Published: 2022-08-03 00:00:00 ET

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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, 2021. In the opinion of management, these financial statements reflect all 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.

Effects of COVID-19

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 beginning in 2020 and to a lesser extent have continued into 2022. Chesapeake Utilities is considered an “essential business,” which allowed us to continue operational activities and construction projects while social distancing restrictions were in place. At this time, restrictions have predominantly been lifted as vaccines have become widely available in the United States. Previously existing states of emergency in all of our service territories expired during the second and third quarters of 2021 eliminating a majority of restrictions initially implemented to slow the spread of the virus. The expiration of the states of emergency along with the settlement of our limited proceeding in Florida concluded our ability to defer incremental pandemic related costs for consideration through the applicable regulatory process. We 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 and Safety and Health Administration, as new developments occur.

Refer to Note 5, Rates and Other Regulatory Activities, for further information on the regulated assets established as a result of the incremental expenses associated with COVID-19.

Recent Accounting Standards Yet to be Adopted

Reference Rate Reform - (ASC 848) - In March 2020, the FASB issued ASU 2020-04, Reference Rate Reform (Topic 848): Facilitation of the Effects of Reference Rate Reform on Financial Reporting, which was subsequently amended by ASU 2021-01. The standard provides relief for companies preparing for the discontinuation of interest rates, such as LIBOR, and allows optional expedients and exceptions for applying GAAP to contracts, hedging relationships and other transactions affected by reference rate reform. The amendments included in this ASU are to be applied prospectively, and are not expected to have a material impact on our financial position or results of operations. Refer to Note 16, Short-Term Borrowings, for further information regarding the expected timing of implementing this update.

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3.     Acquisitions

Acquisition of Davenport Energy

On June 13, 2022, Sharp acquired the propane operating assets of Davenport Energy's Siler City propane division for approximately $2.0 million. In connection with this acquisition, we recorded a $0.1 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. Included with the acquisition was less than $0.1 million of working capital from the Seller consisting predominantly of accounts receivable and propane inventory. Through this acquisition, the Company expands its operating footprint further into North Carolina, where customers will be served by Sharp Energy’s Diversified Energy division. Sharp added approximately 850 customers, along with expected 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 are deductible for income tax purposes. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions and finalization prior to the first anniversary of the transaction closing. The financial results associated with this acquisition will be included within Sharp's Diversified Energy division, primarily as a result of their geographic proximity, as well as other synergies they generate due to their service territory.

Acquisition of Diversified Energy

On December 15, 2021, Sharp acquired the propane operating assets of Diversified Energy for approximately $37.5 million, net of cash acquired. In connection with this acquisition, we recorded a $2.1 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. Included with the acquisition, was approximately $1.7 million of working capital from the Seller consisting predominantly of accounts receivable and propane inventory. We accounted for this acquisition as a business combination within our Unregulated Energy Segment beginning in the fourth quarter of 2021. In January 2022, we recorded a post-closing true-up of $0.8 million related to the provision for working capital valuation at the time of closing. There were multiple strategic benefits to this acquisition including it: (i) expands our propane service territory into North Carolina and South Carolina (ii) builds upon our existing propane presence in Virginia and Pennsylvania, and (iii) includes an established customer base with opportunities for future growth. Through this acquisition, the Company added approximately 19,000 residential, commercial and agricultural customers, along with expected distribution of approximately 10.0 million gallons of propane annually. In connection with this acquisition, we recorded $23.1 million in property plant and equipment, $6.2 million in intangible assets associated with customer relationships and non-compete agreements and $5.9 million in goodwill, all of which is deductible for income tax purposes. The amounts recorded in conjunction with the acquisition are preliminary, and subject to adjustment based on contractual provisions and finalization prior to the first anniversary of the transaction closing.

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We recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the month following the satisfaction of our performance obligation. The following table displays our revenue by major source based on product and service type for the three months ended June 30, 2022 and 2021:

						Three months ended June 30, 2022																								Three months ended June 30, 2021
(in thousands)						Regulated Energy						Unregulated Energy						Other and Eliminations						Total						Regulated Energy						Unregulated Energy						Other and Eliminations						Total
Energy distribution
Delaware natural gas division						$	13,086					$	—					$	—					$	13,086					$	10,068					$	—					$	—					$	10,068
Florida natural gas division						9,619						—						—						9,619						8,446						—						—						8,446
FPU electric distribution						20,305						—						—						20,305						18,898						—						—						18,898
FPU natural gas distribution						25,817						—						—						25,817						23,159						—						—						23,159
Maryland natural gas division						4,372						—						—						4,372						3,224						—						—						3,224
Sandpiper natural gas/propane operations						4,248						—						—						4,248						3,814						—						—						3,814
Elkton Gas						1,705						—						—						1,705						1,195						—						—						1,195
Total energy distribution						79,152						—						—						79,152						68,804						—						—						68,804
Energy transmission
Aspire Energy						—						10,808						—						10,808						—						5,578						—						5,578
Aspire Energy Express						369						—						—						369						47						—						—						47
Eastern Shore						18,875						—						—						18,875						18,617						—						—						18,617
Peninsula Pipeline						6,777						—						—						6,777						6,610						—						—						6,610
Total energy transmission						26,021						10,808						—						36,829						25,274						5,578						—						30,852
Energy generation
Eight Flags						—						5,916						—						5,916						—						4,173						—						4,173
Propane operations
Propane delivery operations						—						34,469						—						34,469						—						23,098						—						23,098
Compressed Natural Gas Services
Marlin Gas Services						—						2,380						—						2,380						—						1,989						—						1,989
Other and eliminations
Eliminations						(12,980)						(110)						(6,271)						(19,361)						(13,168)						(65)						(4,734)						(17,967)
Other						—						—						85						85						—						—						133						133
Total other and eliminations						(12,980)						(110)						(6,186)						(19,276)						(13,168)						(65)						(4,601)						(17,834)
Total operating revenues (1)						$	92,193					$	53,463					$	(6,186)					$	139,470					$	80,910					$	34,773					$	(4,601)					$	111,082

(1) Total operating revenues for the three months ended June 30, 2022, include other revenue (revenues from sources other than contracts with customers) of $(0.1) million for Regulated and $0.1 million Unregulated Energy segments, respectively, and $0.1 million for both our Regulated and Unregulated Energy segments, respectively, for the three months ended June 30, 2021. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper Energy and late fees.

