subject to anti-dilution adjustments. Upon a person or entity becoming an "acquiring person," each Right (other than the Rights held by the acquiring person) will become exercisable to purchase a number of shares of our common stock having a market value equal to two times the exercise price of the Right. The Rights expire on August 20, 2019, unless they are redeemed earlier by us at the redemption price of $0.01 per Right. We may redeem the Rights at any time before they become exercisable and thereafter only in limited circumstances.
Accumulated Other Comprehensive LossIncome (Loss)

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements call options and natural gas futures contracts, designated as commodity contracts cash flow hedges, and the unrealized gains (losses) of our interest rate swap agreements designated as cash flow hedges are the components of our accumulated other comprehensive loss.
income (loss). The following tables present the changes in the balance of accumulated other comprehensive loss forgain (loss) as of March 31, 2023 and 2022. All amounts in the nine months ended September 30, 2017 and 2016. All amountsfollowing tables are presented net of tax.


Defined BenefitCommodityInterest Rate
Pension andContractsSwap
PostretirementCash FlowCash Flow
Plan ItemsHedgesHedgesTotal
(in thousands)
As of December 31, 2022$(2,506)$1,092 $35 $(1,379)
Other comprehensive income (loss) before reclassifications— 22 (148)(126)
Amounts reclassified from accumulated other comprehensive income (loss)10 (440)(48)(478)
Net current-period other comprehensive income (loss)10 (418)(196)(604)
As of March 31, 2023$(2,496)$674 $(161)$(1,983)
As of December 31, 2021$(3,268)$4,571 $— $1,303 
Other comprehensive income before reclassifications— 2,498 — 2,498 
Amounts reclassified from accumulated other comprehensive income (loss)18 (1,969)— (1,951)
Net prior-period other comprehensive income18 529 — 547 
As of March 31, 2022$(3,250)$5,100 $— $1,850 
  Defined Benefit Commodity  
  Pension and Contracts  
  Postretirement Cash Flow  
  Plan Items Hedges Total
(in thousands)      
As of December 31, 2016 $(5,360) $482
 $(4,878)
Other comprehensive income/(loss) before reclassifications (9) 322
 313
Amounts reclassified from accumulated other comprehensive income/(loss) 271
 (965) (694)
Net current-period other comprehensive income/(loss) 262
 (643) (381)
As of September 30, 2017 $(5,098) $(161) $(5,259)

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  Defined Benefit Commodity  
  Pension and Contracts  
  Postretirement Cash Flow  
  Plan Items Hedges Total
(in thousands)      
As of December 31, 2015 $(5,580) $(260) $(5,840)
Other comprehensive income before reclassifications —
 641
 641
Amounts reclassified from accumulated other comprehensive income/(loss) 263
 (93) 170
Net prior-period other comprehensive income 263
 548
 811
As of September 30, 2016 $(5,317) $288
 $(5,029)
The following table presents amounts reclassified out of accumulated other comprehensive loss for the three and nine months ended September 30, 2017 and 2016. Deferred gains or losses for our commodity contracts and interest rate swap cash flow hedges are recognized in earnings upon settlement.
  Three Months Ended Nine Months Ended
  September 30, September 30,
  2017 2016 2017 2016
(in thousands)        
Amortization of defined benefit pension and postretirement plan items:        
Prior service credit (1)
 $19
 $20
 $58
 $60
Net loss(1)
 (171) (166) (509) (500)
Total before income taxes (152)
(146) (451)
(440)
Income tax benefit 61
 58
 180
 177
Net of tax $(91) $(88) $(271)
$(263)
         
Gains and losses on commodity contracts cash flow hedges        
Propane swap agreements (2)
 $198
 $—
 $663
 $(322)
Natural gas swaps (2)
 1
 —
 1
 —
Natural gas futures (2)
 (852) 105
 929
 464
Total before income taxes (653) 105
 1,593

142
Income tax benefit (expense) 248
 (41) (628) (49)
Net of tax (405) 64

965
 93
Total reclassifications for the period $(496) $(24)
$694
 $(170)
(1) These amounts Prior service credit and net loss related to the defined benefit pension plan and postretirement plans are included in the computation of net periodic costs (benefits). See Note 8, 10, Employee Benefit Plans, for additional details.
(2) These amounts Gains on commodity contracts classified as cash flow hedges related to our propane swaps are included in the effects of gains and losses from derivative instruments. See Note 11, 12, Derivative Instruments, for additional details.
Amortization of defined benefit pension and postretirement plan items isare included in operationsother expense, andnet gains and losses on propane swap agreements and call optionscontracts are included in costrevenue and unregulated propane and natural gas, the

17
Table of sales,Contents

realized gain or loss on interest rate swap agreements is recognized as a component of interest charges in the accompanying condensed consolidated statements of income. The income tax benefit is included in income tax income (expense)expense in the accompanying condensed consolidated statements of income.

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8.Employee Benefit Plans
10.    Employee Benefit Plans
Net periodic benefit costs for our pension and post-retirement benefits plansthe FPU Pension Plan for the three and nine months ended September 30, 2017March 31, 2023 and 2016 are2022 is set forth in the following tables:table:
FPU
Pension Plan
For the Three Months Ended March 31,20232022
(in thousands)  
Interest cost$633 $449 
Expected return on plan assets(668)(857)
Amortization of net (gain) loss110 124 
Total periodic cost (benefit)$75 $(284)
  Chesapeake
Pension Plan		 FPU
Pension Plan		 Chesapeake SERP Chesapeake
Postretirement
Plan		 FPU
Medical
Plan
For the Three Months Ended September 30, 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016
(in thousands)                    
Interest cost $103
 $105
 $623
 $635
 $22
 $23
 $11
 $11
 $13
 $14
Expected return on plan assets (127) (131) (699) (625) —
 —
 —
 —
 —
 —
Amortization of prior service credit —
 —
 —
 —
 —
 —
 (19) (20) —
 —
Amortization of net loss 107
 103
 131
 133
 22
 22
 17
 16
 —
 —
Net periodic cost (benefit) 83
 77
 55
 143
 44
 45
 9
 7
 13
 14
Amortization of pre-merger regulatory asset —
 —
 191
 191
 —
 —
 —
 —
 2
 2
Total periodic cost $83
 $77
 $246
 $334
 $44
 $45
 $9
 $7

$15
 $16


  
Chesapeake
Pension Plan
 
FPU
Pension Plan
 Chesapeake SERP 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
For the Nine Months Ended September 30, 2017 2016 2017 2016 2017 2016 2017 2016 2017 2016
(in thousands)      
              
Interest cost $309
 $315
 $1,870
 $1,894
 $66
 $68
 $31
 $32
 $38
 $41
Expected return on plan assets (381) (392) (2,098) (2,027) —
 —
 —
 —
 —
 —
Amortization of prior service credit —
 —
 —
 —
 —
 —
 (58) (60) —
 —
Amortization of net loss 319
 309
 392
 389
 65
 66
 50
 51
 —
 —
Net periodic cost (benefit) 247
 232
 164
 256
 131
 134
 23
 23
 38
 41
Amortization of pre-merger regulatory asset —
 —
 571
 571
 —
 —
 —
 —
 6
 6
Total periodic cost $247
 $232
 $735
 $827
 $131
 $134
 $23
 $23
 $44
 $47

We expect to record pensionThe following table presents the amounts included in the regulatory asset and postretirement benefit costs of approximately $1.6 million for 2017. Included in these costs is approximately $769,000 related to continued amortizationaccumulated other comprehensive income that were recognized as components 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 ofPension Plan's net periodic benefit cost during the three months ended March 31, 2023 and 2022:
FPU
Pension Plan
For the Three Months Ended March 31,20232022
(in thousands)
Net loss$110 $124 
Total recognized in net periodic benefit cost110 124 
Recognized from accumulated other comprehensive (income) loss (1)
21 24 
Recognized from regulatory asset89 100 
Total$110 $124 
(1)See Note 9, Stockholders' Equity.
Net periodic benefit cost for our other pension and post-retirement benefit plans were not material for the three months ended March 31, 2023 and 2022.

The components of our net periodic costs priorhave been recorded or reclassified to other expense, net in 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 balancecondensed consolidated statements of this regulatory asset was approximately $1.5 million and approximately $2.1 million at September 30, 2017 and December 31, 2016, respectively.
income. Pursuant to a Florida PSC order,their respective regulatory orders, FPU continuesand Chesapeake Utilities continue to record, as a regulatory asset, a portion of thetheir unrecognized pension and postretirement benefit costs related to itstheir regulated operations after the FPU merger.operations. The portion of the unrecognized pension and postretirement benefit costs related to FPU’s unregulated operations and Chesapeake Utilities' operations is recorded to accumulated other comprehensive loss.
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The following tables present the amounts included in the regulatory asset and accumulated other comprehensive loss that were recognized as components of net periodic benefit cost during the three and nine months ended September 30, 2017 and 2016:
For the Three Months Ended September 30, 2017 Chesapeake
Pension
Plan		 FPU
Pension
Plan		 Chesapeake SERP Chesapeake
Postretirement
Plan		 FPU
Medical
Plan		 Total
(in thousands)            
Prior service credit $—
 $—
 $—
 $(19) $—
 $(19)
Net loss 107
 131
 22
 17
 —
 277
Total recognized in net periodic benefit cost 107
 131
 22
 (2) —
 258
Recognized from accumulated other comprehensive loss (1)
 107
 25
 22
 (2) —
 152
Recognized from regulatory asset —
 106
 —
 —
 —
 106
Total $107
 $131
 $22
 $(2) $—
 $258

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

$(4)
$—

$254

For the Nine Months Ended September 30, 2017 
Chesapeake
Pension
Plan
 
FPU
Pension
Plan
 Chesapeake SERP 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
 Total
(in thousands)            
Prior service credit $—
 $—
 $—
 $(58) $—
 $(58)
Net loss 319
 392
 65
 50
 —
 826
Total recognized in net periodic benefit cost 319
 392
 65
 (8) —
 768
Recognized from accumulated other comprehensive loss (1)
 319
 75
 65
 (8) —
 451
Recognized from regulatory asset —
 317
 —
 —
 —
 317
Total $319
 $392
 $65
 $(8) $—
 $768

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For the Nine Months Ended September 30, 2016 
Chesapeake
Pension
Plan
 
FPU
Pension
Plan
 Chesapeake SERP 
Chesapeake
Postretirement
Plan
 
FPU
Medical
Plan
 Total
(in thousands)            
Prior service credit $—
 $—
 $—
 $(60) $—
 $(60)
Net loss 309
 389
 66
 51
 —
 815
Total recognized in net periodic benefit cost 309
 389
 66
 (9) —
 755
Recognized from accumulated other comprehensive loss (1)
 309
 74
 66
 (9) —
 440
Recognized from regulatory asset —
 315
 —
 —
 —
 315
Total $309
 $389
 $66
 $(9) $—
 $755

(1) See Note 7, Stockholder's Equity.income.
During the three and nine months ended September 30, 2017, we contributed approximately $67,000 and $234,000, respectively, to the Chesapeake Pension Plan and approximately $110,000 and $1.6 million, respectively,March 31, 2023, there were no contributions to the FPU Pension Plan. WePlan and we do not expect to contribute a total of approximately $746,000 and approximately $3.0 million to the Chesapeake Pension Plan and FPU Pension Plan respectively, during 2017, which represents the minimum annual contribution payments required.
2023. 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 SERPthese other post retirement benefit plans for the three and nine months ended September 30, 2017,March 31, 2023 were approximately $38,000 and $114,000, respectively.immaterial. We expect to pay total cash benefits of approximately $151,000 under$0.2 million for the Chesapeake SERP, in 2017. Cash benefits paid underapproximately $0.1 million for the Chesapeake Postretirement Plan, primarily for medical claims for the three and nine months ended September 30, 2017, were approximately $30,000 and $94,000, respectively. We estimate that approximately $83,000 will be paid for such benefits under the Chesapeake Postretirement Plan in 2017. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and nine months ended September 30, 2017, were approximately $13,000 and $48,000, respectively. We estimate that approximately $129,000 will be paid for such benefits$0.1 million under the FPU Medical Plan in 2017.2023.


Non-Qualified Deferred Compensation Plan
9.Investments
The investment balances at September 30, 2017
Members of our Board of Directors and December 31, 2016, consistedofficers of the following:
(in thousands)September 30,
2017		 December 31,
2016
Rabbi trust (associated with the Deferred Compensation Plan)$6,358
 $4,881
Investments in equity securities22
 21
Total$6,380
 4,902
We classify these investments as trading securities and report them at their fair value. For the three months ended September 30, 2017 and 2016, we recorded a net unrealized gain of approximately $261,000 and $193,000, respectively, in other income (expense), netCompany are eligible to participate in the condensed consolidated statementsNon-Qualified Deferred Compensation Plan. Directors can elect to defer any portion of income relatedtheir cash or stock compensation and officers

18
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can defer up to these investments. For the nine months ended September 30, 2017 and 2016, we recorded an unrealized gain80 percent of approximately $694,000 and $246,000, respectively, in other income (expense), nettheir base compensation, cash bonuses or any amount of their stock bonuses (net of required withholdings). Officers may receive a matching contribution on their cash compensation deferrals up to 6 percent of their compensation, provided it does not duplicate a match they receive in the condensed consolidated statementsRetirement Savings Plan.
All obligations arising under the Non-Qualified Deferred Compensation Plan are payable from our general assets, although we have established a Rabbi Trust to informally fund the plan. Deferrals of income related to thesecash compensation may be invested by the participants in various mutual funds (the same options that are available in the Retirement Savings Plan). The participants are credited with gains or losses on those investments. For the investmentAssets held in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs inas Investments on the condensed consolidated balance sheetssheet, had a fair value of $10.8 million at March 31, 2023 and is adjusted each month for the gains and losses incurred by the investments in$10.6 million at December 31, 2022. The assets of the Rabbi Trust.Trust are at all times subject to the claims of our general creditors.
11.    Share-Based Compensation
10.Share-Based Compensation
Our non-employee directors and key employees arehave been granted share-based awards through our SICP. We record these share-based awards as compensation costs over the respective service period for which services are received in exchange for an award of equity or equity-based compensation. The compensation cost is based primarily on the fair value of the shares
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awarded, using the estimated fair value of each share on the date it was granted, and the number of shares to be issued at the end of the service period.
The table below presents the amounts included in net income related to share-based compensation expense for the three and nine months ended September 30, 2017March 31, 2023 and 2016:2022:
    
 Three Months Ended Nine Months EndedThree Months Ended
 September 30, September 30,March 31,
 2017 2016 2017 201620232022
(in thousands)        (in thousands)  
Awards to key employeesAwards to key employees$2,156 $1,979 
Awards to non-employee directors $134
 $135
 $406
 $445
Awards to non-employee directors252 234 
Awards to key employees 662
 488
 1,202
 1,442
Total compensation expense 796
 623
 1,608
 1,887
Total compensation expense2,408 2,213 
Less: tax benefit (320) (251) (647) (760)Less: tax benefit(622)(571)
Share-based compensation amounts included in net income $476
 $372
 $961
 $1,127
Share-based compensation amounts included in net income$1,786 $1,642 
Non-employee DirectorsOfficers and Key Employees
Shares grantedOur Compensation Committee is authorized to non-employee directors are issued in advancegrant our key employees the right to receive awards of shares of our common stock, contingent upon the achievement of established performance goals and subject to SEC transfer restrictions once awarded. Our President and CEO has the right to issue awards of shares of our common stock, to other officers of the directors’ service periodsCompany, contingent upon various performance goals and subject to SEC transfer restrictions.

We currently have several outstanding multi-year performance plans, which are fully vested asbased upon the successful achievement of long-term goals, growth and financial results and comprise both market-based and performance-based conditions and targets. The fair value per share, tied to a performance-based condition or target, is equal to the market price per share on the grant date. We record a prepaid expense equalFor the market-based conditions, we used the Monte Carlo valuation to estimate the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2017, each of our non-employee directors received an annual retainer of 835 shares of common stock under the SICP for service as a director through the 2018 Annual Meeting of Stockholders.share granted.
A summary of the stock activity for our non-employee directors during the nine months ended September 30, 2017 is presented below:
  Number of Shares 
Weighted Average
Fair Value
Outstanding— December 31, 2016 —
 $—
Granted 7,515
 $71.80
Vested (7,515) $71.80
Outstanding— September 30, 2017 —
 $—
At September 30, 2017, there was approximately $314,000 of unrecognized compensation expense related to these awards. This expense will be recognized over the directors' remaining service periods ending April 30, 2018.
Key Employees
The table below presents the summary of the stock activity for awards to key employees for the ninethree months ended September 30, 2017:March 31, 2023:
Number of SharesWeighted Average
Fair Value
Outstanding—December 31, 2022204,149 $103.17 
Granted80,551 $128.01 
Vested(68,302)$91.59 
Expired(2,053)$94.64 
Outstanding—March 31, 2023214,345 $117.23 

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  Number of Shares 
Weighted Average
Fair Value
Outstanding— December 31, 2016 115,091
 $51.85
Granted 52,355
 $63.42
Vested (32,926) $38.88
Expired (1,878) $39.97
Outstanding— September 30, 2017 132,642
 $52.42
In February and May 2017, our Board of DirectorsDuring the three months ended March 31, 2023, we granted awards of 52,35580,551 shares of common stock to key employees under the SICP.SICP, including awards granted in February 2023 to key employees appointed in officer positions. The shares granted in February and May 2017 are multi-year awards that will vest at the end ofno later than the three-year service period ending December 31, 2019.2025. All of these stock awards are earned based upon the successful achievement of long-term goals, growth and financial results, which comprise bothare comprised of market-based and performance-based conditions or targets. The fair value of each performance-based condition or target is equal to the market price of our common stock on the grant date of each award. For the market-based conditions, we used the Black-Scholes pricing modelMonte Carlo valuation to estimate the fair value of each market-based award granted.
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AtIn March 2023, upon the election ofby certain of our executives, in March 2017, for shares that were awarded for the performance period ending December 31, 2016,executive officers, we withheld shares with a value at least equivalent to each such executive’sexecutive officer’s minimum statutory obligation for applicable income and other employment taxes remittedrelated to shares that vested and were paid in March 2023 for the cash to the appropriate taxing authorities, andperformance period ended December 31, 2022. We paid the balance of such awarded shares to each such executive.executive officer and remitted cash equivalent to the withheld shares to the appropriate taxing authorities. We withheld 10,26919,859 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.date. Total combined payments for the employees’ tax obligations to the taxing authorities were approximately $692,000.$2.5 million.

