EDGAR 10-K Filing

Company CIK: 19745
Filing Year: 2025
Filename: 19745_10-K_2025_0001628280-25-008213.json

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ITEM 1. BUSINESS
ITEM 1. Business.
Corporate Overview and Strategy
Chesapeake Utilities Corporation is a Delaware corporation formed in 1947 with operations primarily in the Mid-Atlantic region, North Carolina, South Carolina, Florida and Ohio. We are an energy delivery company engaged in the distribution of natural gas, electricity and propane, the transmission of natural gas, the generation of electricity and steam, and in providing mobile compressed natural gas and other energy-related services to our customers.
Our strategy is focused on growing earnings from a stable regulated energy delivery foundation and investing in related businesses and services that together provide opportunities for returns greater than traditional utility returns. We seek to identify and develop opportunities across the energy value chain, with emphasis on regulated midstream and downstream investments that are accretive to earnings per share and create opportunities to continue our record of top tier returns on equity relative to our peer group. The Company’s growth strategy includes the continued investment and expansion of the Company’s regulated operations that provide a stable base of earnings, as well as investments in other related non-regulated businesses and services including sustainable investments, such as renewable natural gas related investments.
Currently, the Company’s growth strategy is focused on the following platforms, including:
•Prudently deploying investment capital.
◦Optimizing the earnings growth in our existing businesses, which includes organic growth, territory expansions, and new products and services
◦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.
◦Leveraging our current capabilities, including our integrated set of energy delivery businesses, to support and contribute to a more sustainable future.
•Proactively managing our regulatory agenda.
◦Driving regulatory initiatives that align with our growth strategy and investment plans.
•Continually executing on our business transformation initiatives.
◦Increased opportunities to transform the Company with a focus on people, process, technology and organizational structure.
Operating Segments
We conduct operations within two reportable segments: Regulated Energy and Unregulated Energy. The remainder of our operations are presented as "Other businesses and eliminations" which were not material to our earnings or our financial position at December 31, 2024. These segments are described below in detail.
Regulated Energy
Overview
Our regulated energy businesses are comprised of natural gas and electric distribution, as well as natural gas transmission services.
On November 30, 2023, we completed the acquisition of FCG for $922.8 million in cash, including working capital adjustments as defined in the agreement, pursuant to the previously disclosed stock purchase agreement with Florida Power & Light Company. Upon completion of the acquisition, FCG became a wholly-owned subsidiary of the Company and is included within our Regulated Energy segment. FCG serves approximately 123,000 residential and commercial natural gas customers across eight counties in Florida, including Miami-Dade, Broward, Brevard, Palm Beach, Hendry, Martin, St. Lucie and Indian River. Its natural gas system includes approximately 3,982 miles of distribution main and 80 miles of transmission pipe. Results for FCG are included within our consolidated results from the acquisition date.
Chesapeake Utilities Corporation 2024 Form 10-K Page 3
The following table presents net income for the year ended December 31, 2024 and total assets as of December 31, 2024, by operation and area served:
Operations Areas Served Net Income Total Assets
(in millions)
Natural Gas Distribution
Florida Natural Gas Florida $ 26.4 $ 617.1
Florida City Gas Florida 13.5 1,106.9
Delmarva Natural Gas (1)
Delaware/Maryland 12.1 449.5
Natural Gas Transmission
Eastern Shore Delaware/Maryland/
Pennsylvania 25.2 508.9
Peninsula Pipeline Florida 14.7 165.5
Aspire Energy Express Ohio 0.9 6.8
Electric Distribution
FPU Florida 5.1 188.2
Total Regulated Energy $ 97.9 $ 3,042.9
(1) Delmarva Natural Gas consists of Delaware division, Maryland division, Sandpiper Energy and Elkton Gas.
Revenues in the Regulated Energy segment are based on rates regulated by the PSC in the states in which we operate or, in the case of Eastern Shore which is an interstate business, by the FERC. The rates are designed to generate revenues to recover all prudent operating and financing costs and provide a reasonable return for our stockholders. Each of our distribution and transmission operations has a rate base, which generally consists of the original cost of the operation's plant (less accumulated depreciation), working capital and other assets. For Delmarva Natural Gas and Eastern Shore, rate base also includes deferred income tax liabilities and other additions or deductions. The Florida Natural Gas, FCG, and FPU electric regulated energy operations do not include deferred income tax liabilities in their rate base.
Our natural gas and electric distribution operations bill customers at standard rates approved by their respective state PSC. Each state PSC allows us to negotiate rates, based on approved methodologies, for large customers that can switch to other fuels. Some of our customers in Maryland receive propane through underground distribution systems in Worcester County. We bill these customers under PSC-approved rates and include them in the natural gas distribution results and customer statistics.
Our natural gas and electric distribution operations earn profits on the delivery of natural gas or electricity to customers. The cost of natural gas or electricity that we deliver is passed through to customers under PSC-approved fuel cost recovery mechanisms. The mechanisms allow us to adjust our rates on an ongoing basis without filing a rate case to recover changes in the cost of the natural gas and electricity that we purchase for customers. Therefore, while our distribution operating revenues fluctuate with the cost of natural gas or electricity we purchase, our distribution adjusted gross margin is generally not impacted by fluctuations in the cost of natural gas or electricity.
Our natural gas transmission operations bill customers under rate schedules approved by the FERC or at rates negotiated with customers.
Chesapeake Utilities Corporation 2024 Form 10-K Page 4
Operational Highlights
The following table presents operating revenues, volumes and the average number of customers by customer class for our natural gas and electric distribution operations for the year ended December 31, 2024:
Delmarva
Natural Gas Distribution
Florida
Natural Gas Distribution Florida
City Gas Distribution FPU
Electric
Distribution
Operating Revenues (in millions)
Residential $ 79.4 62 % $ 48.8 29 % $ 52.4 37 % $ 50.3 54 %
Commercial and Industrial 47.7 37 % 107.4 63 % 69.1 49 % 48.1 52 %
Other (1)
1.7 1 % 14.1 8 % 18.8 14 % (5.8) (6) %
Total Operating Revenues $ 128.8 100 % $ 170.3 100 % $ 140.3 100 % $ 92.6 100 %
Volumes (in Dts for natural gas/MW Hours for electric)
Residential 4,502,823 29 % 2,315,717 5 % 1,805,825 10 % 311,628 44 %
Commercial and Industrial 10,559,929 69 % 38,377,357 90 % 11,260,037 59 % 396,393 56 %
Other 280,468 2 % 2,139,372 5 % 5,938,383 31 % - - %
Total Volumes 15,343,220 100 % 42,832,446 100 % 19,004,245 100 % 708,021 100 %
Average Number of Customers (2)
Residential 101,610 92 % 91,839 92 % 113,917 93 % 25,756 78 %
Commercial and Industrial 8,379 8 % 8,517 8 % 8,561 7 % 7,350 22 %
Other 25 - % - - % 113 <1% - - %
Total Average Number of Customers 110,014 100 % 100,356 100 % 122,591 100 % 33,106 100 %
(1) Operating Revenues from "Other" sources include revenue, unbilled revenue, under (over) recoveries of fuel cost, conservation revenue, other miscellaneous charges, fees for billing services provided to third parties, and adjustments for pass-through taxes.
(2) Average number of customers is based on the twelve-month average for the year ended December 31, 2024.
The following table presents operating revenues, by customer type, for Eastern Shore and Peninsula Pipeline for the year ended December 31, 2024, as well as contracted firm transportation capacity by customer type, and design day capacity at December 31, 2024. Aspire Energy Express has been excluded from the table below and had operating revenue of $1.5 million and firm transportation capacity of 300,000 Dts/d for the year ended December 31, 2024:
Eastern Shore Peninsula Pipeline
Operating Revenues (in millions)
Local distribution companies - affiliated (1)
$ 35.2 43 % $ 32.3 94 %
Local distribution companies - non-affiliated 22.3 27 % - - %
Commercial and industrial - affiliated - - % 1.1 3 %
Commercial and industrial - non-affiliated 23.9 29 % 0.5 1 %
Other (2)
0.3 1 % 0.6 2 %
Total Operating Revenues $ 81.7 100 % $ 34.5 100 %
Contracted firm transportation capacity (in Dts/d)
Local distribution companies - affiliated 167,595 52 % 907,501 99 %
Local distribution companies - non-affiliated 56,576 18 % - - %
Commercial and industrial - affiliated - - % 1,500 - %
Commercial and industrial - non-affiliated 96,040 30 % 5,100 1 %
Total Contracted firm transportation capacity 320,211 100 % 914,101 100 %
Design day capacity (in Dts/d)
320,211 100 % 914,101 100 %
(1) Eastern Shore's and Peninsula Pipeline's service to our local distribution affiliates is based on the respective regulator's approved rates and is an integral component of the cost associated with providing natural gas supplies to the end users of those affiliates. We eliminate operating revenues of these entities against the natural gas costs of those affiliates in our consolidated financial information; however, our local distribution affiliates include this amount in their purchased fuel cost and recover it through fuel cost recovery mechanisms.
(2) Operating revenues from "Other" sources include the rental of gas properties.
Chesapeake Utilities Corporation 2024 Form 10-K Page 5
Regulatory Overview
The following table highlights key regulatory information that was effective for each of our principal Regulated Energy operations at December 31, 2024. Peninsula Pipeline and Aspire Energy Express are not regulated with regard to cost of service by either the Florida PSC, the Ohio PUC or the FERC and are therefore excluded from the table. See Item 8, Financial Statements and Supplementary Data (Note 18, Rates and Other Regulatory Activities, in the consolidated financial statements) for further discussion on the impact of this legislation on our regulated businesses.
Natural Gas Distribution
Delmarva Florida Electric Distribution Natural Gas Transmission
Operation/Division Delaware (1)
Maryland (2)
Sandpiper (2)
Elkton Gas (2) (3)
Florida Natural Gas Florida City Gas FPU (4)
Eastern Shore
Regulatory Agency Delaware PSC Maryland PSC Florida PSC FERC
Effective date - Last Rate Order 01/01/2017
12/01/2007 12/01/2019 02/07/2019 03/01/2023
06/09/2023
10/08/2020 08/01/2017
Rate Base (in Rates) (in millions) Not stated
Not stated Not stated Not stated $453.7 $487.3 $24.9 Not stated
Annual Rate Increase Approved (in millions) $2.3 $0.6 N/A(5)
$0.1 $17.2 $14.1 $3.4 base rate and $7.7 from storm surcharge $9.8
Capital Structure (in rates) (6)*
Not stated
LTD: 42% STD: 5% Equity: 53% Not stated
LTD: 50% Equity: 50% LTD: 33%
STD: 5%
Equity: 45%
Other: 17% LTD: 31%
STD: 4%
Equity: 53%
Other: 12% LTD: 22%
STD: 23%
Equity: 55% Not stated
Allowed ROE (7)
9.75%
10.75%
Not stated (8)
9.80% 10.25%
9.50%
10.25% (9)
Not stated
TJCA Refund Status associated with customer rates Refunded Refunded Refunded N/A Retained Refunded Refunded Refunded
(1) In August 2024, our Delaware natural gas division filed an application for a natural gas rate case with the Delaware PSC. Additional details related to the filing are disclosed below.
(2) In January 2024, our natural gas distribution businesses in Maryland, CUC-Maryland Division, Sandpiper Energy, Inc., and Elkton Gas Company (collectively, “Maryland natural gas distribution businesses”) filed a joint application for a natural gas rate case with the Maryland PSC additional details regarding the filing are disclosed below.
(3) The rate increase and allowed ROE for Elkton Gas were approved by the Maryland PSC before we acquired the company.
(4) In August 2024, our Florida Electric division filed a petition with the Florida PSC. Additional details in connection with the petition are disclosed below.
(5) The terms of the agreement include revenue neutral rates for the first year (December 1, 2016 through November 30, 2017), followed by a schedule of rate reductions in subsequent years based upon the projected rate of propane to natural gas conversions.
(6) Other components of capital structure include customer deposits, deferred income taxes and tax credits.
(7) Allowed after-tax ROE.
(8) The Maryland PSC approved a declining ROE.
(9) The terms of the settlement agreement for the FPU electric division limited proceeding with the Florida PSC prescribed an authorized ROE range of 9.25 to 11.25 percent, with a mid-point of 10.25 percent.
* LTD-Long-term debt; STD-Short-term debt.
In January 2024, our natural gas distribution businesses in Maryland, CUC-Maryland Division, Sandpiper Energy, Inc., and Elkton Gas Company (collectively, “Maryland natural gas distribution businesses”) filed a joint application for a natural gas rate case with the Maryland PSC. In connection with the application, we are seeking approval of the following: (i) permanent rate relief of approximately $6.9 million with a ROE of 11.5 percent; (ii) authorization to make certain changes to tariffs to include a unified rate structure and to consolidate the Maryland natural gas distribution businesses which we anticipate will be called Chesapeake Utilities of Maryland, Inc.; and (iii) authorization to establish a rider for recovery of the costs associated with our new technology systems. In August 2024, the Maryland natural gas distribution businesses, the Maryland Office of Peoples' Counsel ("OPC") and PSC Staff reached a settlement agreement which provided for, among other things, an increase in annual base rates of $2.6 million. In September 2024, the Maryland Public Utility Judge issued an order approving the settlement agreement in part. The $2.6 million increase in annual base rates was approved and the Company filed the Phase II filing in November 2024 to determine rate design across the Maryland natural gas distribution businesses, consolidation of the applicable tariffs and recovery of technology costs. The discovery process for Phase II has commenced and the hearing has been scheduled for March 2025. The outcome of the application is subject to review and approval by the Maryland PSC.
In January 2024, our Maryland natural gas distribution businesses also filed a joint petition for approval of their proposed unified depreciation rates with the Maryland PSC. A settlement agreement between the Company, PSC staff and the OPC was reached and the final order approving the settlement agreement went into effect in July 2024, with new depreciation rates
Chesapeake Utilities Corporation 2024 Form 10-K Page 6
effective as of January 1, 2023. The approved depreciation resulted in an annual reduction in depreciation expense of approximately $1.2 million.
In August 2024, our Florida Electric division filed a petition with the Florida PSC seeking a general base rate increase of $12.6 million with a ROE of 11.3 percent based on a 2025 projected test year. Annualized interim rates of approximately $1.8 million, were approved and became effective in November 2024. The outcome of the application is subject to review and approval by the Florida PSC. The hearings for the approval of the revenue requirement and rates are scheduled to occur in March 2025.
In August 2024, our Delaware natural gas division filed an application for a natural gas rate case with the Delaware PSC. In connection with the application, we are seeking approval of the following: (i) permanent rate relief of approximately $12.1 million with ROE of 11.5 percent; (ii) proposed changes to depreciation rates which were part of a depreciation study also submitted with the filing; and (iii) authorization to make certain changes to tariffs. Annualized interim rates approved by the Delaware PSC in the amount of $2.5 million became effective in October 2024. The discovery process has commenced and the hearing for the proceeding has been scheduled for May 2025. The outcome of the application is subject to review and approval by the Delaware PSC.
In May 2022, our legacy natural gas distribution businesses 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 in January 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. 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 were approved by the Florida PSC in February 2023 which became effective in March 2023.
In May 2022, FCG filed a general base rate increase with the Florida PSC based on a projected 2023 test year. In June 2023, the Florida PSC issued an order approving a single total base revenue increase of $23.3 million (which included an incremental increase of $14.1 million, a previously approved increase of $3.8 million for a liquefied natural gas facility, and $5.3 million to transfer the SAFE investments from a rider clause to base rates), with new rates becoming effective as of May 1, 2023. The Commission also approved FCG's proposed reserve surplus amortization mechanism ("RSAM") with a $25.0 million reserve amount, continuation and expansion of the capital SAFE program, implementation of an automated metering infrastructure pilot, and continuation of the storm damage reserve with a target reserve of $0.8 million. In June 2023, the Florida OPC filed a motion for reconsideration of the PSC’s approval of RSAM, which was denied in September 2023. In July 2023, the Florida OPC filed a notice of appeal with the Florida Supreme Court, which is pending. The Florida OPC filed their initial brief in January 2024 with answer briefs filed in April 2024. Oral arguments in the case were held in December 2024.
In February 2025, FCG filed a depreciation study with the Florida PSC. The application is requesting approval of revised annual depreciation rates, as well as a reduction related to a reserve imbalance that would be amortized over a two-year period. The outcome of the application is subject to review and approval by the Florida PSC.
The following table presents margin stability mechanisms that have been approved by the respective PSC for our regulated energy distribution businesses at December 31, 2024. These include: Delaware surcharges to expand natural gas service in its service territory as well as for the conversion of propane distribution systems to natural gas; Maryland’s surcharges to fund natural gas conversions and system improvements in Worcester County; Elkton's Strategic Infrastructure Development and Enhanced (STRIDE) plan for accelerated pipeline replacement for older portions of the natural gas distribution system; Florida’s GUARD surcharge which provides accelerated recovery of the costs of replacing older portions of the natural gas distribution system to improve safety and reliability; FCG's SAFE surcharge which provides accelerated recovery of the costs of replacing older portions of that natural gas distribution system to improve safety and reliability; and the Florida electric distribution operation's limited proceeding which allowed recovery of storm-related costs and the Storm Protection Plan ("SPP") which provides recovery of storm hardening costs.
Chesapeake Utilities Corporation 2024 Form 10-K Page 7
Operation(s)/Division(s) Jurisdiction Infrastructure mechanism
Margin stability mechanism (1)
Delaware division Delaware Yes No
Maryland division Maryland No Yes
Sandpiper Energy Maryland Yes Yes
Elkton Gas Maryland Yes Yes
Florida Natural Gas Florida Yes No
Florida City Gas (2)
Florida Yes No
FPU electric division Florida Yes No
(1) Margin stability mechanisms reduce variability due to rate design, revenue normalization clauses, and other riders.
(2) See Item 8, Financial Statements and Supplementary Data, Note 18, Rates and Other Regulatory Activities, for additional information related to FCG's RSAM that was approved as part of its rate case effective as of May 1, 2023.
Weather
Weather variations directly influence the volume of natural gas and electricity sold and delivered to residential and commercial customers for heating and cooling and changes in volumes delivered impact the revenue generated from these customers. Natural gas volumes are highest during the winter months, when residential and commercial customers use more natural gas for heating. Demand for electricity is highest during the summer months, when more electricity is used for cooling. We measure the relative impact of weather using degree-days. A degree-day is the measure of the variation in the weather based on the extent to which the average daily temperature falls above or below 65 degrees Fahrenheit. Each degree of temperature below 65 degrees Fahrenheit is counted as one HDD, and each degree of temperature above 65 degrees Fahrenheit is counted as one CDD. Normal heating and cooling degree-days are based on the most recent 10-year average.
Competition
Natural Gas Distribution
While our natural gas distribution operations do not compete directly with other distributors of natural gas for residential and commercial customers in our service areas, we do compete with other natural gas suppliers and alternative fuel providers for sales to industrial customers. Large customers could bypass our natural gas distribution systems and connect directly to intrastate or interstate transmission pipelines, and we compete in all aspects of our natural gas business with alternative energy sources, including electricity, oil, propane and renewables. The most effective means to compete against alternative fuels are lower prices, superior reliability and flexibility of service. Natural gas historically has maintained a price advantage in the residential, commercial and industrial markets, and reliability of natural gas supply and service has been excellent. In addition, we provide flexible pricing to our large customers to minimize fuel switching and protect these volumes and their contributions to the profitability of our natural gas distribution operations.
Chesapeake Utilities Corporation 2024 Form 10-K Page 8
Natural Gas Transmission
Our natural gas transmission business competes with other interstate and intrastate pipeline companies to provide service to large industrial, generation and distribution customers, primarily in the northern portion of the Delmarva Peninsula and in Florida. Our transmission business in Ohio, Aspire Energy Express, services one customer, Guernsey Power Station, to which it is the sole supplier.
Electric Distribution
While our electric distribution operations do not compete directly with other distributors of electricity for residential and commercial customers in our service areas, we do compete with other electricity suppliers and alternative fuel providers for sales to industrial customers. Some of our large industrial customers may be capable of generating their own electricity, and we structure rates, service offerings and flexibility to retain these customers in order to retain their business and contributions to the profitability of our electric distribution operations.
Supplies, Transmission and Storage
Natural Gas Distribution
Our natural gas distribution operations purchase natural gas from marketers and producers and maintain contracts for transportation and storage with several interstate pipeline companies to meet projected customer demand requirements. We believe that our supply and capacity strategy will adequately meet our customers’ needs over the next several years and we will continue to adapt our supply strategy to meet projected growth in customer demand within our service territories.
The Delmarva Natural Gas distribution systems are directly connected to Eastern Shore’s pipeline, which has connections to other pipelines that provide us with transportation and storage. These operations can also use propane-air and liquefied natural gas peak-shaving equipment to serve customers. Our Delmarva Peninsula natural gas distribution operations maintain asset management agreements with a third party to manage their natural gas transportation and storage capacity. The current agreements were effective as of April 2023 and expire in March 2026. Our Delmarva operations receive a fee, which we share with our customers, from the asset manager, who optimizes the transportation, storage and natural gas supply for these operations.
Our Florida Natural Gas distribution business uses Peninsula Pipeline and Peoples Gas to transport natural gas where there is no direct connection with FGT. FPU natural gas distribution and Eight Flags entered into separate 10-year asset management agreements with Emera Energy Services, Inc. to manage their natural gas transportation capacity, each of which expires in November 2030. An agreement with Florida Southeast Connection LLC for additional service to Palm Beach County is also in place for an initial term through December 2044. FCG utilizes FGT and Peninsula Pipeline to transport natural gas.
Chesapeake Utilities Corporation 2024 Form 10-K Page 9
A summary of our pipeline capacity contracts follows:
Maximum Daily Firm Transportation Capacity (Dts) Contract Expiration Dates
Division Pipeline
Delmarva Natural Gas Distribution Eastern Shore 161,595 2025-2044
Columbia Gas (1)
5,246 2025-2029
Transco (1)
30,419 2025-2028
TETLP (1)
50,000 2027
Florida Natural Gas Gulfstream (2)
10,000 2032
FGT 47,409 - 78,817 2029-2041
Peninsula Pipeline 362,500 2033-2048
Peoples Gas 12,160 2025-2027
Florida Southeast Connection LLC 5,000 2044
Southern Natural Gas Company 1,500 2029
Florida City Gas FGT 32,235 - 68,955 2030
Peninsula Pipeline 15,000 2033 - 2043
(1) Transco, Columbia Gas and TETLP are interstate pipelines interconnected with Eastern Shore's pipeline.
(2) Pursuant to a capacity release program approved by the Florida PSC, all of the capacity under this agreement has been released to various third parties. Under the terms of these capacity release agreements, Chesapeake Utilities is contingently liable to Gulfstream should any party, that acquired the capacity through release, fail to pay the capacity charge.
Eastern Shore has three agreements with Transco for a total of 7,292 Dts/d of firm daily storage injection and withdrawal entitlements and total storage capacity of 288,003 Dts. These agreements expire in March 2028. Eastern Shore retains these firm storage services in order to provide swing transportation service and firm storage service to customers requesting such services.
Aspire Energy Express, our Ohio intrastate pipeline subsidiary, has an agreement to provide natural gas transportation capacity to Guernsey Power Station. Aspire Energy Express completed construction of the gas transmission facilities in the fourth quarter of 2021 and began billing for transportation services in the first quarter of 2022.
Electric Distribution
Our Florida electric distribution operation purchases wholesale electricity under the power supply contracts summarized below:
Area Served by Contract Counterparty Contracted Amount (MW) Contract Expiration Date
Northwest Florida Florida Power & Light Company Full Requirement* 2032
Northeast Florida Florida Power & Light Company
Full Requirement* 2032
Northeast Florida Eight Flags 21 2036
Northeast Florida Rayonier 1.7 to 3.0 2036
Northeast Florida WestRock Company As-available N/A
*The counter party is obligated to provide us with the electricity to meet our customers’ demand, which may vary.
Chesapeake Utilities Corporation 2024 Form 10-K Page 10
Unregulated Energy
Overview
The following table presents net income for the year ended December 31, 2024 and total assets as of December 31, 2024, for our Unregulated Energy segment by operation and area served:
Operations Area Served Net Income (Loss) Total Assets
(in millions)
Propane Operations (Sharp, Diversified Energy, FPU and Flo-gas) Pennsylvania, Delaware, Maryland, Virginia, North Carolina, South Carolina, Florida $ 11.3 $ 188.4
Energy Transmission (Aspire Energy) Ohio 4.0 146.2
Energy Generation (Eight Flags) Florida 2.1 31.7
Marlin Gas Services The Entire U.S. 3.5 59.1
Sustainable investments and other (1)
Various 0.1 61.0
Total $ 21.0 $ 486.4
(1) Includes our renewable natural gas projects that are in various stages of development.