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The following table displays our revenue by major source based on product and service type for the six months ended June 30, 2022 and 2021:

						Six Months Ended June 30, 2022																								Six Months Ended June 30, 2021
(in thousands)						Regulated Energy						Unregulated Energy						Other and Eliminations						Total						Regulated Energy						Unregulated Energy						Other and Eliminations						Total
Energy distribution
Delaware natural gas division						$	47,568					$	—					$	—					$	47,568					$	43,340					$	—					$	—					$	43,340
Florida natural gas division						19,885						—						—						19,885						17,402						—						—						17,402
FPU electric distribution						39,394						—						—						39,394						37,449						—						—						37,449
FPU natural gas distribution						55,837						—						—						55,837						50,020						—						—						50,020
Maryland natural gas division						14,836						—						—						14,836						13,690						—						—						13,690
Sandpiper natural gas/propane operations						11,885						—						—						11,885						11,885						—						—						11,885
Elkton Gas						5,071						—						—						5,071						3,830						—						—						3,830
Total energy distribution						194,476						—						—						194,476						177,616						—						—						177,616
Energy transmission
Aspire Energy						—						28,844						—						28,844						—						18,484						—						18,484
Aspire Energy Express						632						—						—						632						93						—						—						93
Eastern Shore						39,196						—						—						39,196						38,589						—						—						38,589
Peninsula Pipeline						13,549						—						—						13,549						13,077						—						—						13,077
Total energy transmission						53,377						28,844						—						82,221						51,759						18,484						—						70,243
Energy generation
Eight Flags						—						11,455						—						11,455						—						8,502						—						8,502
Propane operations
Propane delivery operations						—						110,075						—						110,075						—						78,361						—						78,361
Compressed Natural Gas Services
Marlin Gas Services						—						4,589						—						4,589						—						4,340						—						4,340
Other and eliminations
Eliminations						(27,769)						(207)						(12,706)						(40,682)						(27,268)						(156)						(9,635)						(37,059)
Other						—						—						216						216						—						—						265						265
Total other and eliminations						(27,769)						(207)						(12,490)						(40,466)						(27,268)						(156)						(9,370)						(36,794)
Total operating revenues (1)						$	220,084					$	154,756					$	(12,490)					$	362,350					$	202,107					$	109,531					$	(9,370)					$	302,268

(1) Total operating revenues for the six months ended June 30, 2022, include other revenue (revenues from sources other than contracts with customers) of $0.1 million for Regulated and $0.2 million Unregulated Energy segments, respectively, and $(0.2) million and $0.2 million for our Regulated and Unregulated Energy segments, respectively, for the six months ended June 30, 2021. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for the Maryland division and Sandpiper Energy and late fees.

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Contract balances

The timing of revenue recognition, customer billings and cash collections results in trade receivables, unbilled receivables (contract assets), and customer advances (contract liabilities) in our condensed consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of June 30, 2022 and December 31, 2021 were as follows:

						Trade Receivables						Contract Assets (Current)						Contract Assets (Non-current)						Contract Liabilities (Current)
(in thousands)
Balance at 12/31/2021						$	56,277					$	18					$	4,806					$	747
Balance at 6/30/2022						38,778						18						4,607						724
Decrease						$	(17,499)					$	—					$	(199)					$	(23)

Our trade receivables are included in trade and other receivables in the condensed consolidated balance sheets. Our current contract assets are included in other 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 been recovered through rates for the sale of electricity to our electric distribution operation pursuant to a long-term service agreement.

At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. Contract liabilities are included in other accrued liabilities in the condensed consolidated balance sheets and relate to non-refundable prepaid fixed fees for our Mid-Atlantic propane delivery operation's retail offerings. Our performance obligation is satisfied over the term of the respective customer retail program on a ratable basis. For the three months ended June 30, 2022 and 2021, we recognized revenue of $0.3 million and $0.2 million. For the six months ended June 30, 2022 and 2021, we recognized revenue of $0.7 million and $0.6 million.

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 these businesses for the remaining performance obligations, at June 30, 2022, are expected to be recognized as follows:

(in thousands)			2022						2023						2024						2025						2026						2027						2028 and thereafter
Eastern Shore and Peninsula Pipeline			$	24,379					$	45,426					$	40,431					$	33,804					$	29,294					$	25,096					$	179,259
Natural gas distribution operations			3,433						6,238						6,050						5,698						5,515						5,100						33,113
FPU electric distribution			326						652						652						275						275						275						275
Total revenue contracts with remaining performance obligations			$	28,138					$	52,316					$	47,133					$	39,777					$	35,084					$	30,471					$	212,647

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 subsidiaries, are subject to regulation (excluding cost of service) by the Florida PSC and Public Utilities Commission of Ohio, respectively.

Delaware

See the discussion below under COVID-19 impact.

Maryland

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Ocean City Maryland Reinforcement: In March 2022, we filed a 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 project will increase the reliability of the existing distribution system in those areas while also expanding infrastructure to serve new customers. Construction began in the second quarter of 2022, with estimated completion in the fourth quarter of 2022.

Strategic Infrastructure Development and Enhancement (“STRIDE”) Plan: In March 2021, Elkton Gas filed a STRIDE plan with the Maryland PSC. The STRIDE plan accelerates Elkton Gas' Aldyl-A pipeline replacement program as costs of the plan are recovered through a fixed charge rider which is effective for five years. Under Elkton Gas’ STRIDE plan, the Aldyl-A pipelines will be fully replaced by the end of 2023. In July 2021, Elkton Gas reached a settlement with the Maryland PSC Staff and the Maryland Office of Public Counsel that approved Elkton Gas’ STRIDE plan. The STRIDE plan allows for recovery of the associated revenue requirement through a monthly surcharge, which was implemented effective September 2021. We filed the annual STRIDE plan update with the Maryland PSC on November 1, 2021, which was approved for new rates effective January 1, 2022.