At September 30, 2017,March 31, 2023, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $10.4$27.4 million. At September 30, 2017,March 31, 2023, there was approximately $2.7$11.1 million of unrecognized compensation cost related to these awards, which is expected towill be recognized from 2017 through 2019.2025.
Stock Options
Non-employee Directors
Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the grant date. We did not have anyrecord a deferred expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year or less.
Our directors receive an annual retainer of shares of common stock options outstanding at September 30, 2017 or 2016, norunder the SICP for services rendered through the subsequent Annual Meeting of Shareholders.Accordingly, our directors that served on the Board as of May 2022 each received 652 shares of common stock, respectively, with a weighted average fair value of $130.36 per share.
In July 2022, we announced the appointment of two new non-employee directors to our Board. These newly appointed directors were any stock options issued during these periods.each granted a prorated share-based award of 526 shares through the SICP in accordance with the beginning of their service period. The associated expense is being recognized consistent with the methodology described above.

At March 31, 2023, there was approximately$0.1 million of unrecognized compensation expense related to shares granted to non-employee directors. This expense will be recognized over the remaining service period ending in May 2023.

11.Derivative Instruments

12.    Derivative Instruments

We use derivative and non-derivative contracts to engage in trading activities and manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane.propane and to mitigate interest rate risk. 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 EnergyOur natural gas gathering and transmission company has entered into contracts with producers to secure natural gas to meet its obligations. Purchases under these contracts typically either do not meet the definition of derivatives or are considered “normal purchases and normal sales” and are accounted for on an accrual basis. Our propane distribution and natural gas marketing operations may also enter into fair value hedges of their inventory or cash flow hedges of their future purchase commitments in order to mitigate the impact of wholesale price fluctuations. Occasionally, we may enter into interest rate swap agreements to mitigate risk associated with changes in short-term borrowing rates. As of September 30, 2017,March 31, 2023, our natural gas and electric distribution operations did not have any outstanding derivative contracts.
Hedging Activities in 2017
In 2017,

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Volume of Derivative Activity

As of March 31, 2023, the volume of our commodity derivative contracts were as follows:

Business unitCommodityContract TypeQuantity hedged (in millions)DesignationLongest Expiration date of hedge
SharpPropane (gallons)Purchases13.5Cash flow hedgesAugust 2025
SharpPropane (gallons)Sales3.2Cash flow hedgesDecember 2023

Sharp entered into severalfutures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 11.1 million gallonsthe propane volumes that are expected to be purchased from October 2017 through September 2018.and/or sold during the heating season. Under the futures and swap agreements, Sharp will receive the difference between (i) the index prices (Mont Belvieu prices in October 2017March 2023 through September 2018)August 2025) and (ii) the per gallon propane swap prices, of $0.5900 and $0.6750 per gallon, to the extent the index prices exceed the swapcontracted prices. If the index prices are lower than the swap price,contract prices, Sharp will pay the difference. We designated and accounted for these swap agreementsthe propane swaps as cash flow hedges, and there is no ineffective portion of these hedges. At September 30, 2017, the swap agreements had a fair value asset of approximately $1.5 million. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss). 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 $1.0 million from accumulated other comprehensive income (loss) related to our commodity cash flow hedges to earnings during the next 12-month period ended March 31, 2024.


PESCO entersInterest Rate Swap Activities

We manage interest rate risk by entering into natural gas futuresderivative contracts associatedto hedge the variability in cash flows attributable to changes in the short-term borrowing rates. In September 2022, we entered into an interest rate swap with a notional amount of $50.0 million through September 2025, with pricing of 3.98 percent.

Prior to August 2022, our short-term borrowing was based on the purchase30-day LIBOR rate. In August 2022, we amended and salerestated our revolver and transitioned the benchmark interest rate to the 30-day SOFR as a result of natural gas to other specific customers. These contracts have a two-year term,the impending expiration of LIBOR. Our prior interest rate swaps were cash settled monthly as the counter-party paid us the 30-day LIBOR rate less the fixed rate. Our interest rate swap is cash settled monthly as the counter-party pays us the 30-day SOFR rate less the fixed rate.

We designate and we accountedaccount for theminterest rate swaps as cash flow hedges. There is no ineffective portion of these hedges. At September 30, 2017, PESCO had a total of 4.0 million Dts hedged under natural gas futures contracts,Accordingly, unrealized gains and losses associated with a liability fair value of approximately $1.3 million accounted forthe interest rate swap are recorded as a cash flow hedge. The change in fair valuecomponent of the natural gas futures contracts is recorded as unrealized gain (loss) inaccumulated other comprehensive income (loss). When the interest rate swap settles, the realized gain or loss is recorded in the income statement and is recognized as a component of interest charges.
In August 2017, PESCO entered into natural gas swap agreements associated with ARM's financial contracts
Broker Margin

Futures exchanges have contract specific margin requirements that require the posting of cash or cash equivalents relating to mitigatetraded contracts. Margin requirements consist of initial margin that is posted upon the riskinitiation of fluctuations in wholesale natural gas prices associated with 12.0 million Dts PESCO expectsa position, maintenance margin that is usually expressed as a percent of initial margin, and variation margin that fluctuates based on the daily mark-to-market relative to purchase through January 2020.maintenance margin requirements. We accountedcurrently maintain a broker margin account for these swap agreements as cash flow hedges,Sharp which was classified within our Other Current Assets on the consolidated balance sheet with a liability fair valuebalance of approximately $412,000. The change$0.1 million as of March 31, 2023. At December 31, 2022, $0.1 million was classified in fair value ofOther Current Liabilities on the natural gas swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss).consolidated balance sheet.
The impact of PESCO's financial instruments that were not designated as hedges in our condensed consolidated financial statements for the nine months ended September 30, 2017 was $13,000, which was recorded as an increase in gas costs and is associated with 1.4 million Dts of natural gas. This presentation does not reflect the expected gains or losses arising from the underlying physical transactions associated with these financial instruments.



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Financial Statements Presentation
Hedging Activities in 2016
In 2016, Sharp entered into swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with 4.8 million gallons expected to be purchased through September 2017. Under the swap agreements, Sharp would receive the difference between the index prices (Mont Belvieu prices in October 2016 through September 2017) and the swap prices of $0.5225 and $0.5650 per gallon, to the extent the index prices exceeded the swap prices. If the index prices were lower than the swap price, Sharp would pay the difference. Sharp received a total of approximately $193,000, which represented the difference between the index prices and swap prices during the months of October 2016 through September 2017. We had accounted for these swap agreements as cash flow hedges.
In December 2016, Sharp paid a total of $33,000 to purchase a put option to protect against a decline in propane prices and related potential inventory losses associated with 630,000 gallons for its propane price cap program in the 2016-2017 heating season. The put option expired without being exercised because the propane prices did not fall below the strike price of $0.5650 per gallon in December 2016, January 2017, or February 2017. We accounted for the put option as a fair value hedge, and there was no ineffective portion of this hedge.
In January 2016, PESCO entered into a supplier agreement with Columbia Gas to provide natural gas supply for one of its local distribution customer pools. PESCO also assumed the obligation to store natural gas inventory to satisfy its obligations under the supplier agreement, which terminated on March 31, 2017. In conjunction with the supplier agreement, PESCO entered into natural gas futures contracts during the second quarter of 2016 in order to protect its natural gas inventory against market price fluctuations. We had previously accounted for these contracts as fair value hedges, with any ineffective portion being reported directly in earnings and offset by any associated gain (loss) on the inventory value being hedged. During the third quarter of 2016, we discontinued hedge accounting as the hedges were no longer highly effective. As of September 30, 2017, these contracts have all expired and are no longer reported on the balance sheet.

Commodity Contracts for Trading Activities
Shortly after the first quarter of 2017, Xeron wound down its operations. Xeron was previously engaged in trading activities using forward and futures contracts for propane and crude oil. These contracts were considered derivatives and were accounted for using the mark-to-market method of accounting. As of September 30, 2017, Xeron had no outstanding contracts that were accounted for as derivatives.
The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit risk-relatedcredit-risk-related contingency. The fairFair values of the derivative contracts recorded in the condensed consolidated balance sheets as of September 30, 2017March 31, 2023 and December 31, 2016,2022, are as follows: 
 Derivative Assets
  Fair Value As Of
(in thousands)Balance Sheet LocationMarch 31, 2023December 31, 2022
Derivatives designated as cash flow hedges
Propane swap agreementsDerivative assets, at fair value$1,801 $3,317 
Interest rate swap agreementsDerivative assets, at fair value345 452 
Total Derivative Assets (1)
$2,146 $3,769 
  
    Fair Value As Of
(in thousands) Balance Sheet Location September 30, 2017 December 31, 2016
Derivatives not designated as hedging instruments      
Propane swap agreements Derivative assets, at fair value $15
 $8
Put options Derivative assets, at fair value —
 9
       Natural gas swap contracts Derivative assets, at fair value 1
 —
Derivatives designated as cash flow hedges      
Natural gas futures contracts Derivative assets, at fair value —
 113
Propane swap agreements Derivative assets, at fair value 1,510
 693
Total asset derivatives   $1,526
 $823
(1) Derivative assets, at fair value include $1.2 million and $2.8 million in current assets in the condensed consolidated balance sheet at March 31, 2023 and December 31, 2022, respectively, with the remainder of the balance classified as long-term.

 Derivative Liabilities
  Fair Value As Of
(in thousands)Balance Sheet LocationMarch 31, 2023December 31, 2022
Derivatives designated as cash flow hedges
Propane swap agreementsDerivative liabilities, at fair value$871 $1,810 
Interest rate swap agreementsDerivative liabilities, at fair value563 405 
Total Derivative Liabilities (1)
$1,434 $2,215 
(1) Derivative liabilities, at fair value include $0.8 million and $0.6 million in current liabilities in the condensed consolidated balance sheet at March 31, 2023 and December 31, 2022, respectively, with the remainder of the balance classified as long-term.
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  Liability Derivatives
    Fair Value As Of
(in thousands) Balance Sheet Location September 30, 2017 December 31, 2016
Derivatives not designated as hedging instruments      
Natural gas futures contracts Derivative liabilities, at fair value $13
 $773
Derivatives designated as cash flow hedges      
Natural gas swap contracts Derivative liabilities, at fair value 412
 —
Natural gas futures contracts Derivative liabilities, at fair value 1,307
 —
Total liability derivatives   $1,732
 $773
The effects of gains and losses from derivative instruments on the condensed consolidated financial statements are as follows:
 Amount of Gain (Loss) on Derivatives
Location of GainFor the Three Months Ended March 31,
(in thousands)(Loss) on Derivatives20232022
Derivatives not designated as hedging instruments
Propane swap agreementsUnregulated propane and natural gas costs$— $56 
Derivatives designated as cash flow hedges
Propane swap agreementsRevenues733 (826)
Propane swap agreementsUnregulated propane and natural gas costs(127)3,547 
Propane swap agreementsOther comprehensive income (loss)(577)714 
Interest rate swap agreementsInterest expense65 — 
Interest rate swap agreementsOther comprehensive income (loss)(265)— 
Total$(171)$3,491 


22
  
   Amount of Gain (Loss) on Derivatives:
  Location of Gain For the Three Months Ended September 30, For the Nine Months Ended September 30,
(in thousands) (Loss) on Derivatives 2017 2016 2017 2016
Derivatives not designated as hedging instruments          
Realized gain on forward contracts and options (1)
 Revenue $—
 $(231) $112
 $44
Unrealized gain (loss) on forward contracts (1)
 Revenue —
 (2) —
 —
Natural gas futures contracts Cost of sales 286
 205
 907
 205
Propane swap agreements Cost of sales 15
 —
 11
 —
Natural gas swap contracts Cost of sales 1
 —
 1
 —
Derivatives designated as fair value hedges          
Put /Call option (2)
 Cost of sales —
 —
 (9) 73
       Natural gas futures contracts Natural gas inventory —
 —
 —
 (233)
Derivatives designated as cash flow hedges          
Propane swap agreements Cost of sales 198
 —
 663
 (364)
Propane swap agreements Other comprehensive income 1,590
 213
 814
 559
       Natural gas futures contracts Cost of sales (852) 105
 929
 464
       Natural gas futures contracts Other comprehensive income (loss) (1,296) (123) (1,420) 349
       Natural gas swap agreements Cost of sales 1
 —
 1
 —
       Natural gas swap agreements Other comprehensive loss (413) —
 (413) —
Total   $(470) $167
 $1,596
 $1,097
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(1)
All of the realized and unrealized gain (loss) on forward contracts represents the effect of trading activities on our condensed consolidated statements of income.
(2)
As a fair value hedge with no ineffective portion, the unrealized gains and losses associated with this call option are recorded in cost of sales, offset by the corresponding change in the value of propane inventory (hedged item), which is also recorded in cost of sales. The amounts in cost of sales offset to zero, and the unrealized gains and losses of this put option effectively changed the value of propane inventory on the condensed consolidated balance sheets.
13.    Fair Value of Financial Instruments
12.Fair Value of Financial Instruments
GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The hierarchy gives the highest priority to unadjusted quoted prices in active markets for identical assets or liabilities (Level 1 measurements) and the lowest priority to unobservable inputs (Level 3 measurements). The three levels of the fair value hierarchy are the following:
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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 value of the propane put/call options, propane and interest rate swap agreements 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.


Level 1: Unadjusted quoted prices in active markets that are accessible at the measurement date for identical, unrestricted assets or liabilities;
Level 2: Quoted prices in markets that are not active, or inputs which are observable, either directly or indirectly, for substantially the full term of the asset or liability; and
Level 3: Prices or valuation techniques requiring inputs that are both significant to the fair value measurement and unobservable (i.e. supported by little or no market activity).


Financial Assets and Liabilities Measured at Fair Value
The following table 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, 2017March 31, 2023 and December 31, 2016:2022:
 Fair Value Measurements Using:
   Fair Value Measurements Using:
As of September 30, 2017 Fair Value 
Quoted Prices in
Active Markets
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
As of March 31, 2023As of March 31, 2023Fair ValueQuoted Prices in
Active Markets
(Level 1)		Significant Other
Observable
Inputs
(Level 2)		Significant
Unobservable
Inputs
(Level 3)
(in thousands)        (in thousands)
Assets:        Assets:
Investments—equity securities $22
 $22
 $—
 $—
Investments—equity securities$24 $24 $— $— 
Investments—guaranteed income fund 642
 —
 —
 642
Investments—guaranteed income fund1,781 — — 1,781 
Investments—mutual funds and other 5,716
 5,716
 —
 —
Investments—mutual funds and other9,061 9,061 — — 
Total investments 6,380
 5,738

—

642
Total investments10,866 9,085 — 1,781 
Derivative assets 1,526
 —
 1,526
 —
Derivative assets2,146 — 2,146 — 
Total assets $7,906

$5,738

$1,526

$642
Total assets$13,012 $9,085 $2,146 $1,781 
Liabilities:        Liabilities:
Derivative liabilities $1,732
 $—
 $1,732
 $—
Derivative liabilities$1,434 $— $1,434 $— 
 

23
    Fair Value Measurements Using:
As of December 31, 2016 Fair Value 
Quoted Prices in
Active Markets
(Level 1)
 
Significant Other
Observable
Inputs
(Level 2)
 
Significant
Unobservable
Inputs
(Level 3)
(in thousands)        
Assets:        
Investments—equity securities $21
 $21
 $—
 $—
Investments—guaranteed income fund 561
 —
 —
 561
Investments—mutual funds and other 4,320
 4,320
 —
 —
Total investments 4,902
 4,341

—

561
Derivative assets 823
 —
 823
 —
Total assets $5,725

$4,341

$823

$561
Liabilities:        
Derivative liabilities $773
 $—
 $773
 $—

The following valuation techniques were used to measure the fair value of assets and liabilities in the tables above:
Level 1 Fair Value Measurements:
Investments - equity securities — The fair values of these trading securities are recorded at fair value based on unadjusted quoted prices in active markets for identical securities.
Investments - mutual funds and other — The fair values of these investments, comprised of money market and mutual funds, are recorded at fair value based on quoted net asset values of the shares.
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 Fair Value Measurements Using:
As of December 31, 2022Fair ValueQuoted Prices in
Active Markets
(Level 1)		Significant Other
Observable
Inputs
(Level 2)		Significant
Unobservable
Inputs
(Level 3)
(in thousands)
Assets:
Investments—equity securities$24 $24 $— $— 
Investments—guaranteed income fund1,853 — — 1,853 
Investments—mutual funds and other8,699 8,699 — — 
Total investments10,576 8,723 — 1,853 
Derivative assets3,769 — 3,769 — 
Total assets$14,345 $8,723 $3,769 $1,853 
Liabilities:
Derivative liabilities$2,215 $— $2,215 $— 
Level 2 Fair Value Measurements:
Derivative assets and liabilities — The fair values of forward contracts are measured using market transactions in either the listed or OTC markets. The fair value of the propane put/call options, swap agreements and natural gas futures contracts are measured using market transactions for similar assets and liabilities in either the listed or OTC markets.
Level 3 Fair Value Measurements:
Investments - guaranteed income fund — The fair values of these investments are recorded at the contract value, which approximates their fair value.
The following table sets forth the summary of the changes in the fair value of Level 3 investments for the ninethree months ended September 30, 2017March 31, 2023 and 2016:2022:
Three Months Ended March 31,
20232022
(in thousands) 
Beginning Balance$1,853 $2,036 
Purchases and adjustments— 131 
Transfers— — 
Distribution(81)(71)
Investment income9 8 
Ending Balance$1,781 $2,104 
 Nine Months Ended 
 September 30,
 2017 2016
(in thousands)   
Beginning Balance$561
 $279
Purchases and adjustments76
 120
Transfers—
 88
Distribution(2) (8)
Investment income7
 6
Ending Balance$642
 $485


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

At September 30, 2017,March 31, 2023, 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 shortnear-term maturities and because interest rates approximate current market rates (Level 32 measurement).
At September 30, 2017,March 31, 2023, long-term debt, includingwhich includes current maturities but excluding a capital lease obligation,excludes debt issuance costs, had a carrying value of approximately $211.4$678.8 million, compared to the estimated fair value of $597.5 million. This comparesAt December 31, 2022, long-term debt, which includes the current maturities but excludes debt issuance costs, had a carrying value of approximately $600.8 million, compared to a fair value of approximately $224.2 million,$505.0 million. The fair value was calculated using a discounted cash flow methodology that incorporates a market interest rate based on published corporate borrowing rates for debt instruments with similar terms and average maturities, and with adjustments for duration, optionality, and risk profile. At December 31, 2016, long-term debt, including the current maturities but excluding a capital lease obligation, had a carrying value of approximately $145.9 million, compared to the estimated fair value of approximately $161.5 million. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 32 measurement.