Propane Operations
Our propane operations sell propane to residential, commercial/industrial, wholesale and AutoGas customers, in the Mid-Atlantic region, North Carolina, South Carolina and Florida, through Sharp Energy, Inc., Sharpgas, Inc., Diversified Energy, FPU and Flo-gas. We deliver to and bill our propane customers based on two primary customer types: bulk delivery customers and metered customers. Bulk delivery customers receive deliveries into tanks at their location. We invoice and record revenues for these customers at the time of delivery. Metered customers are either part of an underground propane distribution system or have a meter installed on the tank at their location. We invoice and recognize revenue for these customers based on their consumption as dictated by scheduled meter reads. As a member of AutoGas Alliance, we install and support propane vehicle conversion systems for vehicle fleets and provide on-site fueling infrastructure.
Propane Operations - Operational Highlights
For the year ended December 31, 2024, operating revenues, volumes sold and average number of customers by customer class for our propane operations were as follows:
Operating Revenues
(in millions) Volumes
(in thousands of gallons) Average Number of Customers (1)
Residential bulk $ 47.6 30 % 15,842 22 % 61,166 72 %
Residential metered 14.9 9 % 4,545 6 % 16,479 19 %
Commercial bulk 40.4 26 % 22,013 30 % 7,761 9 %
Commercial metered 1.7 1 % 571 1 % 214 <1%
Wholesale 24.1 15 % 24,513 34 % 31 <1%
AutoGas 7.6 5 % 5,168 7 % 87 <1%
Other (2)
21.6 14 % - - % - - %
Total $ 157.9 100 % 72,652 100 % 85,738 100 %
(1) Average number of customers is based on a twelve-month average for the year ended December 31, 2024.
(2) Operating revenues from "Other" sources include revenues from customer loyalty programs; delivery, service and appliance fees; and unbilled revenues.
Chesapeake Utilities Corporation 2024 Form 10-K Page 11
Competition
Our propane operations compete with national and local independent companies primarily on the basis of price and service. Propane is generally a lower cost fuel alternative for home heating compared to oil and electricity but more expensive than natural gas. Our propane operations are largely concentrated in areas that are not currently served by natural gas distribution systems.
Supplies, Transportation and Storage
We purchase propane from major oil companies and independent natural gas liquids producers. Propane is transported by truck and rail to our bulk storage facilities in Pennsylvania, Delaware, Maryland, Virginia, North Carolina, South Carolina and Florida which have a total storage capacity of 8.5 million gallons. Deliveries are made from these facilities by truck to tanks located on customers’ premises or to central storage tanks that feed our underground propane distribution systems. While propane supply has traditionally been adequate, significant fluctuations in weather, closing of refineries and disruption in supply chains, could cause temporary reductions in available supplies.
Weather
Propane revenues are affected by seasonal variations in temperature and weather conditions, which directly influence the volume of propane used by our customers. Our propane revenues are typically highest during the winter months when propane is used for heating. Sustained warmer-than-normal temperatures will tend to reduce propane use, while sustained colder-than-normal temperatures will tend to increase consumption.
Unregulated Energy Transmission and Supply (Aspire Energy)
Aspire Energy owns approximately 2,800 miles of natural gas pipeline systems in 40 counties in Ohio. The majority of Aspire Energy’s revenues are derived from long-term supply agreements with Columbia Gas of Ohio and Consumers Gas Cooperative ("CGC"), which together serve more than 23,000 end-use customers. Aspire Energy purchases natural gas to serve these customers from conventional producers in the Marcellus and Utica natural gas production areas. In addition, Aspire Energy's Noble Road Landfill RNG pipeline transports RNG generated from the landfill to Aspire Energy’s pipeline system, displacing conventionally produced natural gas. In 2024, the RNG volumes represented approximately 10 percent of Aspire Energy’s gas gathering volumes and are anticipated to continue at such rate in 2024 and beyond. In addition, Aspire Energy earns revenue by gathering and processing natural gas for customers.
For the year ended December 31, 2024, Aspire Energy's operating revenues and deliveries by customer type were as follows:
Operating revenues Deliveries
(in millions) % of Total (in thousands Dts) % of Total
Supply to Columbia Gas of Ohio $ 12.5 35 % 2,463 36 %
Supply to CGC 14.6 42 % 1,784 26 %
Supply to Marketers 5.0 14 % 2,500 37 %
Other (including natural gas gathering and processing) 3.0 9 % 42 1 %
Total $ 35.1 100 % 6,789 100 %
Energy Generation (Eight Flags)
Eight Flags generates electricity and steam at its CHP plant located on Amelia Island, Florida. The plant is powered by natural gas transported by Peninsula Pipeline and our Florida Natural Gas distribution business and produces approximately 21 MW of electricity and 75,000 pounds per hour of steam. Eight Flags sells the electricity generated from the plant to our Florida electric distribution operation and sells the steam to the customer who owns the site on which the plant is located, both under separate 20-year contracts.
Marlin Gas Services
Marlin Gas Services is a supplier of mobile CNG and virtual pipeline solutions, primarily to utilities and pipelines. Marlin Gas Services provides temporary hold services, pipeline integrity services, emergency services for damaged pipelines and specialized gas services for customers who have unique requirements. These services are provided by a highly trained staff of drivers and maintenance technicians who safely perform these functions throughout the United States. Marlin Gas Services maintains a fleet of CNG trailers, mobile compression equipment, LNG tankers and vaporizers, and an internally developed patented regulator system which allows for delivery of over 7,000 Dts/d of natural gas. Marlin Gas Services continues to
Chesapeake Utilities Corporation 2024 Form 10-K Page 12
actively expand the territories it serves, as well as leveraging its fleet of equipment and patented technologies to serve LNG and RNG market needs.
Sustainable Investments
Our sustainable investments are comprised primarily of our renewable natural gas projects that are in various stages of development. Included in these are the assets and intellectual property of Planet Found that we acquired during the fourth quarter of 2022, whose farm scale anaerobic digestion pilot system and technology produces biogas from poultry litter. In addition, we constructed a dairy manure RNG facility that we own and operate 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, with capital expenditures totaling $27.5 million through December 31, 2024. The facility became operational in 2024, with the first injection of RNG during the second quarter of 2024.
Environmental Matters
See Item 8, Financial Statements and Supplementary Data (Note 19, Environmental Commitments and Contingencies, in the consolidated financial statements).
Human Capital Initiatives
Our tradition of serving employees, customers, investors, partners and communities is at the core of our special culture. Our unique culture is grounded in a solid foundation of regulated businesses, but enhanced by an entrepreneurial, innovative and competitive market mindset. Among the ongoing initiatives across our enterprise, we highlight below the importance of our culture of safety, our team, and our commitment to supporting a more sustainable future.
Workplace Health and Safety
We are committed to ensuring safety is at the center of our culture and the way we do business. The importance of safety is exhibited throughout the entire organization, with the direction and tone set by both the Board of Directors and our President and CEO, and evidenced through required attendance at monthly safety meetings, routine safety training and the inclusion of safety moments at key team meetings. Additionally, we remain committed to providing products and services to our customers in a safe and reliable manner.
To maintain safety as a priority, our employees remain committed and work together to ensure that our plans, programs, policies and behaviors are aligned with our aspirations as a Company. The achievement of superior safety performance is both an important short-term and long-term strategic initiative in managing our operations. Our state-of-the art training facilities called, Safety Towns, located in Dover, Delaware and DeBary Florida, now serve as resources for training our employees who build, maintain and operate our natural gas infrastructure, offering hands-on training and fully immersive, on-the-job field experiences. First responders and other community partners also benefit from the simulated environment and conditions they could encounter as they enter homes in the community.
Our Team Drives Our Performance
Our employees are the key to our success. Our leadership and human resources teams are responsible for attracting and retaining top talent and as an equal opportunity employer committed to creating a diverse workforce, we consider all qualified applicants without regard to race, religion, color, sex, national origin, age, sexual orientation, gender identity, disability or veteran status, among other factors. Our senior management team includes a Chief Human Resources Officer, with expertise in diverse candidate recruitment, to ensure that we continue to expand our candidate pools to better reflect the diverse demographics of the communities we serve.
Throughout our organization, we seek to promote from within, reviewing strategic positions regularly and identifying potential internal candidates to fill those positions, evaluating critical job skill sets to identify competency gaps and creating developmental plans to facilitate employee professional growth. We provide training and development programs, including many forms of training on our internal learning platform, as well as tuition reimbursement to promote continued professional growth.
We had more than 1,200 employees at December 31, 2024, 194 of whom are union employees represented by two labor unions: the International Brotherhood of Electrical Workers ("IBEW") and the United Food and Commercial Workers Union. The collective bargaining agreements covering our employees with these labor unions expire in late 2025. We consider our relationships with employees, including those covered by collective bargaining agreements, to be in good standing. We provide a competitive Total Rewards package for our employees including health insurance coverage, wellness initiatives,
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retirement savings benefits, paid time off, employee assistance programs, educational and tuition reimbursement, competitive pay, career growth opportunities, paid volunteer time, and a culture of recognition.
We listen to our employees and actively seek their input and feedback. Many of the initiatives we have in place are driven by feedback from our employees during an annual survey process or through regular employee engagement. We have also been purposeful in wanting to provide adequate recognition of our employees and their many efforts. We maintain an internal recognition platform which enables employees to be recognized in real-time for their contributions.
We have a values-driven culture that supports diversity and inclusion across our enterprise including within our employee resource groups ("ERGs").
Our first ERG was established in 2019, and as of December 31, 2024, there were 12 active ERGs meeting throughout the Company. ERGs are voluntary, employee-led groups that focus on shared identities, affinities and experiences and seek to apply those perspectives to initiatives that create value throughout the Company. The ERGs support their members' personal growth and professional development, and help develop learning programs and community service opportunities throughout the Company. ERGs also help foster a sense of belonging by creating a deep and intentional community that extends beyond an employee’s day-to-day team and colleagues into a companywide network.
Driving Sustainability across the Company
Consistent with our culture of teamwork, the focus on sustainability is supported and shared across our organization by the dedication and efforts of our Board of Directors and its Committees, as well as the entrepreneurship and dedication of our team. As stewards of long-term enterprise value, the Board of Directors is committed to overseeing the sustainability of the Company, its environmental stewardship initiatives, its safety and operational compliance practices. Throughout the year, Chesapeake Utilities drove numerous initiatives in support of its sustainability focus, including but not limited to:
•Completed construction of our first full scale RNG production facility in Lee, Florida utilizing dairy waste and progressed on construction to upgrade raw biogas produced at our Planet Found poultry anaerobic digester facility in Worcester County, Maryland, to pipeline quality RNG;
•Received FERC approval for the Worcester Resiliency Upgrade project, an LNG storage facility project on Delmarva that received letters of support from many stakeholders;
•Established a Methane Emissions Reduction Committee to focus on identifying and recommending ways to further reduce methane emissions for our transmission and gathering operations;
•Received Delaware PSC approval to establish a first-of-its-kind energy efficiency program in Delaware focused on natural gas;
•Received approval to expand FCG’s SAFE program to more closely align with FPU’s GUARD program; and
•Donated recycled benches from our Pipe Recycling Project to various organizations.
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Information About Executive Officers
Set forth below are the names, ages, and positions of our executive officers with their recent business experience. The age of each officer is as of the filing date of this Annual Report.
Name Age Executive Officer Since Offices Held During the Past Five Years
Jeffry M. Householder 67 2010 Chair of the Board of Directors (May 2023 - present) President (January 2019 - present) Chief Executive Officer (January 2019 - present) Director (January 2019 - present)
President of FPU (June 2010 - February 2019)
Beth W. Cooper 58 2005 Executive Vice President (February 2019 - present)
Chief Financial Officer (September 2008 - present)
Senior Vice President (September 2008 - February 2019)
Treasurer (January 2022 - present)
Assistant Corporate Secretary (March 2015 - present)
James F. Moriarty 67 2015 Executive Vice President (February 2019 - present) General Counsel & Corporate Secretary (March 2015 - present) Chief Policy and Risk Officer (February 2019 - present)
Senior Vice President (February 2017 - February 2019) Vice President (March 2015 - February 2017)
Kevin J. Webber 66 2010 Chief Development Officer (January 2022 - present)
Senior Vice President (February 2019 - present) President FPU (February 2019 - December 2019) Vice President Gas Operations and Business Development Florida Business Units (July 2010 - February 2019)
Jeffrey S. Sylvester 55 2019 Chief Operating Officer (January 2022 - present)
Senior Vice President (December 2019 - present) Vice President Black Hills Energy (October 2012 - December 2019)
Available Information on Corporate Governance Documents
Our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and other reports and amendments to these reports that we file with or furnish to the SEC at their website, www.sec.gov, are also available free of charge at our website, www.chpk.com, as soon as reasonably practicable after we electronically file these reports with, or furnish these reports to the SEC. The content of this website is not part of this Annual Report.
In addition, the following documents are available free of charge on our website, www.chpk.com:
•Business Code of Ethics and Conduct applicable to all employees, officers and directors;
•Code of Ethics for Financial Officers;
•Corporate Governance Guidelines; and
•Charters for the Audit Committee, Compensation Committee, Investment Committee, and Corporate Governance Committee of the Board of Directors.
Any of these reports or documents may also be obtained by writing to: Corporate Secretary; c/o Chesapeake Utilities Corporation, 500 Energy Lane Suite 100, Dover, DE 19901.
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ITEM 1A. RISK FACTORS
ITEM 1A. RISK FACTORS.
The risks described below fall into three broad categories related to (1) financial risks, (2) operational risks, and (3) regulatory, legal and environmental risks, all of which may affect our operations and/or the financial performance of our regulated and unregulated energy businesses. These are not the only risks we face but are considered to be the most material. There may be other unknown or unpredictable risks or other factors that could have material adverse effects on our future results. Refer to Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations of this Annual Report for an additional discussion of these and other related factors that affect our operations and/or financial performance.
FINANCIAL RISKS
Our financial results may fluctuate significantly and may not fully reflect the underlying performance of our business.
Our operating results, including our revenues, operating margin, profitability, and cash flow, may vary significantly in the future and period-to-period comparisons of our operating results may not be meaningful. Accordingly, the results of any one quarter or year should not be relied upon as an indication of future performance. Our financial results may fluctuate as a result of a variety of factors, many of which are outside of our control, and such fluctuations and related impacts to any capital or earnings guidance we may issue from time to time, or any modification or withdrawal thereof, may negatively impact the value of our securities.
Our access to the capital markets at competitive rates, which could be impacted by instability and volatility in the financial markets as well as our credit ratings, could negatively impact access to capital at competitive rates which could affect our ability to implement our strategic plan, undertake improvements and make other investments required for our future growth.
Our business strategy includes the continued pursuit of growth and requires capital investment in excess of cash flow from operations. As a result, the successful execution of our strategy is dependent upon access to equity and debt at reasonable costs. Our ability to issue new debt and equity capital and the cost of equity and debt are greatly affected by our financial performance and the conditions of the financial markets. In addition, our ability to obtain adequate and cost-effective debt depends on our credit ratings. A downgrade in our current credit ratings could negatively impact our access to and cost of debt. If we are not able to access capital at competitive rates, our ability to implement our strategic plan, undertake improvements and make other investments required for our future growth may be limited.
Fluctuations in propane gas prices could negatively affect results of operations.
The combination of high demand and lower-than-average inventory is always a common driver for higher propane gas prices. We adjust the price of the propane we sell based on changes in our cost of purchasing propane. However, if the market does not allow us to increase propane sales prices to compensate fully for fluctuations in purchased propane costs, our results of operations and cash flows could be negatively affected.
If we fail to comply with our debt covenant obligations, we could experience adverse financial consequences that could affect our liquidity and ability to borrow funds.
Our long-term debt obligations and our Revolver contain financial covenants related to debt-to-capital ratios and interest-coverage ratios. Failure to comply with any of these covenants could result in an event of default which, if not cured or waived, could result in the acceleration of outstanding debt obligations, the inability to borrow under certain credit agreements and terms, or the inability to access capital from other sources. Any such default could cause a material adverse change in our financial condition, results of operations and cash flows. As of December 31, 2024, we were in compliance with all of our debt covenants.
Increases in interest rates may adversely affect our results of operations and cash flows.
Increases in interest rates could increase the cost of future debt issuances. To the extent we are not able to fully recover higher debt costs in the rates we charge our utility customers, or the timing of such recovery is not certain, our earnings could be adversely affected. Increases in short-term interest rates could negatively affect our results of operations, which depend on short-term debt to finance accounts receivable and storage gas inventories and to temporarily finance capital expenditures. Reference should be made to Item 7A, Quantitative and Qualitative Disclosures about Market Risk for additional information.
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Continuing or worsening inflationary and/or supply chain issues may adversely impact our financial condition and results of operations.
Our business is dependent on the supply chain to ensure that equipment, materials and other resources are available to both expand and maintain our services in a safe and reliable manner. Pricing of equipment, materials and other resources have increased steadily in recent years and may continue to do so in the future. Failure to secure equipment, materials and other resources on economically acceptable terms, including failure to eliminate or manage the constraints in the supply chain, may impact the availability of items that are necessary to support normal operations as well as materials that are required for continued infrastructure growth, and as a result, may adversely impact our financial condition and results of operations.
In addition, it may become more costly for us to recruit and retain key employees, particularly specialized/technical personnel, in the face of competitive market conditions and increased competition for specialized and experienced workers in our industry.
Disruptions, uncertainty or volatility in the credit and capital markets may exert downward pressure on the market price of the Company’s common stock.
The market price and trading volume of the Company’s common stock is subject to fluctuations as a result of, among other factors, general credit and capital market conditions and changes in market sentiment regarding the operations, business and financing strategies of the Company and its subsidiaries. As a result, disruptions, uncertainty or volatility in the credit and capital markets may, amongst other things, have a material adverse effect on the market price of the Company’s common stock.
Current market conditions could adversely impact the return on plan assets for our Company sponsored defined benefit plans, which may require significant additional funding.
The Company’s primary defined benefit pension plan, the FPU pension plan, is a funded plan that is closed to new employees and the future benefits are frozen. At December 31, 2024, the FPU pension plan benefit obligation was $45.5 million but was fully funded at that date. The costs of providing benefits and related funding requirements of the FPU plan is subject to changes in the market value of the assets that fund the plan and the discount rates used to estimate the pension benefit obligations. The funded status of the plans and the related costs reflected in our financial statements are affected by various factors that are subject to an inherent degree of uncertainty, particularly in the current economic environment. Future losses of asset values and further declines in discount rates may necessitate accelerated funding of the plans to meet minimum federal government requirements and may result in higher pension expense in future years. Adverse changes in the benefit obligation of the FPU pension plan may require us to record higher pension expense and fund obligations earlier than originally planned, which would have an adverse impact on our cash flows from operations, decrease borrowing capacity and increase interest expense.
OPERATIONAL RISKS
We must construct new facilities to support future growth in earnings in our natural gas and electric distribution and natural gas transmission operations.
Construction of new facilities required to support future growth is subject to various regulatory and developmental risks, including but not limited to: (i) our ability to obtain timely certificate authorizations, necessary approvals and permits from regulatory agencies and on terms that are acceptable to us; (ii) potential changes in federal, state and local statutes and regulations, including environmental requirements, that prevent a project from proceeding or increase the anticipated cost of the project; (iii) our inability to acquire rights-of-way or land rights on a timely basis on terms that are acceptable to us; (iv) lack of anticipated future growth in available natural gas and electricity supply and demand; (v) insufficient customer throughput commitments; and (vi) lack of available and qualified third-party contractors which could impact the timely construction of new facilities. Adverse outcomes and/or changes in these risks could limit the future growth of our business and cause a material adverse change in our financial condition, results of operations and cash flows.
We do not own all of the land on which our pipelines and facilities are located, which could result in disruptions to our operations.
Because we do not own all of the land on which our pipelines and facilities have been constructed, we are subject to the possibility of more onerous terms or increased costs to retain necessary land use if we do not have valid rights-of-way, easements or other property rights or if such rights or easements lapse or terminate. We obtain the rights to construct and operate our pipelines on land owned by third parties and governmental agencies for a specific period of time. Our loss of these rights, through our inability to renew right-of-way contracts or otherwise, could have a material adverse effect on our business, financial condition and results of operations.
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We operate in a competitive environment, and we may lose customers to competitors.
Natural Gas. Our natural gas transmission and distribution operations compete with interstate pipelines when our customers are located close enough to a competing pipeline to make direct connections economically feasible. Customers also have the option to switch to alternative fuels, including renewable energy sources. Failure to retain and grow our natural gas customer base would have an adverse effect on our financial condition, results of operations and cash flows.
Electric. Our Florida electric distribution business has remained substantially free from direct competition from other electric service providers but does face competition from other energy sources. Changes in the competitive environment caused by legislation, regulation, market conditions, or initiatives of other electric power providers, particularly with respect to retail electric competition, would adversely affect our financial condition, results of operations and cash flows.
Propane. Our propane operations compete with other propane distributors, primarily on the basis of service and price. Our ability to grow the propane operations business is contingent upon capturing additional market share, expanding into new markets, and successfully utilizing pricing programs that retain and grow our customer base. Failure to retain and grow our customer base in our propane operations would have an adverse effect on our financial condition, results of operations and cash flows.
Fluctuations in weather may cause a significant variance in our earnings.
Our natural gas distribution, propane operations and natural gas transmission operations are sensitive to fluctuations in weather conditions, which directly influence the volume of natural gas and propane we transport, sell and deliver to our customers. A significant portion of our natural gas distribution, propane operations and natural gas transmission revenue is derived from the sales and deliveries to residential, commercial and industrial heating customers during the five-month peak heating season (November through March). Other than our Maryland natural gas distribution businesses (CUC-Maryland division, Sandpiper Energy and Elkton Gas) which have revenue normalization mechanisms, if the weather is warmer than normal, we generally sell and deliver less natural gas and propane to customers, and earn less revenue, which could adversely affect our financial condition, results of operations and cash flows. Conversely, if the weather is colder than normal, we generally sell and deliver more natural gas and propane to customers, and earn more revenue, which could positively affect our financial condition, results of operations and cash flows. Variations in weather from year to year can cause our financial condition, results of operations and cash flows to vary accordingly.
Our electric distribution operation is also affected by variations in weather conditions and unusually severe weather conditions. However, electricity consumption is generally less seasonal than natural gas and propane because it is used for both heating and cooling in our service areas.
Severe weather events (such as a major hurricane, flood, or tornado), natural disasters and acts of terrorism could adversely impact earnings and access to insurance coverage.
Inherent in energy transmission and distribution activities are a variety of hazards and operational risks, such as leaks, ruptures, fires, uncontrollable flows of natural gas, explosions, release of contaminants into the environment, sabotage and mechanical problems. Severe weather events and natural disasters, especially in our service areas that are susceptible to more frequent severe weather events and natural disasters, may damage our assets, cause operational interruptions and result in the loss of human life, all of which could negatively affect our financial condition, results of operations and cash flows.
Acts of terrorism and the impact of retaliatory military and other action by the U.S. and its allies may lead to increased political, economic and financial market instability and volatility in the price of natural gas, electricity and propane that could negatively affect our operations. Companies in the energy industry may face a heightened risk of exposure to acts of terrorism, which could affect our financial condition, results of operations and cash flows.
The insurance industry may also be affected by severe weather events (such as major hurricanes), natural disasters (such as wildfires) and acts of terrorism. As a result, the availability of insurance covering risks against which we and our competitors typically insure may be limited. In addition, the insurance we are able to obtain may have higher deductibles, higher premiums and more restrictive policy terms, which could adversely affect our financial condition, results of operations and cash flows.
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Operating events affecting public safety and the reliability of our natural gas and electric distribution and transmission systems could adversely affect our operations and increase our costs.
Our natural gas and electric operations are exposed to operational events and risks, such as: major leaks, outages, mechanical failures and breakdown; operations below the expected level of performance or efficiency; and accidents that could affect public safety and the reliability of our distribution and transmission systems, significantly increase costs and cause loss of customer confidence. If we are unable to recover all or some of these costs from insurance and/or customers through the regulatory process, our financial condition, results of operations and cash flows could be adversely affected.
A security breach disrupting our operating systems, facilities, and workforce or exposing confidential information may adversely affect our reputation, disrupt our operations and increase our costs.
The cybersecurity risks associated with the protection of our infrastructure and facilities is evolving and increasingly complex. We continue to heavily rely on technological tools that support our business operations and corporate functions while enhancing our security. There are various risks associated with our information technology infrastructure, including hardware and software failure, communications failure, data distortion or destruction, unauthorized access to data, misuse of proprietary or confidential data, unauthorized control through electronic means, cyber-attacks, cyber-terrorism, data breaches, programming mistakes, and other inadvertent errors or deliberate human acts. Further, the U.S. government has issued public warnings that indicate energy assets might be specific targets of cybersecurity threats and/or attacks.
Many of our employees, service providers, and vendors have been working, and continue to work, from remote locations where cybersecurity protections could be limited and cybersecurity procedures and safeguards could be less effective. As such, we could be subject to a higher risk of cybersecurity breaches than ever before. Therefore, we could be required to expend significant resources to continue to modify or enhance our procedures and controls or to upgrade our digital and operational systems, related infrastructure, technologies and network security.