Florida

Natural Gas Rate Case: In May 2022, 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”) filed a consolidated natural gas rate case with the Florida PSC. In connection with the application, we are seeking approval of the following: (i) interim rate relief of approximately $7.2 million, subject to refund, pending the outcome of the rate case proceeding; (ii) permanent rate relief of approximately $24.1 million, effective January 1, 2023, (iii) a depreciation study also submitted with filing; (iv) 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; (v) authorization to retain the acquisition adjustment recorded at the time of the FPU merger in our revenue requirement; and (vi) 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 reading in September 2022. The interim rates are subject to refund pending the final outcome of the rate case proceeding. The discovery process has commenced and hearing for the proceeding has been scheduled for October 2022. The outcome of the application is subject to review and approval by the Florida PSC.

Winter Haven Expansion Project: In May 2021, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with CFG for an incremental 6,800 Dts/d of firm service in the Winter Haven, Florida area. As part of this agreement, Peninsula Pipeline will construct a new interconnect with FGT and a new regulator station for CFG. CFG will use the additional firm service to support new incremental load due to growth, including providing service to a new can manufacturing facility, as well as provide reliability and operational benefits to CFG’s existing distribution system in the area. In connection with Peninsula Pipeline’s new regulator station, CFG is also extending its distribution system to connect to the new station. The Transportation Service Agreement was approved by the Florida PSC in September 2021. Construction commenced in February 2021 and the expected in-service date is the third quarter of 2022.

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 Indian River's barrier island. As part of this agreement, Peninsula Pipeline will construct 11.3 miles of pipeline from its existing pipeline in the Sebastian, Florida area, which will travel east under the Intercoastal Waterway ("ICW") and southward on the barrier island. As required by Peninsula Pipeline’s tariff and Florida Statutes, Peninsula Pipeline filed the required company and customer affidavits with the Florida PSC in June 2021. Construction commenced in June 2021 and the expected in-service date is first quarter of 2023.

St.Cloud / Twin Lakes Expansion: In July 2022, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with our Florida natural gas division, 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 pipeline extension and regulator station for FPU. The extension will be used to support 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 operation benefits to FPU's existing distribution system in the area, supporting future growth in the area. We expect this expansion to be in service by the first quarter of 2023.

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Eastern Shore

Southern Expansion Project: In January 2022, Eastern Shore submitted a prior notice filing with the FERC pursuant to blanket certificate procedures, regarding its proposal to install an additional compressor unit and related facilities at Eastern Shore's existing compressor station in Bridgeville, Sussex County, Delaware. The project will enable Eastern Shore to provide additional firm natural gas transportation service to an existing shipper on Eastern Shore's pipeline system, with a projected in-service date in the fourth quarter of 2023. We are currently awaiting an order from the FERC on the Company's filing.

Capital Cost Surcharge: In June 2021, Eastern Shore submitted a filing with the FERC regarding a capital cost surcharge to recover capital costs associated with two mandated highway relocate projects that required the replacement of existing Eastern Shore facilities. The capital cost surcharge was an approved item in Eastern Shore’s last rate case. In conjunction with the filing of this surcharge, pursuant to the settlement agreement, a cumulative adjustment to the existing surcharge to reflect additional depreciation was included in this filing. The FERC issued an order approving the surcharge as filed on July 7, 2021. The combined revised surcharge became effective July 15, 2021.

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. 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 these unprecedented times. 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 offers 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 amortized over two years and is 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 June 30, 2022 and December 31, 2021, our total COVID-19 regulatory asset balance was $1.8 million and $2.3 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 occur.

Storm Protection Plan

In 2020, the Florida PSC implemented the Storm Protection Plan ("SPP") and Storm Protection Plan Cost Recovery ("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. The Company’s SPP plan was filed in April 2022, with hearings scheduled for early August 2022. The SPP cost recovery clause ("SPPCRC") was filed in May 2022 with requested rates effective January 1, 2023. The SPPCRC hearing is scheduled for November 2022.

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    Summary TCJA Table

Customer rates for our regulated businesses were adjusted as approved by the regulators, 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 June 30, 2022 and December 31, 2021:

						Amount (in thousands)
Operation and Regulatory Jurisdiction						June 30, 2022			December 31, 2021			Status
Eastern Shore (FERC)						$34,190			$34,190			Will be addressed in Eastern Shore's next rate case filing.
Delaware natural gas division (Delaware PSC)						$12,510			$12,591			PSC approved amortization of ADIT in January 2019.
Maryland natural gas division (Maryland PSC)						$3,772			$3,840			PSC approved amortization of ADIT in May 2018.
Sandpiper Energy (Maryland PSC)						$3,626			$3,656			PSC approved amortization of ADIT in May 2018.
Chesapeake Florida natural gas division/CFG (Florida PSC)						$7,939			$8,032			PSC issued order authorizing amortization and retention of net ADIT liability by the Company in February 2019.
FPU natural gas (excludes Fort Meade and Indiantown) (Florida PSC)						$19,058			$19,189			Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU Fort Meade and Indiantown natural gas divisions (Florida PSC)						$265			$271			Same treatment on a net basis as Chesapeake Florida Gas Division (above).
FPU electric division (Florida PSC)						$5,115			$5,237			In January 2019, PSC issued order approving amortization of ADIT through purchased power cost recovery, storm reserve and rates.
Elkton Gas (Maryland PSC)						$1,074			$1,091			PSC approved amortization of ADIT in March 2018.

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

MGP Sites

We have participated in the investigation, assessment or remediation of, and have exposures at, seven former MGP sites. We have received approval for recovery of clean-up costs in rates for sites located in Salisbury, Maryland; Seaford, Delaware; and Winter Haven, Key West, Pensacola, Sanford and West Palm Beach, Florida.

As of June 30, 2022 and December 31, 2021, we had approximately $4.8 million and $5.2 million, respectively, in environmental liabilities related to the former MGP sites. As of June 30, 2022 and December 31, 2021, we have cumulative regulatory assets of $1.0 million and $1.3 million, respectively, for future recovery of environmental costs for customers. Specific to FPU’s four MGP sites in Key West, Pensacola, Sanford and West Palm Beach, FPU has approval to recover, from insurance and through customer rates, up to $14.0 million of its environmental costs related to its MGP sites. As of June 30, 2022 and December 31, 2021, we had recovered approximately $13.1 million and $12.9 million, respectively, leaving approximately $0.9 million and $1.1 million, respectively, in regulatory assets for future recovery of environmental costs from FPU’s customers.

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

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Natural Gas, Electric and Propane Supply

In March 2020, our Delmarva Peninsula natural gas distribution operations entered into asset management agreements with a third party to manage their natural gas transportation and storage capacity. The agreements were effective as of April 1, 2020 and expire in March 2023.