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14.    Long-Term Debt
13.Long-Term Debt
Our outstanding long-term debt is shown below:
March 31,December 31,
(in thousands)20232022
Uncollateralized senior notes:
5.93% note, due October 31, 2023$3,000 $3,000 
5.68% note, due June 30, 202611,600 11,600 
6.43% note, due May 2, 20284,200 4,200 
3.73% note, due December 16, 202812,000 12,000 
3.88% note, due May 15, 202935,000 35,000 
3.25% note, due April 30, 203264,750 66,500 
3.48% note, due May 31, 203850,000 50,000 
3.58% note, due November 30, 203850,000 50,000 
3.98% note, due August 20, 2039100,000 100,000 
       2.98% note, due December 20, 203470,000 70,000 
3.00% note, due July 15, 203550,000 50,000 
2.96% note, due August 15, 203540,000 40,000 
2.49% notes Due January 25, 203750,000 50,000 
2.95% notes Due March 15, 204250,000 50,000 
5.43% notes Due March 14, 203880,000 — 
Equipment security note
2.46% note, due September 24, 20318,298 8,517 
Less: debt issuance costs(1,075)(946)
Total long-term debt677,773 599,871 
Less: current maturities(21,489)(21,483)
Total long-term debt, net of current maturities$656,284 $578,388 
  September 30, December 31,
(in thousands) 2017 2016
FPU secured first mortgage bonds (1) :
    
9.08% bond, due June 1, 2022 $7,981
 $7,978
Uncollateralized senior notes:    
6.64% note, due October 31, 2017 2,727
 2,727
5.50% note, due October 12, 2020 8,000
 8,000
5.93% note, due October 31, 2023 19,500
 21,000
5.68% note, due June 30, 2026 26,100
 29,000
6.43% note, due May 2, 2028 7,000
 7,000
3.73% note, due December 16, 2028 20,000
 20,000
3.88% note, due May 15, 2029 50,000
 50,000
3.25% note, due April 30, 2032 70,000
 —
Promissory notes 97
 168
Capital lease obligation 2,425
 3,471
Less: debt issuance costs (446) (291)
Total long-term debt 213,384
 149,053
Less: current maturities (12,136) (12,099)
Total long-term debt, net of current maturities $201,248

$136,954

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

On March 15, 2022 we issued 2.95 percent Senior Notes due March 15, 2042 to MetLife in the aggregate principal amount of $50.0 million. We used the proceeds received from the issuances of the Senior Notes to reduce short-term borrowings under the Revolver and to fund capital expenditures. These Senior Notes have similar covenants and default provisions as our other Senior Notes, and have an annual principal payment beginning in the eleventh year after the issuance.

On March 14, 2023 we issued 5.43 percent Senior Notes due March 14, 2038 in the aggregate principal amount of $80.0 million and used the proceeds received from the issuances of the Senior Notes to reduce short-term borrowings under our Revolver credit facility and to fund capital expenditures. These Senior Notes have similar covenants and default provisions as our other Senior Notes, and have an annual principal payment beginning in the sixth year after the issuance.

Shelf Agreements
In October 2015, weWe have entered into theShelf Agreements with Prudential Shelf Agreement, under which we may request that Prudential purchase, through October 8, 2018, up to $150.0 million of Prudential Shelf Notes. The Prudential Shelf Notes have a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance. Prudential isMetLife, whom are under no obligation to purchase any unsecured debt. In February 2023, we amended our Shelf Agreements with Prudential and MetLife. The amended agreements expand the total borrowing capacity and extend the term of the agreements for an additional three years from the effective dates. The following table summarizes the current available capacity under our Shelf Agreements at March 31, 2023:

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(in thousands)Total Borrowing CapacityLess: Amount of Debt IssuedLess: Unfunded CommitmentsRemaining Borrowing Capacity
Shelf Agreements (1)
Prudential Shelf Agreement$405,000 $(300,000)$— $105,000 
MetLife Shelf Agreement200,000 (50,000)— 150,000 
Total Shelf Agreements as of March 31, 2023$605,000 $(350,000)$— $255,000 
(1) The Prudential and MetLife Shelf Notes. The interest rate and terms of payment of any series of the Prudential Shelf Notes will be determined at the time of purchase.Agreements both expire in February 2026.
In May 2016, Prudential confirmed and accepted our request that Prudential purchase $70.0 million of 3.25 percent Prudential Shelf Notes, which were issued on April 21, 2017. The proceeds received from this issuance of Prudential Shelf Notes were used to reduce short-term borrowings under the Revolver. The balance under the Revolver had accumulated over time as capital expenditures were temporarily financed.
The Prudential Shelf Agreement setsUncollateralized Senior Notes set forth certain business covenants to which we are subject when any Prudential Shelf Notenote is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.
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
15.    Short-Term Borrowings
We are authorized by our Board of Directors to borrow up to $150.0$400.0 million of short-term debt, as required. At March 31, 2023 and December 31, 2022, we had $94.1 million and $100.0$202.2 million, respectively, of our unsecured senior debt. The unsecured senior debt would haveshort-term borrowings outstanding at a fixedweighted average interest rate of 5.17 percent and a maturity date not to exceed 20 years from5.04 percent, respectively.

In August 2022, we amended both tranches of our Revolver, which now bear interest using SOFR as the date of issuance. MetLife and NYL are under no obligation to purchase any unsecured senior debt. Thebenchmark interest rate, plus a 10-basis point SOFR adjustment, in lieu of LIBOR which is being retired by financial institutions. In addition, the 364-day tranche was extended for the current year, expiring in August 2023. As part of these amendments, the parties agreed to eliminate the previous covenant capping the aggregate investments limit at $150.0 million where we maintain an ownership interest less than 50 percent. Additionally the 364-day tranche of the facility now offers a reduced interest margin similar to the five-year tranche for amounts borrowed in connection with new sustainable investments. All other terms and termsconditions remain unchanged. Borrowings outstanding under the sustainable investment sublimit of paymentthe 364-day tranche amounted to $9.4 million at March 31, 2023.

The availability of any seriesfunds under the Revolver is subject to conditions specified in the credit agreement, all of unsecured senior debtwhich we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in the Revolver's loan documents. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of March 31, 2023, we are in compliance with this covenant.

The 364-day tranche of the Revolver expires in August 2023 and the five-year tranche expires in August 2026, both of which are available to fund our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of our capital expenditures. Borrowings under both tranches of the Revolver are subject to a pricing grid, including the commitment fee and the interest rate charged based upon our total indebtedness to total capitalization ratio for the prior quarter. As of March 31, 2023, the pricing under the 364-day tranche of the Revolver included an unused commitment fee of 9 basis points and maintains an interest rate of 70 basis points over SOFR plus a 10 basis point SOFR adjustment. As of March 31, 2023, the pricing under the five-year tranche of the Revolver included an unused commitment fee of 9 basis points and an interest rate of 95 basis points over SOFR plus a 10 basis point SOFR adjustment.

Our total available credit under the Revolver at March 31, 2023 was $300.1 million. As of March 31, 2023, we had issued $5.8 million in letters of credit to various counterparties under the Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be determined atdrawn upon by the timecounterparties. The letters of purchase. As of September 30, 2017, no unsecured senior debt has been issuedcredit reduce the available borrowings under the MetLife and NYL Shelf Agreements.Revolver.

For additional information on interest rate swaps related to our short-term borrowings, see Note 12, Derivative Instruments.




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16.    Leases
We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These lease arrangements enable us to better conduct business operations in the regions in which we operate. Office space is leased to provide adequate workspace for our employees in several locations throughout our service territories. 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 also 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 not have resulted in material 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 consolidated balance sheet at March 31, 2023, 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 that would preclude our ability to pay dividends, obtain financing or enter into additional leases. As of March 31, 2023, 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 consolidated statements of income:

 Three Months Ended
March 31,
( in thousands)Classification20232022
Operating lease cost (1)
Operations expense$788$651
(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 condensed consolidated balance sheet at March 31, 2023 and December 31, 2022:
(in thousands)Balance sheet classificationMarch 31, 2023December 31, 2022
Assets 
Operating lease assetsOperating lease right-of-use assets$14,272 $14,421 
Liabilities
Current
Operating lease liabilitiesOther accrued liabilities$2,562 $2,552 
Noncurrent
Operating lease liabilitiesOperating lease - liabilities12,110 12,392 
Total lease liabilities $14,672 $14,944 


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The following table presents our weighted-average remaining lease terms and weighted-average discount rates for our operating leases at March 31, 2023 and December 31, 2022:

March 31, 2023December 31, 2022
Weighted-average remaining lease term (in years)
 
Operating leases8.408.54
Weighted-average discount rate
Operating leases3.5 %3.4 %


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, 2023 and 2022:

Three Months Ended
March 31,
(in thousands)20232022
Operating cash flows from operating leases$722 $609 

The following table presents the future undiscounted maturities of our operating and financing leases at March 31, 2023 and for each of the next five years and thereafter:
(in thousands)
Operating 
Leases (1)
Remainder of 2023$2,296 
20242,623 
20252,236 
20261,725 
20271,571 
20281,192 
Thereafter5,243 
Total lease payments16,886 
Less: Interest(2,214)
Present value of lease liabilities$14,672 
(1) Operating lease payments include $2.1 million related to options to extend lease terms that are reasonably certain of being exercised.



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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations
Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K for the year ended December 31, 2016,2022, 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 (this "Quarterly Report") that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and 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 eventevents or otherwise. These statements are subject to many risks and uncertainties. In addition to the risk factors described under Item 1A, Risk Factors in our 20162022 Annual Report on Form 10-K, the following important factors, among others, could cause actual future results to differ materially from those expressed in the forward-looking statements:
•state and federal legislative and regulatory initiatives (including deregulation) that affect cost and investment recovery, have an impact on rate structures, and affect the speed and the degree ofto which competition enteringenters 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 climate change, including the impact of greenhouse gas emissions or other legislation or regulations intended to address climate change;
•the impact of significant changes to current tax regulations and rates;
•the timing of certificatecertification 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 availability and reliability of adequate technology, including our ability to adapt to technological advances, effectively implement new technologies and manage the related costs;
•the inherent hazards and risks involved in transporting and distributing natural gas, electricity and propane;
•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 natural gas, electricity, propane or other external factors over which we have no control;fuels;
•risks related to cyber-attacks or cyber-terrorism that could disrupt our business operations or result in failure of information technology systems or result in the loss or exposure of confidential or sensitive customer, employee or Company information;
•adverse weather conditions, including the 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 weathereffect of competition on our businesses from other energy suppliers and other natural phenomena, including the economic, operational and other effectsalternative forms of hurricanes, ice storms and other damaging weather events;energy;
•the timing and extent of changes in commodity prices and interest rates;
the ability to establish and maintain key supply sources;
•the effect of spot, forward and future market prices on our various energy businesses;
the effect of competition on our businesses;
the capital-intensive nature of our regulated energy businesses;
•the extent of our success in connecting natural gas and electric supplies to our transmission systems, establishing and inmaintaining key supply sources, and expanding natural gas and electric markets;
the ability to construct facilities at or below estimated costs and within projected time frames;
•the creditworthiness of counterparties with which we are engaged in transactions;
•the resultscapital-intensive nature of financing efforts,our regulated energy businesses;
•our ability to access the credit and capital markets to execute our business strategy, including our ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;
•the ability to successfully execute, manage and integrate merger, acquisition or divestiture plans, regulatory or other limitations imposed as a result of a merger, acquisition or divestiture of assets or businesses and the success ofrelated regulatory or other conditions associated with the business following a merger, acquisition or divestiture;
•the impact on our costcosts 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;

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•the ability to continue to hire, train and retain appropriately qualified personnel;
•the availability of, and competition for, qualified personnel supporting our natural gas, electricity and propane businesses;
•the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; and
•the timingimpacts associated with a pandemic, including the duration and successscope of technological improvements;the pandemic the corresponding impact on our supply chains, our personnel, our contract counterparties, general economic conditions and growth, the financial markets and any costs to comply with governmental mandates.
risks related to cyber-attacks that could disrupt our business operations or result in failure of information technology systems;
the impact of significant changes to current tax regulations and rates; and
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the impact of future rate case proceedings.
Introduction
We are a diversifiedan energy delivery company engaged directly or throughin the distribution of natural gas, electricity and propane; the transmission of natural gas; the generation of electricity and steam, and in providing related services to our operating divisions and subsidiaries, in regulated and unregulated energy businesses.customers.

Our strategy is focused on growing earnings from a stable utilityregulated energy delivery foundation and investing in related businesses and services that provide opportunities for returns greater than traditional utility returns. We are focused on identifyingseek to identify and developingdevelop 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 elementsstrategy and create opportunities to continue our record of thistop tier returns on equity relative to our peer group. Our growth strategy include:
executingincludes the continued investment and expansion of our regulated operations that provide a capital investment program in pursuitstable base of growth opportunities that generate returns equal to or greater than our cost of capital;
expanding our energy distribution and transmission businesses organicallyearnings, as well as into new geographic areas;investments in other related non-regulated businesses and services including sustainable energy initiatives. By investing in these related business and services, we create opportunities to sustain our track record of higher returns, as compared to a traditional utility.
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.
Currently, our growth strategy is focused on the following platforms, including:
•Optimizing the earnings growth in our existing businesses, which includes organic growth, territory expansions, and new products and services as well as increased opportunities to transform the Company with a focus on people, process, technology and organizational structure.
•Identification and pursuit of additional pipeline expansions, including new interstate and intrastate transmission projects.
•Growth of Marlin Gas Services’ CNG transport business and expansion into LNG and RNG transport services as well as methane capture.
•Identifying and undertaking additional strategic propane acquisitions that provide a larger foundation in current markets and expand our brand and presence into new strategic growth markets.
•Pursuit of growth opportunities that enable us to utilize our integrated set of energy delivery businesses to participate in sustainable energy opportunities.
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.

Earnings per share information is presented on a diluted basis, unless otherwise noted.

The following discussions and those elsewherelater in this Quarterly Report on Form 10-Qthe document on operating income and segment results include the use of the term “gross margin",Adjusted Gross Margin which is determineda non-GAAP measure throughout our discussion on operating results. Adjusted Gross Margin is calculated by deducting the cost of sales from operating revenue. Cost of sales includes the purchased cost of natural gas, electricitypropane and propaneelectricity and the cost of labor spent on direct revenue-producing activities from operating revenues. The costs included in Adjusted Gross Margin exclude depreciation and excludes depreciation, amortization and accretion.certain costs presented in operations and maintenance expenses in accordance with regulatory requirements. Adjusted Gross marginMargin should not be considered an alternative to operating income or net income,Gross Margin under U.S. GAAP which are determined in accordance with GAAP.is defined as the excess of sales over cost of goods sold. We believe that gross margin,Adjusted 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 structurestructures for non-regulated segments.our unregulated energy operations. Our management uses gross marginAdjusted Gross Margin as one of the financial measures in measuring itsassessing our business units’ performance and has historically analyzed and reported gross margin information publicly.performance. Other companies may calculate gross marginAdjusted Gross Margin in a different manner.


Unless otherwise noted, earnings per share information is presented on a diluted basis.The below tables reconcile Gross Margin as defined under GAAP to our non-GAAP measure of Adjusted Gross Margin for the three months ended March 31, 2023 and 2022:


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For the Three Months Ended March 31, 2023
(in thousands)Regulated EnergyUnregulated EnergyOther and EliminationsTotal
Operating Revenues$142,270 $83,165 $(7,306)$218,129 
Cost of Sales:
Natural gas, propane and electric costs(55,288)(40,571)7,270 (88,589)
Depreciation & amortization(12,952)(4,234)3 (17,183)
Operations & maintenance expense (1)
(9,287)(8,476)5 (17,758)
Gross Margin (GAAP)64,743 29,884 (28)94,599 
Operations & maintenance expense (1)
9,287 8,476 (5)17,758 
Depreciation & amortization12,952 4,234 (3)17,183 
Adjusted Gross Margin (Non-GAAP)$86,982 $42,594 $(36)$129,540 
For the Three Months Ended March 31, 2022
(in thousands)Regulated EnergyUnregulated EnergyOther and EliminationsTotal
Operating Revenues$127,891 $101,292 $(6,303)$222,880 
Cost of Sales:
Natural gas, propane and electric costs(45,442)(58,008)6,270 (97,180)
Depreciation & amortization(13,086)(3,881)(10)(16,977)
Operations & maintenance expense (1)
(8,176)(7,063)(401)(15,640)
Gross Margin (GAAP)61,187 32,340 (444)93,083 
Operations & maintenance expense (1)
8,176 7,063 401 15,640 
Depreciation & amortization13,086 3,881 10 16,977 
Adjusted Gross Margin (Non-GAAP)$82,449 $43,284 $(33)$125,700 
(1) Operations & maintenance expenses within the Consolidated Statements of Income are presented in accordance with regulatory requirements and to provide comparability within the industry. Operations & maintenance expenses which are deemed to be directly attributable to revenue producing activities have been separately presented above in order to calculate Gross Margin as defined under U.S. GAAP.

2023 to 2022 Gross Margin (GAAP) Variance – Regulated Energy

Gross Margin (GAAP) for the Regulated Energy segment for the quarter ended March 31, 2023 was $64.7 million, an increase of $3.6 million, or 5.8 percent, compared to the same period in 2022. Higher gross margin was driven by contributions from our Florida natural gas base rate proceeding, organic growth in the natural gas distribution businesses, incremental contributions associated with regulated infrastructure programs, and continued pipeline expansion projects. These increases were partially offset by changes in customer consumption due to significantly warmer weather during the first quarter of 2023, higher depreciation and amortization related to recent capital investments and higher facilities, maintenance and outside services costs.

2023 to 2022 Gross Margin (GAAP) Variance – Unregulated Energy

Gross Margin (GAAP) for the Unregulated Energy segment for the quarter ended March 31, 2023 was $29.9 million, compared to $32.3 million for the same period in 2022. Primary drivers of the change in gross margin included changes in customer consumption due to significantly warmer weather during the first quarter of 2023, higher depreciation, amortization and property taxes related to recent capital investments and increased payroll, benefits and employee related expenses. These factors were partially offset by increased propane margins and fees and increased demand for our CNG, RNG and LNG services.

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Results of Operations for the Three and Nine Months ended September 30, 2017Ended March 31, 2023
Overview

Chesapeake Utilities Corporation is a Delaware corporation formed in 1947. We are a diversified energy company engaged, through our operating divisions and subsidiaries, in regulated energy, unregulated energy and other businesses. We operate primarily on the Delmarva Peninsula and in Florida, Pennsylvania and Ohioeast coast of the United States and provide natural gas distribution transmission, supply, gathering, processing and marketing;transmission; electric distribution and generation; propane gas distribution; mobile compressed natural gas services; steam generation; and other energy-related services.