Any such failure, attack, or security breach could adversely impact our ability to safely and reliably deliver services to our customers through our transmission, distribution, and generation systems, subjecting us to reputational and other harm, and subject us to legal and regulatory proceedings and claims and demands from third parties, any of which could adversely affect our business, our earnings, results of operation, financial condition and cash flows. In addition, the protection of customer, employee and Company data is crucial to our operational security. A breach or breakdown of our systems that results in the unauthorized release of individually identifiable customer information or other sensitive data could have an adverse effect on our reputation, results of operations and financial condition and could also materially increase our costs of maintaining our system and protecting it against future breakdowns or breaches. We take reasonable precautions to safeguard our information systems from cyber-attacks and security breaches; however, there is no guarantee that the procedures implemented to protect against unauthorized access to our information systems are adequate to safeguard against all attacks and breaches. We also cannot assure that any redundancies built into our networks and technology, or the procedures we have implemented to protect against cyber-attacks and other unauthorized access to secured data, are adequate to safeguard against all failures of technology or security breaches.
The Company’s business, results of operations, financial condition and cash flows could be adversely affected by interruption of the Company’s information technology or network systems as well as the Company’s implementation of its technology roadmap.
Currently, we rely on centralized and local information technology networks and systems, some of which are managed or accessible by third parties, to process, transmit and store electronic information, and to otherwise manage or support our business. Additionally, the Company collects and stores certain data, including proprietary business information, and has access to confidential or personal information that is subject to privacy and security laws, regulations and customer-imposed controls. The processing and storage of personal information is increasingly subject to privacy and data security regulations. The interpretation and application of data protection laws in the U.S. are continuing to evolve and may be different across jurisdictions. Violations of these laws could result in criminal or civil sanctions and even the mere allegation of such violations, could harm the Company’s reputation.
Information technology system and/or network disruptions, whether caused by acts of sabotage, employee error, malfeasance or otherwise, could have an adverse impact on the Company’s operations as well as the operations of the Company’s customers and suppliers. As a result, the Company may be subject to legal claims or regulatory proceedings which could result in liability or penalties under privacy laws, disruption in the Company’s operations, and damage to the Company’s reputation, adversely affecting the Company’s business, financial condition, results of operations and cash flows.
The Company is also implementing a technology roadmap that will significantly advance our technological capabilities. The implementation of new software in multiple phases is a complex process that involves several risks. Some of the common risks include:
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•Expectations of what the software can do is not achieved and requires additional spending, resources and time;
•Inadequate planning, including changes in implementation plans, can lead to delays, cost overruns, and poor outcomes;
•Ensuring continued team engagement is critical as technology and systems projects are significant and involve many resources within the Company as well as the use of various third parties;
•Implementing new software can expose the organization to new security risks;
•Integrating new software with existing systems can be challenging, as a result of compatibility issues, data migration and system downtime; and
•The ability to continue to recover appropriate costs as approved by our regulators.
Concerns relating to the responsible use of new and evolving technologies, such as artificial intelligence (AI), may result in reputational or financial harm and liability.
While providing significant benefits, AI poses emerging legal, social, and ethical issues and presents risks and challenges. If we utilize AI solutions that have unintended consequences or may be deemed controversial, or if we are unable to develop effective internal policies and frameworks relating to the responsible use of AI, we may experience brand or reputational harm, competitive harm or legal liability. Complying with regulations related to AI could increase our cost of doing business, may change the way that we operate in certain jurisdictions, or may impede our ability to offer services in certain jurisdictions if we are unable to comply with regulations.
Failure to attract and retain an appropriately qualified employee workforce could adversely affect operations.
Our ability to implement our business strategy and serve our customers depends upon our continuing ability to attract, develop and retain talented professionals and a technically skilled workforce in a manner competitive with current market conditions, and transfer the knowledge and expertise of our workforce to new employees as our existing employees retire. Failure to hire and adequately train replacement employees, including the transfer of significant internal historical knowledge and expertise to new employees, or the future availability and cost of contract labor could adversely affect our ability to manage and operate our business. If we were unable to hire, train and retain appropriately qualified personnel, our results of operations could be adversely affected.
A strike, work stoppage or a labor dispute could adversely affect our operations.
We are party to collective bargaining agreements with labor unions at some of our Florida operations. A strike, work stoppage or a labor dispute with a union or employees represented by a union could cause interruption to our operations and our results could be adversely affected.
Our businesses are capital-intensive, and the increased costs and/or delays of capital projects may adversely affect our future earnings.
Our businesses are capital-intensive and require significant investments in ongoing infrastructure projects. These projects are subject to state and federal regulatory oversight and require certain property rights, such as easements and rights-of-way from public and private owners, as well as regulatory approvals, including environmental and other permits and licenses. There is no assurance that we will be able to obtain the necessary property rights, permits and licenses and approvals in a timely and cost-efficient manner, or at all, which may result in the delay or failure to complete a project. In addition, the availability of the necessary materials and qualified vendors could also impact our ability to complete such projects on a timely basis and manage the overall costs. Failure to complete any pending or future infrastructure projects could have a material adverse impact on our financial condition, results of operations and cash flows. Where we are able to successfully complete pending or future infrastructure projects, our revenues may not increase immediately upon the expenditure of funds on a particular project or as anticipated over the life of the project. As a result, there is the risk that new and expanded infrastructure may not achieve our expected investment returns, which could have a material adverse effect on our business, financial condition and results of operations.
Our regulated energy business may be at risk if franchise agreements are not renewed, or new franchise agreements are not obtained, which could adversely affect our future results or operating cash flows and financial condition.
Our regulated natural gas and electric distribution operations hold franchises in each of the incorporated municipalities that require franchise agreements in order to provide natural gas and electricity. Ongoing financial results would be adversely impacted in the event that franchise agreements were not renewed. If we are unable to obtain franchise agreements for new service areas, growth in our future earnings could be negatively impacted.
Slowdowns in customer growth may adversely affect earnings and cash flows.
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Our ability to increase revenues in our natural gas, propane and electric distribution businesses is dependent upon growth in the residential construction market, adding new commercial and industrial customers and conversion of customers to natural gas, electricity or propane from other energy sources. Slowdowns in growth may adversely affect our financial condition, results of operations and cash flows.
Energy conservation could lower energy consumption, which would adversely affect our earnings.
Federal and state legislative and regulatory initiatives to promote energy efficiency, conservation and the use of alternative energy sources could lower consumption of natural gas and propane by our customers. For example, in August 2022, the Inflation Reduction Act of 2022 was signed into law, with hundreds of billions of dollars in incentives for the development of renewable energy, clean hydrogen, and clean fuels, amongst other provisions. These incentives could further accelerate the transition of the U.S. economy away from the use of fossil fuels towards lower- or zero-carbon emissions alternatives and impact demand for our products and services. In addition, increasing attention to climate change, societal expectations on companies to address climate change, investor and societal expectations including mandatory climate related disclosures, and the aforementioned demand for alternative forms of energy, may result in increased costs and reduced demand for our products and services. While we cannot predict the ultimate effect that the development of alternative energy sources and related laws might have on our operations, we may be subject to reduced profits, increased investigations and litigation against us, and negative impacts on the market price of our common stock and access to capital markets.
In addition, higher costs of natural gas, propane and electricity may cause customers to conserve fuel. To the extent recovery through customer rates of higher costs or lower consumption from energy efficiency or conservation is not allowed, and our propane retail prices cannot be increased due to market conditions, our financial condition, results of operations and cash flows could be adversely affected.
Commodity price increases may adversely affect the operating costs and competitive positions of our natural gas, electric and propane operations, which may adversely affect our financial condition, results of operations and cash flows.
Natural Gas and Electricity. Higher natural gas prices can significantly increase the cost of gas billed to our natural gas customers. Increases in the cost of natural gas and other fuels used to generate electricity can significantly increase the cost of electricity billed to our electric customers. Damage to the production or transportation facilities of our suppliers, which decreases their supply of natural gas and electricity, could result in increased supply costs and higher prices for our customers. Such cost increases generally have no immediate effect on our revenues and earnings because of our regulated fuel cost recovery mechanisms. However, our net income may be reduced by higher expenses that we may incur for uncollectible customer accounts and by lower volumes of natural gas and electricity deliveries when customers reduce their consumption. Therefore, increases in the price of natural gas and other fuels can adversely affect our financial condition, results of operations and cash flows, as well as the competitiveness of natural gas and electricity as energy sources.
Propane. Propane costs are subject to changes as a result of product supply or other market conditions, including weather, economic and political factors affecting crude oil and natural gas supply or pricing. For example, weather conditions could damage production or transportation facilities, which could result in decreased supplies of propane, increased supply costs and higher prices for customers. Such increases in costs can occur rapidly and can negatively affect profitability. There is no assurance that we will be able to pass on propane cost increases fully or immediately, particularly when propane costs increase rapidly. Therefore, average retail sales prices can vary significantly from year-to-year as product costs fluctuate in response to propane, fuel oil, crude oil and natural gas commodity market conditions. In addition, in periods of sustained higher commodity prices, declines in retail sales volumes due to reduced consumption and increased amounts of uncollectible accounts may adversely affect net income.
Refer to Item 7A, Quantitative and Qualitative Disclosures about Market Risk for additional information.
Our use of derivative instruments may adversely affect our results of operations.
Fluctuating commodity prices may affect our earnings and financing costs because our propane operations use derivative instruments, including forwards, futures, swaps, puts, and calls, to hedge price risk. While we have risk management policies and operating procedures in place to control our exposure to risk, if we purchase derivative instruments that are not properly matched to our exposure, our financial condition, results of operations and cash flows may be adversely affected. In addition, fluctuations in market prices could result in significant unrealized gains or losses, which could require margins to be posted on unsettled positions and impact our financial position, results of operations and cash flows.
A substantial disruption or lack of growth in interstate natural gas pipeline transmission and storage capacity or electric transmission capacity may impair our ability to meet customers’ existing and future requirements.
Chesapeake Utilities Corporation 2024 Form 10-K Page 21
In order to meet existing and future customer demands for natural gas and electricity, we must acquire sufficient supplies of natural gas and electricity, interstate pipeline transmission and storage capacity, and electric transmission capacity to serve such requirements. We must contract for reliable and adequate upstream transmission capacity for our distribution systems while considering the dynamics of the interstate pipeline and storage and electric transmission markets, our own on-system resources, as well as the characteristics of our markets. Our financial condition and results of operations would be materially and adversely affected if the future availability of these capacities were insufficient to meet future customer demands for natural gas and electricity. Currently, our natural gas operations in Florida rely primarily on two pipeline systems, FGT and Peninsula Pipeline (our intrastate pipeline subsidiary), for most of their natural gas supply and transmission. Our Florida electric operation secures electricity from external parties. Any continued interruption of service from these suppliers could adversely affect our ability to meet the demands of our customers, which could negatively impact our financial condition, results of operations and cash flows.
Our ability to grow our businesses could be adversely affected if we are not successful in making acquisitions or integrating the acquisitions we have completed.
One of our strategies is to grow through acquisitions of complementary businesses. On November 30, 2023, we completed the acquisition of FCG, a regulated natural gas distribution utility serving approximately 123,000 residential and commercial natural gas customers in Florida, for $922.8 million in cash, pursuant to the stock purchase agreement with Florida Power & Light Company. Our acquisitions, including FCG as well as future acquisitions, involve a number of risks including, but not limited to, the following:
•We may fail to realize the benefits and growth prospects anticipated as a result of the acquisition;
•We may not identify all material facts, issues and/or liabilities in due diligence; accurately anticipate required capital expenditures; or design and implement an effective internal control environment with respect to acquired businesses;
•We may experience difficulty in integrating the technology, systems, policies, processes or operations and retaining the employees, including key personnel of the acquired business;
•The historical financial results of acquisitions may not be representative of our future financial condition, results of operations and cash flows, and may not deliver the expected strategic and operational benefits;
•An acquisition may divert management’s attention to integration activities or disrupt ongoing operations; and
•We may overpay for assets, which could result in the recording of excess goodwill and other intangible assets at values that ultimately may be subject to impairment charges.
These factors, amongst others, could impact our ability to successfully grow our business which could have a material adverse effect on our financial condition, results of operations and cash flows.
An impairment of our assets including long-lived assets, goodwill and other intangible assets, could negatively impact our financial condition and results of operations.
In accordance with GAAP, goodwill, intangibles, and other long-lived assets are tested for impairment annually or whenever events or changes in circumstances indicate impairment may have occurred. The testing of assets for impairment requires us to make significant estimates about our future performance and cash flows, as well as other assumptions. These values may be impacted by significant negative industry or economic trends, changes in technology, regulatory or industry conditions, disruptions to our business, inability to effectively integrate acquired businesses, unexpected significant change or planned changes in use of our assets, changes in the structure of our business, divestitures, market capitalization declines or changes in economic conditions or interest rates. If the testing performed indicates that impairment has occurred, we are required to record an impairment charge for the difference between the carrying value of the applicable asset and the implied fair value in the period the determination is made. Any changes in key assumptions, or actual performance compared with key assumptions, about our business and its future prospects could affect the fair value of one or more of our assets, which may result in an impairment charge and could negatively affect our financial condition and results of operations.
REGULATORY, LEGAL AND ENVIRONMENTAL RISKS
Regulation of our businesses, including changes in the regulatory environment, may adversely affect our financial condition, results of operations and cash flows.
The Delaware, Maryland, Ohio and Florida PSCs regulate our utility operations in those states. Eastern Shore is regulated by the FERC. The PSCs and the FERC set the rates that we can charge customers for services subject to their regulatory jurisdiction. Our ability to obtain timely rate increases and rate supplements to maintain current rates of return depends on regulatory approvals, and there can be no assurance that our regulated operations will be able to obtain such approvals or maintain currently authorized rates of return. When earnings from our regulated utilities exceed the authorized rate of return, the respective regulatory authority may require us to reduce our rates charged to customers in the future.
Chesapeake Utilities Corporation 2024 Form 10-K Page 22
We may face certain regulatory and financial risks related to pipeline safety legislation.
We are subject to a number of legislative proposals at the federal and state level to implement increased oversight over natural gas pipeline operations and facilities to inspect pipeline facilities, upgrade pipeline facilities, or control the impact of a breach of such facilities. Additional operating expenses and capital expenditures may be necessary to remain in compliance. If new legislation is adopted and we incur additional expenses and expenditures, our financial condition, results of operations and cash flows could be adversely affected, particularly if we are not authorized through the regulatory process to recover from customers some or all of these costs and earn at an authorized rate of return.
Pipeline integrity programs and repairs may impose significant costs and liabilities on the Company.
The PHMSA requires pipeline operators to develop integrity management programs to comprehensively evaluate their pipelines and to take additional measures to protect pipeline segments located in areas where a leak or rupture could potentially do the most harm. The PHMSA constantly updates its regulations to ensure the highest levels of pipeline safety. As the operator of pipelines, we are required to: perform ongoing assessments of pipeline integrity; identify and characterize applicable threats to pipelines; improve data collection, integration and analysis; repair and remediate the pipelines as necessary; and implement preventative and mitigating actions. These new and any future regulations adopted by the PHMSA may impose more stringent requirements applicable to integrity management programs and other pipeline safety aspects of our operations, which could cause us to incur increased capital and operating costs and operational delays. Moreover, should we fail to comply with the PHMSA rules and regulations, we could be subject to significant penalties and fines which may adversely affect our financial condition, results of operations and cash flows.
We are subject to operating and litigation risks that may not be fully covered by insurance.
Our operations are subject to the operating hazards and risks normally incidental to handling, storing, transporting, transmitting and delivering natural gas, electricity and propane to end users. From time to time, we are a defendant in legal proceedings arising in the ordinary course of business. We maintain insurance coverage for our general liabilities in the amount of $52 million, which we believe is reasonable and prudent. However, there can be no assurance that such insurance will be adequate to protect us from all material expenses related to potential future claims for personal injury and property damage or that such levels of insurance will be available in the future at economical prices.
Costs of compliance with environmental laws may be significant.
We are subject to federal, state and local laws and regulations governing environmental quality and pollution control. These evolving laws and regulations may require expenditures over a long period of time to control environmental effects at our current and former operating sites, especially former MGP sites. To date, we have been able to recover, through regulatory rate mechanisms, the costs associated with the remediation of former MGP sites. However, there is no guarantee that we will be able to recover future remediation costs in the same manner or at all. A change in our approved rate mechanisms for recovery of environmental remediation costs, including costs at former MGP sites, could adversely affect our financial condition, results of operations and cash flows.
Further, existing environmental laws and regulations may be revised, or new laws and regulations seeking to protect the environment may be adopted and applicable to us. Revised or additional laws and regulations could result in additional operating restrictions on our facilities or increased compliance costs, which may not be fully recoverable. Any such increase in compliance costs could adversely affect our financial condition, results of operations and cash flows. Compliance with these legal obligations requires us to commit capital. If we fail to comply with environmental laws and regulations, even if such failure is caused by factors beyond our control, we may be assessed administrative, civil, or criminal penalties and fines, imposed with investigatory and remedial obligations, or issued injunctions all of which could impact our financial condition, results of operations and cash flows. See Item 8, Financial Statements and Supplementary Data (Note 19, Environmental Commitments and Contingencies, in the consolidated financial statements).
Unanticipated changes in our tax provisions or exposure to additional tax liabilities could affect our profitability and cash flow.
We are subject to income and other taxes in the U.S. and the states in which we operate. Changes in applicable state or U.S. tax laws and regulations, or their interpretation and application, including the possibility of retroactive effect, could affect our tax expense and profitability. In addition, the final determination of any tax audits or related litigation could be materially different from our historical income tax provisions and accruals. Changes in our tax provision or an increase in our tax liabilities, due to changes in applicable law and regulations, the interpretation or application thereof, future changes in the tax rate or a final determination of tax audits or litigation, could have a material adverse effect on our financial position, results of operations and cash flows.
Chesapeake Utilities Corporation 2024 Form 10-K Page 23
Our business may be subject in the future to additional regulatory and financial risks associated with global warming and climate change.
There have been a number of federal and state legislative and regulatory initiatives proposed in recent years in an attempt to control or limit the effects of global warming and overall climate change, including greenhouse gas emissions. The direction of future U.S. climate change regulation is difficult to predict given the potential for policy changes under different Presidential administrations and Congressional leadership. The Environmental Protection Agency, or other Federal agencies, may or may not continue developing regulations to reduce greenhouse gas emissions. Even if federal efforts in this area slow, states, cities and local jurisdictions may continue pursuing climate regulations. Any laws or regulations that may be adopted to restrict or reduce emissions of greenhouse gases could require us to incur additional operating costs, such as costs to purchase and operate emissions controls, to obtain emission allowances or to pay emission taxes, and could reduce demand for our energy delivery services. Federal, state and local legislative initiatives to implement renewable portfolio standards or to further subsidize the cost of solar, wind and other renewable power sources may change the demand for natural gas. We cannot predict the potential impact that such laws or regulations, if adopted, may have on our future business, financial condition or financial results.
Climate changes may impact the demand for our services in the future and could result in more frequent and more severe weather events, which ultimately could adversely affect our financial results.
Significant climate change creates physical and financial risks for us. Our customers' energy needs vary with weather conditions, primarily temperature and humidity. For residential customers, heating and cooling represent their largest energy use. To the extent weather conditions may be affected by climate change, customers' energy use could increase or decrease depending on the duration and magnitude of any changes. To the extent that climate change adversely impacts the economic health or weather conditions of our service territories directly, it could adversely impact customer demand or our customers’ ability to pay. Changes in energy use due to weather variations may affect our financial condition through volatility and/or decreased revenues and cash flows. Extreme weather conditions require more system backups and can increase costs and system stresses, including service interruptions. Severe weather impacts our operating territories primarily through thunderstorms, tornadoes, hurricanes, and snow or ice storms. Weather conditions outside of our operating territories could also have an impact on our revenues and cash flows by affecting natural gas prices. To the extent the frequency of extreme weather events increases, this could increase our costs of providing services. We may not be able to pass on the higher costs to our customers or recover all the costs related to mitigating these physical risks. To the extent financial markets view climate change and emissions of greenhouse gases as a financial risk, this could adversely affect our ability to access capital markets or cause us to receive less favorable terms and conditions in future financings. Our business could be affected by the potential for investigations and lawsuits related to or against greenhouse gas emitters based on the claimed connection between greenhouse gas emissions and climate change, which could impact adversely our business, results of operations and cash flows.
Our certificate of incorporation and bylaws may delay or prevent a transaction that stockholders would view as favorable.
Our certificate of incorporation and bylaws, as well as Delaware law, contain provisions that could delay, defer or prevent an unsolicited change in control of Chesapeake Utilities, which may negatively affect the market price of our common stock or the ability of stockholders to participate in a transaction in which they might otherwise receive a premium for their shares over the then current market price. These provisions may also prevent changes in management. In addition, our Board of Directors is authorized to issue preferred stock without stockholder approval on such terms as our Board of Directors may determine. Our common stockholders will be subject to, and may be negatively affected by, the rights of any preferred stock that may be issued in the future.

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ITEM 1B. UNRESOLVED STAFF COMMENTS
ITEM 1B. UNRESOLVED STAFF COMMENTS.
None.

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ITEM 2. PROPERTIES
ITEM 2. Properties.
Offices and other operational facilities
We own or lease offices and other operational facilities in our service territories located in Pennsylvania, Delaware, Maryland, Virginia, North Carolina, South Carolina, Florida and Ohio.
Regulated Energy Segment
The following table presents a summary of miles of assets operated by our natural gas distribution, natural gas transmission and electric business units as of December 31, 2024:
Operations Miles
Natural Gas Distribution
Delmarva Natural Gas (Natural gas pipelines) 2,136
Delmarva Natural Gas (Underground propane pipelines) 17
FPU (Natural gas pipelines) 3,216
Florida City Gas (Natural gas pipelines) 3,982
Natural Gas Transmission
Eastern Shore 521
Florida City Gas 79
Peninsula Pipeline 187
Aspire Energy Express (1)
-
Electric Distribution
FPU 924
Total 11,062
(1) Aspire Energy Express had less than 1 mile of natural gas pipeline at December 31, 2024.
Peninsula Pipeline also has a 50 percent jointly owned intrastate transmission pipeline with Seacoast Gas Transmission, LLC ("Seacoast Gas Transmission") in Nassau County, Florida. The 26-mile pipeline serves demand in both Nassau and Duval Counties.
Chesapeake Utilities Corporation 2024 Form 10-K Page 26
Unregulated Energy Segment
The following table presents propane storage capacity, miles of underground distribution mains and transmission for our Unregulated Energy Segment operations as of December 31, 2024:
Operations Gallons or miles
Propane distribution
Propane storage capacity (gallons in millions) 8.5
Underground propane distribution mains (miles) 152
Unregulated Energy Transmission and gathering (Aspire Energy)
Natural gas pipelines (miles) 2,800

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ITEM 3. LEGAL PROCEEDINGS
ITEM 3. Legal Proceedings.
See Item 8, Financial Statements and Supplementary Data (Note 20, Other Commitments and Contingencies, in the consolidated financial statements), which is incorporated into Item 3 by reference.

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ITEM 4. MINE SAFETY DISCLOSURE
ITEM 4. Mine Safety Disclosures.
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
ITEM 5. Market for the Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.
Common Stock Dividends and Stockholder Information:
Chesapeake Utilities common stock is traded on the New York Stock Exchange ("NYSE") under the ticker symbol CPK. As of February 24, 2025, we had 1,930 holders of record of our common stock. We declared quarterly cash dividends on our common stock totaling $2.510 per share in 2024 and $2.305 per share in 2023, and have paid a cash dividend to holders of our common stock for 64 consecutive years. Future dividend payments and amounts are at the discretion of the Board of Directors and will depend on our financial condition, results of operations, capital requirements, and other factors.
Indentures to our long-term debt contain various restrictions which limit our ability to pay dividends. Refer to Item 8, Financial Statements and Supplementary Data (Note 12, Long-Term Debt, in the consolidated financial statements) for additional information.
Purchases of Equity Securities by the Issuer
The following table sets forth information on purchases by us or on our behalf of shares of our common stock during the quarter ended December 31, 2024:
Total
Number
of Shares
Purchased Average
Price Paid
per Share Total Number of Shares
Purchased as Part of
Publicly Announced Plans
or Programs (2)
Maximum Number of
Shares That May Yet Be
Purchased Under the Plans
or Programs (2)
Period
October 1, 2024 through October 31, 2024 (1)
602 $ 120.38 - -
November 1, 2024 through November 30, 2024 - - - -
December 1, 2024 through December 31, 2024 - - - -
Total 602 $ 120.38 - -
(1) In October 2024, we purchased 602 shares of common stock on the open market for the purpose of reinvesting the dividend on shares held in the Rabbi Trust accounts under the Non-Qualified Deferred Compensation Plan. The Non-Qualified Deferred Compensation Plan is discussed in detail in Item 8, Financial Statements and Supplementary Data (Note 16, Employee Benefit Plans, in the consolidated financial statements).
Chesapeake Utilities Corporation 2024 Form 10-K Page 27
(2) Except for the purpose described in footnote (1), we have no publicly announced plans or programs to repurchase our shares.
Information on certain of our equity compensation plans, for which shares of our common stock are authorized for issuance, is included in the section of our Proxy Statement captioned “Equity Compensation Plan Information” and is incorporated herein by reference.