FPU natural gas distribution operations 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.

Chesapeake Utilities' natural gas division, CFG has firm transportation service contracts with FGT and Gulfstream. Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under these agreements has been released to various third parties. 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 supply contracts require FPU to maintain an acceptable standard of creditworthiness based on specific financial ratios. FPU’s agreement with Florida Power & Light Company requires FPU to meet or exceed a debt service coverage ratio of 1.25 times based on the results of the prior 12 months. If FPU fails to meet this ratio, it must provide an irrevocable letter of credit or pay all amounts outstanding under the agreement within five business days. FPU’s electric supply agreement with Gulf Power requires FPU to meet the following ratios based on the average of the prior six quarters: (a) funds from operations interest coverage ratio (minimum of two times), and (b) total debt to total capital (maximum of 65 percent). If FPU fails to meet the requirements, it has to provide the supplier a written explanation of actions taken, or proposed to be taken, to become compliant. Failure to comply with the ratios specified in the Gulf Power agreement could also result in FPU having to provide an irrevocable letter of credit. As of June 30, 2022, FPU was in compliance with all of the requirements of its fuel supply contracts.

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

Corporate Guarantees

The Board of Directors has authorized us to issue corporate guarantees securing obligations of our subsidiaries and to obtain letters of credit securing our subsidiaries' obligations. The maximum authorized liability under such guarantees and letters of credit as of June 30, 2022 was $20.0 million. The aggregate amount guaranteed related to our subsidiaries at June 30, 2022 was approximately $11.4 million with the guarantees expiring on various dates through May 22, 2023. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at June 30, 2022 was $2.0 million. In July 2022, in connection with the Florida rate case, we entered into a guarantee in the amount of $7.1 million with the Florida PSC.

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

Our operations are entirely domestic and are comprised of two reportable segments:

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

•Unregulated Energy. Includes energy transmission, energy generation (the operations of our Eight Flags' CHP plant), propane operations, and mobile compressed natural gas distribution and pipeline solutions subsidiary. 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.

The remainder of our operations is presented as “Other businesses and eliminations,” which consists of unregulated subsidiaries that own real estate leased to Chesapeake Utilities, as well as certain corporate costs not allocated to other operations. The following table presents financial information about our reportable segments:

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						Three Months Ended												Six Months Ended
						June 30,												June 30,
						2022						2021						2022						2021
(in thousands)
Operating Revenues, Unaffiliated Customers
Regulated Energy						$	91,830					$	80,374					$	215,888					$	201,095
Unregulated Energy						47,640						30,708						146,462						101,173
Total operating revenues, unaffiliated customers						$	139,470					$	111,082					$	362,350					$	302,268
Intersegment Revenues (1)
Regulated Energy						$	363					$	536					$	4,196					$	1,012
Unregulated Energy						5,823						4,065						7,819						8,358
Other businesses						85						133						691						265
Total intersegment revenues						$	6,271					$	4,734					$	12,706					$	9,635
Operating Income
Regulated Energy						$	25,841					$	22,760					$	60,539					$	55,466
Unregulated Energy						560						(465)						20,613						18,575
Other businesses and eliminations						68						283						182						134
Operating income						26,469						22,578						81,334						74,175
Other income, net						2,584						1,453						3,498						1,828
Interest charges						5,825						5,054						11,164						10,159
Income before Income Taxes						23,228						18,977						73,668						65,844
Income Taxes						6,177						5,164						19,683						17,565
Net Income						$	17,051					$	13,813					$	53,985					$	48,279

    

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

(in thousands)						June 30, 2022						December 31, 2021
Identifiable Assets
Regulated Energy segment						$	1,637,003					$	1,629,191
Unregulated Energy segment						447,209						439,114
Other businesses and eliminations						33,130						46,564
Total identifiable assets						$	2,117,342					$	2,114,869

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Common Stock Issuances

In June 2020, we filed a shelf registration statement with the SEC to facilitate the issuance of our common stock from time to time. In August 2020, we filed a prospectus supplement under the shelf registration statement for an ATM equity program under which we may issue and sell shares of our common stock up to an aggregate offering price of $75.0 million.

We maintain an effective shelf registration statement with the SEC for the issuance of shares under our DRIP. Depending on our capital needs and subject to market conditions, in addition to other possible debt and equity offerings, we may issue additional shares under the direct stock purchase component of the DRIP. In 2021, we issued just over 0.1 million shares at an average price per share of $125.71 and received net proceeds of $15.2 million under the DRIP. In the first six months of 2022, we issued less than 0.1 million shares at an average price per share of $137.24 and received net proceeds of $4.3 million under the DRIP.

We used the net proceeds from our share issuances, after fees, for general corporate purposes, including, but not limited to, financing of capital expenditures, repayment of short-term debt, financing acquisitions, investing in subsidiaries, and general working capital purposes.

Accumulated Other Comprehensive Gain (Loss)

Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements 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 income (loss). The following tables present the changes in the balance of accumulated other comprehensive gain (loss) as of June 30, 2022 and 2021. All amounts in the following tables are presented net of tax.

						Defined Benefit						Commodity						Interest Rate
						Pension and						Contracts						Swap
						Postretirement						Cash Flow						Cash Flow
						Plan Items						Hedges						Hedges (1)						Total
(in thousands)
As of December 31, 2021						$	(3,268)					$	4,571					$	—					$	1,303
Other comprehensive income before reclassifications						—						2,206						—						2,206
Amounts reclassified from accumulated other comprehensive income/(loss)						35						(2,174)						—						(2,139)
Net current-period other comprehensive income						35						32						—						67
As of June 30, 2022						$	(3,233)					$	4,603					$	—					$	1,370

(in thousands)
As of December 31, 2020						$	(5,146)					$	2,309					$	(28)					$	(2,865)
Other comprehensive income before reclassifications						—						5,825						23						5,848
Amounts reclassified from accumulated other comprehensive income/(loss)						128						(2,534)						(19)						(2,425)
Net prior-period other comprehensive income						128						3,291						4						3,423
As of June 30, 2021						$	(5,018)					$	5,600					$	(24)					$	558

(1) All of our interest rate swaps expired at December 31, 2021

The following table presents amounts reclassified out of accumulated other comprehensive income (loss) for the three and six months ended June 30, 2022 and 2021. Deferred gains or losses for our commodity contracts and interest rate swap cash flow hedges are recognized in earnings upon settlement.