Sustainability Initiatives

In February 2022, we published our inaugural sustainability report, and are actively working on an updated report to be published in 2023. We continue to remain steadfast in regard to our commitments, including the following:

•Maintaining a leading role in the journey to a lower carbon future in our service areas.

•Continuing to promote a diverse and inclusive workplace and further the sustainability of the communities we serve.

•Operating our businesses with integrity and the highest ethical standards.

These commitments guide our mission to deliver energy that makes life better for the people and communities we serve. They impact every aspect of the relationships we have with our stakeholders. We encourage our investors to review the report, which can be accessed on our website, and welcome feedback as we continue to enhance our sustainability disclosures.

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Operational Highlights

Our net income for the quarterthree months ended September 30, 2017March 31, 2023 was $6.8$36.3 million, or $0.42 per share. This represents an increase of $2.4 million, or $0.13$2.04 per share, compared to net income of $4.4$36.9 million, or $0.29$2.08 per share, reported for the same quarter in 2016.of 2022. Operating income increased $4.1 million for the three months ended September 30, 2017.first quarter of 2023 was $54.9 million, which was relatively consistent with the same period in 2022, despite significantly warmer temperatures in our northern service territories in 2023. Adjusted gross margin in the first quarter of 2023 was positively impacted by contributions from our Florida natural gas base rate proceeding, increased propane margins and fees, organic growth in the our natural gas distribution businesses, increased demand for CNG, RNG and LNG services, incremental contributions associated with regulated infrastructure programs, and continued pipeline expansion projects. These increases in adjusted gross margin were partially offset by reduced consumption experienced during the first quarter of 2023 as a result of unprecedented temperatures in our northern service territories. We recorded higher depreciation, amortization and property taxes related to continued capital investments, higher operating expenses associated primarily with growth initiatives, and increased payroll, benefits and employee expenses driven by the ongoing competitive labor market. We continued to actively manage our operating expenses to mitigate ongoing interest and other inflationary expense increases.

Three Months Ended
March 31,Increase
20232022(Decrease)
(in thousands, except per share data)   
Adjusted Gross Margin
  Regulated Energy segment$86,982 $82,449 $4,533 
  Unregulated Energy segment42,594 43,284 (690)
Other businesses and eliminations(36)(33)(3)
Total Adjusted Gross Margin$129,540 $125,700 $3,840 
Operating Income
  Regulated Energy segment$37,625 $34,681 $2,944 
  Unregulated Energy segment17,245 20,046 (2,801)
Other businesses and eliminations45 138 (93)
Total Operating Income54,915 54,865 50 
Other income, net276 913 (637)
Interest charges7,232 5,339 1,893 
Income from Before Income Taxes47,959 50,439 (2,480)
Income Taxes11,615 13,506 (1,891)
Net Income$36,344 $36,933 $(589)
Basic Earnings Per Share of Common Stock$2.05 $2.09 $(0.04)
Diluted Earnings Per Share of Common Stock$2.04 $2.08 $(0.04)

33
  Three Months Ended  
  September 30, Increase
  2017 2016 (decrease)
(in thousands except per share)      
Business Segment:      
Regulated Energy segment $15,168
 $13,115
 $2,053
Unregulated Energy segment (989) (3,080) 2,091
Other businesses and eliminations 60
 121
 (61)
Operating Income $14,239
 $10,156
 $4,083
Other income (expense), net 239
 (28) 267
Interest charges 3,321
 2,722
 599
Pre-tax Income 11,157
 7,406
 3,751
Income taxes 4,324
 2,990
 1,334
Net Income $6,833
 $4,416
 $2,417
Earnings Per Share of Common Stock      
Basic $0.42
 $0.29
 $0.13
Diluted $0.42
 $0.29
 $0.13
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Key variances between the thirdfirst quarter of 20172023 and the third quarter of 2016,2022, included:
(in thousands, except per share data)Pre-tax
Income		Net
Income		Earnings
Per Share
First Quarter of 2022 Reported Results$50,439 $36,933 $2.08 
Adjusting for Unusual Items:
One-time benefit associated with reduction in state tax rate— 1,284 0.07 
— 1,284 0.07 
Increased (Decreased) Adjusted Gross Margins:
Customer consumption - primarily resulting from weather(6,916)(5,241)(0.29)
Contribution from rates associated with Florida natural gas base rate proceeding*4,097 3,104 0.17 
Increased propane margins and service fees3,064 2,322 0.13 
Natural gas growth including conversions (excluding service expansions)1,522 1,153 0.06 
Increased margins related to demand for CNG/RNG/LNG services*1,288 976 0.05 
Contributions from regulated infrastructure programs*798 605 0.03 
Natural gas transmission service expansions*481 365 0.02 
Eastern Shore contracted rate adjustments(320)(242)(0.01)
4,014 3,042 0.16 
(Increased) Operating Expenses (Excluding Natural Gas, Propane, and Electric Costs):
Increased payroll, benefits and other employee-related expenses(1,142)(866)(0.05)
Depreciation, amortization and property taxes(1,125)(852)(0.05)
Increased facilities expenses, maintenance costs and outside services(1,061)(804)(0.05)
(3,328)(2,522)(0.15)
Interest charges(1,893)(1,435)(0.08)
Changes in Other income, net(706)(535)(0.03)
Net other changes(567)(423)(0.01)
(3,166)(2,393)(0.12)
First Quarter of 2023 Reported Results$47,959 $36,344 $2.04 
(in thousands, except per share data) Pre-tax
Income		 Net
Income		 Earnings
Per Share
Third Quarter of 2016 Reported Results $7,406
 $4,416
 $0.29
       
Adjusting for unusual items:      
Absence of Xeron's third quarter 2016 loss 545
 334
 0.02
Weather impact (333) (204) (0.01)
  212

130

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

2,601

0.17
 Decreased (Increased) Other Operating Expenses:      
Higher depreciation, asset removal and property tax costs due to new capital investments (1,710) (1,047) (0.07)
Lower outside services and facilities maintenance costs 1,678
 1,028
 0.07
Higher payroll expense (913) (559) (0.04)
Lower benefit and other employee-related expenses 295
 181
 0.01
Eight Flags' operating expenses 293
 179
 0.01
  (357)
(218)
(0.02)
       
Net other changes (349)
(96) (0.01)
  (349) (96) (0.01)
       
EPS impact of increase in outstanding shares due to September 2016 offering —
 —
 (0.02)
Third Quarter of 2017 Reported Results $11,157

$6,833

$0.42


*See the Major Projects and Initiatives table.




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Our net income for the nine months ended September 30, 2017 was $32.0 million, or $1.96 per share. This represents a decrease of $789,000, or $0.18 per share, compared to net income of $32.8 million, or $2.14 per share, reported for the same period in 2016. Operating income increased $303,000 for the nine months ended September 30, 2017.
  Nine Months Ended  
  September 30, Increase
  2017 2016 (decrease)
(in thousands except per share)      
Business Segment:      
Regulated Energy segment $51,915
 $52,660
 $(745)
Unregulated Energy segment 10,504
 9,267
 1,237
Other businesses and eliminations 161
 350
 (189)
Operating Income $62,580
 $62,277
 $303
Other expense, net (643) (68) (575)
Interest charges 9,133
 7,996
 1,137
Pre-tax Income 52,804
 54,213
 (1,409)
Income taxes 20,781
 21,401
 (620)
Net Income $32,023
 $32,812
 $(789)
Earnings Per Share of Common Stock      
Basic $1.96
 $2.14
 $(0.18)
Diluted $1.96
 $2.14
 $(0.18)





























Table of Contents

Key variances, between the nine months ended 2017 and the nine months ended 2016, included:
(in thousands, except per share data) Pre-tax
Income		 Net
Income		 Earnings
Per Share
Nine Months Ended September 30, 2016 Reported Results $54,213
 $32,812
 $2.14
       
Adjusting for unusual items:      
Weather impact (1,782) (1,081) (0.07)
Wind-down and absence of loss from Xeron operations (341) (207) (0.01)
  (2,123) (1,288) (0.08)
Increased Gross Margins:      
Eight Flags' CHP plant 4,721
 2,863
 0.19
Natural gas marketing 1,760
 1,067
 0.07
GRIP* 1,619
 982
 0.06
Natural gas growth (excluding service expansions) 1,574
 955
 0.06
Service expansions* 1,371
 831
 0.05
Pricing amendments to Aspire Energy's long-term agreements 1,143
 693
 0.04
Implementation of new rates for Eastern Shore* 1,020
 619
 0.04
Wholesale propane margins 728
 441
 0.03
Customer consumption (non-weather) 700
 425
 0.03
Implementation of Delaware Division settled rates 249
 151
 0.01
  14,885
 9,027
 0.58
Increased Other Operating Expenses:      
Higher depreciation, asset removal and property tax costs due to new capital investments (4,251) (2,578) (0.17)
Higher payroll expense (3,074) (1,864) (0.12)
Eight Flags' operating expenses (2,821) (1,711) (0.11)
Higher benefit and other employee-related expenses (1,669) (1,012) (0.07)
Higher regulatory expenses associated with rate filings (855) (519) (0.03)
Higher outside services and facilities maintenance costs (318) (193) (0.01)
  (12,988) (7,877) (0.51)
       
Interest charges (1,136) (689) (0.04)
Net other changes (47) 38
 (0.01)
  (1,183) (651) (0.05)
       
EPS impact of increase in outstanding shares due to September 2016 offering —
 —
 (0.12)
Nine Months Ended September 30, 2017 Reported Results $52,804

$32,023

$1.96

*See the Major Projects and Initiatives table.


Table of Contents

Summary of Key Factors
Recently Completed and Ongoing Major Projects and Initiatives
We constantly pursue and develop additional projects and initiatives to serve existing and new customers, and to further grow our businesses and earnings, with the intention to increase shareholder value. The following table summarizes gross margin for ourincludes the major projects and projects/initiatives recently completed and currently underway. Major projects and initiatives currently underway, but which willthat have generated consistent year-over-year adjusted gross margin contributions are removed from the table at the beginning of the next calendar year. Our practice is to add new projects and initiatives to this table once negotiations or details are substantially final and/or the associated earnings can be estimated.
Adjusted Gross Margin
Three Months EndedYear EndedEstimate for
March 31,December 31,Fiscal
(in thousands)20232022202220232024
Pipeline Expansions:
Guernsey Power Station$365 $263 $1,377 $1,486 $1,482 
Southern Expansion— — — 586 2,344 
Winter Haven Expansion139 33 260 576 626 
Beachside Pipeline Expansion— — — 1,825 2,451 
    North Ocean City Connector— — — — 200 
St. Cloud / Twin Lakes Expansion— — — 268 584 
Clean Energy (1)
247 — 126 1,009 1,009 
Wildlight26 — — 528 2,000 
Lake Wales— — — TBDTBD
Total Pipeline Expansions777 296 1,763 6,278 10,696 
CNG/RNG/LNG Transportation and Infrastructure3,521 2,233 11,100 12,521 12,348 
Regulatory Initiatives:
Florida GUARD program— — — TBDTBD
Capital Cost Surcharge Programs720 517 2,001 2,811 3,558 
Florida Rate Case Proceeding (2)
4,097 — 2,474 16,289 17,153 
Electric Storm Protection Plan206 — 486 1,663 3,032 
Total Regulatory Initiatives5,023 517 4,961 20,763 23,743 
Total$9,321 $3,046 $17,824 $39,562 $46,787 

(1) Includes adjusted gross margin generated from interim services.
(2) Includes adjusted gross margin during the first quarter of 2023 comprised of both interim rates and permanent base rates.

Detailed Discussion of Major Projects and Initiatives

Pipeline Expansions

Guernsey Power Station
Guernsey Power Station and our affiliate, Aspire Energy Express, are engaged in a firm transportation capacity agreement whereby Guernsey Power Station has constructed a power generation facility and Aspire Energy Express provides firm natural gas transportation service to this facility. Guernsey Power Station commenced construction of the project in October 2019, Aspire Energy Express completed construction of the gas transmission facilities in the future. Grossfourth quarter of 2021, and the facility went into service during the first quarter of 2023. The project generated additional adjusted gross margin reflects operating revenue less cost of sales, excluding depreciation, amortization$0.1 million for the three months ended March 31, 2023, and accretion (dollarsis expected to produce adjusted gross margin of approximately $1.5 million in thousands):2023 and beyond.

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 Gross Margin for the Period
 Three Months EndedNine Months Ended Year Ended      
 September 30,September 30, December 31, Estimate for
 2017 2016 Variance2017 2016 Variance 2016 2017 2018 2019
Major Projects and Initiatives Recently Completed                  
Capital Investment Projects$9,807
 $8,963
 $844
$29,533
 $21,822
 $7,711
 $29,819
 $35,346
 $31,814
 $32,724
     Eastern Shore Rate Case (1)
1,020
 —
 1,020
1,020
 —
 1,020
 —
 TBD
 TBD
 TBD
Settled Delaware Division Rate Case431
 469
 (38)1,596
 1,347
 249
 1,487
 2,250
 2,250
 2,250
Total Major Projects and Initiatives Recently Completed11,258
 9,432
 1,826
32,149
 23,169
 8,980
 31,306
 37,596
 34,064
 34,974
Future Major Projects and Initiatives                  
Capital Investment Projects                  
2017 Eastern Shore System Expansion—
 —
 —
—
 —
 —
 — 126
 9,313
 15,799
Northwest Florida Expansion—
 —
 —
—
 —
 —
 — —
 3,484
 5,127
Other Florida Pipeline Expansions—
 —
 —
—
 —
 —
 — —
 2,044
 2,542
Total Future Major Projects and Initiatives—
 —
 —
—
 —
 —
 — 126
 14,841
 23,468
Total$11,258
 $9,432
 $1,826
$32,149
 $23,169
 $8,980
 $31,306
 $37,722
 $48,905
 $58,442

(1) In January 2017, Southern Expansion
Eastern Shore plans to install a new natural gas driven compressor skid unit at its existing Bridgeville, Delaware compressor station that will provide 7,300 Dts of incremental firm transportation pipeline capacity. The project obtained FERC approval in December 2022 and is currently estimated to go into service in the fourth quarter of 2023. Eastern Shore expects the Southern Expansion project to generate annual adjusted gross margin of $0.6 million in 2023 and $2.3 million in 2024 and thereafter.

Winter Haven Expansion
In May 2021, Peninsula Pipeline filed a rate casepetition with the FERCFlorida PSC for approval of its Transportation Service Agreement with Florida Natural Gas Distribution for an incremental 6,800 Dts/d of firm service in the Winter Haven, Florida area. As part of this agreement, Peninsula Pipeline constructed a new interconnect with FGT and a new regulator station for Florida Natural Gas Distribution. Florida Natural Gas Distribution is using the additional firm service to recoversupport new incremental load due to growth in the costs of the 2016 System Reliability Project and other investments and expenses associated with the expansion,area, including providing service, most immediately, to a new can manufacturing facility, as well as reliability and safety initiatives completed by ESNG sinceoperational benefits to Florida Natural Gas Distribution’s existing distribution system in the area. In connection with Peninsula Pipeline’s new regulator station, Florida Natural Gas Distribution also extended its last rate settlementdistribution system to connect to the new station. This expansion was placed in 2012. Settlement discussions among Eastern Shore, intervenors and the FERC Staff are ongoing and future margin contributions will be provided once a settlement is finalized. Forservice in the third quarter of 2017,2022. The project generated additional adjusted gross margin of approximately $0.1 million in the first quarter and is expected to produce adjusted gross margin of approximately $0.6 million in 2023 and beyond.

Beachside Pipeline Expansion
In June 2021, Peninsula Pipeline and Florida City Gas entered into a portionTransportation Service Agreement for an incremental 10,176 Dts/d of firm service in Indian River County, Florida, to support Florida City Gas’ growth along the increaseIndian River's barrier island. As part of this agreement, Peninsula Pipeline has constructed approximately 11.3 miles of pipeline from its existing pipeline in rates, implemented subject to refund in August 2017, has been recorded as revenuethe Sebastian, Florida, area east under the Intercoastal Waterway and southward on the barrier island. Construction was completed and the remainder has been reserved pending the settlement. See Note 3, Rates and Other Regulatory Activities, forproject went into service in April 2023. We expect this extension to generate additional information.

Major Projects and Initiatives Recently Completed
The following table summarizesannual adjusted gross margin generated byof $1.8 million in 2023 and $2.5 million thereafter.

North Ocean City Connector
During the second quarter of 2022, we began construction of an extension of service into North Ocean City, Maryland. Our Delaware natural gas division and Sandpiper are installing approximately 5.7 miles of pipeline across southern Sussex County, Delaware to Fenwick Island, Delaware and Worcester County, Maryland. The project will reinforce our major projectsexisting system in Ocean City, Maryland and initiatives recently completed (dollarsallow for incremental growth along the pipeline. Adjusted gross margin in thousands):connection with this project is expected to be recognized contingent upon the completion and approval of our next rate case in Maryland. We expect this expansion to generate annual adjusted gross margin of $0.2 million beginning in 2024, with additional margin opportunities from incremental growth.

 Gross Margin for the Period
 Three Months EndedNine Months EndedYear Ended      
 September 30,September 30,December 31, Estimate for
 2017 2016 Variance2017 2016 Variance2016 2017 2018 2019
Capital Investment Projects:                 
Service Expansions:                 
Short-term contracts (Delaware)$1,283
 $3,080
 $(1,797)$5,140
 $8,271
 $(3,131)$11,454
 $5,642
 $1,096
 $1,096
Long-term contracts (Delaware)2,793
 862
 1,931
7,089
 2,587
 4,502
1,815
 7,611
 7,605
 7,583
Total Service Expansions4,076
 3,942
 134
12,229
 10,858
 1,371
13,269
 13,253
 8,701
 8,679
Florida GRIP3,393
 2,987
 406
10,002
 8,383
 1,619
11,552
 13,727
 14,407
 15,085
Eight Flags' CHP Plant2,338
 2,034
 304
7,302
 2,581
 4,721
4,998
 8,366
 8,706
 8,960
Total Capital Investment Projects9,807
 8,963
 844
29,533
 21,822

7,711
29,819
 35,346
 31,814
 32,724
Eastern Shore Rate Case (1)
1,020
 —
 1,020
1,020
 —
 1,020
—
 TBD TBD TBD
Settled Delaware Division Rate Case431
 469
 (38)1,596
 1,347
 249
1,487
 2,250
 2,250
 2,250
Total Major Projects and Initiatives Recently Completed$11,258
 $9,432
 $1,826
$32,149
 $23,169
 $8,980
$31,306
 $37,596
 $34,064
 $34,974
St.Cloud / Twin Lakes Expansion
Table of Contents

(1)In January 2017, Eastern ShoreJuly 2022, Peninsula Pipeline filed a rate casepetition with the FERCFlorida PSC for approval of its Transportation Service Agreement with FPU for an additional 2,400 Dt/day of firm service in the St. Cloud, Florida area. As part of this agreement, Peninsula Pipeline will construct a pipeline extension and regulator station for FPU. The extension will be used to recoversupport new incremental load due to growth in the costs ofarea, including providing service, most immediately, to the 2016 System Reliability Project and other investments and expenses associated with theresidential development, Twin Lakes. The expansion will also improve reliability and safety initiatives completed by ESNG since its last rate settlementprovide operational benefits to FPU’s existing distribution system in 2012. Settlement discussions among Eastern Shore, intervenors and the FERC Staff are ongoing andarea, supporting future margin contributions willgrowth. We expect this expansion to be provided once a settlement is finalized. Forin service in the thirdsecond quarter of 2017, a portion2023 and generate adjusted gross margin of $0.3 million in 2023 and $0.6 million thereafter.