Common Stock Performance Graph
The stock performance graph and table below compares cumulative total stockholder return on our common stock during the five fiscal years ended December 31, 2024, with the cumulative total stockholder return of the Standard & Poor’s 500 Index and the cumulative total stockholder return of select peers, which include the following companies: Atmos Energy Corporation; Black Hills Corporation; New Jersey Resources Corporation; NiSource; Northwest Natural Gas Company; Northwestern Corporation; ONE Gas, Inc.; RGC Resources, Inc.; Spire, Inc.; and Unitil Corporation.
The comparison assumes $100 was invested on December 31, 2019 in our common stock and in each of the foregoing indices and assumes reinvested dividends. The comparisons in the graph below are based on historical data and are not intended to forecast the possible future performance of our common stock.
2019 2020 2021 2022 2023 2024
Chesapeake Utilities $ 100 $ 115 $ 158 $ 130 $ 118 $ 139
Industry Index $ 100 $ 84 $ 96 $ 104 $ 102 $ 129
S&P 500 Index $ 100 $ 118 $ 152 $ 125 $ 157 $ 197
Chesapeake Utilities Corporation 2024 Form 10-K Page 28

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ITEM 6. SELECTED FINANCIAL DATA
ITEM 6. RESERVED.

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
ITEM 7. Management's Discussion and Analysis of Financial Condition and Results of Operations.
This section provides management’s discussion of Chesapeake Utilities and its consolidated subsidiaries, with specific information on results of operations, liquidity and capital resources, as well as discussion of how certain accounting principles affect our financial statements. It includes management’s interpretation of our financial results and our operating segments, the factors affecting these results, the major factors expected to affect future operating results as well as investment and financing plans. This discussion should be read in conjunction with our consolidated financial statements and notes thereto in Item 8, Financial Statements and Supplementary Data.
Several factors exist that could influence our future financial performance, some of which are described in Item 1A, Risk Factors. They should be considered in connection with forward-looking statements contained in this Annual Report, or otherwise made by or on behalf of us, since these factors could cause actual results and conditions to differ materially from those set out in such forward-looking statements.
Earnings per share ("EPS") and Adjusted EPS information is presented on a diluted basis, unless otherwise noted.
Acquisition of FCG
On November 30, 2023, we completed the acquisition of FCG for $922.8 million in cash, including working capital adjustments as defined in the agreement that were settled during the first quarter of 2024, pursuant to the stock purchase agreement with Florida Power & Light Company. Upon completion of the acquisition, FCG became a wholly-owned subsidiary of the Company and is included within our Regulated Energy segment. FCG serves approximately 123,000 residential and commercial natural gas customers across eight counties in Florida, including Miami-Dade, Broward, Brevard, Palm Beach, Hendry, Martin, St. Lucie and Indian River. Its natural gas system includes approximately 3,982 miles of distribution main and 80 miles of transmission pipe. Results for FCG are included within our consolidated results from the acquisition date.
In June 2023, FCG received approval from the Florida PSC for a $23.3 million total increase in base revenue in connection with its May 2022 rate case filing. The new rates, which became effective as of May 1, 2023, included the transfer of its SAFE program provisions from a rider clause to base rates, an increase in rates associated with a liquefied natural gas facility, and approval of FCG's proposed reserve surplus amortization mechanism ("RSAM") with a $25.0 million reserve amount. The RSAM is recorded as either an increase or decrease to accrued removal costs on the balance sheet, with a corresponding increase or decrease to depreciation and amortization expense. At December 31, 2024, the RSAM reserve had been completely utilized.
In February 2025, FCG filed a depreciation study with the Florida PSC. The application is requesting approval of revised annual depreciation rates, as well as a reduction related to a reserve imbalance that would be amortized over a two-year period. The outcome of the application is subject to review and approval by the Florida PSC.
Non-GAAP Financial Measures
This document, including the tables herein, include references to both Generally Accepted Accounting Principles ("GAAP") and non-GAAP financial measures, including Adjusted Gross Margin, Adjusted Net Income and Adjusted EPS. A "non-GAAP financial measure" is generally defined as a numerical measure of a company's historical or future performance that includes or excludes amounts, or that is subject to adjustments, so as to be different from the most directly comparable measure calculated or presented in accordance with GAAP. Our management believes certain non-GAAP financial measures, when considered together with GAAP financial measures, provide information that is useful to investors in understanding period-over-period operating results separate and apart from items that may, or could, have a disproportionately positive or negative impact on results in any particular period.
We calculate Adjusted Gross Margin by deducting the purchased cost of natural gas, propane and electricity and the cost of labor spent on direct revenue-producing activities from operating revenues. The costs included in Adjusted Gross Margin exclude depreciation and amortization and certain costs presented in operations and maintenance expenses in accordance with regulatory requirements. We calculate Adjusted Net Income and Adjusted EPS by deducting non-recurring costs and expenses associated with significant acquisitions that may affect the comparison of period-over-period results. These non-GAAP financial measures are not in accordance with, or an alternative to, GAAP and should be considered in addition to, and not as a substitute for, the comparable GAAP measures. We believe that these non-GAAP financial measures are useful and meaningful to investors as a basis for making investment decisions, and provide investors with information that demonstrates the profitability achieved by the Company under allowed rates for regulated energy operations and under the Company's competitive pricing structures for unregulated energy operations. The Company's management uses these non-GAAP financial measures in assessing a business unit's and the overall Company performance. Other companies may calculate these non-GAAP financial measures in a different manner.
Chesapeake Utilities Corporation 2024 Form 10-K Page 29
The following tables reconcile Gross Margin, Net Income, and EPS, all as defined under GAAP, to our non-GAAP financial measures of Adjusted Gross Margin, Adjusted Net Income and Adjusted EPS for the years ended December 31, 2024, 2023 and 2022:
Adjusted Gross Margin
For the Year Ended December 31, 2024
(in millions) Regulated Energy Unregulated Energy Other and Eliminations Total
Operating Revenues $ 583.4 $ 228.4 $ (24.6) $ 787.2
Cost of Sales:
Natural gas, propane and electric costs (144.2) (100.2) 24.6 (219.8)
Depreciation & amortization (48.8) (16.9) - (65.7)
Operations & maintenance expenses (1)
(48.6) (33.1) - (81.7)
Gross Margin (GAAP) 341.8 78.2 - 420.0
Operations & maintenance expenses (1)
48.6 33.1 - 81.7
Depreciation & amortization 48.8 16.9 - 65.7
Adjusted Gross Margin (Non-GAAP) $ 439.2 $ 128.2 $ - $ 567.4
For the Year Ended December 31, 2023
(in millions) Regulated Energy Unregulated Energy Other and Eliminations Total
Operating Revenues $ 473.6 $ 223.1 $ (26.1) $ 670.6
Cost of Sales:
Natural gas, propane and electric costs (140.0) (102.5) 26.0 (216.5)
Depreciation & amortization (48.2) (17.3) - (65.5)
Operations & maintenance expenses (1)
(27.5) (31.5) 0.3 (58.7)
Gross Margin (GAAP) 257.9 71.8 0.2 329.9
Operations & maintenance expenses (1)
27.5 31.5 (0.3) 58.7
Depreciation & amortization 48.2 17.3 - 65.5
Adjusted Gross Margin (Non-GAAP) $ 333.6 $ 120.6 $ (0.1) $ 454.1
Chesapeake Utilities Corporation 2024 Form 10-K Page 30
For the Year Ended December 31, 2022
(in millions) Regulated Energy Unregulated Energy Other and Eliminations Total
Operating Revenues $ 429.4 $ 280.8 $ (29.5) $ 680.7
Cost of Sales:
Natural gas, propane and electric costs (127.2) (162.7) 29.4 (260.5)
Depreciation & amortization (52.7) (16.3) - (69.0)
Operations & maintenance expenses (1)
(35.5) (29.8) - (65.3)
Gross Margin (GAAP) 214.0 72.0 (0.1) 285.9
Operations & maintenance expenses (1)
35.5 29.8 - 65.3
Depreciation & amortization 52.7 16.3 - 69.0
Adjusted Gross Margin (Non-GAAP) $ 302.2 $ 118.1 $ (0.1) $ 420.2
(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 GAAP.
2024 to 2023 Gross Margin (GAAP) Variance - Regulated Energy
Gross Margin (GAAP) for the Regulated Energy segment for 2024 was $341.8 million, an increase of $83.9 million, or 32.5 percent, compared to 2023. Higher gross margin reflects contributions attributable to the acquisition of FCG, incremental margin from regulatory initiatives and infrastructure programs, natural gas organic growth and pipeline expansion projects.
2023 to 2022 Gross Margin (GAAP) Variance - Regulated Energy
Gross Margin (GAAP) for the Regulated Energy segment for the year ended December 31, 2023 compared to 2022 is described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2023, which is incorporated herein by reference.
2024 to 2023 Gross Margin (GAAP) Variance - Unregulated Energy
Gross Margin (GAAP) for the Unregulated Energy segment for 2024 was $78.2 million, an increase of $6.4 million, or 8.9 percent, compared to 2023. Higher gross margin resulted from increased levels of virtual pipeline services and increased propane consumption, margins and service fees.
2023 to 2022 Gross Margin (GAAP) Variance - Unregulated Energy
Gross Margin (GAAP) for the Unregulated Energy segment for the year ended December 31, 2023 compared to 2022 is described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2023, which is incorporated herein by reference.
Chesapeake Utilities Corporation 2024 Form 10-K Page 31
Adjusted Net Income and Adjusted EPS
Year Ended
December 31,
(dollars in millions, shares in thousands (except per share data)) 2024 2023 2022
Net Income (GAAP) $ 118.6 $ 87.2 $ 89.8
FCG transaction and transition-related expenses, net (1)
2.9 10.6 -
Adjusted Net Income (Non-GAAP) $ 121.5 $ 97.8 $ 89.8
Weighted average common shares outstanding - diluted (2)
22,531 18,435 17,804
Earnings Per Share - Diluted (GAAP) $ 5.26 $ 4.73 $ 5.04
FCG transaction and transition-related expenses, net (1)
0.13 0.58 -
Adjusted Earnings Per Share - Diluted (Non-GAAP) $ 5.39 $ 5.31 $ 5.04
(1) Transaction and transition-related expenses represent non-recurring costs attributable to the acquisition and integration of FCG including, but not limited to transaction costs, transition services, consulting, system integration, rebranding, and legal fees.
(2) Weighted average shares reflect the impact of 4.4 million common shares issued in November 2023 in connection with the acquisition of FCG. See Notes 4 and 15 for additional details on the acquisition and related equity offering.
2024 to 2023 Net Income (GAAP) Variance
Net income (GAAP) for the year ended December 31, 2024 was $118.6 million, or $5.26 per share, compared to $87.2 million, or $4.73 per share in 2023. Net income for the years ended December 31, 2024 and 2023 included $2.9 million and $10.6 million, respectively, of transaction and transition-related expenses in connection with the acquisition and integration of FCG. Excluding these costs, net income increased by $23.7 million or 24.2 percent compared to the prior year.
2023 to 2022 Net Income (GAAP) Variance
Net income (GAAP) for the year ended December 31, 2023 compared to 2022 is described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2023, which is incorporated herein by reference.
Chesapeake Utilities Corporation 2024 Form 10-K Page 32
OVERVIEW AND HIGHLIGHTS
(dollars in millions, shares in thousands (except per share data)) Increase Increase
For the Year Ended December 31, 2024 2023 (Decrease) 2023 2022 (Decrease)
Operating Income
Regulated Energy $ 196.2 $ 126.2 $ 70.0 $ 126.2 $ 115.3 $ 10.9
Unregulated Energy 31.7 24.4 7.3 24.4 27.5 (3.1)
Other businesses and eliminations 0.3 0.2 0.1 0.2 0.1 0.1
Total Operating Income 228.2 150.8 77.4 150.8 142.9 7.9
Other income, net 2.0 1.4 0.6 1.4 5.1 (3.7)
Interest charges 68.4 36.9 31.5 36.9 24.4 12.5
Income from Before Income Taxes 161.8 115.3 46.5 115.3 123.6 (8.3)
Income taxes 43.2 28.1 15.1 28.1 33.8 (5.7)
Net Income $ 118.6 $ 87.2 $ 31.4 $ 87.2 $ 89.8 $ (2.6)
Weighted Average Common Shares Outstanding: (1)
Basic 22,469 18,371 4,098 18,371 17,722 649
Diluted 22,531 18,435 4,096 18,435 17,804 631
Earnings Per Share of Common Stock
Basic $ 5.28 $ 4.75 $ 0.53 $ 4.75 $ 5.07 $ (0.32)
Diluted $ 5.26 $ 4.73 $ 0.53 $ 4.73 $ 5.04 $ (0.31)
Adjusted Net Income and Adjusted Earnings Per Share
Net Income (GAAP) $ 118.6 $ 87.2 $ 31.4 $ 87.2 $ 89.8 $ (2.6)
FCG transaction and transition-related expenses, net (2)
2.9 10.6 (7.7) 10.6 - 10.6
Adjusted Net Income (Non-GAAP) $ 121.5 $ 97.8 $ 23.7 $ 97.8 $ 89.8 $ 8.0
Earnings Per Share - Diluted (GAAP) $ 5.26 $ 4.73 $ 0.53 $ 4.73 $ 5.04 $ (0.31)
FCG transaction and transition-related expenses, net (2)
0.13 0.58 (0.45) 0.58 - 0.58
Adjusted Earnings Per Share - Diluted (Non-GAAP) $ 5.39 $ 5.31 $ 0.08 $ 5.31 $ 5.04 $ 0.27
(1) Weighted average shares reflect the impact of 4.4 million common shares issued in November 2023 in connection with the acquisition of FCG.
(2) Transaction and transition-related expenses represent costs attributable to the acquisition and integration of FCG including, but not limited to, transaction costs, transition services, consulting, system integration, rebranding and legal fees.
Chesapeake Utilities Corporation 2024 Form 10-K Page 33
2024 compared to 2023
Key variances in operations between 2024 and 2023 included:
(in millions, except per share data) Pre-tax
Income Net
Income Earnings
Per Share
Year ended December 31, 2023 Adjusted Results**
$ 129.7 $ 97.8 $ 5.31
Non-recurring Items:
Absence of one-time benefit associated with reduction in state tax rate - (2.5) (0.13)
- (2.5) (0.13)
Increased (Decreased) Adjusted Gross Margins:
Contributions from acquisition 89.6 65.7 2.91
Margin from regulated infrastructure programs* 6.2 4.6 0.20
Natural gas growth (excluding service expansions) 5.8 4.2 0.19
Natural gas transmission service expansions, including interim services* 5.2 3.8 0.17
Increased demand for virtual pipeline services 4.5 3.3 0.15
Rate changes associated with Florida natural gas base rate proceeding* 1.6 1.2 0.05
Improved Aspire Energy performance - rate changes and gathering fees 1.6 1.1 0.05
Interim rates from recent rate case activities* 0.9 0.7 0.03
Changes in customer consumption 0.3 0.2 0.01
Reduced propane margins per gallon and fees (0.3) (0.2) (0.01)
Expiration of regulatory recovery for pandemic-related costs (1.2) (0.9) (0.04)
114.2 83.7 3.71
(Increased) Decreased Other Operating Expenses (Excluding Natural Gas, Electricity and Propane Costs):
FCG operating expenses (37.8) (27.7) (1.23)
Depreciation, amortization and property taxes (3.2) (2.3) (0.10)
Increased insurance-related costs (1.6) (1.2) (0.05)
Facilities expenses, maintenance costs and outside services (1.4) (1.0) (0.05)
Increased vehicle expenses (0.9) (0.7) (0.03)
Payroll, benefits and other employee-related expenses 2.0 1.5 0.07
(42.9) (31.4) (1.39)
Interest charges (35.5) (26.0) (1.15)
Increase in shares outstanding due to 2024 and 2023 equity issuances*** - - (0.96)
Net other changes 0.3 (0.1) -
Year ended December 31, 2024 Adjusted Results**
$ 165.8 $ 121.5 $ 5.39
* See the Major Projects and Initiatives table.
** Transaction and transition-related expenses attributable to the acquisition and integration of FCG have been excluded from the Company’s non-GAAP
measures of adjusted net income and adjusted EPS. See reconciliations above for a detailed comparison to the related GAAP measures.
*** Reflects the impact of 4.4 million common shares issued in November 2023 in connection with the acquisition of FCG and shares also issued in 2024.
Chesapeake Utilities Corporation 2024 Form 10-K Page 34
SUMMARY OF KEY FACTORS
Recently Completed and Ongoing Major Projects and Initiatives
We constantly pursue and develop additional projects and regulatory initiatives to serve existing and new customers, further grow our businesses and earnings, and increase shareholder value. The following table includes the major projects and initiatives that are currently underway or recently completed. Our practice is to add incremental margin associated with new projects and regulatory initiatives to this table once negotiations or details are substantially final and/or the associated earnings can be estimated. Major projects and initiatives that have generated consistent year-over-year adjusted gross margin contributions are removed from the table at the beginning of the next calendar year.
Adjusted Gross Margin
Year Ended December 31, Estimate for Calendar Year
(in millions) 2022 2023 2024 2025 2026
Pipeline Expansions:
Southern Expansion $ - $ 0.6 $ 2.3 $ 2.3 $ 2.3
Beachside Pipeline Expansions - 1.8 2.4 2.4 2.4
St. Cloud / Twin Lakes Expansion - 0.3 0.6 2.8 3.8
Wildlight - 0.5 1.5 3.0 4.3
Lake Wales - 0.3 0.5 0.5 0.5
Newberry - - 1.4 2.6 2.6
Worcester Resiliency Upgrade - - - 3.0 13.7
Boynton Beach - - - 3.1 3.4
New Smyrna Beach - - - 1.7 2.6
Central Florida Reinforcement - - 0.1 2.0 4.3
Warwick - - 0.4 1.9 1.9
Renewable Natural Gas Supply Projects - - - 5.7 6.7
Total Pipeline Expansions - 3.5 9.2 31.0 48.5
CNG/RNG/LNG Transportation and Infrastructure 11.1 11.1 16.4 20.0 20.7
Regulatory Initiatives:
Florida GUARD Program - 0.4 3.6 6.3 8.8
FCG SAFE Program - - 3.8 8.3 10.9
Capital Cost Surcharge Programs 2.0 2.8 3.2 5.3 6.7
Florida Rate Case (1)
2.5 15.8 17.4 17.2 17.2
Maryland Rate Case (2)
- - - TBD TBD
Delaware Rate Case (3)
- - 0.6 TBD TBD
Electric Rate Case (3)
- - 0.3 TBD TBD
Electric Storm Protection Plan 0.5 1.3 3.2 5.6 5.6
Total Regulatory Initiatives 5.0 20.3 32.1 42.7 49.2
Total $ 16.1 $ 34.9 $ 57.7 $ 93.7 $ 118.4
(1) Includes adjusted gross margin during 2023 comprised of both interim rates and permanent base rates which became effective in March 2023.
(2) Rate case application and depreciation study filed with the Maryland PSC in January 2024. See additional information provided below.
(3) Includes adjusted gross margin attributable to interim rates during 2024. See additional information provided below.
Chesapeake Utilities Corporation 2024 Form 10-K Page 35
Discussion of Major Projects and Initiatives
Pipeline Expansions
Southern Expansion
Eastern Shore installed a new natural gas driven compressor skid unit at its existing Bridgeville, Delaware compressor station that provides 7,300 Dts of incremental firm transportation pipeline capacity. The project was placed in service in the fourth quarter of 2023. The project generated additional adjusted gross margin of $1.7 million for the year ended December 31, 2024, and is expected to produce adjusted gross margin of approximately $2.3 million in 2025 and thereafter.
Beachside Pipeline Expansion
In June 2021, Peninsula Pipeline and FCG entered into a Transportation Service Agreement for an incremental 10,176 Dts/d of firm service in Indian River County, Florida, to support FCG's growth along the Indian River's barrier island. As part of this agreement, Peninsula Pipeline constructed approximately 11.3 miles of pipeline from its existing pipeline in the Sebastian, Florida. The project went into service in April 2023. Subsequent to the acquisition of FCG, the agreement is now an affiliate agreement. The project generated additional adjusted gross margin of $0.6 million for the year ended December 31, 2024, and is expected to produce adjusted gross margin of approximately $2.4 million in 2025 and thereafter.
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 FPU for an additional 2,400 Dts/d of firm service in the St. Cloud, Florida area. As part of this agreement, Peninsula Pipeline constructed a pipeline extension and regulator station for FPU. The extension supports new incremental load due to growth in the area, including providing service, most immediately, to the residential development, Twin Lakes. The expansion also improves reliability and provides operational benefits to FPU’s existing distribution system in the area, supporting future growth. This project was placed into service in July 2023 and generated additional adjusted gross margin of $0.3 million for the year ended December 31, 2024. We expect this extension to generate annual adjusted gross margin of $0.6 million in 2025 and thereafter.
In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of an amendment to its Transportation Service Agreement with FPU for a project that will support additional supply to communities in the St. Cloud, Florida area. The project is driven by the need to expand gas service to future communities that are expected in that area. Peninsula Pipeline will construct pipeline expansions that will allow FPU to serve the expected new growth. The expansion will provide FPU with an additional 10,000 Dts/d. The Florida PSC approved the project in May 2024, and it is expected to be complete in the fourth quarter of 2025. We expect this expansion to generate approximately $2.2 million of adjusted gross margin in 2025 and $3.2 million thereafter.
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, Florida. The project enables us to meet the significant growing demand for service in Yulee, Florida. The agreement enables us to construct the project during the 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 gas injection interconnect with associated facilities. Phase two will consist of two additional pipeline extensions. The petition was approved by the Florida PSC in November 2022. The various phases of the project commenced in the first quarter of 2023, with construction on the overall project continuing through 2025. The project generated additional adjusted gross margin of $1.0 million for the year ended December 31, 2024, and is expected to contribute adjusted gross margin of approximately $3.0 million in 2025 and $4.3 million thereafter.
Lake Wales Expansion
In February 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with FPU for an additional 9,000 Dts/d of firm service in the Lake Wales, Florida area. The PSC approved the petition in April 2023 and Peninsula Pipeline completed the acquisition of an existing pipeline in May 2023 that is being utilized to serve both current and new natural gas customers. The project generated additional adjusted gross margin of $0.2 million for the year ended December 31, 2024, and is expected to contribute adjusted gross margin of approximately $0.5 million in 2025 and thereafter.
Chesapeake Utilities Corporation 2024 Form 10-K Page 36
Newberry Expansion
In April 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with FPU for an additional 8,000 Dts/d of firm service in the Newberry, Florida area. The petition was approved by the Florida PSC in the third quarter of 2023. Peninsula Pipeline will construct a pipeline extension, which will be used by FPU to support the development of a natural gas distribution system to provide gas service to the City of Newberry. A filing to address the acquisition and conversion of existing Company owned propane community gas systems in Newberry was made in November 2023. The Florida PSC approved it in April 2024, and conversions of the community gas systems commenced in the second quarter of 2024. The project generated adjusted gross margin of $1.4 million for the year ended December 31, 2024, and is expected to contribute adjusted gross margin of approximately $2.6 million in 2025 and thereafter.
Worcester Resiliency Upgrade
In August 2023, Eastern Shore filed an application with the FERC requesting authorization to construct the Worcester Resiliency Upgrade, which consists of a mixture of storage and transmission facilities in Sussex County, DE and Wicomico, Worcester, and Somerset Counties in Maryland. The project will provide long-term incremental supply necessary to support the growing demand of the participating shippers. In January 2025, the FERC approved the project, and construction is expected to be complete in the third quarter of 2025. The project is expected to contribute adjusted gross margin of approximately $3.0 million in 2025 and $13.7 million thereafter.
East Coast Reinforcement Projects (Boynton Beach and New Smyrna Beach)
In December 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will support additional supply to communities on the East Coast of Florida. The projects are driven by the need for increased supply to coastal portions of the state that have experienced an increase in population growth. Peninsula Pipeline will construct several pipeline extensions which will support FPU’s distribution system in the areas of Boynton Beach and New Smyrna Beach with an additional 15,000 Dts/d and 3,400 Dts/d, respectively. The Florida PSC approved the projects in March 2024. Construction is projected to be complete in the second and fourth quarters of 2025 for New Smyrna Beach and Boynton Beach, respectively. The projects are expected to contribute adjusted gross margin of approximately $4.8 million in 2025 and $6.0 million in 2026 and thereafter.
Central Florida Reinforcement Projects
In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will support additional supply to communities located in Central Florida. The projects are driven by the need for increased supply to communities in central Florida that are experiencing significant population growth. Peninsula Pipeline will construct several pipeline extensions which will support FPU’s distribution system in the areas of Plant City and Lake Mattie with an additional 5,000 Dts/d and 8,700 Dts/d, respectively. The Florida PSC approved the projects in May 2024. The Plant City project was completed in the fourth quarter of 2024, and the Lake Mattie project is projected to be completed during the fourth quarter of 2025. The completed project generated adjusted gross margin of $0.1 million for the year ended December 31, 2024, and is expected to contribute adjusted gross margin of approximately $2.0 million in 2025 and $4.3 million thereafter.