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						Three Months Ended												Six Months Ended
						June 30,												June 30,
						2022						2021						2022						2021
(in thousands)
Amortization of defined benefit pension and postretirement plan items:
Prior service credit (1)						$	19					$	19					$	38					$	38
Net loss(1)						(43)						(106)						(86)						(209)
Total before income taxes						(24)						(87)						(48)						(171)
Income tax benefit						6						23						13						43
Net of tax						$	(18)					$	(64)					$	(35)					$	(128)
Gains on commodity contracts cash flow hedges:
Propane swap agreements (2)						$	283					$	455					$	3,004					$	3,502
Income tax expense						(78)						(126)						(830)						(968)
Net of tax						$	205					$	329					$	2,174					$	2,534
Gains on interest rate swap cash flow hedges:
Interest rate swap agreements						$	—					$	22					$	—					$	26
Income tax expense						—						(6)						—						(7)
Net of tax						$	—					$	16					$	—					$	19
Total reclassifications for the period						$	187					$	281					$	2,139					$	2,425

(1) These amounts are included in the computation of net periodic costs (benefits). See Note 10, Employee Benefit Plans, for additional details.

(2) These amounts are included in the effects of gains and losses from derivative instruments. See Note 13, Derivative Instruments, for additional details.

Amortization of defined benefit pension and postretirement plan items are included in other expense, net gains and losses on propane swap agreements contracts are included in revenue and unregulated propane and natural gas, the 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 expense in the accompanying condensed consolidated statements of income.

Net periodic benefit costs for our pension and post-retirement benefits plans for the three and six months ended June 30, 2022 and 2021 are set forth in the following tables:

						Chesapeake Pension Plan												FPU Pension Plan												Chesapeake SERP												Chesapeake Postretirement Plan												FPU Medical Plan
For the Three Months Ended June 30,						2022						2021						2022						2021						2022						2021						2022						2021						2022						2021
(in thousands)
Interest cost						$	—					$	34					$	449					$	429					$	13					$	12					$	6					$	6					$	6					$	6
Expected return on plan assets						—						(40)						(857)						(830)						—						—						—						—						—						—
Amortization of prior service credit						—						—						—						—						—						—						(19)						(19)						—						—
Amortization of net (gain) loss						—						60						124						155						7						7						12						10						—						(2)
Total periodic cost (benefit)						$	—					$	54					$	(284)					$	(246)					$	20					$	19					$	(1)					$	(3)					$	6					$	4

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						Chesapeake Pension Plan												FPU Pension Plan												Chesapeake SERP												Chesapeake Postretirement Plan												FPU Medical Plan
For the Six Months Ended June 30,						2022						2021						2022						2021						2022						2021						2022						2021						2022						2021
(in thousands)
Interest cost						$	—					$	68					$	898					$	858					$	26					$	24					$	12					$	12					$	12					$	12
Expected return on plan assets						—						(80)						(1,714)						(1,660)						—						—						—						—						—						—
Amortization of prior service credit						—						—						—						—						—						—						(38)						(38)						—						—
Amortization of net (gain) loss						—						120						248						310						14						14						24						18						—						(4)
Total periodic cost (benefit)						$	—					$	108					$	(568)					$	(492)					$	40					$	38					$	(2)					$	(8)					$	12					$	8

In 2019, we began executing a de-risking strategy for the Chesapeake Pension Plan. In line with this strategy, we fully terminated the Chesapeake Pension Plan during the fourth quarter of 2021, and as of December 31, 2021, there were no remaining assets in the Chesapeake Pension Plan. Accordingly, a portion of the pension settlement expense associated with the termination was allocated to our Regulated Energy operations and was recorded as regulatory assets, previously approved in all of the impacted jurisdictions. The remaining portion of the pension settlement expense totaling $0.6 million was recorded in other expense in our consolidated statement of income in the fourth quarter 2021 which reflected the amount allocated to our Unregulated Energy operations or was deemed not recoverable through the regulatory process.

The components of our net periodic costs have been recorded or reclassified to other expense, net in the condensed consolidated statements of income. Pursuant to their respective regulatory orders, FPU and Chesapeake Utilities continue to record, as a regulatory asset, a portion of their unrecognized postretirement benefit costs related to their regulated 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 income.

The following tables present the amounts included in the regulatory asset and accumulated other comprehensive income that were recognized as components of net periodic benefit cost during the three and six months ended June 30, 2022 and 2021: 

For the Three Months Ended June 30, 2022						Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP						Chesapeake Postretirement Plan						FPU Medical Plan						Total
(in thousands)
Prior service credit						$	—					$	—					$	—					$	(19)					$	—					$	(19)
Net loss						—						124						7						12						—						143
Total recognized in net periodic benefit cost						—						124						7						(7)						—						124
Recognized from accumulated other comprehensive (income)/loss (1)						—						24						7						(7)						—						24
Recognized from regulatory asset						—						100						—						—						—						100
Total						$	—					$	124					$	7					$	(7)					$	—					$	124

    

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For the Three Months Ended June 30, 2021						Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP						Chesapeake Postretirement Plan						FPU Medical Plan						Total
(in thousands)
Prior service credit						$	—					$	—					$	—					$	(19)					$	—					$	(19)
Net loss						60						155						7						10						(2)						230
Total recognized in net periodic benefit cost						60						155						7						(9)						(2)						211
Recognized from accumulated other comprehensive (income)/loss (1)						60						29						7						(9)						—						87
Recognized from regulatory asset						—						126						—						—						(2)						124
Total						$	60					$	155					$	7					$	(9)					$	(2)					$	211

.