Clean Energy Expansion
During the increase in rates, implemented subject to refund in August 2017, has been recorded as revenuefourth quarter of 2022, Clean Energy Fuels ("Clean Energy") and the remainder has been reserved pending the settlement. See Note 3, Rates and Other Regulatory Activities, for additional information.

Service Expansions
In August 2014, Eastern ShoreFlorida Natural Gas Distribution entered into a precedent agreement for firm transportation services associated with an electric power generatora CNG fueling station Clean Energy is constructing. We plan to install approximately 2.2 miles of main extension in KentDavenport, Florida to support the filling station. Construction is underway and is expected to be complete in the third quarter of 2023. Our subsidiary, Marlin Gas Services, is providing interim services to Clean Energy during the construction phase of the project. The project generated adjusted gross margin of approximately $0.2 million in the first quarter and is expected to produce adjusted gross margin of approximately $1.0 million in 2023 and beyond.

Wildlight Expansion
In August 2022, Peninsula Pipeline and FPU filed a joint petition with the Florida PSC for approval of its Transportation Service Agreement associated with the Wildlight planned community located in Nassau County, Delaware,Florida. The project enables us to providemeet the significant growing demand for service in Yulee, Florida. The agreement will enable us to build the project during

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the construction and build-out of the community, and charge the reservation rate as each phase of the project goes into service. Construction of the pipeline facilities will occur in two separate phases. Phase one consists of three extensions with associated facilities, and a 20-year OPT 90 ≤gas injection interconnect with associated facilities. Phase two will consist of two additional pipeline extensions. Various phases of the project commenced in the first quarter of 2023, with construction on the overall project continuing through 2025. This project is expected to contribute adjusted gross margin of approximately $0.5 million in 2023 and $2.0 million in 2024 and beyond.

Lake Wales Expansion
In February 2022, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with our Florida natural gas transmissiondivision, FPU for an additional 9,000 Dt/d of firm service in the Lake Wales, Florida area. Approval of the agreement by the Florida PSC will enable Peninsula Pipeline to begin executing on the acquisition of an existing pipeline in the area that will be utilized to serve our current natural gas customers as well as new customers. The Florida PSC approved the petition in April 2023.

CNG/RNG/LNG Transportation and Infrastructure

We have made a commitment to meet customer demand for 45,000 Dts/d deliverableCNG, RNG and LNG in the markets we serve.This has included making investments within Marlin Gas Services to be able to transport these products through its virtual pipeline fleet to customers. To date, we have also made an infrastructure investment in Ohio, enabling RNG to fuel a third party landfill fleet and to transport RNG to end use customers off our pipeline system. Similarly, we announced in March 2022, the opening of a high-capacity CNG truck and tube trailer fueling station in Port Wentworth, Georgia. As one of the largest public access CNG stations on the East Coast, it will offer a RNG option to customers in the near future. We constructed the station in partnership with Atlanta Gas Light, a subsidiary of Southern Company Gas.

We are also involved in various other projects, all at various stages and all with different opportunities to participate across the energy value chain. In many of these projects, Marlin will play a key role in ensuring the RNG is transported to one of our many pipeline systems where it will be injected. We include our RNG transportation services and infrastructure related adjusted gross margin from across the organization in combination with our CNG and LNG projects.

For the three months ended March 31, 2023, we generated $1.3 million in additional adjusted gross margin associated with the transportation of CNG and RNG by Marlin’s virtual pipeline and Aspire Energy’s Noble Road RNG pipeline. We estimate annual adjusted gross margin of approximately $12.5 million in 2023, and $12.3 million in 2024 for these transportation related services, with potential for additional growth in future years.

Full Circle Dairy
In February 2023, we announced plans to construct, own and operate a dairy manure RNG facility at Full Circle Dairy in Madison County, Florida. The project consists of a facility converting dairy manure to RNG and transportation assets to bring the gas to market. The first injection of RNG is projected to occur in the first half of 2024.

Planet Found Development
In late October 2022, we consummated the acquisition of Planet Found. Planet Found's farm scale anaerobic digestion pilot system and technology produces biogas from 1,200 tons of poultry litter annually, which can be used to create renewable energy in the form of electricity or upgraded to renewable natural gas. In addition to generating biogas, Planet Found’s nutrient capture system plays a major role in converting digestate into a nutrient-rich soil conditioner, which is distributed to bulk and retail markets under the brand Element Soil. The transaction will accelerate our efforts in converting poultry waste to renewable, sustainable energy while simultaneously improving the local environments in our service territories. The expertise, technologies and know-how can be leveraged for various scale projects across our geographic footprint.

Noble Road Landfill RNG Project
In October 2021, Aspire Energy completed construction of its Noble Road Landfill RNG pipeline project, a 33.1-mile pipeline, which transports RNG generated from the Noble Road landfill to Aspire Energy’s pipeline system, displacing conventionally produced natural gas. In conjunction with this expansion, Aspire Energy also upgraded an existing compressor station and installed two new metering and regulation sites. The RNG volume is expected to represent nearly 10 percent of Aspire Energy’s gas gathering volumes.





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Regulatory Initiatives

Florida GUARD Program
In February 2023, FPU filed a petition with the Florida PSC for approval of the GUARD program. GUARD is a proposed ten-year program to enhance the safety, reliability and accessibility of portions of our natural gas distribution system. We have identified various categories of eligible projects to be included in GUARD, which includes the relocation of mains and service lines located in rear easements and other difficult to access areas to the lateral servingfront of the customer's facility. street, the replacement of problematic distribution mains, service lines and M&R equipment, and system reliability projects. The petition is currently under review by the Florida PSC.

Capital Cost Surcharge Programs
In July 2016,December 2019, the FERC authorizedapproved Eastern Shore’s capital cost surcharge to become effective January 1, 2020. The surcharge, an approved item in the settlement of Eastern Shore’s last general rate case, allows Eastern Shore to construct and operaterecover capital costs associated with mandated highway or railroad relocation projects that required the project, which consistsreplacement of 5.4 miles of 16-inch pipeline looping and new compression capability in Delaware.existing Eastern Shore provided interim servicesfacilities. For the three months ended March 31, 2023, there was $0.2 million of incremental adjusted gross margin generated pursuant to this customer pending construction of facilities. Construction of the project was completed, and long-term service commenced in March 2017. This service generated an additionalprogram. Eastern Shore expects to produce adjusted gross margin of $106,000approximately $2.8 million in 2023 and $3.6 million in 2024 from relocation projects, which is ultimately dependent upon the timing of filings and the completion of construction.

Florida Natural Gas Base Rate Proceeding
In May 2022, our natural gas distribution businesses in Florida filed a consolidated natural gas rate case with the Florida PSC. The application included a request for the following: (i) permanent rate relief of approximately $24.1 million, effective January 1, 2023, (ii) a depreciation study also submitted with the filing; (iii) authorization to make certain changes to tariffs to include the consolidation of rates and rate structure across the businesses and to unify the Florida natural gas distribution businesses under FPU; (iv) authorization to retain the acquisition adjustment recorded at the time of the FPU merger in our revenue requirement; and (v) authorization to establish an environmental remediation surcharge for the purposes of addressing future expected remediation costs for FPU MGP sites. In August 2022, interim rates were approved by the Florida PSC in the amount of approximately $7.7 million on an annualized basis, effective for all meter readings in September 2022. The discovery process and related hearings were concluded during the ninefourth quarter of 2022 and briefs were submitted in the same quarter of 2022. In January 2023, the Florida PSC approved the application for consolidation and permanent rate relief of approximately $17.2 million on an annual basis. Actual rates in connection with the rate relief were approved by the Florida PSC in February 2023 with an effective date of March 1, 2023. For the three months ended September 30, 2017March 31, 2023, this proceeding generated adjusted gross margin of approximately $4.1 million and is expected to generate $16.3 million of additional adjusted gross margin in 2023 and $17.2 million in 2024.

Storm Protection Plan
In 2020, the Florida PSC implemented the SPP and SPPCR rules, which require electric utilities to petition the Florida PSC for approval of a Transmission and Distribution Storm Protection Plan that covers the utility’s immediate 10-year planning period with updates to the plan at least every 3 years. The SPPCR rules allow the utility to file for recovery of associated costs related to its SPP. Our Florida electric distribution operation's SPP and SPPCRC were filed during the first quarter of 2022 and approved in the fourth quarter of 2022 with modifications, by the Florida PSC. For the three months ended March 31, 2023, this initiative generated adjusted gross margin of approximately $0.2 million and is expected to generate $1.7 million of additional adjusted gross margin in 2023 and $3.0 million in 2024. We expect continued investment under the SPP going forward.

COVID-19 Regulatory Proceeding
In October 2020, the Florida PSC approved a joint petition of our natural gas and electric distribution utilities in Florida to establish a regulatory asset to record incremental expenses incurred due to COVID-19. The regulatory asset allows us to obtain recovery of these costs in the next base rate proceedings. Our Florida regulated business units reached a settlement with the Florida OPC in June 2021, enabling the business units to establish a regulatory asset of $2.1 million. This amount includes COVID-19 related incremental expenses for bad debt write-offs, personnel protective equipment, cleaning and business information services for remote work. Our Florida regulated business units are currently amortizing the amount over two years effective January 1, 2022 and recovering the regulatory asset through the Purchased Gas Adjustment and Swing Service mechanisms for the natural gas business units and through the Fuel Purchased Power Cost Recovery clause for the electric division. This results in additional adjusted gross margin of $1.0 million annually that is being offset by a corresponding amortization of regulatory asset expense, for both 2022 and 2023.


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Other Major Factors Influencing Adjusted Gross Margin
Weather Impact
For the first quarter of 2023, lower consumption driven primarily by weather resulted in a $6.9 million decrease in adjusted gross margin compared to the same period in 2016. There was no incremental margin change during the third quarter as the margin generated from the permanent services equated2022. The impact to the margin generated from providing interim services during the third quarter of 2016. This service is expected to generateadjusted gross margin was largely the result of $7.0 million for 2017 and between $5.8 million and $7.8 million annually through the remaining term of the agreement.
In December 2015, the FERC approved Eastern Shore's application to make certain meter tube and control valve replacements and related improvements at its TETLP interconnect facilities to increase natural gas receipts from TETLP by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. The project was completed and placedunprecedented temperatures in our northern service in March 2016. Approximately 35territories that were more than 20 percent of the increased capacity has been subscribed on a short-term firm service basis through October 2017. This service generated additionalhigher than historical averages. Assuming normal temperatures, as detailed below, gross margin of $80,000 and $1.3 million for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. The remaining capacity is available for firm or interruptible service.
GRIP
GRIP is a natural gas pipe replacement program approvedwould have been higher by the Florida PSC, designed to expedite the replacement of qualifying distribution mains and services (any material other than coated steel or plastic) to enhance the reliability and integrity of the Florida natural gas distribution systems. This program allows recovery, through regulated rates, of capital and other program-related costs, inclusive of a return on investment, associated with the replacement of the mains and services. Since the program's inception in August 2012, we have invested $110.5 million to replace 240 miles of qualifying distribution mains, including $7.6 million during the first nine months of 2017. The increased investment in GRIP generated additional gross margin of $406,000 and $1.6 million for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016.
Eight Flags' CHP plant
In June 2016, Eight Flags completed construction of a CHP plant on Amelia Island, Florida. This CHP plant, which consists of a natural-gas-fired turbine and associated electric generator, produces approximately 20 MWH of base load power and includes a heat recovery steam generator capable of providing approximately 75,000 pounds per hour of residual steam. In June 2016, Eight Flags began selling power generated from the CHP plant to FPU, pursuant to a 20-year power purchase agreement for distribution to its retail electric customers. In July 2016, it also started selling steam to the industrial customer that owns the property on which Eight Flags' CHP plant is located, pursuant to a separate 20-year contract.
The CHP plant is powered by natural gas transported by FPU through its distribution system and by Peninsula Pipeline. For the three and nine months ended September 30, 2017, Eight Flags and other affiliates of Chesapeake Utilities generated $304,000 and $4.7 million, in additional gross margin as a result of these services that began in June 2016. This amount includes gross margin of $7,000 and $534,000, for the three and nine months ended September 30, 2017, respectively, attributable to natural gas distribution and transportation services provided to the CHP plant by Chesapeake Utilities' regulated affiliates.
System Reliability Project
In July 2016, the FERC authorized Eastern Shore to construct and operate the System Reliability Project, which consisted of approximately 10.1 miles of 16-inch pipeline looping and auxiliary facilities in New Castle and Kent Counties, Delaware, and a new compressor at its existing Bridgeville compressor station in Sussex County, Delaware. A 2.5 mile looping segment was completed and placed into service in December 2016. The remaining looping and the new compressor were completed and placed into service in the second quarter of 2017. This project was included in Eastern Shore's January 2017 base rate case filing with the FERC. We began to recover the project's costs in August 2017, coinciding with the proposed effectiveness of new rates, subject to refund pending final resolution of the base rate case.

Table of Contents

Major Projects and Initiatives Currently Underway
Northwest Florida Expansion Project
Peninsula Pipeline and FPU's natural gas division are constructing a pipeline in Escambia County, Florida that will interconnect with FGT's pipeline. The project consists of 33 miles of 12-inch transmission line from the FGT interconnect that will be operated by Peninsula Pipeline and 8 miles of 8-inch lateral distribution lines that will be operated by Chesapeake Utilities' Florida natural gas division. We entered into agreements to serve two industrial customers and are currently marketing to other potential customers located close to the facilities. The estimated annual gross margin associated with this project, once in service, is approximately $5.1$5.4 million.

New Smyrna Beach, Florida Project
Peninsula Pipeline is constructing a pipeline in Volusia County, Florida that will interconnect with FGT's pipeline. The project consists of 14 miles of transmission line from the FGT interconnect that will be operated by Peninsula Pipeline and will serve FPU natural gas distribution customers. The estimated annual gross margin associated with this project, once in service, is approximately $1.4 million.
2017 Expansion Project
In May 2016, Eastern Shore submitted a request to the FERC to initiate the FERC's pre-filing process for its proposed 2017 Expansion Project. This project, which will expand Eastern Shore's firm service capacity by 26 percent, will provide 61,162 Dts/d of additional firm natural gas transportation service on Eastern Shore's pipeline system with an additional 52,500 Dts/d of firm transportation service at certain Eastern Shore receipt facilities pursuant to precedent agreements Eastern Shore entered into with existing customers. We expect to invest approximately $115.0 million in this expansion project, and for the project to generate approximately $15.8 million of gross margin in the first full year after the new transportation services go into effect. On October 4, 2017, the FERC issued a CP authorizing Eastern Shore to construct and operate the proposed 2017 expansion project.

Other major factors influencing gross margin

Weather and Consumption
Temperature variation in 2017 negatively impacted our earnings. Compared to the prior year, cooler temperatures in Florida during the third quarter of 2017, reduced gross margin by $333,000, and warmer temperatures in all of our service territories during the first nine months of 2017, reduced gross margin by $1.8 million, respectively. Warmer than normal temperatures for the quarter and nine months ended September 30, 2017 reduced gross margin by $193,000 and $4.3 million, respectively. The following table summarizes HDD and CDD variances from the 10-year average HDD/CDD ("Normal") for the three and nine months ended September 30, 2017 and 2016.

Table of Contents

HDD and CDD Information
 Three Months Ended   Nine Months Ended  
 September 30,   September 30,  
 2017 2016 Variance 2017 2016 Variance
Delmarva           
Actual HDD16
 11
 5
 2,262
 2,590
 (328)
10-Year Average HDD ("Delmarva Normal")62
 65
 (3) 2,845
 2,919
 (74)
Variance from Delmarva Normal(46) (54)   (583) (329)  
Florida           
Actual HDD—
 —
 —
 298
 514
 (216)
10-Year Average HDD ("Florida Normal")—
 —
 —
 602
 553
 49
Variance from Florida Normal—
 —
 
 (304) (39) 
Ohio    
     
Actual HDD 
80
 39
 41
 3,072
 3,596
 (524)
10-Year Average HDD ("Ohio Normal")92
 103
 (11) 3,866
 3,865
 1
Variance from Ohio Normal(12) (64)   (794) (269)  
Florida           
Actual CDD1,526
 1,679
 (153) 2,606
 2,792
 (186)
10-Year Average CDD ("Florida CDD Normal")1,542
 1,523
 19
 2,579
 2,548
 31
Variance from Florida CDD Normal(16) 156
   27
 244
  

Propane Operations
Our Florida and Delmarva propane distribution operations added $2.0 million and $1.4 million, in incremental margin for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016. Higher volumes sold to retail customers and improved margins due to effective supply management activities generated $905,000 and $440,000, in incremental margin, for the three months ended September 30, 2017, respectively, compared to the same period in 2016 and higher service revenue added $187,000 in additional margin, during the quarter.

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

Wholesale propane margins increased, generating additional gross margin of $271,000 and $728,000 for the three and nine months ended September 30, 2017, respectively, due primarily to higher volumes sold and improved margins resulting from supply management activities.