Warwick Pipeline Project
In July 2024, we announced plans to extend Eastern Shore's transmission deliverability by constructing an additional 4.4 miles of six inch steel pipeline. The project will reinforce the supply and growth for our Delaware division distribution system and expand natural gas service further into Maryland for anticipated future growth. This project was placed into service during the fourth quarter of 2024, generated adjusted gross margin of $0.4 million for the year ended December 31, 2024, and is expected to contribute adjusted gross margin of approximately $1.9 million in 2025 and thereafter.
Pioneer Supply Header Pipeline Project
In March 2024, Peninsula Pipeline filed a petition with the Florida PSC for its approval of Firm Transportation Service Agreements with both FCG and FPU for a project that will support greater supply growth of natural gas service in southeast Florida. The project consists of the transfer of a pipeline asset from FCG to Peninsula Pipeline. Peninsula Pipeline will proceed to provide transportation service to both FCG and FPU using the pipeline asset, which supports continued customer growth and system reinforcement of these distribution systems. The Florida PSC approved the petition in July 2024 and the project was completed in September 2024.
Renewable Natural Gas Supply Projects
In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for its approval of its Transportation Service Agreements with FCG for projects that will support the transportation of additional renewable energy supply to FCG. The projects, located in Florida’s Brevard, Indian River and Miami-Dade counties, will bring renewable natural gas produced from local landfills into FCG’s natural gas distribution system. Peninsula Pipeline will construct several pipeline extensions which
Chesapeake Utilities Corporation 2024 Form 10-K Page 37
will support FCG's distribution system in Brevard County, Indian River County, and Miami-Dade County. Benefits of these projects include increased gas supply to serve expected FCG growth, strengthened system reliability and additional system flexibility. The Florida PSC approved the petition in July 2024 with the projects estimated to be completed in the first half of 2025. These three renewable projects are projected to generate total adjusted gross margin of approximately $5.7 million in 2025 and $6.7 million thereafter.
CNG/RNG/LNG Transportation and Infrastructure
We have made a commitment to meet customer demand for CNG, 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.
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 year ended December 31, 2024, we generated $5.3 million in additional adjusted gross margin including the margin attributable to the Full Circle Dairy and Noble Road projects described below. We estimate annual adjusted gross margin of approximately $20.0 million in 2025, and $20.7 million in 2026 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 occurred in the second quarter of 2024.
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 represents more than 10 percent of Aspire Energy’s gas gathering volumes.
Regulatory Initiatives (with recent regulatory actions)
Florida GUARD Program
In February 2023, FPU filed a petition with the Florida PSC for approval of the GUARD program. GUARD is a ten-year program to enhance the safety, reliability, and accessibility of portions of our natural gas distribution system. We identified various categories of projects to be included in GUARD, which include 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 maintenance and repair equipment and system reliability projects. In August 2023, the Florida PSC approved the GUARD program, which included $205 million of capital expenditures projected to be spent over a 10-year period. For the year ended December 31, 2024, there was $3.2 million of incremental adjusted gross margin generated pursuant to the program. The program is expected to generate $6.3 million of adjusted gross margin in 2025 and $8.8 million in 2026.
Chesapeake Utilities Corporation 2024 Form 10-K Page 38
FCG SAFE Program
In June 2023, the Florida PSC issued the approval order for the continuation of the SAFE program beyond its 2025 expiration date and inclusion of 150 miles of additional mains and services located in rear property easements. The SAFE program is designed to relocate certain mains and facilities associated with rear lot easements to street front locations to improve FCG's ability to inspect and maintain the facilities and reduce opportunities for damage and theft. In the same order, the Commission approved a replacement of 160 miles of pipe that was used in the 1970s and 1980s and shown through industry research to exhibit premature failure in the form of cracking. The program includes projected capital expenditures of $205 million over a 10-year period. For the year ended December 31, 2024, there was $3.8 million of adjusted gross margin generated pursuant to the program. The program is expected to generate $8.3 million of adjusted gross margin in 2025 and $10.9 million in 2026.
In April 2024, FCG filed a petition with the Florida PSC to more closely align the SAFE Program with FPU's GUARD program. Specifically, the requested modifications will enable FCG to accelerate remediation related to problematic pipe and facilities consisting of obsolete and exposed pipe. These efforts will serve to improve the safety and reliability of service to FCG's customers, and the modifications will result in an estimated additional $50.0 million in capital expenditures associated with the SAFE Program which would increase the total projected capital expenditures to approximately $255.0 million over a 10-year period. The Florida PSC approved the modifications in September 2024.
Capital Cost Surcharge Programs
In December 2024, Eastern Shore submitted a filing with the FERC regarding a capital cost surcharge to recover capital costs associated with the replacement of existing Eastern Shore facilities because of mandated highway relocation projects as well as compliance with a PHMSA regulation. The capital cost surcharge mechanism was approved in Eastern Shore's last rate case. In conjunction with the filing of this surcharge, a cumulative adjustment to the existing surcharge to reflect additional depreciation was included. The FERC issued an order approving the surcharge as filed in December 2024. The combined revised surcharge became effective January 1, 2025. For the year ended December 31, 2024, there was $0.4 million of incremental adjusted gross margin generated pursuant to the program. Eastern Shore expects to produce adjusted gross margin of approximately $5.3 million in 2025 and $6.7 million in 2026 from relocation projects, which is ultimately dependent upon the timing of filings and the completion of construction.
Florida Natural Gas Rate Case Proceeding
In May 2022, our legacy 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 business 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. 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 were approved by the Florida PSC in February 2023 with an effective date of March 1, 2023. The proceeding is expected to generate $17.2 million of total adjusted gross margin in 2025 and thereafter.
Maryland Natural Gas Rate Case
In January 2024, our natural gas distribution businesses in Maryland, CUC-Maryland Division, Sandpiper Energy, Inc., and Elkton Gas Company (collectively, “Maryland natural gas distribution businesses”) filed a joint application for a natural gas rate case with the Maryland PSC. In connection with the application, we sought approval of the following: (i) permanent rate relief of approximately $6.9 million with an ROE of 11.5 percent; (ii)authorization to make certain changes to tariffs to include a unified rate structure and to consolidate the Maryland natural gas distribution businesses which we anticipate will be called Chesapeake Utilities of Maryland, Inc.; and (iii) authorization to establish a rider for recovery of the costs associated with our new technology systems. In August 2024, the Maryland natural gas distribution businesses, the Maryland Office of Peoples' Counsel ("OPC") and PSC Staff reached a settlement agreement which provided for, among other things, an increase in annual base rates of $2.6 million. In September 2024, the Maryland Public Utility Judge issued an order approving the settlement agreement in part. The $2.6 million increase in annual base rates was approved and the Company filed the Phase II filing in November 2024 to determine rate design across the Maryland natural gas distribution businesses, consolidation of the applicable tariffs and recovery of technology costs. The hearing has been scheduled for March 2025 and the outcome of the application is subject to review and approval by the Maryland PSC.
Maryland Natural Gas Depreciation Study
In January 2024, our Maryland natural gas distribution businesses filed a joint petition for approval of their proposed unified depreciation rates with the Maryland PSC. A settlement agreement between the Company, PSC staff and the OPC was reached and the final order approving the settlement agreement went into effect in July 2024, with new depreciation rates effective as of
Chesapeake Utilities Corporation 2024 Form 10-K Page 39
January 1, 2023. The approved depreciation rates resulted in an annual reduction in depreciation expense of approximately $1.2 million.
Delaware Natural Gas Rate Case
In August 2024, our Delaware natural gas division filed an application for a natural gas rate case with the Delaware PSC. In connection with the application, we are seeking approval of the following: (i) permanent rate relief of approximately $12.1 million with a ROE of 11.5 percent; (ii) proposed changes to depreciation rates which were part of a depreciation study also submitted with the filing; and (iii) authorization to make certain changes to tariffs. Annualized interim rates were approved by the Delaware PSC in the amount of $2.5 million and became effective October 2024. The hearing for the proceeding has been scheduled for May 2025, and the outcome of the application is subject to review and approval by the Delaware PSC.
FPU Electric Rate Case
In August 2024, our Florida Electric division filed a petition with the Florida PSC seeking a general base rate increase of $12.6 million with a ROE of 11.3 percent based on a 2025 projected test year. Annualized interim rates of approximately $1.8 million were approved with an effective date of November 1, 2024. The outcome of the application is subject to review and approval by the Florida PSC. The hearings for the approval of the revenue requirement and rates are scheduled to occur in March 2025.
Storm Protection Plan
In 2020, the Florida PSC implemented the Storm Protection Plan ("SPP") and Storm Protection Plan Cost Recovery Clause ("SPPCRC"), 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 SPPCRC 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. In October 2024, the Florida PSC approved the Company's projected 2025 SPP costs for both capital and operating expenses. For the year ended December 31, 2024, this initiative generated incremental adjusted gross margin of $1.9 million, and is expected to generate $5.6 million in 2025 and 2026. We expect continued investment under the SPP going forward.
Chesapeake Utilities Corporation 2024 Form 10-K Page 40
Other Major Factors Influencing Adjusted Gross Margin
Weather Impact
In 2024, higher consumption which includes the effects of colder weather compared to the prior year resulted in a $0.3 million increase in adjusted gross margin. While temperatures in our Delmarva service territories were colder than the prior year, our Ohio service territories experienced warmer temperatures compared to 2023. In addition, temperatures in the Delmarva and Ohio service territories in 2024 were both approximately 10 percent warmer compared to normal temperatures. The following table summarizes HDD and CDD variances from the 10-year average HDD/CDD ("Normal") for the years ended 2024 compared to 2023, and 2023 compared to 2022.
HDD and CDD Information
For the Year Ended December 31,
2024 2023 Variance 2023 2022 Variance
Delmarva
Actual HDD 3,634 3,416 218 3,416 4,088 (672)
10-Year Average HDD ("Normal") 4,039 4,161 (122) 4,161 4,147 14
Variance from Normal (405) (745) (745) (59)
Florida
Actual HDD 796 664 132 664 836 (172)
10-Year Average HDD ("Normal") 794 826 (32) 826 828 (2)
Variance from Normal 2 (162) (162) 8
Ohio
Actual HDD 5,014 5,043 (29) 5,043 5,532 (489)
10-Year Average HDD ("Normal") 5,594 5,594 - 5,594 5,557 37
Variance from Normal (580) (551) (551) (25)
Florida
Actual CDD 3,299 3,101 198 3,101 2,826 275
10-Year Average CDD ("Normal") 3,009 2,934 75 2,934 2,929 5
Variance from Normal 290 167 167 (103)
Natural Gas Distribution Growth
The average number of residential customers served on the Delmarva Peninsula and our legacy Florida Natural Gas distribution business increased by approximately 4.0 percent and 3.9 percent, respectively, during 2024.
The details are provided in the following table:
Adjusted Gross Margin Increase
For the Year Ended December 31, 2024
(in millions) Delmarva Peninsula Florida
Customer growth:
Residential $ 1.6 $ 2.7
Commercial and industrial 0.5 1.0
Total customer growth (1)
$ 2.1 $ 3.7
(1) Includes growth amounts for our legacy Florida operations, but excludes the effects of FCG.
Chesapeake Utilities Corporation 2024 Form 10-K Page 41
REGULATED ENERGY
Increase Increase
For the Year Ended December 2024 2023 (Decrease) 2023 2022 (Decrease)
(in millions)
Revenue $ 583.4 $ 473.6 $ 109.8 $ 473.6 $ 429.4 $ 44.2
Regulated natural gas and electric costs 144.2 140.0 4.2 140.0 127.2 12.8
Adjusted gross margin (1)
439.2 333.6 105.6 333.6 302.2 31.4
Operations & maintenance 150.4 119.8 30.6 119.8 108.2 11.6
Depreciation, amortization and property taxes 82.5 71.7 10.8 71.7 74.0 (2.3)
FCG transaction and transition-related expenses (2)
4.0 10.4 (6.4) 10.4 - 10.4
Other taxes 6.1 5.5 0.6 5.5 4.7 0.8
Other operating expenses 243.0 207.4 35.6 207.4 186.9 20.5
Operating Income $ 196.2 $ 126.2 $ 70.0 $ 126.2 $ 115.3 $ 10.9
(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.
(2) Transaction and transition-related expenses represent costs attributable to the acquisition and integration of FCG including, but not limited to, transaction costs, transition services, consulting, system integration, rebranding and legal fees.
2024 compared to 2023
Operating income for the Regulated Energy segment for 2024 was $196.2 million, an increase of $70.0 million or 55.5 percent compared to 2023. Excluding transaction and transition-related expenses associated with the acquisition of FCG, operating income increased $63.6 million or 46.6 percent compared to the prior year. Higher operating income reflects incremental contributions from the acquisition of FCG, incremental margin from our regulatory initiatives and infrastructure programs, and organic growth in our natural gas distribution businesses and pipeline expansion projects. Excluding the transaction and transition-related expenses described above, operating expenses increased by $42.0 million compared to the prior year primarily attributable to increased FCG operating expenses, higher depreciation, amortization and property taxes and increased facilities expenses, maintenance costs and outside services. Increases in depreciation, amortization and property taxes attributable to growth projects and FCG were offset by lower depreciation rates that were approved as part of the rate filings for our Florida electric operations and Maryland natural gas utilities and a $10.4 million increase in the RSAM adjustment from FCG in 2024 compared to the prior year.
Adjusted Gross Margin
Items contributing to the year-over-year adjusted gross margin increase are listed in the following table:
(in millions)
Contribution from FCG $ 88.6
Margin from regulated infrastructure programs 6.2
Natural gas growth including conversions (excluding service expansions) 5.8
Natural gas transmission service expansions, including interim services 5.2
Rate changes associated with Florida natural gas base rate proceeding (1)
1.6
Interim rates from recent rate case activities 0.9
Expiration of regulatory recovery for pandemic related costs (1.2)
Other variances (1.5)
Year-over-year increase in adjusted gross margin $ 105.6
(1) Includes adjusted gross margin contributions from permanent base rates that became effective in March 2023.
The following narrative discussion provides further detail and analysis of the significant variances in adjusted gross margin detailed above.
Contribution from Acquisition of FCG
FCG contributed incremental adjusted gross margin of $88.6 million for the year ended December 31, 2024.
Chesapeake Utilities Corporation 2024 Form 10-K Page 42
Margin from Regulated Infrastructure Programs
Regulated infrastructure programs generated incremental adjusted gross margin of $6.2 million for the year ended December 31, 2024. The increase in adjusted gross margin was primarily related to Florida's GUARD program and FPU Electric's SPP. Refer to Note 18, Rates and Other Regulatory Activities, in the consolidated financial statements for additional information.
Natural Gas Distribution Customer Growth
We generated additional adjusted gross margin of $5.8 million from natural gas customer growth. Adjusted gross margin increased by $3.7 million for our Florida Natural Gas distribution business and $2.1 million on the Delmarva Peninsula compared to 2023, due primarily to residential customer growth of 3.9 percent and 4.0 percent in Florida and on the Delmarva Peninsula, respectively.
Natural Gas Transmission Service Expansions, including interim services
We generated increased adjusted gross margin of $5.2 million for the year ended December 31, 2024 from natural gas transmission service expansions of Peninsula Pipeline and Eastern Shore.
Rate Changes Associated with the Florida Natural Gas Base Rate Proceeding
Permanent rates associated with the Florida Natural Gas base rate proceeding, effective on March 1, 2023, contributed additional adjusted gross margin of $1.6 million for the year ended December 31, 2024. Refer to Note 18, Rates and Other Regulatory Activities, in the consolidated financial statements for additional information.
Interim Rates from Recent Rate Case Activities
Interim rates associated with the Delaware natural gas rate case and Florida Electric base rate case contributed additional adjusted gross margin of $0.9 million for the year ended December 31, 2024. Refer to Note 18, Rates and Other Regulatory Activities, in the consolidated financial statements for additional information.
Expiration of Regulatory Recovery for Pandemic Related Costs
The expiration of regulatory recovery for pandemic related costs offset adjusted gross margin by $1.2 million for the year ended December 31, 2024.
Other Operating Expenses
Items contributing to the year-over-year increase in other operating expenses are listed in the following table:
(in millions)
FCG operating expenses $ 37.8
Depreciation, amortization and property tax costs 3.6
Facilities expenses, maintenance costs and outside services 1.3
Insurance related costs 1.0
Payroll, benefits and other employee-related expenses (1.0)
FCG transaction and transition-related expenses (1)
(6.4)
Other variances (0.7)
Year-over-year increase in other operating expenses $ 35.6
(1) Transaction and transition-related expenses represent costs attributable to the acquisition and integration of FCG including, but not limited to, transaction costs, transition services, consulting, system integration, rebranding and legal fees.
2023 compared to 2022
The results for the Regulated Energy segment for the year ended December 31, 2023 compared to 2022 are described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2023, which is incorporated herein by reference.
Chesapeake Utilities Corporation 2024 Form 10-K Page 43
UNREGULATED ENERGY
Increase Increase
For the Year Ended December 31, 2024 2023 (Decrease) 2023 2022 (Decrease)
(in millions)
Revenue $ 228.4 $ 223.1 $ 5.3 $ 223.1 $ 280.8 $ (57.7)
Propane and natural gas costs 100.2 102.5 (2.3) 102.5 162.7 (60.2)
Adjusted gross margin (1)
128.2 120.6 7.6 120.6 118.1 2.5
Operations & maintenance 74.8 74.2 0.6 74.2 70.5 3.7
Depreciation, amortization and property taxes 19.1 19.5 (0.4) 19.5 17.8 1.7
Other taxes 2.6 2.5 0.1 2.5 2.4 0.1
Other operating expenses 96.5 96.2 0.3 96.2 90.7 5.5
Operating Income $ 31.7 $ 24.4 $ 7.3 $ 24.4 $ 27.4 $ (3.0)
(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.
2024 Compared to 2023
Operating income for the Unregulated Energy segment for 2024 increased by $7.3 million or 29.9 percent compared to 2023. Adjusted gross margin in the Unregulated Energy segment increased primarily due to increased levels of virtual pipeline services, increased propane consumption including the impact of the December 2023 acquisition, and increased gathering fees and rate changes at Aspire. These increases were partially offset by reduced customer consumption at Aspire primarily from agricultural customers and reduced propane margins and service fees. The increase in operating expenses included higher vehicle expenses and insurance costs which were largely offset by lower payroll, benefits and other employee-related expenses compared to the prior year.
Adjusted Gross Margin
Items contributing to the year-over-year increase in adjusted gross margin are listed in the following table:
(in millions)
Propane Operations
Increased propane customer consumption $ 1.8
Contributions from acquisition 1.0
Decreased propane margins and service fees (0.3)
CNG/RNG/LNG Transportation and Infrastructure
Increased demand for virtual pipeline services 4.5
Aspire Energy
Increased margins - rate changes and gathering fees 1.6
Change in customer consumption (1.4)
Other variances 0.4
Year-over-year increase in adjusted gross margin $ 7.6
The following narrative discussion provides further detail and analysis of the significant items in the foregoing table.
Propane Operations
•Increased propane customer consumption - Adjusted gross margin was positively impacted by $1.8 million as a result of increased customer consumption driven by colder weather experienced in our Mid-Atlantic and North Carolina service areas during the fourth quarter of 2024.
•Contributions from acquisition - Adjusted gross margin increased by $1.0 million from the acquisition of J.T. Lee and Son's that was completed in December 2023.
•Propane margins and fees - Adjusted gross margin decreased by $0.3 million, mainly due to lower margins and customer service fees. 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.
Chesapeake Utilities Corporation 2024 Form 10-K Page 44
CNG/RNG/LNG Transportation and Infrastructure
•Increased levels of virtual pipeline services - Adjusted gross margin increased by $4.5 million over 2023 largely due to increased demand for CNG and RNG hold services.
Aspire Energy
•Increase in gathering charges - Adjusted gross margin increased by $1.6 million primarily due to increased gathering charges associated with a large commercial customer.
•Change in customer consumption - Adjusted gross margin decreased by $1.4 million due to lower customer consumption from agricultural customers compared to the prior year.
Other Operating Expenses
Items contributing to the year-over-year increase in other operating expenses are listed in the following table:
(in millions)
Vehicle expenses $ 0.9
Insurance related costs 0.6
Facilities, maintenance costs, and outside services 0.1
Payroll, benefits and other employee-related expenses (1.0)
Depreciation, amortization and property tax costs (0.4)
Other variances 0.1
Year-over-year increase in other operating expenses $ 0.3
2023 compared to 2022
The results for the Unregulated Energy segment for the year ended December 31, 2023 compared to 2022 are described in Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations in our Annual Report on Form 10-K for the year ended December 31, 2023, which is incorporated by reference.
OTHER INCOME, NET
2024 Compared to 2023
Other income, net, which includes non-operating investment income, interest income, late fees charged to customers, gains or losses from the sale of assets and pension and other benefits expense, amounted to $2.0 million and $1.4 million for 2024 and 2023, respectively.
INTEREST CHARGES
2024 Compared to 2023
Interest charges for 2024 increased by $31.5 million compared to the same period in 2023. This increase is primarily attributable to the Senior Notes issued in November 2023 in connection with the acquisition of FCG. Higher interest expense on Revolver borrowings driven by higher average outstanding borrowings and rates compared to the prior year also contributed to the increase. The weighted-average interest rate on our Revolver borrowings was 5.68 percent for the year ended December 31, 2024 compared to 5.41 percent during the prior year. These factors were partially offset by higher capitalized interest of $2.2 million during the current year associated with growth capital projects.
INCOME TAXES
2024 Compared to 2023
Income tax expense was $43.2 million for 2024 compared to $28.1 million for 2023. Our effective income tax rates were 26.7 percent and 24.4 percent for the years ended December 31, 2024 and 2023, respectively. Income tax expense for the year ended December 31, 2023 included a $2.5 million benefit in deferred tax expense resulting from a reduction in the Pennsylvania state income tax rate. Excluding this change, our effective income tax rate was 26.5 percent in 2023.
Chesapeake Utilities Corporation 2024 Form 10-K Page 45
LIQUIDITY AND CAPITAL RESOURCES
Our capital requirements reflect the capital-intensive and seasonal nature of our business and are principally attributable to investment in new plant and equipment, retirement of outstanding debt and seasonal variability in working capital. We rely on cash generated from operations, short-term borrowings, and other sources to meet normal working capital requirements and to temporarily finance capital expenditures. We may also issue long-term debt and equity to fund capital expenditures and to maintain our capital structure within our target capital structure range. We maintain effective shelf registration statements with the SEC, as applicable, for the issuance of shares of common stock under various types of equity offerings, including the DRIP and under an ATM equity program. 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 our 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 distribution operations, and our natural gas transmission operations to customers during the peak heating season. In addition, our natural gas and propane inventories, which usually peak in the fall months, are largely drawn down in the heating season and provide a source of cash as the inventory is used to satisfy winter sales demand.
Capital expenditures for investments in new or acquired plant and equipment are our largest capital requirements. Our capital expenditures were $355.8 million in 2024.
The following table shows total capital expenditures for the year ended December 31, 2024 by segment and by business line:
For the Year Ended December 31, 2024
(in millions)
Regulated Energy:
Natural gas distribution $ 218.6
Natural gas transmission 68.8
Electric distribution 32.8
Total Regulated Energy 320.2
Unregulated Energy:
Propane distribution 12.0
Energy transmission 5.3
Other unregulated energy 16.6
Total Unregulated Energy 33.9
Other:
Corporate and other businesses 1.7
Total Other 1.7
Total 2024 Capital Expenditures $ 355.8
In the table below, we have provided a range of our forecasted capital expenditures by segment and business line for 2025:
Chesapeake Utilities Corporation 2024 Form 10-K Page 46
Estimate for Fiscal 2025
(in millions) Low High
Regulated Energy:
Natural gas distribution $ 135.0 $ 155.0
Natural gas transmission 135.0 145.0
Electric distribution 35.0 45.0
Total Regulated Energy 305.0 345.0
Unregulated Energy:
Propane distribution 12.0 15.0
Energy transmission 5.0 10.0
Other unregulated energy 2.0 3.0
Total Unregulated Energy 19.0 28.0
Other:
Corporate and other businesses 1.0 2.0
Total 2025 Forecasted Capital Expenditures $ 325.0 $ 375.0
The 2025 forecast excludes potential acquisitions due to their opportunistic nature.
The Company continues to re-affirm its capital guidance for the five-year period ended 2028 of $1.5 billion to $1.8 billion, and projects capital expenditures of $325 million to $375 million for 2025.
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 and other factors discussed in Item 1A, Risk Factors. 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.
Capital Structure
We are committed to maintaining a sound capital structure and strong credit 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, which will benefit our customers, creditors, employees and stockholders.