For the Six months ended June 30, 2022						Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP						Chesapeake Postretirement Plan						FPU Medical Plan						Total
(in thousands)
Prior service credit						$	—					$	—					$	—					$	(38)					$	—					$	(38)
Net loss						—						248						14						24						—						286
Total recognized in net periodic benefit cost						—						248						14						(14)						—						248
Recognized from accumulated other comprehensive (income)/loss (1)						—						48						14						(14)						—						48
Recognized from regulatory asset						—						200						—						—						—						200
Total						$	—					$	248					$	14					$	(14)					$	—					$	248

For the Six months ended June 30, 2021						Chesapeake Pension Plan						FPU Pension Plan						Chesapeake SERP						Chesapeake Postretirement Plan						FPU Medical Plan						Total
(in thousands)
Prior service credit						$	—					$	—					$	—					$	(38)					$	—					$	(38)
Net loss						120						310						14						18						(4)						458
Total recognized in net periodic benefit cost						120						310						14						(20)						(4)						420
Recognized from accumulated other comprehensive (income)/loss (1)						120						58						14						(20)						(1)						171
Recognized from regulatory asset						—						252						—						—						(3)						249
Total						$	120					$	310					$	14					$	(20)					$	(4)					$	420

(1) See Note 9, Stockholders' Equity.

During the three and six months ended June 30, 2022, we contributed $0.1 million to the FPU Pension Plan. We expect to contribute approximately $0.3 million to the FPU Pension Plan during 2022, which represents the minimum annual contribution payments required.

The Chesapeake SERP, the Chesapeake Postretirement Plan and the FPU Medical Plan are unfunded and are expected to be paid out of our general funds. Cash benefits paid under the Chesapeake SERP for the three and six months ended June 30, 2022 were less than $0.1 million in both periods. We expect to pay total cash benefits of approximately $0.2 million under the Chesapeake SERP in 2022. Cash benefits paid under the Chesapeake Postretirement Plan, primarily for medical claims for both the three and six months ended June 30, 2022 were $0.1 million. We estimate that approximately $0.1 million will be paid for such benefits under the Chesapeake Postretirement Plan in 2022. Cash benefits paid under the FPU Medical Plan, primarily for medical claims for the three and six months ended June 30, 2022, were immaterial. We estimate that approximately $0.1 million will be paid for such benefits under the FPU Medical Plan in 2022.

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The investment balances at June 30, 2022 and December 31, 2021, consisted of the following:

    

(in thousands)			June 30, 2022						December 31, 2021
Rabbi trust (associated with the Non-Qualified Deferred Compensation Plan)			$	10,499					$	12,069
Investments in equity securities			24						26
Total			$	10,523					$	12,095

We classify these investments as trading securities and report them at their fair value. For the three months ended June 30, 2022 and 2021, we recorded a net unrealized loss of $1.4 million and a net unrealized gain of $0.6 million, respectively, in other income, net in the condensed consolidated statements of income related to these investments. For the six months ended June 30, 2022 and 2021, we recorded a net unrealized loss of approximately $2.0 million and a net unrealized gain of approximately $1.0 million, respectively, in other expense, net in the condensed consolidated statements of income related to these investments. For the investment in the Rabbi Trust, we also have recorded an associated liability, which is included in other pension and benefit costs in the consolidated balance sheets and is adjusted each period for the gains and losses incurred by the investments in the Rabbi Trust.

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

The table below presents the amounts included in net income related to share-based compensation expense for the three and six months ended June 30, 2022 and 2021:

    

						Three Months Ended												Six Months Ended
						June 30,												June 30,
						2022						2021						2022						2021
(in thousands)
Awards to non-employee directors						$	220					$	192					$	454					$	380
Awards to key employees						1,122						1,247						3,101						2,935
Total compensation expense						1,342						1,439						3,555						3,315
Less: tax benefit						(346)						(384)						(917)						(885)
Share-based compensation amounts included in net income						$	996					$	1,055					$	2,638					$	2,430

    

Non-employee Directors

Shares granted to non-employee directors are issued in advance of the directors’ service periods and are fully vested as of the grant date. We record a deferred expense equal to the fair value of the shares issued and amortize the expense equally over a service period of one year. In May 2022, after the most recent election of directors, each of our non-employee directors received an annual retainer of 652 shares of common stock under the SICP for service as a director through the 2023 Annual Meeting of Stockholders; accordingly, 6,520 shares, with a weighted average fair value of $130.36 per share, were issued and vested in 2022.

At June 30, 2022, there was approximately $0.7 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 of 2023.

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In July, 2022, we announced the appointment of two new non-employee directors to our current Board. These newly appointed directors will be granted share-based awards through the SICP that will be pro-rated in accordance with the beginning of their service period. The associated expense will be recognized in the same manner utilized for our current non-employee directors.

Key Employees

The table below presents the summary of the stock activity for awards to key employees for the six months ended June 30, 2022: 

						Number of Shares						Weighted Average Fair Value
Outstanding—December 31, 2021						197,398						$	94.15
Granted						66,942						$	119.77
Vested						(60,850)						$	90.60
Expired						557						$	91.42
Outstanding—June 30, 2022						204,047						$	102.91

During the six months ended June 30, 2022, we granted awards of 66,942 shares of common stock to key employees under the SICP, including awards granted in February 2022 and to key employees appointed in officer positions. The shares granted are multi-year awards that will vest no later than the three-year service period ending December 31, 2024. All of these stock awards are earned based upon the successful achievement of long-term financial results, which are 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 Monte Carlo valuation to estimate the fair value of each market-based award granted.

In March 2022, upon the election by certain of our executive officers, we withheld shares with a value at least equivalent to each such executive officer’s minimum statutory obligation for applicable income and other employment taxes related to shares that vested and were paid in February 2022 for the performance period ended December 31, 2021, paid the balance of such awarded shares to each such executive officer net cash remitted to the appropriate taxing authorities. We withheld 21,832 shares, based on the value of the shares on their award date. Total combined payments for the employees’ tax obligations to the taxing authorities were approximately $2.8 million.

At June 30, 2022, the aggregate intrinsic value of the SICP awards granted to key employees was approximately $26.4 million. At June 30, 2022, there was approximately $8.8 million of unrecognized compensation cost related to these awards, which will be recognized through 2024.

Stock Options

There were no stock options outstanding or issued during the six months ended June 30, 2022 and 2021.

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Volume of Derivative Activity

As of June 30, 2022, the volume of our commodity derivative contracts were as follows:

Business unit

Commodity

Contract Type

Quantity hedged (in millions)

Designation

Longest Expiration date of hedge

Sharp

Propane (gallons)

Purchases

16.0

Cash flows hedges

June 2024

Sharp

Propane (gallons)

Sales

3.8

Cash flows hedges

March 2023

Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes that are expected to be purchased 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 June 2022 through June 2024) and (ii) the per gallon propane swap prices, to the extent the index prices exceed the contracted prices. If the index prices are lower than the contract prices, Sharp will pay the difference. We designated and accounted for the propane swaps as cash flows hedges. The change in the fair value of the swap agreements is recorded as unrealized gain (loss) in other comprehensive income (loss) and later recognized in the statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $3.8 million from accumulated other comprehensive income to earnings during the next 12-month period ended June 30, 2023.