PESCO
PESCO provides natural gas supply and supply management services to residential, commercial, industrial and wholesale customers. PESCO operates primarily in Florida, on the Delmarva Peninsula, in Ohio, and, as a result of the recent acquisition of certain operating assets of ARM, in western Pennsylvania. PESCO competes with regulated utilities and other unregulated third-party marketers to sell natural gas supplies directly to residential, commercial and industrial customers through competitively-priced contracts. PESCO does not currently own or operate any natural gas transmission or distribution assets but sells gas that is delivered to retail, commercial or wholesale customers through affiliated and non-affiliated local distribution company systems and transmission pipelines.
In 2017, our Delmarva natural gas distribution operations entered into asset management agreements with PESCO to manage a portion of their natural gas transportation and storage capacity. The asset management agreements were effective April 1, 2017, and each has a three-year term, expiring on March 31, 2020. As a result of these agreements, PESCO manages capacity on regional pipelines as well as third-party storage contracts for our Delmarva natural gas distribution operations in conjunction with PESCO's asset management services.2023 and 2022.
For the three months ended September 30, 2017, PESCO's gross margin increased by $56,000. For the nine months ended September 30, 2017, PESCO generated additional gross margin of $1.8 million compared to the same period in 2016, as a result
Three Months Ended
March 31,
20232022Variance
Delmarva Peninsula
Actual HDD1,774 2,181 (407)
10-Year Average HDD ("Normal")2,285 2,255 30 
Variance from Normal(511)(74)
Florida
Actual HDD344 497 (153)
10-Year Average HDD ("Normal")505 497 8 
Variance from Normal(161)— 
Ohio
Actual HDD2,384 2,926 (542)
10-Year Average HDD ("Normal")2,965 2,912 53 
Variance from Normal(581)14 
Florida
Actual CDD323 195 128 
10-Year Average CDD ("Normal")192 197 (5)
Variance from Normal131 (2)
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of revenues from a supplier agreement with a customer in Ohio, which expired on March 31, 2017, as well as additional customers in Florida, partially offset by lower margin in the Mid-Atlantic region, primarily during the first quarter of 2017.
Xeron
As disclosed previously, Xeron's operations were wound down during the second quarter of 2017. As a result, Xeron did not generate an operating loss during the third quarter of 2017 and will not report operating results during the fourth quarter of 2017 or subsequent years. During the third quarter of 2016, Xeron generated a pre-tax loss of $486,000. On a year-to-date basis, Xeron's pre-tax operating loss increased by $375,000, compared to the same period in 2016, driven primarily by non-recurring employee severance costs and costs associated with the termination of leased office space in Houston, Texas. The Company does not anticipate incurring any additional costs that will have a material impact associated with winding down Xeron's operations.
Other Natural Gas Growth - Distribution OperationsAdjusted Gross Margin Growth
In addition to service expansions, the natural gas distribution operations on the Delmarva Peninsula generated $379,000 and $1.0 million in additional gross margin for the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016, due to an increase in residential, commercial and industrial customers served. The average number of residential customers served on the Delmarva Peninsula and in Florida increased by 3.7approximately 5.8 percent and 3.84.4 percent, respectively, during 2023. On the threeDelmarva Peninsula, a larger percentage of the adjusted gross margin growth was generated from residential growth given the expansion of gas into new housing communities and nine months ended September 30, 2017, respectively, comparedconversions to the same periods in 2016. The natural gas as our distribution operations ininfrastructure continues to build out. In Florida, generated $187,000as new communities continue to build out due to population growth and $1.2 million in additional gross margin forinfrastructure is added to support the three and nine months ended September 30, 2017, respectively, compared to the same periods in 2016, due primarily to an increase ingrowth, there is increased load from both residential customers as well as new commercial and industrial customerscustomers. The details are provided in Florida.the following table:


Regulatory Proceedings
Three Months Ended
March 31, 2023
(in thousands)Delmarva PeninsulaFlorida
Customer Growth:
Residential$610 $316 
Commercial and industrial212 384 
Total Customer Growth (1)
$822 $700 
Delaware Division Rate Case
In December 2016,(1) Customer growth amounts for Florida include the Delaware PSC approved a settlement agreement, which, among other things, provided for an increase ineffects of revised rates associated with our Delaware division revenue requirement of $2.25 million and a rate of return on common equity of 9.75 percent. The new authorized rates went into effect on January 1, 2017. For the three months ended September 30, 2017, compared to the same period in 2016, revenue decreased by $38,000, reflecting the variance between settled and interim rates. For the nine months ended September 30, 2017 compared to the same period in 2016, we recorded incremental revenue of approximately $249,000 related to the rate case. Any amounts collected through 2016 interim rates in excess of the respective portion of the $2.25 million were refunded to the ratepayers in March 2017.
Eastern Shore Rate Case
In January 2017, Eastern Shore filed anatural gas base rate proceeding with the FERC, as required by the terms of its 2012 rate case settlement agreement. Eastern Shore's proposed rates were based on the mainline cost of service of approximately $60.0 million, resulting in an overall requested revenue increase of approximately $18.9 million and a requested rate of return on common equity of 13.75 percent. The filing includes incremental rates for the White Oak Lateral Project and White Oak Mainline Expansion Project, which benefits a single customer. Eastern Shore also proposed to revise its depreciation rates and negative salvage rate based on the results of independent, third-party depreciation and negative salvage value studies. In March 2017, the FERC issued an order suspending the tariff rates for the usual five-month period.proceeding.
On August 1, 2017, Eastern Shore implemented new rates, subject to refund based upon the outcome of the rate proceeding.  Eastern Shore recorded incremental revenue of approximately $1.0 million for the three and nine months ended September 30, 2017, and established a regulatory liability to reserve a portion of the total incremental revenues generated by the new rates until resolution of the rate case.  Settlement discussions continue with other parties to the case.
Investing for Future Growth
To support and continue our growth, we have expanded, and will continue to expand, our resources and capabilities. Eastern Shore previously expanded, and continues to significantly expand, its transmission system, which require additional staffing. We requested recovery of most of Eastern Shore's increased staffing costs in its 2017 rate case.Growth in non-regulated energy businesses, including Aspire Energy, PESCO and Eight Flags, also requires additional staff as well as corporate resources to support the increased level of business operations. Finally, to allow us to continue to identify and move growth initiatives forward and to assist in developing additional initiatives, staffing and resources have been added in our corporate shared services departments. For the three and nine months ended September 30, 2017, our staffing and associated costs increased by $617,000 and $4.7 million, respectively, or three percent and nine percent, respectively, compared to the same periods in 2016. We are prudently managing the pace and magnitude of the investments being made, while ensuring that we appropriately expand our human resources and systems capabilities to capitalize on future growth opportunities.





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Regulated Energy Segment


For the quarter ended September 30, 2017March 31, 2023, compared to the quarter ended September 30, 2016March 31, 2022:

Three Months Ended
March 31,Increase
20232022(Decrease)
(in thousands)  
Revenue$142,270 $127,891 $14,379 
Regulated natural gas and electric costs55,288 45,442 9,846 
Adjusted gross margin (1)
86,982 82,449 4,533 
Operations & maintenance30,336 29,149 1,187 
Depreciation & amortization12,952 13,086 (134)
Other taxes6,069 5,533 536 
Total operating expenses49,357 47,768 1,589 
Operating income$37,625 $34,681 $2,944 
(1)Adjusted Gross Margin is a non-GAAP measure utilized by Management to review business unit performance. For a more detailed discussion on the differences between Gross Margin (GAAP) and Adjusted Gross Margin, see the Reconciliation of GAAP to Non-GAAP Measures presented above.
  Three Months Ended  
  September 30, Increase
  2017 2016 (decrease)
(in thousands)      
Revenue $69,703
 $70,019
 $(316)
Cost of sales 22,794
 24,644
 (1,850)
Gross margin 46,909
 45,375
 1,534
Operations & maintenance 21,149
 22,912
 (1,763)
Depreciation & amortization 7,338
 6,346
 992
Other taxes 3,254
 3,002
 252
Other operating expenses 31,741
 32,260
 (519)
Operating income $15,168
 $13,115
 $2,053

Operating income for the Regulated Energy segment for the three months ended September 30, 2017first quarter of 2023 was $15.2$37.6 million, an increase of $2.1$2.9 million, or 8.5 percent, over the same period in 2022. Higher operating income reflects contributions from our Florida natural gas base rate proceeding, organic growth in our natural gas distribution businesses, incremental contributions associated with regulated infrastructure programs, and continued pipeline expansion projects. These increases were partially offset by changes in customer consumption due to significantly warmer weather during the first quarter of 2023. Operating expenses increased by $1.6 million compared to the same period in 2016. The increased operating income resulted from increased gross margin of $1.5 millionprior year quarter primarily due to higher depreciation and a decrease in operating expenses of $519,000.amortization related to recent capital investments and higher facilities, maintenance and outside services costs.
Gross Margin
Items contributing to the quarter-over-quarter increase of $1.5 million, or 3.4 percent, in adjusted gross margin are listed in the following table:
(in thousands)
Rate changes associated with the Florida natural gas base rate proceeding (1)
$4,097 
Natural gas growth including conversions (excluding service expansions)1,522 
Contributions from regulated infrastructure programs798 
Natural gas transmission service expansions481 
Changes in customer consumption - primarily related to weather(1,865)
Eastern Shore contracted rate adjustments(320)
Other variances(180)
Quarter-over-quarter increase in adjusted gross margin**$4,533
(in thousands) 
Gross margin for the three months ended September 30, 2016$45,375
Factors contributing to the gross margin increase for the three months ended September 30, 2017: 
Implementation of Eastern Shore rates1,020
Additional Revenue from GRIP in Florida406
Natural gas growth (excluding service expansions)347
Other(239)
Gross margin for the three months ended September 30, 2017$46,909
(1) Includes adjusted gross margin comprised of both interim rates and permanent base rates that became effective in March 2023.

The following is a narrative discussion provides further detail and analysis of the significant items in the foregoing table, whichtable.

Rate Changes Associated with the Florida Natural Gas Base Rate Proceeding
In August 2022, the Florida PSC approved interim rates starting in September 2022. In March 2023, we believe is necessary to understandobtained a final rate order in connection with the information disclosed in the table.
Implementation of Eastern Shore Rates
Eastern Shore generatedFlorida natural gas base rate proceeding with permanent rates effective on March 1, 2023. These interim and permanent rates contributed additional adjusted gross margin of $1.0 million from the implementation of new rates as a result of its rate case filing. See $4.1 million. Please refer to Note 3,5, Rates and Other Regulatory Activities, toin the condensed consolidated financial statements for additional details.information.
Additional Revenue from GRIP in Florida
Increased investment in GRIPNatural Gas Distribution Customer Growth
We generated additional adjusted gross margin of $406,000$1.5 million from natural gas customer growth. Adjusted gross margin increased by $0.7 million in Florida and $0.8 million on the Delmarva Peninsula for the three months ended September 30, 2017,March 31, 2023, as compared to the same period in 2016.
Natural Gas Growth (excluding service expansions)
Increased gross margin of $347,000 from other growth in natural gas (excluding service expansions) was generated primarily from the following:
$379,000 from a four-percent increase in the average number of residential customers in the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers;
$187,000 from Florida natural gas customer growth,2022, due primarily to new services to commercialresidential customer growth of 4.4 percent and industrial customers;5.8 percent in Florida and
which were partially offset by $219,000 in decreased margin from Eastern Shore's interruptible services. on the Delmarva Peninsula, respectively.

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Other Operating ExpensesContributions from Regulated Infrastructure Programs
Other operating expenses decreased by $519,000. The significant factors contributing to the decrease in other operating expenses included:
$1.6Contributions from regulated infrastructure programs generated incremental adjusted gross margin of $0.8 million in lower coststhe first quarter of 2023. The increase in adjusted gross margin was primarily related to outside servicescontinued investment in the Florida Gas Reliability Infrastructure Program, Eastern Shore's capital surcharge program, FPU Electric's storm protection plan, and facilitiesthe Elkton Gas STRIDE Plan. Refer to Note 5, Rates and maintenance costs, due primarilyOther Regulatory Activities,in the condensed consolidated financial statements for additional information.

Natural Gas Transmission Service Expansions
We generated increased adjusted gross margin of $0.5 million for the three months ended March 31, 2023 from natural gas transmission service expansions including, Peninsula Pipeline's Twin Lakes and Winter Haven projects, FPU natural gas' Clean Energy project and Aspire Energy Express' Guernsey pipeline expansion.

Changes in Customer Consumption
Significantly warmer weather contributed to lower consulting and service contractor costs;
$437,000changes in lower benefits and employee-related costs (since we are self-insured for healthcare, benefits costs fluctuate depending upon filed claims);
$1.4weather-related consumption resulting in reduced adjusted gross margin of $1.9 million in higher depreciation, asset removalthe first quarter of 2023. The Delmarva Peninsula and property tax costs associated with recent capital investments.

ForFlorida were warmer by approximately 19 percent and 31 percent, respectively, for the Nine Months Ended September 30, 2017 compared to the ninethree months ended September 30, 2016

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

64,673
 3,196
Depreciation & amortization 21,365
 18,909
 2,456
Other taxes 9,998
 9,204
 794
Other operating expenses 99,232
 92,786
 6,446
Operating income $51,915
 $52,660
 $(745)
Operating income for the Regulated Energy segment for the nine months ended September 30, 2017 was $51.9 million, a decrease of $745,000March 31, 2023 compared to the same period in 2016. The decreased operating income was due2022.

Eastern Shore Contracted Rate Adjustments
Adjustments to an increasecontracted rates charged to various Eastern Shore customers resulted in reduced adjusted gross margin of $5.7$0.3 million offset by higher operating expensesduring the first quarter of $6.4 million. Of the total $6.4 million increase in operating expenses, $4.7 million is associated with Eastern Shore's recently completed projects as well as initiatives underway.2023.
Gross Margin
Operating Expenses
Items contributing to the period-over-periodquarter-over-quarter increase in operating expenses are listed in the following table:
(in thousands)
Depreciation, amortization and property taxes$550 
Increased facilities expenses, maintenance costs and outside services382 
Increased payroll, benefits and other employee-related expenses293 
Other variances364 
Quarter-over-quarter increase in operating expenses$1,589

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Unregulated Energy Segment

For the quarter ended March 31, 2023, compared to the quarter ended March 31, 2022:
Three Months Ended
March 31,Increase
20232022(Decrease)
(in thousands)   
Revenue$83,165 $101,292 $(18,127)
Unregulated propane and natural gas costs40,571 58,008 (17,437)
Adjusted gross margin (1)
42,594 43,284 (690)
Operations & maintenance19,614 18,090 1,524 
Depreciation & amortization4,234 3,881 353 
Other taxes1,501 1,267 234 
Total operating expenses25,349 23,238 2,111 
Operating Income$17,245 $20,046 $(2,801)
(1) Adjusted Gross Margin is a non-GAAP measure utilized by Management to review business unit performance. For a more detailed discussion on the differences between Gross Margin (GAAP) and Adjusted Gross Margin, see the Reconciliation of GAAP to Non-GAAP Measures presented above.

Operating results for the Unregulated Energy segment for the first quarter of 2023 experienced a reduction of $2.8 million or 3.9 percent,compared to the same period in 2022. Adjusted gross margin in the Unregulated Energy segment during the first quarter was impacted by changes in customer consumption due to significantly warmer weather in our Mid-Atlantic service territories. Additionally, we experienced increased operating expenses associated with higher payroll, benefits and employee related expenses driven by the continued competition in the current labor market, depreciation, amortization and property taxes and increased costs for facilities, maintenance, and outside services. These factors were partially offset by expanded propane margins and fees and increased demand for CNG, RNG and LNG services.
Items contributing to the quarter-over-quarter increase in adjusted gross margin are listed in the following table:
(in thousands) 
Gross margin for the nine months ended September 30, 2016$145,446
Factors contributing to the gross margin increase for the nine months ended September 30, 2017: 
Additional revenue from GRIP in Florida1,619
Natural gas growth (excluding service expansions)1,574
Service expansions1,371
Customer consumption - weather and other(1,249)
Implementation of Eastern Shore rates1,020
Service to Eight Flags534
Implementation of Delaware Division Rates249
Other583
Gross margin for the nine months ended September 30, 2017$151,147
(in thousands)
Propane Operations
Propane customer consumption - primarily weather related$(4,543)
Increased propane margins and service fees3,064 
CNG/RNG/LNG Transportation and Infrastructure
Increased demand for CNG/RNG/LNG Services1,288 
Aspire Energy
Reduced customer consumption - primarily weather related(508)
Other variances9 
Quarter-over-quarter decrease in adjusted gross margin$(690)
The following is a narrative discussion provides further detail and analysis of the significant items in the foregoing table, which we believe is necessary to understand the information disclosed in the table.
Additional Revenue from GRIP in FloridaPropane Operations
Increased investment in GRIP generated additional•Propane customer consumption - Adjusted gross margin of $1.6fell by $4.5 million due to reduced customer consumption as weather on the Delmarva Peninsula and in Florida was approximately 19 and 31 percent, warmer relative to the prior year.
•Increased Propane Margins and Service Fees - Adjusted gross margin increased by $3.1 million for the ninethree months ended September 30, 2017,March 31, 2023, mainly due to increased margins and customer service fees. Propane margins also increased due to gains with our SWAP agreements. These market conditions, which include market pricing and 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.


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CNG/RNG/LNG Transportation and Infrastructure
•Increased demand for CNG/RNG/LNG services - Adjusted gross margin increased by $1.3 million during the first quarter as compared to the same period in 2016.the prior year due to higher demand for CNG hold services and contributions from an Aspire RNG project .
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Aspire Energy

Natural Gas Growth (Excluding Service Expansions)
Increased•Reduced Customer Consumption - Adjusted gross margin of $1.6was reduced by $0.5 million from growth (excluding service expansions)due to reduced demand as weather in Ohio was generated primarily from the following:
$1.2 million from Florida natural gas customer growth, due primarily to new services to commercial and industrial customers; and
$1.0 million from a four-percent increase in the average number of residential customers in the Delmarva natural gas distribution operations, as well as growth in the number of commercial and industrial customers.
Service Expansions
Eastern Shore generated increased gross margin of $1.4 million from natural gas service expansions related to short-term firm service that commenced in March 2016. Following certain measurement and related improvements to Eastern Shore's interconnect with TETLP, Eastern Shore's natural gas receipt capacity from TETLP increased by 53,000 Dts/d, for a total capacity of 160,000 Dts/d. The remaining capacity is available for firm or interruptible service.
Customer Consumption - Weather and Other
Gross margin decreased by $1.2 million from lower customer consumption of electricity and natural gas, due primarily toapproximately 19 percent warmer temperatures in Florida and on the Delmarva Peninsula. Because Maryland and Sandpiper Energy rates include a weather normalization adjustment for residential heating and smaller commercial heating customers, these operations experienced minimal impact from the warmer weather during the first nine months of 2017.
Implementation of Eastern Shore Rates
Eastern Shore generated additional gross margin of $1.0 million from implementation of new rates as a result of its rate case filing. See Note 3, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.
Service to Eight Flags
We generated additional gross margin of $534,000 in the nine months ended September 30, 2017, compared toover the same period in 2016, from new natural gas transmission and distribution services provided by our affiliates to Eight Flags' CHP plant.the prior year.
Implementation of Delaware Division Rates
Our Delaware Division generated additional gross margin of $249,000 as a result of the settlement of the rate case. See Note 3, Rates and Other Regulatory Activities, to the condensed consolidated financial statements for additional details.
Other Operating Expenses
Other operating expenses increased by $6.4 million. The significant components of the increase in other operating expenses included:
$3.5 million in higher depreciation, asset removal and property tax costs associated with recent capital investments;
$1.6 million in higher payroll expenses for addition personnel to support growth;
$855,000 in increased regulatory expenses, due primarily to costs associated with Eastern Shore’s rate case filing in 2017; and
$722,000 in higher benefits and employee-related costs in 2017 (since we are self-insured for healthcare, benefits costs fluctuate depending upon claims filed).