The following tables present our capitalization as of December 31, 2024 and 2023 and includes the impacts associated with financing the FCG acquisition:
December 31, 2024 December 31, 2023
(dollars in millions)
Long-term debt, net of current maturities $ 1,261.7 48 % $ 1,187.1 49 %
Stockholders’ equity 1,390.2 52 % 1,246.1 51 %
Total capitalization, excluding short-term borrowings $ 2,651.9 100 % $ 2,433.2 100 %
December 31, 2024 December 31, 2023
(dollars in millions)
Short-term debt $ 196.5 7 % $ 179.9 7 %
Long-term debt, including current maturities 1,287.2 45 % 1,205.6 46 %
Stockholders’ equity 1,390.2 48 % 1,246.1 47 %
Total capitalization, including short-term borrowings $ 2,873.9 100 % $ 2,631.6 100 %
Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. We seek to align permanent financing with the in-service dates of our capital 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. We expect to move closer to our target capital structure over the next couple of years.
Chesapeake Utilities Corporation 2024 Form 10-K Page 47
In November 2023, in connection with our acquisition of FCG, we completed an overnight offering resulting in the issuance of 4.4 million shares of our common stock at a price per share of $82.72 (net of underwriter discounts and commissions). We received net proceeds of $366.4 million which were used to partially finance the acquisition.
For the year ended December 31, 2024, we received net proceeds of $72.5 million associated with shares issued under the direct stock purchase and waiver components of the DRIP. During 2023, there were no issuances under the DRIP.
Shelf Agreements
We have entered into Shelf Agreements with Prudential and MetLife with terms that extend through February 2026, however neither of such lenders have any obligation to purchase debt thereunder. At December 31, 2024, a total of $255.0 million of borrowing capacity was available under these agreements.
Long-Term Debt
All of our outstanding Senior 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.
On November 1, 2024, we issued 5.20 percent Senior Notes due in November 2029 in the aggregate principal amount of $100.0 million. The proceeds received were used to reduce short-term borrowings under our Revolver and to fund capital expenditures. These Senior Notes have similar covenants and default provisions as our other Senior Notes, and have semi-annual interest payments due on May 1 and November 1 of each year beginning in 2025.
On November 20, 2023, we issued Senior Notes in the aggregate principal amount of $550.0 million at an average interest rate of 6.54 percent that were used to partially finance our acquisition of FCG. These notes have varying maturity dates of between three and 15 years, and the outstanding principal balance of the notes (net of annual payments on the 6.73 percent notes which begin in 2029) will be due on their respective maturity dates with interest payments payable semiannually until the principal has been paid in full. These Senior Notes have similar covenants and default provisions as our other Senior Notes.
On March 14, 2023, we issued 5.43 percent Senior Notes due in March 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 and to fund capital expenditures. These Senior Notes have similar covenants and default provisions as our other Senior Notes, and have an annual principal amortization payment beginning in the sixth year after the issuance.
Short-Term Borrowings
We are authorized by our Board of Directors to borrow up to $450.0 million of short-term debt, as required. At December 31, 2024 and 2023, we had $196.5 million and $179.9 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 5.06 percent and 5.83 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at December 31, 2024.
In August 2024, we amended and restated our revolving credit agreement, which increased the total borrowing capacity under the Revolver to $450.0 million, including $250.0 million available under the 364-day tranche which now expires in August 2025 and $200.0 million available under the five-year tranche which now expires in August 2029. We may also request increases under the Revolver of up to $50.0 million under the 364-day tranche and up to $100.0 million under the five-year tranche, with the lenders having sole discretion of whether to approve each requested increase. Borrowings under both tranches of the Revolver continue to be 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. The 364-day tranche continues to bear interest (i) based upon the SOFR, plus a 10-basis point credit spread adjustment, and an applicable margin of 1.05 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate, solely at our discretion. The five-year tranche continues to bear interest (i) based upon the SOFR, plus a 10-basis point credit spread adjustment, and an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate, solely at our discretion.
We also utilize interest rate swaps to manage rate risk under our Revolver. For additional information on interest rate swaps, including swaps currently in place related to our short-term borrowings, see Note 8, Derivative Instruments.
Chesapeake Utilities Corporation 2024 Form 10-K Page 48
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 December 31, 2024, we are in compliance with this covenant.
Our total available credit under the Revolver at December 31, 2024 was $250.0 million. As of December 31, 2024, we had issued $6.9 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 drawn upon by the counterparties. The letters of credit reduce the available borrowings under the Revolver.
In connection with our acquisition of FCG, we entered into a 364-day Bridge Facility commitment with Barclays Bank PLC and other lending parties for up to $965.0 million. Upon closing of the FCG acquisition in November 2023, and with the completion of other financing activities as defined in the lending agreement, this facility was terminated with no funds drawn to finance the transaction. For additional information regarding the acquisition and related financing, see Note 4, Acquisitions, Note 12, Long-Term Debt and Note 15, Stockholders Equity.
Key statistics regarding our unsecured short-term credit facilities (our Revolver and previous bilateral lines of credit and revolving credit facility) for the years ended December 31, 2024, 2023 and 2022 are as follows:
(dollars in millions) 2024 2023 2022
Average borrowings during the year $ 185.7 $ 130.2 $ 170.4
Weighted average interest rate for the year 5.67 % 5.41 % 2.49 %
Maximum month-end borrowings $ 249.7 $ 206.5 $ 225.1
Cash Flows
The following table provides a summary of our operating, investing and financing cash flows for the years ended December 31, 2024, 2023 and 2022:
For the Year Ended December 31,
2024 2023 2022
(in millions)
Net cash provided by (used in):
Operating activities $ 239.4 $ 203.5 $ 158.9
Investing activities (349.9) (1,111.4) (136.5)
Financing activities 113.5 906.6 (21.2)
Net increase (decrease) in cash and cash equivalents 3.0 (1.3) 1.2
Cash and cash equivalents-beginning of period 4.9 6.2 5.0
Cash and cash equivalents-end of period $ 7.9 $ 4.9 $ 6.2
Cash Flows Provided by Operating Activities
Changes in our cash flows from operating activities are attributable primarily to changes in net income, adjusted for non-cash items, such as depreciation and amortization, changes in deferred income taxes, share based compensation expense and changes in working capital. Working 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.
We normally generate a large portion of our annual net income and related increases in our accounts receivable in the first and fourth quarters of each year due to significant volumes of natural gas and propane delivered to customers during the peak heating season by our natural gas and propane operations and our natural gas supply, gathering and processing operation. 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.
During 2024, net cash provided by operating activities was $239.4 million. Operating cash flows were primarily impacted by the following:
•Net income, adjusted for non-cash adjustments, provided a $202.1 million source of cash; and
Chesapeake Utilities Corporation 2024 Form 10-K Page 49
•An increased level of deferred taxes associated largely with incremental tax depreciation from growth investments resulted in a source of cash of $36.4 million.
Cash Flows Used in Investing Activities
Net cash used in investing activities totaled $349.9 million during the year ended December 31, 2024, largely driven by $355.3 million for new capital expenditures partially offset by $5.2 million of proceeds from asset sales.
Cash Flows Provided by Financing Activities
Net cash provided by financing activities totaled $113.5 million for the year ended December 31, 2024. This source of cash was largely related to:
•A net increase in long-term debt borrowings resulting in a net source of cash of $81.0 million, including $99.5 million from issuances partially offset by long-term repayments of $18.5 million;
•Net proceeds of $72.6 million from the issuance of common stock under the DRIP;
•Net borrowings under the Revolver of $14.1 million; partially offset by
•A $54.2 million use of cash for dividend payments in 2024.
Chesapeake Utilities Corporation 2024 Form 10-K Page 50
CONTRACTUAL OBLIGATIONS
We have the following contractual obligations and other commercial commitments as of December 31, 2024:
Payments Due by Period
Contractual Obligations 2025 2026-2027 2028-2029 After 2029 Total
(in millions)
Long-term debt (1)
$ 25.5 $ 266.3 $ 293.7 $ 705.3 $ 1,290.8
Operating leases (2)
2.6 3.5 2.3 4.1 12.5
Purchase obligations (3)
Transmission capacity 45.1 87.8 59.8 103.0 295.7
Storage capacity 3.4 2.1 0.2 - 5.7
Commodities 34.9 - - - 34.9
Electric supply 6.8 13.7 13.7 16.4 50.6
Unfunded benefits (4)
0.3 0.6 0.6 1.1 2.6
Funded benefits (5)
2.2 4.4 4.3 3.5 14.4
Total Contractual Obligations $ 120.8 $ 378.4 $ 374.6 $ 833.4 $ 1,707.2
(1) This represents principal payments on long-term debt. See Item 8, Financial Statements and Supplementary Data, Note 12, Long-Term Debt, for additional information. The expected interest payments on long-term debt are $63.9 million, $118.3 million, $87.7 million and $126.0 million, respectively, for the periods indicated above. Expected interest payments for all periods total $395.9 million.
(2) See Item 8, Financial Statements and Supplementary Data, Note 14, Leases, for additional information.
(3) See Item 8, Financial Statements and Supplementary Data, Note 20, Other Commitments and Contingencies, for additional information.
(4) These amounts associated with our unfunded post-employment and post-retirement benefit plans are based on expected payments to current retirees and assume a retirement age of 62 for currently active employees. There are many factors that would cause actual payments to differ from these amounts, including early retirement, future health care costs that differ from past experience and discount rates implicit in calculations. See Item 8, Financial Statements and Supplementary Data, Note 16, Employee Benefit Plans, for additional information on the plans.
(5) The FPU Pension Plan was in a $3.6 million over funded position at December 31, 2024. The assets funding this plan are in a separate trust and are not considered assets of ours or included in our balance sheets. We do not expect to make payments to the trust funds in 2025. Additional contributions may be required in future years based on the actual return earned by the plan assets and other actuarial assumptions, such as the discount rate and long-term expected rate of return on plan assets. See Item 8, Financial Statements and Supplementary Data, Note 16, Employee Benefit Plans, for further information on the plans. Additionally, the Contractual Obligations table above includes deferred compensation obligations totaling $14.4 million, funded with Rabbi Trust assets in the same amount. The Rabbi Trust assets are recorded under Investments on the consolidated balance sheets. We assume a retirement age of 65 for purposes of distribution from this trust.
OFF-BALANCE SHEET ARRANGEMENTS
Our 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 December 31, 2024 was $38.0 million. The aggregate amount guaranteed related to our subsidiaries at December 31, 2024 was approximately $28.4 million with the guarantees expiring on various dates through November 2025. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at December 31, 2024 was $5.2 million.
As of December 31, 2024, we have issued letters of credit totaling approximately $6.9 million related to various transportation, transmission, capacity and storage agreements as well as our primary insurance carriers. These letters of credit have various expiration dates through October 2025. There have been no draws on these letters of credit as of December 31, 2024. We do not anticipate that the counterparties will draw upon these letters of credit, and we expect that they will be renewed to the extent necessary in the future. Additional information is presented in Item 8, Financial Statements and Supplementary Data, Note 20, Other Commitments and Contingencies in the consolidated financial statements.
CRITICAL ACCOUNTING ESTIMATES
We prepare our financial statements in accordance with GAAP. Application of these accounting principles requires the use of estimates and assumptions that affect the reported amounts of assets, liabilities, revenues and expenses, and related disclosures of contingencies during the reporting period. We base our estimates on historical experience and on various assumptions that are believed to be reasonable under the circumstances, the results of which form the basis for making judgments about the carrying value of assets and liabilities that are not readily apparent from other sources. Since a significant portion of our businesses are regulated and the accounting methods used by these businesses must comply with the requirements of the regulatory bodies, the choices available are limited by these regulatory requirements. In the normal course of business, estimated amounts are subsequently adjusted to actual results that may differ from the estimates.
Chesapeake Utilities Corporation 2024 Form 10-K Page 51
Regulatory Assets and Liabilities
As a result of the ratemaking process, we record certain assets and liabilities in accordance with ASC Topic 980, Regulated Operations, and consequently, the accounting principles applied by our regulated energy businesses differ in certain respects from those applied by the unregulated businesses. Amounts are deferred as regulatory assets and liabilities when there is a probable expectation that they will be recovered in future revenues or refunded to customers as a result of the regulatory process. This is more fully described in Item 8, Financial Statements and Supplementary Data, Note 2, Summary of Significant Accounting Policies, in the consolidated financial statements. If we were required to terminate the application of ASC Topic 980, we would be required to recognize all such deferred amounts as a charge or a credit to earnings, net of applicable income taxes. Such an adjustment could have a material effect on our results of operations.
Financial Instruments
We utilize financial instruments to mitigate commodity price risk associated with fluctuations of natural gas, electricity and propane and to mitigate interest rate risk. We continually monitor the use of these instruments to ensure compliance with our risk management policies and account for them in accordance with GAAP, such that every derivative instrument is recorded as either an asset or a liability measured at its fair value. It also requires that changes in the derivatives' fair value are recognized in the current period earnings unless specific hedge accounting criteria are met. If these instruments do not meet the definition of derivatives or are considered “normal purchases and normal sales,” they are accounted for on an accrual basis of accounting.
Additionally, GAAP also requires us to classify the derivative assets and liabilities based on the lowest level of input that is significant to the fair value measurement. Our assessment of the significance of a particular input to the fair value measurement requires judgment and may affect the fair value of the assets and liabilities and their placement within the fair value hierarchy.
We determined that certain propane put options, call options, swap agreements and interest rate swap agreements met the specific hedge accounting criteria. We also determined that most of our contracts for the purchase or sale of natural gas, electricity and propane either: (i) did not meet the definition of derivatives because they did not have a minimum purchase/sell requirement, or (ii) were considered “normal purchases and normal sales” because the contracts provided for the purchase or sale of natural gas, electricity or propane to be delivered in quantities that we expect to use or sell over a reasonable period of time in the normal course of business. Accordingly, these contracts were accounted for on an accrual basis of accounting.
Additional information about our derivative instruments is disclosed in Item 8, Financial Statements and Supplementary Data, Note 8, Derivative Instruments, in the consolidated financial statements.
Goodwill and Other Intangible Assets
We test goodwill for impairment at least annually in December, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. We generally use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value. The annual impairment testing for 2024, 2023 and 2022 indicated that goodwill was not impaired. At December 31, 2024, our goodwill balance totaled $507.7 million including $460.9 million attributable to the acquisition of FCG. Additional information is presented in Item 8, Financial Statements and Supplementary Data, Note 4, Acquisitions, and Note 10, Goodwill and Other Intangible Assets, in the consolidated financial statements.
Other Assets Impairment Evaluations
We periodically evaluate whether events or circumstances have occurred which indicate that long-lived assets may not be recoverable. When events or circumstances indicate that an impairment is present, we record an impairment loss equal to the excess of the asset's carrying value over its fair value, if any.
Pension and Other Postretirement Benefits
Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates including the market value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. The assumed discount rates and the expected returns on plan assets are the assumptions that generally have the most significant impact on the pension costs and liabilities. The assumed discount rates, the assumed health care cost trend rates and the assumed rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities. Additional information is presented in Item 8, Financial Statements and Supplementary Data, Note 16, Employee Benefit Plans, in the consolidated financial statements, including plan asset investment allocation, estimated future benefit payments, general descriptions of the plans, significant assumptions, the impact of certain changes in certain assumptions, and significant changes in estimates.
Chesapeake Utilities Corporation 2024 Form 10-K Page 52
At December 31, 2024, actuarial assumptions include expected long-term rates of return on plan assets for FPU's pension plan of 6.00 percent and a discount rate of 5.50 percent. The discount rate was determined by management considering high-quality corporate bond rates, such as the Empower curve index and the FTSE Index, changes in those rates from the prior year and other pertinent factors, including the expected lives of the plans and the availability of the lump-sum payment option. A 25 basis point increase or decrease in the discount rate would not have a material impact on our pension and postretirement liabilities and related costs.
Actual changes in the fair value of plan assets and the differences between the actual return on plan assets and the expected return on plan assets could have a material effect on the amount of pension benefit costs that we ultimately recognize for our funded pension plan. A 25 basis point change in the rate of return would not have a material impact on the funded status of our FPU pension plan and related costs.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK.
INTEREST RATE RISK
The fluctuation in interest rates expose us to potential increased cost we could incur when we issue debt instruments or to provide financing and liquidity for our business activities. We evaluate whether to refinance existing debt or permanently refinance existing short-term borrowings based in part on the fluctuation in interest rates. 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 12, Long-Term Debt, and Note 13, Short-Term Borrowings, respectively, in the consolidated financial statements.
COMMODITY PRICE RISK
Regulated Energy Segment
We have entered into agreements with various wholesale suppliers to purchase natural gas and electricity for resale to our customers. Our regulated energy distribution businesses that sell natural gas or electricity to end-use customers have fuel cost recovery mechanisms authorized by the PSCs that allow us to 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
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 and sales activities.
We can store up to approximately 8.5 million gallons of propane (including leased storage and rail cars) during the winter season to meet our customers’ peak requirements and to serve metered customers. Decreases in the wholesale price of propane may cause the value of stored propane to decline, particularly if we utilize fixed price forward contracts for supply. To mitigate the risk of propane commodity price fluctuations on the inventory valuation, we have a Risk Management Policy that allows our propane distribution operation to enter into fair value hedges, cash flow hedges or other economic hedges of our inventory.
Aspire Energy is exposed to commodity price risk, primarily during the winter season, to the extent we are not successful in balancing our natural gas purchases and sales and have to secure natural gas from alternative sources at higher spot prices. In order to mitigate this risk, we procure firm capacity that meets our estimated volume requirements and we continue to seek out new producers in order to fulfill our natural gas purchase requirements.
The following table reflects the changes in the fair market value of financial derivatives contracts related to propane purchases and sales from December 31, 2023 to December 31, 2024:
(in millions) Balance at December 31, 2023 Increase in Fair Market Value Less Amounts Settled Balance at December 31, 2024
Sharp $ (0.4) $ 2.0 $ (1.0) $ 0.6
There were no changes in the methods of valuations during the year ended December 31, 2024.
Chesapeake Utilities Corporation 2024 Form 10-K Page 53
The following is a summary of fair market value of financial derivatives as of December 31, 2024, by method of valuation and by maturity for each fiscal year period.
(in millions) 2025 2026 2027 Total Fair Value
Price based on Mont Belvieu - Sharp $ 0.5 $ 0.1 $ - $ 0.6
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 Item 8, Financial Statements and Supplementary Data, Note 8, Derivative Instruments, in the 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.
Chesapeake Utilities Corporation 2024 Form 10-K Page 54

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ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA
ITEM 8. FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Board of Directors and Stockholders of
Chesapeake Utilities Corporation
Opinions on the Financial Statements and Internal Control over Financial Reporting
We have audited the accompanying consolidated balance sheets of Chesapeake Utilities Corporation and Subsidiaries (the "Company") as of December 31, 2024 and 2023, the related consolidated statements of income, comprehensive income, stockholders' equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes and financial statement schedules listed in Item 15(a)2 (collectively referred to as the "consolidated financial statements"). We also have audited the Company’s internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework: (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).
In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework: (2013) issued by COSO.
Basis for Opinion
The Company’s management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Report on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company's consolidated financial statements and an opinion on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) ("PCAOB") and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud and whether effective internal control over financial reporting was maintained in all material respects.
Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.
Definition and Limitations of Internal Control Over Financial Reporting
A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company's assets that could have a material effect on the financial statements.
Chesapeake Utilities Corporation 2024 Form 10-K Page 55
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Critical Audit Matter
Critical audit matters are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. We determined that there are no critical audit matters.
/s/ Baker Tilly US, LLP
We have served as the Company's auditor since 2007.
Philadelphia, Pennsylvania
February 26, 2025
Chesapeake Utilities Corporation 2024 Form 10-K Page 56
Chesapeake Utilities Corporation and Subsidiaries
Consolidated Statements of Income
For the Year Ended December 31,
2024 2023 2022
(dollars in millions, shares in thousands (except per share data))
Operating Revenues
Regulated Energy $ 583.4 $ 473.6 $ 429.4
Unregulated Energy 228.4 223.1 280.8
Other businesses and eliminations (24.6) (26.1) (29.5)
Total operating revenues 787.2 670.6 680.7
Operating Expenses
Natural gas and electricity costs 144.2 140.0 127.2
Propane and natural gas costs 75.6 76.5 133.3
Operations 210.1 178.4 164.5
FCG transaction and transition-related expenses 4.0 10.4 -
Maintenance 22.5 20.4 18.2
Depreciation and amortization 65.7 65.5 69.0
Other taxes 36.9 28.6 25.6
Total operating expenses 559.0 519.8 537.8
Operating Income 228.2 150.8 142.9
Other income, net 2.0 1.4 5.1
Interest charges 68.4 36.9 24.4
Income Before Income Taxes 161.8 115.3 123.6
Income taxes 43.2 28.1 33.8
Net Income $ 118.6 $ 87.2 $ 89.8
Weighted Average Common Shares Outstanding:
Basic 22,469 18,371 17,722
Diluted 22,531 18,435 17,804
Earnings Per Share of Common Stock:
Basic $ 5.28 $ 4.75 $ 5.07
Diluted $ 5.26 $ 4.73 $ 5.04
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2024 Form 10-K Page 57
Chesapeake Utilities Corporation and Subsidiaries
Consolidated Statements of Comprehensive Income
For the Year Ended December 31,
2024 2023 2022
(in millions)
Net Income $ 118.6 $ 87.2 $ 89.8
Other Comprehensive Income (Loss), net of tax:
Employee Benefits net gain (loss), net of tax of $0.1, $0.0, and $0.2, respectively
0.5 (0.1) 0.7
Cash Flow Hedges, net of tax:
Net gain (loss) on commodity contract cash flow hedges, net of tax of $0.6, $(0.5), and $(0.4), respectively
1.4 (1.4) (0.9)
Reclassifications of net gain on commodity contract cash flow hedges, net of tax of $(0.3), $0.0, and $(1.0), respectively
(0.7) - (2.5)
Net gain on interest rate swap cash flow hedges, net of tax of $0.2, $0.2, and $0.0, respectively
0.5 0.5 -
Reclassifications of net gain on interest rate swap cash flow hedges, net of tax of $(0.2), $(0.1), and $0.0, respectively
(0.6) (0.4) -
Total Other Comprehensive Income (Loss) 1.1 (1.4) (2.7)
Comprehensive Income $ 119.7 $ 85.8 $ 87.1
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2024 Form 10-K Page 58
Chesapeake Utilities Corporation and Subsidiaries
Consolidated Balance Sheets
As of December 31,
Assets 2024 2023
(in millions, except shares and per share data)
Property, Plant and Equipment
Regulated Energy $ 2,661.8 $ 2,418.5
Unregulated Energy 463.7 410.8
Other businesses 29.9 30.3
Total property, plant and equipment 3,155.4 2,859.6
Less: Accumulated depreciation and amortization (567.6) (516.4)
Plus: Construction work in progress 148.1 113.2
Net property, plant and equipment 2,735.9 2,456.4
Current Assets
Cash and cash equivalents 7.9 4.9
Trade and other receivables 80.0 74.5
Less: Allowance for credit losses (3.3) (2.7)
Trade and other receivables, net 76.7 71.8
Accrued revenue 37.8 32.6
Propane inventory, at average cost 8.9 9.3
Other inventory, at average cost 18.0 19.9
Regulatory assets 23.9 19.5
Storage gas prepayments 3.8 4.7
Income taxes receivable 6.8 3.8
Prepaid expenses 17.3 15.4
Derivative assets, at fair value 0.6 1.0
Other current assets 2.6 2.8
Total current assets 204.3 185.7
Deferred Charges and Other Assets
Goodwill 507.7 508.2
Other intangible assets, net 15.0 16.9
Investments, at fair value 14.4 12.3
Derivative assets, at fair value 0.1 -
Operating lease right-of-use assets 10.5 12.4
Regulatory assets 77.4 96.4
Receivables and other deferred charges 11.7 16.4
Total deferred charges and other assets 636.8 662.6
Total Assets $ 3,577.0 $ 3,304.7
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2024 Form 10-K Page 59
Chesapeake Utilities Corporation and Subsidiaries
Consolidated Balance Sheets
As of December 31,
Capitalization and Liabilities 2024 2023
(in millions, except shares and per share data)
Capitalization
Stockholders’ equity
Preferred stock, par value $0.01 per share (authorized 2,000,000 shares), no shares issued and outstanding $ - $ -
Common stock, par value $0.4867 per share (authorized 50,000,000 shares) 11.1 10.8
Additional paid-in capital 830.5 749.4
Retained earnings 550.3 488.7
Accumulated other comprehensive loss (1.7) (2.8)
Deferred compensation obligation 9.8 9.1
Treasury stock (9.8) (9.1)
Total stockholders’ equity 1,390.2 1,246.1
Long-term debt, net of current maturities 1,261.7 1,187.1
Total capitalization 2,651.9 2,433.2
Current Liabilities
Current portion of long-term debt 25.5 18.5
Short-term borrowing 196.5 179.9
Accounts payable 78.3 77.5
Customer deposits and refunds 45.7 46.4
Accrued interest 4.8 7.0
Dividends payable 14.7 13.1
Accrued compensation 23.9 16.5
Regulatory liabilities 16.1 13.7
Derivative liabilities, at fair value - 0.4
Other accrued liabilities 13.9 13.4
Total current liabilities 419.4 386.4
Deferred Credits and Other Liabilities
Deferred income taxes 296.1 259.1
Regulatory liabilities 184.0 195.3
Environmental liabilities 2.2 2.6
Other pension and benefit costs 13.2 15.3
Derivative liabilities at fair value 0.1 0.9
Operating lease - liabilities 8.7 10.6
Deferred investment tax credits and other liabilities 1.4 1.3
Total deferred credits and other liabilities 505.7 485.1
Environmental and other commitments and contingencies (Notes 19 and 20)
Total Capitalization and Liabilities $ 3,577.0 $ 3,304.7
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2024 Form 10-K Page 60
Chesapeake Utilities Corporation and Subsidiaries
Consolidated Statements of Cash Flows
For the Year Ended December 31,
2024 2023 2022
(in millions)
Operating Activities
Net Income $ 118.6 $ 87.2 $ 89.8
Adjustments to reconcile net income to net operating cash:
Depreciation and amortization 65.7 65.5 69.0
Depreciation and accretion included in operations expenses 15.8 11.9 11.0
Deferred income taxes, net 36.4 3.4 23.7
Realized (loss) on sale of assets/commodity contracts (4.4) (0.8) (7.5)
Unrealized loss (gain) on investments/commodity contracts (1.8) (1.9) 1.8
Employee benefits and compensation - 0.3 (1.1)
Share-based compensation 8.4 7.6 6.4
Other, net (0.2) 0.2 -
Changes in assets and liabilities:
Accounts receivable and accrued revenue (10.3) 2.3 (11.2)
Propane inventory, storage gas and other inventory 3.3 0.3 (7.8)
Regulatory assets/liabilities, net 0.2 20.1 (38.6)
Prepaid expenses and other current assets 0.4 18.7 9.1
Accounts payable and other accrued liabilities 0.4 (16.8) 2.7
Income taxes receivable (2.9) (1.3) 14.9
Customer deposits and refunds (0.7) 3.9 0.7
Accrued compensation 7.0 1.5 (1.2)
Accrued interest (2.2) 3.7 -
Other assets and liabilities, net 5.7 (2.3) (2.8)
Net cash provided by operating activities 239.4 203.5 158.9
Investing Activities
Property, plant and equipment expenditures (355.3) (188.6) (128.3)
Proceeds from sale of assets 5.2 2.9 3.9
Acquisitions, net of cash acquired 0.6 (925.0) (11.8)
Environmental expenditures (0.4) (0.7) (0.3)
Net cash used in investing activities (349.9) (1,111.4) (136.5)
Financing Activities
Common stock dividends (54.2) (40.0) (35.2)
Proceeds from issuance of common stock, net of expenses 72.6 366.4 4.5
Tax withholding payments related to net settled stock compensation (1.5) (2.5) (2.8)
Change in cash overdrafts due to outstanding checks 1.5 (0.3) 1.0
Net borrowings (repayments) under line of credit agreements 14.1 (22.5) (20.6)
Proceeds from issuance of long-term debt 99.5 627.0 49.9
Repayment of long-term debt and finance lease obligation (18.5) (21.5) (18.0)
Net cash provided by (used in) financing activities 113.5 906.6 (21.2)
Net (Decrease) Increase in Cash and Cash Equivalents 3.0 (1.3) 1.2
Cash and Cash Equivalents - Beginning of Period 4.9 6.2 5.0
Cash and Cash Equivalents - End of Period $ 7.9 $ 4.9 $ 6.2
See Note 7 for Supplemental Cash Flow Disclosures.