Interest Rate Swap Activities

We manage interest rate risk by entering into derivative contracts to hedge the variability in cash flows attributable to changes in the short-term borrowing rates. In the fourth quarter of 2020, we entered into two $30.0 million interest rate swaps with a total notional amount of $60.0 million through September and December 2021 with pricing of 0.205 and 0.20 percent, respectively, for the period associated with our outstanding borrowing under the Revolver. In February 2021, we entered into an additional interest rate swap with a notional amount of $40.0 million through December 2021 with pricing of 0.17 percent. Our short-term borrowing is based on the 30-day LIBOR rate. The interest swaps were cash settled monthly as the counter-party pays us the 30-day LIBOR rate less the fixed rate. At December 31, 2021 all of our interest rate swaps had expired and we have not entered into any new derivative contracts associated with our outstanding short-term borrowings in 2022.

We designated and accounted for interest rate swaps as cash flows hedges. Accordingly, unrealized gains and losses associated with the interest rate swaps were recorded as a component of accumulated other comprehensive income (loss). When the interest rate swaps settled, the realized gain or loss was recorded in the income statement and recognized as a component of interest charges.

Broker Margin

Futures exchanges have contract specific margin requirements that require the posting of cash or cash equivalents relating to traded contracts. Margin requirements consist of initial margin that is posted upon the initiation of a position, maintenance margin that is usually expressed as a percent of initial margin, and variation margin that fluctuates based on the daily mark-to-market relative to maintenance margin requirements. We currently maintain a broker margin account for Sharp as follows:

(in thousands)			Balance Sheet Location						June 30, 2022						December 31, 2021
Sharp			Other Accrued Liabilities						$	4,418					$	4,081

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Financial Statements Presentation

The following tables present information about the fair value and related gains and losses of our derivative contracts. We did not have any derivative contracts with a credit-risk-related contingency. Fair values of the derivative contracts recorded in the consolidated balance sheets as of June 30, 2022 and December 31, 2021, are as follows: 

						Derivative Assets
												Fair Value As Of
(in thousands)						Balance Sheet Location						June 30, 2022						December 31, 2021
Derivatives not designated as hedging instruments
Propane swap agreements						Derivative assets, at fair value						$	—					$	16
Derivatives designated as cash flow hedges
Propane swap agreements						Derivative assets, at fair value						6,772						7,060
Total Derivative Assets												$	6,772					$	7,076

 

Derivative Liabilities

Fair Value As Of

(in thousands)

Balance Sheet Location

June 30, 2022

December 31, 2021

Derivatives designated as cash flow hedges

Propane swap agreements

Derivative liabilities, at fair value

$

427

$

743

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

												Amount of Gain (Loss) on Derivatives:
						Location of Gain						For the Three Months Ended June 30,												For the Six Months Ended June 30,
(in thousands)						(Loss) on Derivatives						2022						2021						2022						2021
Derivatives not designated as hedging instruments
Propane swap agreements						Unregulated propane and natural gas costs						$	—					$	—					$	56					$	—
Derivatives designated as fair value hedges
Propane put options						Unregulated propane and natural gas costs						—						—						—						(24)
Derivatives designated as cash flow hedges
Propane swap agreements						Revenues						—						—						(826)						—
Propane swap agreements						Unregulated propane and natural gas costs						283						455						3,830						3,502
Propane swap agreements						Other comprehensive income (loss)						(686)						4,319						28						4,548
Interest rate swap agreements						Interest expense						—						22						—						26
Interest rate swap agreements						Other comprehensive income						—						8						—						5
Total												$	(403)					$	4,804					$	3,088					$	8,057

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GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation methods used to measure fair value. The three levels of the fair value hierarchy are the following:

Fair Value Hierarchy			Description of Fair Value Level			Fair Value Technique Utilized
Level 1			Unadjusted 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 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			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 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)			Investments - guaranteed income fund - The fair values of these investments are recorded at the contract value, which approximates their fair value.

Financial Assets and Liabilities Measured at Fair Value

The following tables 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 June 30, 2022 and December 31, 2021:

												Fair Value Measurements Using:
As of June 30, 2022						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						$	24					$	24					$	—					$	—
Investments—guaranteed income fund						2,102						—						—						2,102
Investments—mutual funds and other						8,397						8,397						—						—
Total investments						10,523						8,421						—						2,102
Derivative assets						6,772						—						6,772						—
Total assets						$	17,295					$	8,421					$	6,772					$	2,102
Liabilities:
Derivative liabilities						$	427					$	—					$	427					$	—

 

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												Fair Value Measurements Using:
As of December 31, 2021						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						$	26					$	26					$	—					$	—
Investments—guaranteed income fund						2,036						—						—						2,036
Investments—mutual funds and other						10,033						10,033						—						—
Total investments						12,095						10,059						—						2,036
Derivative assets						7,076						—						7,076						—
Total assets						$	19,171					$	10,059					$	7,076					$	2,036
Liabilities:
Derivative liabilities						$	743					$	—					$	743					$	—

The following table sets forth the summary of the changes in the fair value of Level 3 investments for the six months ended June 30, 2022 and 2021:

     

			Six months ended June 30,
			2022						2021
(in thousands)
Beginning Balance			$	2,036					$	2,156
Purchases and adjustments			132						70
Transfers			—						—
Distribution			(83)						(51)
Investment income			17						16
Ending Balance			$	2,102					$	2,191

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

At June 30, 2022, 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 near-term maturities and because interest rates approximate current market rates (Level 3 measurement).

At June 30, 2022, long-term debt, which includes current maturities but excludes debt issuance costs, had a carrying value of approximately $608.3 million, compared to the estimated fair value of $540.6 million. At December 31, 2021, long-term debt, which includes the current maturities but excludes debt issuance costs, had a carrying value of approximately $568.8 million, compared to a fair value of approximately $597.2 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. The valuation technique used to estimate the fair value of long-term debt would be considered a Level 3 measurement.