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Unregulated Energy Segment

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

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


Operating loss for the Unregulated Energy segment for the three months ended September 30, 2017 was $989,000, compared to the operating loss of $3.1 million for same period in 2016. The decreased operating loss was due to an increase in gross margin of $3.1 million, which was offset by a $1.0 million increase in operating expenses.
Gross MarginExpenses
Items contributing to the quarter-over-quarter increase of $3.1 million in gross marginoperating expenses are listed in the following table:
(in thousands)
Increased payroll, benefits and other employee-related expenses$825 
Increased facilities expenses, maintenance costs and outside services597 
Increased depreciation, amortization and property tax costs587 
Other variances102 
Quarter-over-quarter increase in operating expenses$2,111



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

The following is a narrative discussion of the significant items in the foregoing table, which we believe is necessary to understand the information disclosed in the table.
Customer Consumption - Weather and Other
Gross margin increased by $1.2 million, due primarily to increased sales volumes of propane to wholesale and retail customers on the Delmarva Peninsula and higher retail propane sales volumes in Florida due primarily to the timing of deliveries.
Retail Propane Margins
Gross margin increased by $440,000, due primarily to favorable supply management activities.
Eight Flags
Eight Flags' CHP plant, which commenced operations in June 2016, generated $297,000 in additional gross margin due primarily to Eight Flags being fully on-line in the third quarter of 2017.
Pricing Amendments to Aspire Energy Long-Term Agreements
An increase in gross margin of $291,000 was due to pricing amendments to long-term sales agreements.
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Wholesale Propane Margins
Gross margin increased by $271,000, due primarily to favorable supply management activities for the Delmarva propane distribution operations.
Xeron
The absence of the prior year operating loss increased gross margin by $233,000.
Other Operating Expenses
Other operating expenses increased by $1.0 million. The significant components of the increase in other operating expenses included:
$730,000 in higher staffing and associated costs for additional personnel to support growth (since we are self-insured for healthcare, benefits costs fluctuate depending upon claims filed);
$347,000 in higher depreciation, amortization and property tax costs due to increased capital investments and amortization of intangible assets acquired through acquisitions in 2017; and
$293,000 in expenses associated with the incremental margin from Eight Flags

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

  Nine Months Ended  
  September 30, Increase
  2017 2016 (decrease)
(in thousands)      
Revenue $220,462
 $136,361
 $84,101
Cost of sales 166,635
 90,981
 75,654
Gross margin 53,827
 45,380
 8,447
Operations & maintenance 34,971
 30,136
 4,835
Depreciation & amortization 5,833
 4,512
 1,321
Other taxes 2,519
 1,465
 1,054
Total operating expenses 43,323
 36,113
 7,210
Operating income $10,504
 $9,267
 $1,237
Operating income for the Unregulated Energy segment for the nine months ended September 30, 2017 was $10.5 million, an increase of $1.2 million compared to the same period in 2016. The increased operating income was due to an increase in gross margin of $8.4 million, which was partially offset by a $7.2 million increase in operating expenses.
Gross Margin
Items contributing to the period-over-period increase of $8.4 million in gross margin are listed in the following table:
(in thousands)  
Gross margin for the nine months ended September 30, 2016 $45,380
Factors contributing to the gross margin increase for the nine months ended September 30, 2017:  
Eight Flags' CHP plant 4,186
Natural Gas Marketing 1,760
Pricing Amendments to Aspire Energy's Long-Term Agreements 1,143
Propane Wholesale Sales 728
Customer consumption - weather and other 168
Other 462
Gross margin for the nine months ended September 30, 2017 $53,827

The following is a narrative discussion of the significant items in the foregoing table, which we believe is necessary to understand the information disclosed in the table.
Eight Flags
Eight Flags' CHP plant, which commenced operations in June 2016, generated $4.2 million in additional gross margin.
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Natural Gas Marketing
PESCO generated additional gross margin of $1.8 million for the nine months ended September 30, 2017 compared to the same period in 2016. The increase in gross margin was generated primarily from providing natural gas to approximately 40,000 end users within one customer pool pursuant to the supplier agreement with Columbia Gas, which expired on March 31, 2017, as well as an increase in commercial and industrial customers served in Florida, offset by lower gross margin in the Mid-Atlantic region.
Pricing Amendments to Aspire Energy's Long-Term Agreements
An increase in gross margin of $1.1 million was due to favorable pricing amendments to long-term sales agreements, which generated $1.6 million in gross margin, offset by the absence of a one-time management fee of $560,000 paid to Aspire Energy by CGC in the first quarter of 2016.
Wholesale Propane Margins
Gross margin increased by $728,000, due primarily to favorable supply management activities for the Delmarva propane distribution operations.
Customer Consumption - Weather and Other
Gross margin increased by $168,000, due primarily to higher sales of propane as a result of timing of deliveries for our propane distributions operations, coupled with increased demand for propane in Florida due to weather conditions in the third quarter of 2017. This was partially offset by the impact of warmer weather primarily during the first three months of 2017.
Other Operating Expenses
Other operating expenses increased by $7.2 million. The significant components of the increase in other operating expenses included:
$2.8 million in higher operating expenses by Eight Flags' CHP plant in support of the margin generated;
$1.5 million in higher payroll costs for additional personnel to support growth;
$950,000 in higher benefits and employee-related costs in 2017 (since we are self-insured for healthcare, benefits costs fluctuate depending upon claims filed);
$800,000 in higher depreciation expense, of which $424,000 relates to a credit adjustment in 2016 recorded in conjunction with the final valuation for Aspire Energy; and
$350,000 in higher outside services costs associated primarily with growth and ongoing compliance activities.

OTHER INCOME (EXPENSE), NET
For the quarter ended September 30, 2017March 31, 2023 compared to the quarter ended September 30, 2016March 31, 2022
Other income, (expense), net, which includes non-operating investment income, (expense), interest income, late fees charged to customers, and gains or losses from the sale of assets increasedand pension and other benefits expense, decreased by $267,000$0.6 million in the thirdfirst quarter of 2017,2023. This was primarily driven by increased pension related expenses and a reduced volume of asset sales, compared to the same period in 2016, due primarily to the gain from the sale of assets within our unregulated energy businesses.2022.
For the nine months ended September 30, 2017 compared to the nine months ended September 30, 2017
Other income (expense), net, which includes non-operating investment income (expense), interest income, late fees charged to customers and gains or losses from the sale of assets, decreased by $575,000 for the first nine months of 2017, compared to the same period in 2016, due partly to costs associated with the termination of a lease for Xeron partially offset by the gain from the sale of assets within our unregulated energy businesses.INTEREST CHARGES

INTEREST CHARGES
For the quarter ended September 30, 2017March 31, 2023 compared to the quarter ended September 30, 2016March 31, 2022
Interest charges for the three months ended September 30, 2017March 31, 2023 increased by $599,000, compared to the same period in 2016, attributable to an increase of $410,000 in interest on long-term debt, largely as a result of the issuance of the Prudential Shelf Notes in April 2017, and an increase of $266,000 in interest on higher short-term borrowings.

For the nine months ended September 30, 2017 compared to the nine months ended September 30, 2016
Interest charges for the nine months ended September 30, 2017 increased by $1.1$1.9 million, compared to the same period in 2016,2022, attributable primarily to an increase of $691,000higher interest rates on outstanding borrowings under our Revolver and $0.3 million in interest on higher short-term borrowings and an increaseexpense as a result of $618,000 in interest ona long-term debt largelyplacement in 2022. These factors were partially offset by $0.4 million related to higher capitalized interest associated with growth projects. The weighted-average interest rate on our Revolver borrowings was 5.17 percent during the first quarter of 2023 compared to 1.17 percent during the prior-year period as a result of the issuanceFederal Reserve raising interest rates throughout 2022 and during the first quarter of 2023. As a result, the Prudential Shelf Notesinterest rates associated with our Revolver have increased 446 basis points since March 31, 2022. Any additional increases in April 2017.interest rates by the Federal Reserve would have a corresponding increase in the interest rates charged under our Revolver.


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INCOME TAXES

INCOME TAXES
For the quarter ended September 30, 2017March 31, 2023 compared to the quarter ended September 30, 2016March 31, 2022
Income tax expense was $4.3$11.6 million for the three monthsquarter ended September 30, 2017,March 31, 2023, compared to $3.0$13.5 million infor the same period in 2016. The increase in income tax expense was due primarily to an increase in our operating results.quarter ended March 31, 2022. Our effective income tax rate was 38.824.2 percent and 40.426.8 percent, for the three months ended September 30, 2017March 31, 2023 and 2016,2022, respectively.

For the nine months ended September 30, 2017 compared to the nine months ended September 30, 2017
Income tax expense was $20.8 million for the nine monthsquarter ended September 30, 2017, compared to $21.4March 31, 2023 includes a $1.3 million benefit in deferred tax expense resulting from a reduction in the same period in 2016. The decrease inPennsylvania state income tax expense was due primarily to a decrease inrate. Excluding this change, our operating results. Our effective income tax rate was 39.4 percent and 39.526.9 percent for the nine monthsquarter ended September 30, 2017 and 2016, respectively.March 31, 2023.


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FINANCIAL POSITION, LIQUIDITYAND 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 alignmaintain our capital structure towithin our target capital structure.structure range. We maintain an effective shelf registration statement with the SEC for the issuance of shares of common stock in various types of equity offerings, including shares of common stock under our ATM equity program, as well as an effective registration statement with respect to the DRIP. Depending on our capital needs and subject to market conditions, in addition to other possible debt and equity offerings, we may consider issuing additional shares under the direct share purchase component of the DRIP and/or under the ATM equity program.
Our energy businesses are weather-sensitive and seasonal. We normally generate a large portion of our annual net income and subsequent increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas, electricity, and propane delivered by our natural gas, electric, and propane distribution operations, and our natural gas gathering and processing operationtransmission operations to customers during the peak heatingpeak-heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.
Capital expenditures for investments in new or acquired plant and equipment are our largest capital requirements. Our capital expenditures were $132.4$41.8 million for the ninethree months ended September 30, 2017.
We originally budgeted $260.3 million forMarch 31, 2023. In the table below, we have provided the range of our forecasted capital expenditures during 2017, and we currently projectfor 2023:
2023
(in thousands)LowHigh
Regulated Energy:
Natural gas distribution$89,000 $100,000 
Natural gas transmission50,000 60,000 
Electric distribution13,000 15,000 
Total Regulated Energy152,000 175,000 
Unregulated Energy:
Propane distribution15,000 16,000 
Energy transmission8,000 9,000 
Other unregulated energy23,000 27,000 
Total Unregulated Energy46,000 52,000 
Other:
Corporate and other businesses2,000 3,000 
Total Other2,000 3,000 
Total 2023 Forecasted Capital Expenditures$200,000 $230,000 

The 2023 forecast, excluding acquisitions, includes capital expenditures of approximately $214.7 millionassociated with the following: Pipeline expansions related to the Eastern Shore Southern Expansion project and the Florida Beachside Pipeline, the Wildlight pipeline expansion, other small pipeline expansion opportunities, continued distribution system expansions including the Wildlight development in 2017. Our currentFlorida. Furthermore, the 2023 forecast by segmentincludes continued expenditures under, the capital cost surcharge program as well as information technology system enhancements, and by business line is shown below:other strategic initiatives and investments.
 2017
(dollars in thousands) 
Regulated Energy: 
Natural gas distribution$76,771
Natural gas transmission93,737
Electric distribution10,768
Total Regulated Energy181,276
Unregulated Energy: 
Propane distribution10,458
Other unregulated energy16,417
Total Unregulated Energy26,875
Other: 
Corporate and other businesses6,507
Total Other6,507
Total 2017 Capital Expenditures$214,658

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, supply chain disruptions, capital delays that are greater than currently anticipated, customer growth in existing areas, regulation, new growth or acquisition opportunities and availability of capital.capital and other factors discussed in Item 1A. Risk Factors in our 2022 Annual Report on Form 10-K. 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.ratings. 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, 2017March 31, 2023 and December 31, 2016:2022:

  
 September 30, 2017 December 31, 2016
(in thousands)        
Long-term debt, net of current maturities $201,248
 30% $136,954
 23%
Stockholders’ equity 463,820
 70% 446,086
 77%
Total capitalization, excluding short-term debt $665,068
 100% $583,040
 100%
         
  September 30, 2017 December 31, 2016
(in thousands)        
Short-term debt $203,098
 23% $209,871
 26%
Long-term debt, including current maturities 213,384
 24% 149,053
 19%
Stockholders’ equity 463,820
 53% 446,086
 55%
Total capitalization, including short-term debt $880,302
 100% $805,010
 100%
Included in the long-term debt balances at September 30, 2017 and December 31, 2016, was a capital lease obligation associated with Sandpiper's capacity, supply and operating agreement (at September 30, 2017, $1.0 million excluding current maturities and $2.4 million including current maturities, and, at December 31, 2016, $2.1 million excluding current maturities and $3.5 million including current maturities). At the closing of the ESG acquisition in May 2013, Sandpiper entered into this agreement, which has a six-year term. The capacity portion of this agreement is accounted for as a capital lease.
March 31, 2023December 31, 2022
(in thousands)    
Long-term debt, net of current maturities$656,284 43 %$578,388 41 %
Stockholders’ equity858,588 57 %832,801 59 %
Total capitalization, excluding short-term debt$1,514,872 100 %$1,411,189 100 %
 March 31, 2023December 31, 2022
(in thousands)    
Short-term debt$94,079 6 %$202,157 12 %
Long-term debt, including current maturities677,773 41 %599,871 37 %
Stockholders’ equity858,588 53 %832,801 51 %
Total capitalization, including short-term debt$1,630,440 100 %$1,634,829 100 %
Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. We have maintained a ratio ofOur equity to total capitalization ratio, including short-term borrowings, between 50was 53 percent and 57 percent duringas of March 31, 2023. We seek to align permanent financing with the past three years. In September 2016, we completed a public offering of 960,488 sharesin-service dates of our common stockcapital projects. We may utilize more temporary short-term debt when the financing cost is attractive as a bridge to the permanent long-term financing or if the equity markets are volatile.
In the first three months of 2023, there were no issuances under the DRIP. In 2022, we issued less than 0.1 million shares at aan average price per share of $62.26. The$136.26 and received net proceeds fromof $4.5 million under the sale of common stock, after deducting underwritingDRIP. See Note 9, Stockholders’ Equity, in the condensed consolidated financial statements for additional information on commissions and expenses, were approximately $57.4 million, which were added to our general funds and used primarily to repay a portion of our short-term debt under unsecured lines of credit.
As described below under “Short-term Borrowings,” we entered into the Credit Agreement and the Revolverfees paid in connection with the Lenders in October 2015, which increased our borrowing capacity by $150.0 million. To facilitate the refinancing of a portion of the short-term borrowings into long-term debt, as appropriate, we also entered into the Prudential Shelf Agreement with Prudential for the potential private placement of the Prudential Shelf Notes as further described below under the heading “Shelf Agreements.” In addition, we also entered into the MetLife and NYL Shelf Agreements, as described in further detail below, to have additional debt capital available to fund future growth capital expenditures.
For larger revenue-generating capital projects, we will seek to align, as much as feasible, any long-term debt or equity issuance(s) with the commencement of service and associated earnings. In addition, the exact timing of any long-term debt or equity issuance(s) will be based on market conditions.these issuances.
Shelf Agreements
In October 2015, weWe have entered into theShelf Agreements with Prudential Shelf Agreement, under which, through October 8, 2018, we may request that Prudential purchase up to $150.0 million of our Prudential Shelf Notes. The Prudential Shelf Notes have a fixed interest rate and a maturity date not to exceed 20 years from the date of issuance. Prudential isMetLife, whom are under no obligation to purchase any unsecured debt. In February 2023, we amended our Shelf Agreements with Prudential and MetLife. The amended agreements now provide for total borrowing capacity of the Prudential Shelf Notes. The interest rate and terms of payment of any series of the Prudential Shelf Notes will be determined at the time of purchase.
In May 2016, Prudential confirmed and accepted our request that Prudential purchase $70.0up to $405.0 million of 3.25 percent Prudential Shelf Notes under the Prudential Shelf Agreement. We issued the Prudential Shelf Notes on April 21, 2017Agreement and used the proceeds to reduce short-term borrowings$200.0 million under the Revolver, which had increased as a resultMetLife Shelf Agreement. Additionally, the amendments extend the term of funding capital expenditures on a temporary basis.the agreements for an additional three years from the effective dates. The following table summarizes our Shelf Agreements at March 31, 2023:
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(in thousands)Total Borrowing CapacityLess: Amount of Debt IssuedLess: Unfunded CommitmentsRemaining Borrowing Capacity
Shelf Agreement (1)
Prudential Shelf Agreement
$405,000 $(300,000)$— $105,000 
MetLife Shelf Agreement200,000 (50,000)— 150,000 
Total Shelf Agreements as of March 31, 2023$605,000 $(350,000)$— $255,000 

(1) The Prudential and MetLife Shelf Agreements both expire in February 2026.