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2024 Form 10-K Page 61
Chesapeake Utilities Corporation and Subsidiaries
Consolidated Statements of Stockholders' Equity
Common Stock (1)
(dollars in millions, shares in thousands (except 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, 2021 17,655 $ 8.6 $ 371.2 $ 393.1 $ 1.3 $ 7.2 $ (7.2) $ 774.2
Net Income - - - 89.8 - - - 89.8
Other comprehensive income (loss) - - - - (2.7) - - (2.7)
Dividends declared ($2.085 per share)
- - - (37.4) - - - (37.4)
Issuance under various plans (5)
39 - 5.3 - - - - 5.3
Share-based compensation and tax benefit (3) (4)
47 - 3.5 - - - - 3.5
Treasury stock activities (2)
- - - - - (0.1) 0.1 -
Balance at December 31, 2022 17,741 8.6 380.0 445.5 (1.4) 7.1 (7.1) 832.7
Net Income - - - 87.2 - - - 87.2
Issuance of common stock in connection with acquisition of FCG 4,439 2.2 364.3 - - - - 366.5
Other comprehensive income (loss) - - - - (1.4) - - (1.4)
Dividends declared ($2.305 per share)
- - - (44.0) - - - (44.0)
Share-based compensation and tax benefit (3) (4)
55 - 5.1 - - - - 5.1
Treasury stock activities (2)
- - - - - 2.0 (2.0) -
Balances at December 31, 2023 22,235 10.8 749.4 488.7 (2.8) 9.1 (9.1) 1,246.1
Net Income - - - 118.6 - - - 118.6
Other comprehensive income (loss) - - - - 1.1 - - 1.1
Dividends declared ($2.510 per share)
- - - (57.0) - - - (57.0)
Issuance under various plans (5)
627 0.3 74.2 - - - - 74.5
Share-based compensation and tax benefit (3) (4)
37 - 6.9 - - - - 6.9
Treasury stock activities (2)
- - - - - 0.7 (0.7) -
Balances at December 31, 2024 22,899 $ 11.1 $ 830.5 $ 550.3 $ (1.7) $ 9.8 $ (9.8) $ 1,390.2
(1) 2.0 million shares of preferred stock at $0.01 par value per share have been authorized. No preferred shares have been issued or are outstanding; accordingly, no information has been included in the Consolidated Statements of Stockholders’ Equity.
(2) Includes 114 thousand, 108 thousand and 108 thousand shares at December 31, 2024, 2023 and 2022, 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 2024, 2023 and 2022, we withheld 14 thousand, 20 thousand and 22 thousand shares, respectively, for taxes.
(5) Includes shares issued under the Retirement Savings Plan, DRIP and/or ATM, as applicable.
The accompanying notes are an integral part of the financial statements.
Chesapeake Utilities Corporation 2024 Form 10-K Page 62
Notes to the Consolidated Financial Statements
1. ORGANIZATION AND BASIS OF PRESENTATION
Chesapeake Utilities, incorporated in 1947 in Delaware, is a diversified energy company engaged in regulated and unregulated energy businesses.
Our regulated energy businesses consist of: (a) regulated natural gas distribution operations in central and southern Delaware, Maryland’s eastern shore and Florida; (b) regulated natural gas transmission operations on the Delmarva Peninsula, in Pennsylvania, Florida and in Ohio; and (c) regulated electric distribution operations serving customers in northeast and northwest Florida.
Our unregulated energy businesses primarily include: (a) propane operations in the Mid-Atlantic region, North Carolina, South Carolina, Virginia and Florida; (b) our unregulated natural gas transmission/supply operation in central and eastern Ohio; (c) our CHP plant in Florida that generates electricity and steam; (d) our subsidiary, based in Florida, that provides CNG, LNG and RNG transportation and pipeline solutions, primarily to utilities and pipelines throughout the United States; and (e) sustainable energy investments including renewable natural gas related investments.
Our consolidated financial statements include the accounts of Chesapeake Utilities and its wholly-owned subsidiaries. We do not have any ownership interest in investments accounted for using the equity method or any interest in a variable interest entity. All intercompany accounts and transactions have been eliminated in consolidation. We have assessed and, if applicable, reported on subsequent events through the date of issuance of these consolidated financial statements. Where necessary to improve comparability, prior period amounts have been reclassified to conform to current period presentation.
2. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES
Use of Estimates
Preparing the consolidated financial statements to conform with GAAP requires management to make estimates in measuring assets and liabilities and related revenues and expenses. These estimates involve judgments about various future economic factors that are difficult to predict and are beyond our control; therefore, actual results could differ from these estimates. As additional information becomes available, or actual amounts are determined, recorded estimates are revised. Consequently, operating results can be affected by revisions to prior accounting estimates.
Property, Plant and Equipment
Property, plant and equipment are stated at original cost less accumulated depreciation or fair value, if impaired. Costs include direct labor, materials and third-party construction contractor costs, allowance for funds used during construction ("AFUDC"), and certain indirect costs related to equipment and employees engaged in construction. The costs of repairs and minor replacements are charged to expense as incurred, and the costs of major renewals and improvements are capitalized. Upon retirement or disposition of property within the regulated businesses, the gain or loss, net of salvage value, is charged to accumulated depreciation. Upon retirement or disposition of property within the unregulated businesses, the gain or loss, net of salvage value, is charged to income. A summary of property, plant and equipment by classification as of December 31, 2024 and 2023 is provided in the following table:
Chesapeake Utilities Corporation 2024 Form 10-K Page 63
Notes to the Consolidated Financial Statements
As of December 31,
(in millions) 2024 2023
Property, plant and equipment
Regulated Energy
Natural gas distribution - Delmarva Peninsula and Florida $ 1,679.3 $ 1,486.8
Natural gas transmission - Delmarva Peninsula, Pennsylvania, Ohio and Florida 819.5 788.2
Electric distribution 163.0 143.5
Unregulated Energy
Propane operations - Mid-Atlantic, North Carolina, South Carolina and Florida 201.6 194.9
Natural gas transmission and supply - Ohio 139.2 134.2
Electricity and steam generation 37.4 37.1
Mobile CNG and pipeline solutions 52.8 40.6
Sustainable energy investments, including renewable natural gas related investments 32.7 4.0
Other 29.9 30.3
Total property, plant and equipment 3,155.4 2,859.6
Less: Accumulated depreciation and amortization (567.6) (516.4)
Plus: Construction work in progress 148.1 113.2
Net property, plant and equipment $ 2,735.9 $ 2,456.4
Contributions or Advances in Aid of Construction
Customer contributions or advances in aid of construction reduce property, plant and equipment, unless the amounts are refundable to customers. Contributions or advances may be refundable to customers after a number of years based on the amount of revenues generated from the customers or the duration of the service provided to the customers. Refundable contributions or advances are recorded initially as liabilities. Non-refundable contributions reduce property, plant and equipment at the time of such determination. As of December 31, 2024 and 2023, the non-refundable contributions totaled $5.9 million and $4.2 million, respectively.
AFUDC
Some of the additions to our regulated property, plant and equipment include AFUDC, which represents the estimated cost of funds, from both debt and equity sources, used to finance the construction of major projects. AFUDC is capitalized in the applicable rate base for rate-making purposes when the completed projects are placed in service. During the year ended December 31, 2024, AFUDC was $1.4 million and was reflected as a reduction of interest expense. For the years ended December 31, 2023 and 2022, AFUDC was not material.
Leases
We have entered into lease arrangements for office space, land, equipment, pipeline facilities and warehouses. These leases enable us to conduct our business operations in the regions in which we operate. Our operating leases are included in operating lease right-of-use assets, other accrued liabilities, and operating lease - liabilities in our consolidated balance sheets.
Right-of-use assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. Operating lease right-of-use assets and liabilities are recognized at commencement date based on the present value of lease payments over the lease term. Leases with an initial term of 12 months or less are not recorded on our balance sheet; we recognize lease expense for these leases on a straight-line basis over the lease term. Our leases do not provide an implicit lease rate, therefore, we utilize our incremental borrowing rate, as the basis to calculate the present value of future lease payments, at lease commencement. Our incremental borrowing rate represents the rate that we would have to pay to borrow funds on a collateralized basis over a similar term and in a similar economic environment.
We have lease agreements with lease and non-lease components. At the adoption of ASC 842, we elected not to separate non-lease components from all classes of our existing leases. The non-lease components have been accounted for as part of the single lease component to which they are related. See Note 14, Leases, for additional information.
Chesapeake Utilities Corporation 2024 Form 10-K Page 64
Notes to the Consolidated Financial Statements
Jointly-owned Pipelines
Property, plant and equipment for our Florida natural gas transmission operation included $28.4 million of jointly owned assets at December 31, 2024, primarily comprised of the 26-mile Callahan intrastate transmission pipeline in Nassau County, Florida jointly-owned with Seacoast Gas Transmission. Peninsula Pipeline's ownership is 50 percent. Direct expenses for the jointly-owned pipeline are included in operating expenses within our consolidated statements of income. Accumulated depreciation for this pipeline totaled $2.8 million and $2.2 million at December 31, 2024 and 2023, respectively.
Impairment of Long-lived Assets
We periodically evaluate whether events or circumstances have occurred, which indicate that long-lived assets may not be fully recoverable. The determination of whether an impairment has occurred is based on an estimate of undiscounted future cash flows attributable to the asset, compared to the carrying value of the asset. When such events or circumstances are present, we record an impairment loss equal to the excess of the asset's carrying value over its fair value, if any.
Depreciation and Accretion Included in Operations Expenses
We compute depreciation expense for our regulated operations by applying composite, annual rates, as approved by the respective regulatory bodies. Certain components of depreciation and accretion are reported in operations expenses, rather than as depreciation and amortization expense, in the accompanying consolidated statements of income in accordance with industry practice and regulatory requirements. Depreciation and accretion included in operations expenses consists of the accretion of the costs of removal for future retirements of utility assets, vehicle depreciation, computer software and hardware depreciation, and other minor amounts of depreciation expense. For the years ended December 31, 2024, 2023 and 2022, we reported $15.8 million, $11.9 million and $11.0 million, respectively, of depreciation and accretion in operations expenses.
The following table shows the average depreciation rates used for regulated operations during the years ended December 31, 2024, 2023 and 2022:
2024 2023 2022
Natural gas distribution - Delmarva Peninsula (1)
2.1% 2.5% 2.5%
Natural gas distribution - Florida (2) (3)
2.7% 2.2% 2.5%
Natural gas transmission - Delmarva Peninsula 2.7% 2.7% 2.7%
Natural gas transmission - Florida 2.4% 2.4% 2.4%
Natural gas transmission - Ohio (4)
2.3% 5.0% 5.0%
Electric distribution 2.4% 2.4% 2.8%
(1) Average for 2024 includes the impact of the depreciation study that was approved by the Maryland PSC for Maryland and Sandpiper.
(2) Includes the impact of FCG beginning in 2024.
(3) Average for 2023 includes the impact of the depreciation study that was approved by the Florida PSC in connection with the natural gas base rate proceeding.
(4) 2024 rate excludes the impact of cumulative adjustments related to a change in useful lives of certain assets. Such adjustments were not material to the Company's results of operations for the year ended December 31, 2024.
For our unregulated operations, we compute depreciation expense on a straight-line basis over the following estimated useful lives of the assets:
Asset Description Useful Life
Propane distribution mains 10-37 years
Propane bulk plants and tanks 10-40 years
Propane equipment, meters and meter installations 5-33 years
Measuring and regulating station equipment 5-37 years
Natural gas pipelines 45 years
Natural gas right of ways Perpetual
CHP plant 30 years
Natural gas processing equipment 20-25 years
Office furniture and equipment 3-10 years
Transportation equipment 4-20 years
Structures and improvements 5-45 years
Other Various
Chesapeake Utilities Corporation 2024 Form 10-K Page 65
Notes to the Consolidated Financial Statements
Regulated Operations
We account for our regulated operations in accordance with ASC Topic 980, Regulated Operations, which includes accounting principles for companies whose rates are determined by independent third-party regulators. When setting rates, regulators often make decisions, the economics of which require companies to defer costs or revenues in different periods than may be appropriate for unregulated enterprises. When this situation occurs, a regulated company defers the associated costs as regulatory assets on the balance sheet and records them as expense on the income statement as it collects revenues. Further, regulators can also impose liabilities upon a regulated company, for amounts previously collected from customers and for recovery of costs that are expected to be incurred in the future, as regulatory liabilities. If we were required to terminate the application of these regulatory provisions to our regulated operations, all such deferred amounts would be recognized in our consolidated statement of income at that time, which could have a material impact on our financial position, results of operations and cash flows.
We monitor our regulatory and competitive environments to determine whether the recovery of our regulatory assets continues to be probable. If we determined that recovery of these assets is no longer probable, we would write off the assets against earnings. We believe that the provisions of ASC Topic 980 continue to apply to our regulated operations and that the recovery of our regulatory assets is probable.
Revenue Recognition
Revenues for our natural gas and electric distribution operations are based on rates approved by the PSC in each state in which they operate. Customers’ base rates may not be changed without formal approval by these commissions. The PSCs, however, have authorized our regulated operations to negotiate rates, based on approved methodologies, with customers that have competitive alternatives. Eastern Shore’s revenues are based on rates approved by the FERC. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to FERC-approved maximum rates.
For regulated deliveries of natural gas and electricity, we read meters and bill customers on monthly cycles that do not coincide with the accounting periods used for financial reporting purposes. We accrue unbilled revenues for natural gas and electricity delivered, but not yet billed, at the end of an accounting period to the extent that they do not coincide. We estimate the amount of the unbilled revenue by jurisdiction and customer class.
All of our regulated natural gas and electric distribution operations have fuel cost recovery mechanisms. These mechanisms allow us to adjust billing rates, without further regulatory approvals, to reflect changes in the cost of purchased fuel. Differences between the cost of fuel purchased and delivered are deferred and accounted for as either unrecovered fuel cost or amounts payable to customers. Generally, these deferred amounts are recovered or refunded within one year.
We charge flexible rates to our natural gas distribution industrial interruptible customers who can use alternative fuels. Interruptible service imposes no contractual obligation to deliver or receive natural gas on a firm service basis.
Our unregulated propane distribution businesses record revenue in the period the products are delivered and/or services are rendered for their bulk delivery customers. For propane customers with meters whose billing cycles do not coincide with our accounting periods, we accrue unbilled revenue for product delivered but not yet billed and bill customers at the end of an accounting period, as we do in our regulated energy businesses.
Our Ohio natural gas transmission/supply operation recognizes revenues based on actual volumes of natural gas shipped using contractual rates based upon index prices that are published monthly.
Eight Flags records revenues based on the amount of electricity and steam generated and sold to its customers.
Our mobile compressed natural gas operation recognizes revenue for CNG services at the end of each calendar month for services provided during the month based on agreed upon rates for labor, equipment utilized, costs incurred for natural gas compression, miles driven, mobilization and demobilization fees.
We report revenue taxes, such as gross receipts taxes, franchise taxes, and sales taxes, on a net basis.
For our businesses with agreements that contain variable consideration, we use the invoice practical expedient method. We determined that the amounts invoiced to customers correspond directly with the value to our customers and our performance to date.
Chesapeake Utilities Corporation 2024 Form 10-K Page 66
Notes to the Consolidated Financial Statements
Natural Gas, Electric and Propane Costs
Natural gas, electric and propane costs include the direct costs attributable to the products sold or services provided to our customers. These costs include primarily the variable commodity cost of natural gas, electricity and propane, costs of pipeline capacity needed to transport and store natural gas, transmission costs for electricity, costs to gather and process natural gas, costs to transport propane to/from our storage facilities or our mobile CNG equipment to customer locations, and steam and electricity generation costs. Depreciation expense is not included in natural gas, electric and propane costs.
Operations and Maintenance Expenses
Operations and maintenance expenses include operations and maintenance salaries and benefits, materials and supplies, usage of vehicles, tools and equipment, payments to contractors, utility plant maintenance, customer service, professional fees and other outside services, insurance expense, minor amounts of depreciation, accretion of removal costs for future retirements of utility assets and other administrative expenses.
Cash and Cash Equivalents
Our policy is to invest cash in excess of operating requirements in overnight income-producing accounts. Such amounts are stated at cost, which approximates fair value. Investments with an original maturity of three months or less when purchased are considered cash equivalents.
Accounts Receivable and Allowance for Credit Losses
Accounts receivable consist primarily of amounts due for sales of natural gas, electricity and propane and transportation and distribution services to customers. An allowance for doubtful accounts is recorded against amounts due based upon our collections experiences and an assessment of our customers’ inability or reluctance to pay. If circumstances change, our estimates of recoverable accounts receivable may also change. Circumstances which could affect such estimates include, but are not limited to, customer credit issues, natural gas, electricity and propane prices and impacts from general economic conditions. Accounts receivable are written off when they are deemed to be uncollectible.
Our estimate for expected credit losses has been developed by analyzing our portfolio of financial assets that present potential credit exposure risk. These assets consist solely of our trade receivables from customers and contract assets. The estimate is based on five years of historical collections experience, a review of current economic and operating conditions in our service territories, and an examination of economic indicators which provide a reasonable and supportable basis of potential future activity. Those indicators include metrics which we believe provide insight into the future collectability of our trade receivables such as unemployment rates and economic growth statistics in our service territories.
When determining estimated credit losses, we analyze the balance of our trade receivables based on the underlying line of business. This includes an examination of trade receivables from our energy distribution, energy transmission, energy delivery services and propane operations businesses. Our energy distribution business consists of all our regulated distribution utility (natural gas and electric) operations on the Delmarva Peninsula and in Florida. These business units have the ability to recover their costs through the rate-making process, which can include consideration for amounts historically written off to be included in rate base. Therefore, they possess a mechanism to recover credit losses which we believe reduces their exposure to credit risk. Our energy transmission and energy delivery services business units consist of our natural gas pipelines and our mobile CNG delivery operations. The majority of customers served by these business units are regulated distribution utilities who also have the ability to recover their costs. We believe this cost recovery mechanism significantly reduces the amount of credit risk associated with these customers. Our propane operations are unregulated and do not have the same ability to recover their costs as our regulated operations. However, historically our propane operations have not had material write offs relative to the amount of revenues generated.
Our estimate of expected credit losses reflects our anticipated losses associated with our trade receivables as a result of non-payment from our customers beginning the day the trade receivable is established. We believe the risk of loss associated with trade receivables classified as current presents the least amount of credit exposure risk and therefore, we assign a lower estimate to our current trade receivables. As our trade receivables age outside of their expected due date, our estimate increases. Our allowance for credit losses relative to the balance of our trade receivables has historically been immaterial as a result of on time payment activity from our customers.
Chesapeake Utilities Corporation 2024 Form 10-K Page 67
Notes to the Consolidated Financial Statements
The table below illustrates the changes in the balance of our allowance for expected credit losses for the year ended December 31, 2024:
(in millions)
Balance at December 31, 2023 $ 2.7
Additions:
Provision for credit losses 2.1
Recoveries 0.4
Deductions:
Write offs (1.9)
Balance at December 31, 2024 $ 3.3
Inventories
We use the average cost method to value propane, materials and supplies, and other merchandise inventory. If market prices drop below cost, inventory balances that are subject to price risk are adjusted to their net realizable value. There were no lower-of-cost-or-net realizable value adjustment for the years ended December 31, 2024, 2023 or 2022.
Goodwill and Other Intangible Assets
Goodwill is not amortized but is tested for impairment at least annually, or more frequently if an event occurs or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying value. We generally use a present value technique based on discounted cash flows to estimate the fair value of our reporting units. An impairment charge is recognized if the carrying value of a reporting unit’s goodwill exceeds its fair value. There were no goodwill impairments recognized during the years ended December 31, 2024, 2023 and 2022. Other intangible assets are amortized on a straight-line basis over their estimated economic useful lives.
Other Deferred Charges
Other deferred charges include issuance costs associated with short-term borrowings. These charges are amortized over the life of the related short-term debt borrowings.
Asset Removal Cost
As authorized by the appropriate regulatory body (state PSC or FERC), we accrue future asset removal costs associated with utility property, plant and equipment even if a legal obligation does not exist. Such accruals are provided for through depreciation expense and are recorded with corresponding credits to regulatory liabilities or assets. When we retire depreciable utility plant and equipment, we charge the associated original costs to accumulated depreciation and amortization, and any related removal costs incurred are charged to regulatory liabilities or assets. The difference between removal costs recognized in depreciation rates and the accretion and depreciation expense recognized for financial reporting purposes is a timing difference between recovery of these costs in rates and their recognition for financial reporting purposes. Accordingly, these differences are deferred as regulatory liabilities or assets. In the rate setting process, the regulatory liability or asset is excluded from the rate base upon which those utilities have the opportunity to earn their allowed rates of return. The costs associated with our asset retirement obligations are either currently being recovered in rates or are probable of recovery in future rates.
See Note 18, Rates and Other Regulatory Activities, for information related to FCG's reserve surplus amortization mechanism ("RSAM") that was approved as part of its rate case effective as of May 1, 2023.
Pension and Other Postretirement Plans
Pension and other postretirement plan costs and liabilities are determined on an actuarial basis and are affected by numerous assumptions and estimates, including the fair value of plan assets, estimates of the expected returns on plan assets, assumed discount rates, the level of contributions made to the plans, and current demographic and actuarial mortality data. We review annually the estimates and assumptions underlying our pension and other postretirement plan costs and liabilities with the assistance of third-party actuarial firms. The assumed discount rates, expected returns on plan assets and the mortality assumption are the factors that generally have the most significant impact on our pension costs and liabilities. The assumed discount rates, health care cost trend rates and rates of retirement generally have the most significant impact on our postretirement plan costs and liabilities.