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Our outstanding long-term debt is shown below: 

						June 30,						December 31,
(in thousands)						2022						2021
Uncollateralized senior notes:
5.93% note, due October 31, 2023						$	4,500					$	6,000
5.68% note, due June 30, 2026						11,600						14,500
6.43% note, due May 2, 2028						4,200						4,900
3.73% note, due December 16, 2028						14,000						14,000
3.88% note, due May 15, 2029						35,000						40,000
3.25% note, due April 30, 2032						70,000						70,000
3.48% note, due May 31, 2038						50,000						50,000
3.58% note, due November 30, 2038						50,000						50,000
3.98% note, due August 20, 2039						100,000						100,000
2.98% note, due December 20, 2034						70,000						70,000
3.00% note, due July 15, 2035						50,000						50,000
2.96% note, due August 15, 2035						40,000						40,000
2.49% notes Due January 25, 2037						50,000						50,000
2.95% notes Due March 15, 2042						50,000						—
Equipment security note
2.46% note, due September 24, 2031						8,950						9,378
Less: debt issuance costs						(973)						(913)
Total long-term debt						607,277						567,865
Less: current maturities						(21,472)						(17,962)
Total long-term debt, net of current maturities						$	585,805					$	549,903

    

Note Purchase Agreement

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 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.

Equipment Security Note

On September 24, 2021, we entered into an Equipment Financing Agreement with Banc of America Leasing & Capital, LLC to issue $9.6 million in sustainable financing to finance the purchase of equipment by our subsidiary, Marlin Gas Services. The equipment security note bears a 2.46 percent interest rate and has a term of ten years. Under the terms of the agreement, we granted a security interest in the equipment to the lender, to serve as collateral.

Shelf Agreements

We have entered into Shelf Agreements with Prudential and MetLife, whom are under no obligation to purchase any unsecured debt. The following table summarizes our Shelf Agreements at June 30, 2022:

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(in thousands)						Total Borrowing Capacity						Less: Amount of Debt Issued						Less: Unfunded Commitments						Remaining Borrowing Capacity
Shelf Agreement
Prudential Shelf Agreement (1)						$	370,000					$	(220,000)					$	—					$	150,000
MetLife Shelf Agreement (1)						150,000						(50,000)						—						100,000
Total Shelf Agreements as of June 30, 2022						$	520,000					$	(270,000)					$	—					$	250,000

     (1) The Prudential and MetLife Shelf Agreements expire in April 2023 and May 2023, respectively.

The Uncollateralized Senior Notes, Shelf Agreements or Shelf Notes set forth certain business covenants to which we are subject when any note is outstanding, including covenants that limit or restrict our ability, and the ability of our subsidiaries, to incur indebtedness, or place or permit liens and encumbrances on any of our property or the property of our subsidiaries.

16.    Short-Term Borrowings

We are authorized by our Board of Directors to borrow up to $400.0 million of short-term debt, as required. At June 30, 2022 and December 31, 2021, we had $137.0 million and $221.6 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 2.38 percent and 0.83 percent, respectively.

In August 2021, we amended and restated our Revolver into a multi-tranche facility totaling $400.0 million with multiple participating lenders. The two tranches of the Revolver consist of a $200.0 million 364-day short-term debt tranche and a $200.0 million five-year tranche, both of which have three (3) one-year extension options, which can be authorized by our Chief Financial Officer. We are eligible to establish the repayment term for individual borrowings under the five year tranche of the Revolver and to the extent that an individual loan under the Revolver exceeded 12 months, the outstanding balance would be classified as a component of long-term debt.

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 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 June 30, 2022, we are in compliance with this covenant.

The 364-day tranche of the Revolver expires in August 2022 and the five-year tranche expires in August 2026 both are available to fund for 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. Our pricing is adjusted each quarter based upon a total indebtedness to total capitalization ratio. As of June 30, 2022, the pricing under the 364-day tranche of the Revolver does not include an unused commitment fee and maintains an interest rate of 0.70 percent over LIBOR. As of June 30, 2022, the pricing under the five-year tranche of the Revolver included an unused commitment fee of 0.09 percent and an interest rate of 0.95 percent over LIBOR.

We are currently in discussions with the various lending institutions regarding the renewal of the 364-day tranche. At that time, the reference interest rate for the 364-day and five-year tranche will transition from LIBOR which is being retired by financial institutions to the Standard Overnight Financing Rate ("SOFR"). We do not expect this transition to have a material impact on our financial condition.

Our total available credit under the Revolver at June 30, 2022 was $257.7 million. As of June 30, 2022, we had issued $5.3 million in letters of credit to various counterparties under the syndicated Revolvers. These letters of 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 our syndicated Revolver.

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    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 June 30, 2022, 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 June 30, 2022, 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												Six Months Ended
												June 30,												June 30,
( in thousands)						Classification						2022						2021						2022						2021
Operating lease cost (1)						Operations expense						$726						$515						$1,377						$1,038

(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 June 30, 2022 and December 31, 2021:

(in thousands)						Balance sheet classification						June 30, 2022						December 31, 2021
Assets
Operating lease assets						Operating lease right-of-use assets						$	15,767					$	10,139
Liabilities
Current
Operating lease liabilities						Other accrued liabilities						$	2,501					$	1,996
Noncurrent
Operating lease liabilities						Operating lease - liabilities						13,807						8,571
Total lease liabilities												$	16,308					$	10,567

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The following table presents our weighted-average remaining lease terms and weighted-average discount rates for our operating and financing leases at June 30, 2022 and December 31, 2021:

						June 30, 2022						December 31, 2021
Weighted-average remaining lease term (in years)
Operating leases						8.32						8.10
Weighted-average discount rate
Operating leases						3.3		%				3.6		%

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 June 30, 2022 and 2021:

						Six Months Ended
						June 30,
(in thousands)						2022						2021
Operating cash flows from operating leases						$	1,428					$	936

The following table presents the future undiscounted maturities of our operating and financing leases at June 30, 2022 and for each of the next five years and thereafter:

(in thousands)						Operating  Leases (1)
Remainder of 2022						$	1,392
2023						2,844
2024						2,629
2025						2,260
2026						1,746
2027						1,501
Thereafter						5,994
Total lease payments						18,366
Less: Interest						(2,058)
Present value of lease liabilities						$	16,308

    (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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