The Prudential Shelf Agreement setsUncollateralized Senior Notes set forth certain business covenants to which we are subject when any Prudential Shelf Notenote is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.
In March 2017, we entered into the MetLife Shelf Agreement and NYL Shelf Agreement, under which we may request that MetLife and NYL, through March 2, 2020, purchase

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Short-term Borrowings
We are authorized by our Board of Directors to borrow up to $150.0$400.0 million of short-term debt, as required. At March 31, 2023 and December 31, 2022, we had $94.1 million and $100.0$202.2 million, respectively, of our unsecured senior debtshort-term borrowings outstanding at a fixed interest rate and with a maturity date not to exceed 20 years from the date of issuance. MetLife and NYL are under no obligation to purchase any unsecured senior debt. The interest rate and terms of payment of any series of unsecured senior debt will be determined at the time of purchase. As of September 30, 2017, no unsecured notes have been issued under either the MetLife Shelf Agreement or the NYL Shelf Agreement.
Short-term Borrowings
Our outstanding short-term borrowings at September 30, 2017 and December 31, 2016 were $203.1 million and $209.9 million, respectively. The weighted average interest rates for our short-term borrowings were 1.96rate of 5.17 percent and 1.495.04 percent respectively.
In August 2022, we amended both tranches of the Revolver, which now bear interest using SOFR as the benchmark interest rate, plus a 10-basis point SOFR adjustment, in lieu of LIBOR which is being retired by financial institutions. In addition, the 364-day tranche was extended for the nine months ended September 30, 2017upcoming year, expiring in August 2023. As part of these amendments, the parties agreed to eliminate the previous covenant capping the aggregate investments at $150.0 million where we maintain an ownership interest less than 50 percent. Additionally, the 364 day tranche of the facility now offers a reduced interest margin similar to the five-year tranche for amounts borrowed in connection with new sustainable investments. All other terms and 2016, respectively.conditions remained unchanged. Borrowings outstanding under the sustainable investment sublimit of the 364-day tranche amounted to $9.4 million at March 31, 2023.
The availability of funds under the Revolver is subject to conditions specified in the credit agreement, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in the Revolver's loan documents. We utilize bank linesare required by the financial covenants in the Revolver to maintain, at the end of crediteach fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of March 31, 2023, we are in compliance with this covenant.

The 364-day tranche of the Revolver expires in August 2023 and the five-year tranche expires in August 2026, both of which are available to provide funds forfund our short-term cash needs to meet seasonal working capital requirements and to temporarily fund portions of the capital expenditure program. As of September 30, 2017, we had four unsecured bank credit facilities with three financial institutions totaling $180.0 million in available credit.
In addition, since October 2015, we have $150.0 million of additional short-term debt capacity available under the Revolver with five participating Lenders. The $150.0 million Revolver has a five-year term and is subject to the terms and conditions set forth in the Credit Agreement. Borrowings under the Revolver will be used for general corporate purposes, including repayments of short-term borrowings, working capital requirements andour capital expenditures. Borrowings under both tranches of the Revolver will bear interest at: (i) the LIBOR Rate plus an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization, both as defined by the Credit Agreement, or (ii) the base rate plus 0.25% or less. Interest is payable quarterly, and the Revolver isare subject to a pricing grid, including the commitment fee onand the unused portioninterest rate charged based upon our total indebtedness to total capitalization ratio for the prior quarter. As of March 31, 2023, the facility. We havepricing under the right, under certain circumstances, to extend the expiration date for up to two years on any anniversary date364-day tranche of the Revolver with such extension subject toincluded an unused commitment fee of 9 basis points and maintains an interest rate of 70 basis points over SOFR plus a 10 basis point SOFR adjustment. As of March 31, 2023, the Lenders' approval. We may also requestpricing under the Lenders to increasefive-year tranche of the Revolver included an unused commitment fee of 9 basis points and an interest rate of 95 basis points over SOFR plus a 10 basis point SOFR adjustment.

Our total available credit under the Revolver at March 31, 2023 was $300.1 million. As of March 31, 2023, we had issued $5.8 million in letters of credit to $200.0 million, with any increase atvarious counterparties under the sole discretionRevolver. These letters of each Lender.credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be drawn upon by the counterparties. The letters of credit reduce the available borrowings under the Revolver.
NoneFor additional information on interest rate swaps related to our short-term borrowings, see Note 12, Derivative Instruments.

Long-Term Debt
On March 15, 2022, we issued 2.95 percent Senior Notes due March 15, 2042 to MetLife in the aggregate principal amount of $50 million. We used the proceeds received from the issuances of the unsecured bank linesSenior Notes to reduce short-term borrowings under the Revolver and to fund capital expenditures. These Senior Notes have similar covenants and default provisions as our other Senior Notes, and have an annual principal payment beginning in the eleventh year after the issuance.

On March 14, 2023 we issued 5.43 percent Senior Notes due March 14, 2038 in the aggregate principal amount of $80.0 million. We used the proceeds received from the issuances of the Senior Notes to reduce short-term borrowings under our Revolver credit requires compensating balances. We are currently authorized byfacility and to fund capital expenditures. These Senior Notes have similar covenants and default provisions as our Boardother Senior Notes, and have an annual principal payment beginning in the sixth year after the issuance.


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Cash Flows
The following table provides a summary of our operating, investing and financing cash flows for the ninethree months ended September 30, 2017March 31, 2023 and 2016:2022:
 
Three Months Ended
March 31,
(in thousands)20232022
Net cash provided by (used in):
Operating activities$81,667 $69,120 
Investing activities(42,654)(29,935)
Financing activities(42,152)(38,953)
Net (decrease) increase in cash and cash equivalents(3,139)232 
Cash and cash equivalents—beginning of period6,204 4,976 
Cash and cash equivalents—end of period$3,065 $5,208 
  Nine Months Ended
  September 30,
  2017 2016
(in thousands)    
Net cash provided by (used in):    
Operating activities $98,372
 $85,733
Investing activities (141,453) (109,730)
Financing activities 42,289
 22,678
Net decrease in cash and cash equivalents (792) (1,319)
Cash and cash equivalents—beginning of period 4,178
 2,855
Cash and cash equivalents—end of period $3,386
 $1,536

Cash Flows Provided Byby Operating Activities
Changes in our cash flows from operating activities are attributable primarily to changes in net income, adjusted for non-cash items such as depreciation and changes in deferred income taxes, depreciation and working capital. Changes in workingWorking capital requirements are determined by a variety of factors, including weather, the prices of natural gas, electricity and propane, the timing of customer collections, payments for purchases of natural gas, electricity and propane, and deferred fuel cost recoveries.
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During the ninethree months ended September 30, 2017 and 2016,March 31, 2023, net cash provided by operating activities was $98.4 million and $85.7 million, respectively, resulting in an increase in$81.7 million. Operating cash flows of $12.6 million. Significant operating activities generatingwere primarily impacted by the cash flows change were as follows:following:
•Net income, adjusted for reconciling activities, increased cash flows by $17.9 million, due primarily to an increase in deferred income taxes as a result of the availability and utilization of bonus depreciation in the first nine months of 2017, which resulted in a higher book-to-tax timing difference and higher non-cash adjustments, for depreciation and amortization related to increased investing activities.provided a $58.1 million source of cash;
Changes in income taxes receivable decreased cash flows by $18.7 million, due to lower tax refunds during the first nine months of 2017 compared to the same period in 2016.
Changes in net accounts receivable and accrued revenue and accounts payable and accrued liabilities increased cash flows by $14.1 million, due primarily to higher revenues and the timing of the receipt of customer payments as well as the timing of payments to vendors.
Net cash flows from changes in other inventories decreased by approximately $6.1 million, due primarily to additional pipes and other construction inventory purchases, which increased the levels of our inventory.
•Changes in net regulatory assets and liabilities increased cash flows by $4.3 million, due primarily to changesthe change in GRIP and fuel costs collected through the various cost recovery mechanisms.mechanisms resulted in a $24.6 million inflow of cash;
Changes•A net increase in net prepaid expenses and other current assets, customer deposits and refunds, other assets and liabilities and accrued compensationincome tax payable increased cash flowsinflows by $1.2 million.$10.1 million;
•An increased level of deferred taxes associated with incremental tax depreciation from growth investments resulted in a source of cash of $2.5 million; and
•Other working capital changes, impacted primarily by propane inventory purchases and hedging activities, resulted in a $13.5 million use of cash.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $141.5 million and $109.7$42.7 million during the ninethree months ended September 30, 2017 and 2016, respectively, resulting in a decrease in cash flows of $31.8 million. Significant investing activities generating the cash flows change were as follows:
Cash paid for capital expenditures increasedMarch 31, 2023, largely driven by $20.5 million to $130.1$42.4 million for the first nine months of 2017, compared to $109.6 million for the same period in 2016.new capital expenditures.
Net cash of $11.7 million was used to acquire ARM and Chipola during the first nine months of 2017; there were no corresponding transactions in 2016.
Cash Flows Used in Financing Activities

Net cash provided in financing activities totaled $42.3 million and $22.7 million during the nine months ended September 30, 2017 and 2016, respectively. The increase in net cash used in financing activities fortotaled $42.2 million during the ninethree months ended September 30, 2017 resulted primarily fromMarch 31, 2023 and included the following:
We received $69.8 million in net cash proceeds from the issuance of the Prudential Shelf Notes, and we paid $2.9 million more in scheduled long-term debt principal payments and capital lease obligations payments.
Net cash flows decreased by $57.3 million from proceeds related to the issuance of common stock during the third quarter of 2016.
•Net repayments under our linethe Revolver of credit arrangements$107.8 million;
•Net increase in long-term debt borrowings resulted in a source of $3.8cash of $77.9 million to permanently finance investment in growth initiatives; and
•A use of cash of $9.5 million for the nine months ended September 30, 2017, compared to net repayments of $21.4 million for the same perioddividend payments in 2016, increased cash flows by $17.6 million. Change in cash overdrafts decreased cash flows by $5.5 million.
We paid $14.8 million in cash dividends for the nine months ended September 30, 2017, compared to $13.0 million for the nine months ended September 30, 2016.2023.
Off-Balance Sheet Arrangements
We have issuedThe Board of Directors has authorized us to issue corporate guarantees to certain vendorssecuring obligations of our subsidiaries primarily PESCO. These corporateand to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees provide for the paymentand letters of natural gas purchases in the eventcredit as of default. PESCO has never defaulted on its obligations to pay its suppliers. The liabilities for these purchases are recorded in our financial statements when incurred.March 31, 2023 was $20.0 million. The aggregate amount guaranteed related to our subsidiaries at September 30, 2017March 31, 2023 was $71.9$14.2 million, with the guarantees expiring on various dates through September 2018.March 30, 2024. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at March 31, 2023 was $4.0 million.
We

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As of March 31, 2023, we have issued letters of credit totaling approximately $5.8 million related to the electric transmission services for FPU's northwest electric division, the firm transportation service agreement between TETLP and our Delaware and Maryland divisions, and to our current and previous primary insurance carriers. These letters of credit have various expiration dates through June 2018. ThereOctober 25, 2023. We have been no draws onnot drawn upon these letters of credit as of September 30, 2017. WeMarch 31, 2023 and do not anticipate that the counterparties will draw upon these letters of credit will be drawn upon by
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the counterparties, and wecredit. We expect that they will be renewed to the extent necessary in the future. Additional information is presented inNote 57, Other Commitments and Contingencies, in the condensed consolidated financial statements.


Contractual Obligations
There has been no material change in the contractual obligations presented in our 20162022 Annual Report on Form 10-K, except for long-term debt, commodity purchase obligations and forward contracts entered into in the ordinary course of our business. The following table summarizes long-term debt, commodity and forwardpurchase contract obligations at September 30, 2017:March 31, 2023:
 
 Payments Due by Period Payments Due by Period
 Less than 1 year 1 - 3 years 3 - 5 years More than 5 years TotalLess than 1 year1 - 3 years3 - 5 yearsMore than 5 yearsTotal
(in thousands)          (in thousands)     
Long-term debt (1)
 $10,698
 $24,226
 $40,700
 $135,800
 $211,424
Purchase obligations - Commodity (2)
 47,069
 1,693
 —
 —
 48,762
Purchase obligations - Commodity (1)
Purchase obligations - Commodity (1)
$15,493 $854 $— $— $16,347 
Total $57,767
 $25,919
 $40,700
 $135,800
 $260,186
Total$15,493 $854 $— $— $16,347 
 
(1)
(1) 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 unamortized debt discount of $1,960.
(2)
In addition to the obligations noted above, we have agreements with commodity suppliers that have provisions with no minimum purchase requirements. There are no monetary penalties for reducing the amounts purchased; however, the propane contracts allow the suppliers to reduce the amounts available in the winter season if we do not purchase specified amounts during the summer season. Under these contracts, the commodity prices will fluctuate as market prices fluctuate.
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 isand Aspire Energy Express, our intrastate pipeline subsidiaries, are subject to regulation (excluding cost of service) by the Florida PSC. At September 30, 2017, we werePSC and Public Utilities Commission of Ohio, respectively. We regularly are involved in regulatory matters in each of the jurisdictions in which we operate. Our significant regulatory matters are fully described in Note 35, 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.

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Item 3. Quantitative and Qualitative Disclosures about Market Risk
INTEREST RATE RISK

Long-term debt is subject to potential losses based on changes in interest rates. Our long-term debt at September 30, 2017, 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. Increases in interest rates expose us to potential increased costs we could incur when we (i) issue new debt instruments or (ii) provide financing and liquidity for our business activities. We utilize interest rate swap agreements to mitigate short-term borrowing rate risk. Additional information about our long-term debt and short-term borrowing is disclosed in Note 13, Long-term14, Long-Term Debt, and Note 15, Short-Term Borrowings, respectively,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 respective PSCs that allow us to periodically adjust fuel rates to reflect changes in the wholesale cost of natural gas and electricity and to ensure that we recover all of the costs prudently incurred in purchasing natural gas and electricity for our customers. Therefore, our regulated energy distribution operations have limited commodity price risk exposure.

Unregulated Energy Segment
Sharp and Flo-gas
Our 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 6.28.8 million gallons of propane (including leased storage and rail cars) during the winter season to meet our customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause
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the value of stored propane to decline, particularly if we utilize fixed price forward contracts for supply. To mitigate the risk of propane commodity price fluctuations on the inventory valuation, we have adopted a Risk Management Policy that allows our propane distribution operation to enter into fair value hedges, cash flowsflow hedges or other economic hedges of our inventory.

Aspire Energy is exposed to commodity price risk, primarily during the winter season, to the extent we are not successful in balancing our natural gas purchases and sales and have to secure natural gas from alternative sources at higher spot prices. In order to mitigate this risk, we procure firm capacity that meets our estimated volume requirements and we continue to seek out new producers with which to contract in order to fulfill our natural gas purchase requirements.
PESCO
The following table reflects the changes in the fair market value of financial derivatives contracts related to propane purchases and sales from December 31, 2022 to March 31, 2023:
(in thousands)Balance at December 31, 2022(Decrease) in Fair Market ValueLess Amounts SettledBalance at March 31, 2023
Sharp$1,507 $(1,183)$606 $930 
There were no changes in methods of valuations during the three months ended March 31, 2023.

The following is a party to natural gas futures contracts. These contracts provide PESCO with the right to purchase natural gas at a fixed price at future dates. Upon expiration, the contracts can be settled financially without taking deliverysummary of natural gas, or PESCO can procure natural gasfair market value of financial derivatives as of March 31, 2023, by method of valuation and by maturity for its customers.each fiscal year period.
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
(in thousands)202320242025Total Fair Value
Price based on Mont Belvieu - Sharp$305 $658 $(33)$930 

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Table 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.Contents

WHOLESALE CREDIT RISK

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

Additional information about our derivative instruments is disclosed in Note 11, 12, Derivative Instruments, in the condensed consolidated financial statements.


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, 2017.March 31, 2023. Based upon their evaluation, the Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of September 30, 2017.March 31, 2023.
Changes in Internal Control over Financial Reporting
During the quarter ended September 30, 2017,March 31, 2023, there was no change in our internal control over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal control over financial reporting.






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PART II—OTHER INFORMATION
Item 1. Legal Proceedings

As disclosed in Note 57, Other Commitments and Contingencies, of the condensed consolidated financial statements in this Quarterly Report on Form 10-Q, we are involved in certain legal actions and claims arising in the normal course of business. We are also involved in certain legal and administrative proceedings before various governmental or regulatory agencies concerning rates and other regulatory actions. In the opinion of management, the ultimate disposition of these proceedings and claims will not have a material effect on our condensed consolidated financial position, results of operations or cash flows.
 
Item 1A. Risk Factors

Our business, operations, and financial condition are subject to various risks and uncertainties. The risk factors described in Part I, “Item 1A. Risk Factors” in our Annual Report on Form 10-K, for the year ended December 31, 2016,2022, 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

Company Purchases of Equity Securities

Share repurchases during the three months ended March 31, 2023 were as follows:
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
PeriodPurchasedper Share
or Programs (2)
or Programs (2)
January 1, 2023
through January 31, 2023 (1)
503 $114.94 — — 
February 1, 2023
through February 28, 2023		— — — — 
March 1, 2023
through March 31, 2023		—— ——
Total503 $114.94 — — 
 
(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 16, Employee Benefit Plans,” in our latest Annual Report on Form 10-K for the year ended December 31, 2022.
(2) Except for the purposes described in Footnote (1), Chesapeake Utilities has no publicly announced plans or programs to repurchase its shares.

  
Total
Number of
Shares
 
Average
Price Paid
 
Total Number of Shares
Purchased as Part of
Publicly Announced Plans
 
Maximum Number of
Shares That May Yet Be
Purchased Under the Plans
Period Purchased per Share 
or Programs (2)
 
or Programs (2)
July 1, 2017
through July 31, 2017 (1)
 387
 $75.75
 —
 —
August 1, 2017
through August 31, 2017
 —
 $—
 —
 —
September 1, 2017
through September 30, 2017
 —
 $—
 —
 —
Total 387
 $75.75
 —
 —
(1)
Chesapeake Utilities purchased shares of stock on the open market for the purpose of reinvesting the dividend on deferred stock units held in the Rabbi Trust accounts for certain Directors and Senior Executives under the Deferred Compensation Plan. The Deferred Compensation Plan is discussed in detail in Item 8 under the heading “Notes to the Consolidated Financial Statements—Note 16, Employee Benefit Plans” in our latest Annual Report on Form 10-K for the year ended December 31, 2016. During the quarter ended September 30, 2017, 387 shares were purchased through the reinvestment of dividends on deferred stock units.
(2)
Except for the purposes described in Footnote (1), Chesapeake Utilities has no publicly announced plans or programs to repurchase its shares.


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

None.

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Item 6.     Exhibits
Item 6.Exhibits
31.1
31.2
32.1
32.2
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.
104Cover Page Interactive Data File - formatted in Inline XBRL and contained in Exhibit 101



*Filed herewith



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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. CHESAPEAKE UTILITIES CORPORATIONOOPER
/S/ BETH W. COOPER
Beth W. Cooper
Senior
Executive Vice President, and Chief Financial Officer,
Treasurer and Assistant Corporate Secretary
Date: November 9, 2017May 3, 2023



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