The discount rates are utilized principally in calculating the actuarial present value of our pension and postretirement obligations and net pension and postretirement costs. When estimating our discount rates, we consider high-quality corporate
Chesapeake Utilities Corporation 2024 Form 10-K Page 68
Notes to the Consolidated Financial Statements
bond rates, such as the Empower curve index and the FTSE Index, changes in those rates from the prior year and other pertinent factors, including the expected life of each of our plans and their respective payment options.
The expected long-term rates of return on assets are utilized in calculating the expected returns on the plan assets component of our annual pension plan costs. We estimate the expected returns on plan assets by evaluating expected bond returns, asset allocations, the effects of active plan management, the impact of periodic plan asset rebalancing and historical performance. We also consider the guidance from our investment advisors in making a final determination of our expected rates of return on plan assets.
We estimate the health care cost trend rates used in determining our postretirement expense based upon actual health care cost experience, the effects of recently enacted legislation and general economic conditions. Our assumed rate of retirement is estimated based upon our annual reviews of participant census information as of the measurement date.
The mortality assumption used for our pension and postretirement plans is reviewed periodically and is based on the actuarial table that best reflects the expected mortality of the plan participants.
Income Taxes, Investment Tax Credit Adjustments and Tax-Related Contingency
Deferred tax assets and liabilities are recorded for the income tax effect of temporary differences between the financial statement basis and tax basis of assets and liabilities and are measured using the enacted income tax rates in effect in the years in which the differences are expected to reverse. Deferred tax assets are recorded when it is more likely than not that such income tax benefits will be realized. Valuation allowances may be recorded if it is determined that some deferred tax assets will not be realized. Investment tax credits on utility property have been deferred and are allocated to income ratably over the lives of the subject property.
We account for uncertainty in income taxes in our consolidated financial statements only if it is more likely than not that an uncertain tax position is sustainable based on technical merits. Recognizable tax positions are then measured to determine the amount of benefit recognized in the consolidated financial statements. We recognize penalties and interest related to unrecognized tax benefits as a component of other income.
We account for contingencies associated with taxes other than income when the likelihood of a loss is both probable and estimable. In assessing the likelihood of a loss, we do not consider the existence of current inquiries, or the likelihood of future inquiries, by tax authorities as a factor. Our assessment is based solely on our application of the appropriate statutes and the likelihood of a loss, assuming the proper inquiries are made by tax authorities.
Financial Instruments
We utilize financial instruments to mitigate commodity price risk associated with fluctuations of natural gas, electricity and propane and to mitigate interest rate risk. Our propane operations enter into derivative transactions, such as swaps, put options and call options in order to mitigate the impact of wholesale price fluctuations on inventory valuation and future purchase commitments. These transactions may be designated as fair value hedges or cash flow hedges, if they meet all of the accounting requirements pursuant to ASC Topic 815, Derivatives and Hedging, and we elect to designate the instruments as hedges. If designated as a fair value hedge, the value of the hedging instrument, such as a swap, future, or put option, is recorded at fair value, with the effective portion of the gain or loss of the hedging instrument effectively reducing or increasing the value of the hedged item. If designated as a cash flow hedge, the value of the hedging instrument, such as a swap or call option, is recorded at fair value with the effective portion of the gain or loss of the hedging instrument being initially recorded in accumulated other comprehensive income (loss) and reclassified to earnings when the associated hedged transaction settles. The ineffective portion of the gain or loss of a hedge is immediately recorded in earnings. If the instrument is not designated as a fair value or cash flow hedge, or it does not meet the accounting requirements of a hedge under ASC Topic 815, Derivatives and Hedging, it is recorded at fair value with all gains or losses being recorded directly in earnings.
Our natural gas, electric and propane operations enter into agreements with suppliers to purchase natural gas, electricity, and propane for resale to our respective customers. Purchases under these contracts, as well as distribution and sales agreements with counterparties or customers, either do not meet the definition of a derivative, or qualify for “normal purchases and normal sales” treatment under ASC Topic 815 and are accounted for on an accrual basis.
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. We designate and account for the interest rate swaps as cash flows hedges. Accordingly, unrealized gains and losses associated with the interest rate swaps are recorded as a component of accumulated other comprehensive income (loss). When the interest rate swaps settle, the realized gain or loss will be recorded in the income statement and recognized as a component of interest charges.
Chesapeake Utilities Corporation 2024 Form 10-K Page 69
Notes to the Consolidated Financial Statements
Recently Adopted Accounting Standards
Segment Reporting (ASC 280) - In November 2023, the FASB issued ASU 2023-07, Improvements to Reportable Segments Disclosures, which modifies required disclosures about a public entity’s reportable segments and addresses requests from investors for more detailed information about a reportable segment’s expenses and a more comprehensive reconciliation of each segment's reported profit or loss. We adopted ASU 2023-07 for our annual financial statements beginning January 1, 2024 and our interim financial statements beginning January 1, 2025. ASU 2023-07 only impacts disclosures, and as a result, did not have an impact on our financial position or results of operations.
Recent Accounting Standards Yet to be Adopted
FASB
Income Taxes (ASC 740) - In December 2023, the FASB issued ASU 2023-09, Improvements to Income Tax Disclosures, which modifies required income tax disclosures primarily related to an entity's rate reconciliation and information pertaining to income taxes paid. These enhancements have been made to address requests from investors related to transparency and usefulness of income tax disclosures. ASU 2023-09 will be effective for our annual financial statements beginning January 1, 2025. ASU 2023-09 only impacts disclosures, and as a result, will not have an impact on our financial position or results of operations.
Income Statement Expense Disaggregation (ASC 220) - In November 2024, the FASB issued ASU 2024-04, Disaggregation of Income Statement Expenses, which require disclosure in the notes to financial statements of specified information about certain costs and expenses. ASU 2024-04 will be effective for our annual financial statements beginning January 1, 2027 and our interim financial statements beginning January 1, 2028. ASU 2024-04 only impacts disclosures, and as a result, will not have an impact on our financial position or results of operations.
SEC
Climate-Related Disclosures - In March 2024, the SEC issued a final rule that requires a public entity to provide disclosures surrounding material Scope 1 and Scope 2 emissions, climate-related risks and the material impact of those risks and material climate targets and goals. In April 2024, the SEC issued a stay on the final rule as a result of various petitions being filed and sought review of the final ruling in multiple courts of appeals. At this time, it is uncertain as to when the review will be completed, the final outcome of the review, and the timing of required disclosure.
3. EARNINGS PER SHARE
The following table presents the calculation of our basic and diluted earnings per share:
For the Year Ended December 31,
2024 2023 2022
(dollars in millions, shares in thousands (except per share data))
Calculation of Basic Earnings Per Share:
Net Income $ 118.6 $ 87.2 $ 89.8
Weighted average shares outstanding (1)
22,469 18,371 17,722
Basic Earnings Per Share
$ 5.28 $ 4.75 $ 5.07
Calculation of Diluted Earnings Per Share:
Reconciliation of Denominator:
Weighted average shares outstanding - Basic (1)
22,469 18,371 17,722
Effect of dilutive securities - Share-based compensation 62 64 82
Adjusted denominator - Diluted (1)
22,531 18,435 17,804
Diluted Earnings Per Share
$ 5.26 $ 4.73 $ 5.04
(1) 2023 and 2024 weighted average shares reflect the impact of 4.4 million common shares issued in November 2023 in connection with the acquisition of FCG. See Notes 4 and 15 for additional details on the acquisition and related equity offering.
Chesapeake Utilities Corporation 2024 Form 10-K Page 70
Notes to the Consolidated Financial Statements
4. ACQUISITIONS
Acquisition of Florida City Gas
On November 30, 2023, we completed the acquisition of FCG for $922.8 million in cash, including working capital adjustments as defined in the agreement that were settled during the first quarter of 2024, pursuant to the stock purchase agreement with Florida Power & Light Company. Upon completion of the acquisition, FCG became a wholly-owned subsidiary of the Company and is included within our Regulated Energy segment.
FCG serves approximately 123,000 residential and commercial natural gas customers across eight counties in Florida, including Miami-Dade, Broward, Brevard, Palm Beach, Hendry, Martin, St. Lucie and Indian River. Its natural gas system includes approximately 3,982 miles of distribution mains and 80 miles of transmission pipe.
The purchase price of the acquisition was funded with $366.4 million of net proceeds from the issuance of 4.4 million shares of our common stock, the issuance of approximately $550.0 million principal amount of uncollateralized senior notes, and borrowings under the Company's Revolver. See Note 12, Long-Term Debt, and Note 15, Stockholders' Equity, for additional details on these financing activities.
The excess of the purchase price for FCG over the fair value of the assets acquired and liabilities assumed was reflected as goodwill within the Regulated Energy segment. Goodwill resulting from the acquisition is largely attributable to expansion opportunities provided within our existing regulated operations in Florida, including planned customer growth and growth in rate base through continued investment in our utility infrastructure, as well as natural gas transmission infrastructure supporting the distribution operations. The goodwill recognized in connection with the acquisition of FCG is deductible for income tax purposes.
The components of the purchase price allocation are as follows:
(in millions)
Assets acquired: Acquisition Date Fair Value
Cash $ 2.3
Accounts receivable, net 14.1
Regulatory assets - current 3.0
Other current assets 2.0
Property, plant and equipment 454.4
Goodwill 460.9
Regulatory assets - non-current 3.4
Other deferred charges and other assets 18.3
Total assets acquired 958.4
Liabilities assumed:
Current liabilities (20.9)
Regulatory liabilities (14.1)
Other deferred credits and other liabilities (0.6)
Total liabilities assumed (35.6)
Net purchase price $ 922.8
Direct transaction and transition-related costs of $10.4 million associated with the FCG acquisition are reflected in “FCG transaction and transition-related expenses” on our consolidated statement of income for the year ended December 31, 2023. In addition, interest charges included $4.1 million related to fees and expenses associated with the Bridge Facility, which was terminated without any funds drawn, for the year ended December 31, 2023. Other transaction costs of $15.9 million related primarily to the debt and equity financings executed in connection with the acquisition, were deferred on the consolidated balance sheet or recorded in equity as an offset to proceeds received, as appropriate, as of December 31, 2023.
For the year ended December 31, 2024, the Company’s consolidated results include $140.3 million of operating revenue and net income of $13.5 million attributable to FCG which includes $4.0 million of transaction and transition-related expenses. For
Chesapeake Utilities Corporation 2024 Form 10-K Page 71
Notes to the Consolidated Financial Statements
the period from the acquisition date through December 31, 2023, the Company’s consolidated results include $12.1 million of operating revenue and a $3.3 million net loss attributable to FCG which includes $7.5 million of the transaction and transition-related expenses described above.
Acquisition of J.T. Lee and Son's
In December 2023, Sharp acquired the propane operating assets of J.T. Lee and Son's in Cape Fear, North Carolina for $3.9 million. In connection with this acquisition, we recorded a $0.3 million liability which was subject to the seller's adherence to various provisions contained in the purchase agreement through the first anniversary of the transaction closing. Upon the expiration of the first anniversary of the transaction, this liability was settled. Through this acquisition, we expanded our operating footprint further in North Carolina, where customers are served by Diversified Energy. Sharp added approximately 3,000 customers and distribution of approximately 800,000 gallons of propane annually. The transaction also includes a bulk plant with 60,000 gallons of propane storage, enabling the Company to realize efficiencies with additional storage capacity and overlapping delivery territories.
In connection with this acquisition, we recorded $2.7 million in property plant and equipment, $0.9 million in goodwill, $0.2 million in working capital, and less than $0.1 million in intangible assets associated primarily with non-compete agreements, all of which are deductible for income tax purposes. The financial results associated with this acquisition are included within our propane distribution operations within our Unregulated Energy segment. The operating revenues and net income of this acquisition were not material to our consolidated results for the years ended December 31, 2024 and 2023.
5. REVENUE RECOGNITION
We recognize revenue when our performance obligations under contracts with customers have been satisfied, which generally occurs when our businesses have delivered or transported natural gas, electricity or propane to customers. We exclude sales taxes and other similar taxes from the transaction price. Typically, our customers pay for the goods and/or services we provide in the month following the satisfaction of our performance obligation. The following tables display revenue by major source based on product and service type for the years ended December 31, 2024, 2023 and 2022:
Chesapeake Utilities Corporation 2024 Form 10-K Page 72
Notes to the Consolidated Financial Statements
For the Year Ended December 31, 2024
(in millions) Regulated Energy Unregulated Energy Other and Eliminations Total
Energy distribution
Delaware natural gas division $ 76.9 $ - $ - $ 76.9
Florida Natural Gas distribution
170.3 - - 170.3
Florida City Gas 140.3 - - 140.3
FPU electric distribution 92.6 - - 92.6
Maryland natural gas division 24.6 - - 24.6
Sandpiper natural gas/propane operations 20.0 - - 20.0
Elkton Gas 7.3 - - 7.3
Total energy distribution 532.0 - - 532.0
Energy transmission
Aspire Energy - 35.2 - 35.2
Aspire Energy Express 1.5 - - 1.5
Eastern Shore 81.7 - - 81.7
Peninsula Pipeline 34.5 - - 34.5
Total energy transmission 117.7 35.2 - 152.9
Energy generation
Eight Flags - 18.0 - 18.0
Propane operations
Propane distribution operations - 157.9 - 157.9
CNG / RNG
Marlin Gas Services - 16.6 - 16.6
Other RNG 1.0 1.0
Total CNG / RNG Services - 17.6 - 17.6
Other and eliminations
Eliminations (66.3) (0.3) (24.8) (91.4)
Other - 0.2 0.2
Total other and eliminations (66.3) (0.3) (24.6) (91.2)
Total operating revenues (1)
$ 583.4 $ 228.4 $ (24.6) $ 787.2
(1) Total operating revenues for the year ended December 31, 2024, include other revenue (revenues from sources other than contracts with customers) of $1.6 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.
Chesapeake Utilities Corporation 2024 Form 10-K Page 73
Notes to the Consolidated Financial Statements
For the Year Ended December 31, 2023
(in millions) Regulated Energy Unregulated Energy Other and Eliminations Total
Energy distribution
Delaware natural gas division $ 83.9 $ - $ - $ 83.9
Florida Natural Gas distribution
168.4 - - 168.4
Florida City Gas (1)
12.1 - - 12.1
FPU electric distribution 99.5 - - 99.5
Maryland natural gas division 28.1 - - 28.1
Sandpiper natural gas/propane operations 20.2 - - 20.2
Elkton Gas 8.8 - - 8.8
Total energy distribution 421.0 - - 421.0
Energy transmission
Aspire Energy - 37.1 - 37.1
Aspire Energy Express 1.5 - - 1.5
Eastern Shore 79.9 - - 79.9
Peninsula Pipeline 30.4 - - 30.4
Total energy transmission 111.8 37.1 - 148.9
Energy generation
Eight Flags - 19.2 - 19.2
Propane operations
Propane distribution operations - 154.7 - 154.7
Compressed Natural Gas Services
Marlin Gas Services - 12.3 - 12.3
Other and eliminations
Eliminations (59.2) (0.2) (26.3) (85.7)
Other - - 0.2 0.2
Total other and eliminations (59.2) (0.2) (26.1) (85.5)
Total operating revenues (2)
$ 473.6 $ 223.1 $ (26.1) $ 670.6
(1) Operating revenues for FCG include amounts from the acquisition date through December 31, 2023. For additional information on FCG's results, see Note 4, Acquisitions, and discussion under Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.
(2) Total operating revenues for the year ended December 31, 2023, include other revenue (revenues from sources other than contracts with customers) of $1.2 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.
Chesapeake Utilities Corporation 2024 Form 10-K Page 74
Notes to the Consolidated Financial Statements
For the Year Ended December 31, 2022
(in millions) Regulated Energy Unregulated Energy Other and Eliminations Total
Energy distribution
Delaware natural gas division $ 82.2 $ - $ - $ 82.2
Florida Natural Gas distribution
155.9 - - 155.9
FPU electric distribution 81.7 - - 81.7
Maryland natural gas division 26.6 - - 26.6
Sandpiper natural gas/propane operations 21.3 - - 21.3
Elkton Gas 9.2 - - 9.2
Total energy distribution 376.9 - - 376.9
Energy transmission
Aspire Energy - 56.2 - 56.2
Aspire Energy Express 1.4 - - 1.4
Eastern Shore 78.6 - - 78.6
Peninsula Pipeline 27.3 - - 27.3
Total energy transmission 107.3 56.2 - 163.5
Energy generation
Eight Flags - 25.3 - 25.3
Propane operations
Propane distribution operations - 188.4 - 188.4
Compressed Natural Gas Services
Marlin Gas Services - 11.2 - 11.2
Other and eliminations
Eliminations (54.8) (0.3) (29.8) (84.9)
Other - - 0.3 0.3
Total other and eliminations (54.8) (0.3) (29.5) (84.6)
Total operating revenues (1)
$ 429.4 $ 280.8 $ (29.5) $ 680.7
(1) Total operating revenues for the year ended December 31, 2022, include other revenue (revenues from sources other than contracts with customers) of $0.5 million and $0.4 million for our Regulated and Unregulated Energy segments, respectively. The sources of other revenues include revenue from alternative revenue programs related to revenue normalization for Maryland division and Sandpiper and late fees.
Regulated Energy Segment
The businesses within our Regulated Energy segment are regulated utilities whose operations and customer contracts are subject to rates approved by the respective state PSC or the FERC.
Our energy distribution operations deliver natural gas or electricity to customers, and we bill the customers for both the delivery of natural gas or electricity and the related commodity, where applicable. In most jurisdictions, our customers are also required to purchase the commodity from us, although certain customers in some jurisdictions may purchase the commodity from a third-party retailer (in which case we provide delivery service only). We consider the delivery of natural gas or electricity and/or the related commodity sale as one performance obligation because the commodity and its delivery are highly interrelated with two-way dependency on one another. Our performance obligation is satisfied over time as natural gas or electricity is delivered and consumed by the customer. We recognize revenues based on monthly meter readings, which are based on the quantity of natural gas or electricity used and the approved rates. We accrue unbilled revenues for natural gas and electricity that have been delivered, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide.
Revenues for Eastern Shore are based on rates approved by the FERC. The FERC has also authorized Eastern Shore to negotiate rates above or below the FERC-approved maximum rates, which customers can elect as an alternative to the FERC-approved maximum rates. Eastern Shore's services can be firm or interruptible. Firm services are offered on a guaranteed basis
Chesapeake Utilities Corporation 2024 Form 10-K Page 75
Notes to the Consolidated Financial Statements
and are available at all times unless prevented by force majeure or other permitted curtailments. Interruptible customers receive service only when there is available capacity or supply. Our performance obligation is satisfied over time as we deliver natural gas to the customers' locations. We recognize revenues based on capacity used or reserved and the fixed monthly charge.
Peninsula Pipeline is engaged in natural gas intrastate transmission to third-party customers and certain affiliates in the State of Florida. Our performance obligation is satisfied over time as the natural gas is transported to customers. We recognize revenue based on rates approved by the Florida PSC and the capacity used or reserved. We accrue unbilled revenues for transportation services provided and not yet billed at the end of an accounting period.
Aspire Energy Express is engaged in natural gas intrastate transmission in the State of Ohio. We currently serve the Guernsey Power Station and our performance obligation is satisfied over time as the natural gas is transported to the plant. We recognize revenue based on rates approved by the Ohio PSC and the capacity used or reserved. We accrue unbilled revenues for transportation services provided and not yet billed at the end of an accounting period.
Unregulated Energy Segment
Revenues generated from the Unregulated Energy segment are not subject to any federal, state, or local pricing regulations. Aspire Energy primarily sources gas from hundreds of conventional producers and performs gathering and processing functions to maintain the quality and reliability of its gas for its wholesale customers. Aspire Energy's performance obligation is satisfied over time as natural gas is delivered to its customers. Aspire Energy recognizes revenue based on the deliveries of natural gas at contractually agreed upon rates (which are based upon an established monthly index price and a monthly operating fee, as applicable). For natural gas customers, we accrue unbilled revenues for natural gas that has been delivered, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide with the end of the accounting period.
Eight Flags' CHP plant, which is located on land leased from a customer, produces three sources of energy: electricity, steam and heated water. This customer purchases the steam (unfired and fired) and heated water, which are used in the customer’s production facility. Our electric distribution operation purchases the electricity generated by the CHP plant for distribution to its customers. Eight Flags' performance obligation is satisfied over time as deliveries of heated water, steam and electricity occur. Eight Flags recognizes revenues over time based on the amount of heated water, steam and electricity generated and delivered to its customers.
For our propane distribution operations, we recognize revenue based upon customer type and service offered. Generally, for propane bulk delivery customers (customers without meters) and wholesale sales, our performance obligation is satisfied when we deliver propane to the customers' locations (point-in-time basis). We recognize revenue from these customers based on the number of gallons delivered and the price per gallon at the point-in-time of delivery. For our propane distribution customers with meters, we satisfy our performance obligation over time. We recognize revenue over time based on the amount of propane consumed and the applicable price per unit. For propane distribution metered customers, we accrue unbilled revenues for propane that is estimated to have been consumed, but not yet billed, at the end of an accounting period, to the extent that billing and delivery do not coincide with the end of the accounting period.
Marlin Gas Services provides mobile CNG and pipeline solutions primarily to utilities and pipelines. Marlin Gas Services provides temporary hold services, pipeline integrity services, emergency services for damaged pipelines and specialized gas services for customers who have unique requirements. Marlin Gas Services continues to actively expand the territories it serves, as well as leveraging its fleet of equipment and patented technologies to also serve LNG and RNG market needs. Marlin Gas Services' performance obligations are comprised of the compression of natural gas, mobilization of CNG equipment, utilization of equipment and on-site CNG support. Our performance obligations for the compression of natural gas, utilization of mobile CNG equipment and for the on-site CNG staff support are satisfied over time when the natural gas is compressed, equipment is utilized or as our staff provide support services to our customers. Our performance obligation for the mobilization of CNG equipment is satisfied at a point-in-time when the equipment is delivered to the customer project location. We recognize revenue for CNG services at the end of each calendar month for services provided during the month based on agreed upon rates for equipment utilized, costs incurred for natural gas compression, miles driven, mobilization and demobilization fees.
Chesapeake Utilities Corporation 2024 Form 10-K Page 76
Notes to the Consolidated Financial Statements
Contract balances
The timing of revenue recognition, customer billings and cash collections results in trade receivables and customer advances (contract liabilities) in our consolidated balance sheets. The balances of our trade receivables, contract assets, and contract liabilities as of December 31, 2024 and 2023 were as follows:
Trade Receivables Contract Assets (Current) Contract Assets (Noncurrent) Contract Liabilities (Current)
(in millions)
Balance at 12/31/2023
$ 67.7 $ - $ 3.5 $ 1.0
Balance at 12/31/2024
66.2 - 3.0 1.2
Increase (decrease) $ (1.5) $ - $ (0.5) $ 0.2
Our trade receivables are included in trade and other receivables in the consolidated balance sheets. Our non-current contract assets are included in receivables and other deferred charges in the consolidated balance sheets and relate to operations and maintenance costs incurred by Eight Flags that have not yet been recovered through rates for the sale of electricity to our electric distribution operation pursuant to a long-term service agreement.
At times, we receive advances or deposits from our customers before we satisfy our performance obligation, resulting in contract liabilities. Contract liabilities are included in other accrued liabilities in the consolidated balance sheets and relate to non-refundable prepaid fixed fees for our propane distribution operation's retail offerings. Our performance obligation is satisfied over the term of the respective retail offering plan on a ratable basis. For the years ended December 31, 2024 and 2023, the amount of contract liabilities recognized in revenue were not material.
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 December 31, 2024 are expected to be recognized as follows:
(in millions) 2025 2026 2027 2028 2029 2030 and thereafter
Eastern Shore and Peninsula Pipeline $ 37.5 $ 34.5 $ 30.8 $ 28.6 $ 26.3 $ 130.6
Natural gas distribution operations 11.7 11.5 10.0 10.0 10.0 33.6
FPU electric distribution 0.7 0.4 0.4 0.4 - -
Total revenue contracts with remaining performance obligations $ 49.9 $ 46.4 $ 41.2 $ 39.0 $ 36.3 $ 164.2
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, our President and 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 distribution operations, mobile compressed natural gas distribution and pipeline solutions operations, and sustainable energy investments including renewable natural gas related investments. 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.
Chesapeake Utilities Corporation 2024 Form 10-K Page 77
Notes to the Consolidated Financial Statements
The remainder of our operations are presented as “Other businesses and eliminations,” which consists of unregulated subsidiaries that own real estate leased to the Company, as well as certain corporate costs not allocated to other operations.
The following tables present information about our reportable segments:
For the Year Ended December 31,
2024 2023
(in millions) Regulated Unregulated Other and Eliminations (1)
Total Regulated Unregulated Other and Eliminations (1)
Total
Operating revenues, unaffiliated customers $ 578.3 $ 208.9 $ 0.2 $ 787.4 $ 471.6 $ 199.0 $ 0.2 $ 670.8
Intersegment revenues (2)
5.1 19.5 (24.8) (0.2) 2.0 24.1 (26.3) (0.2)
583.4 228.4 (24.6) 787.2 473.6 223.1 (26.1) 670.6
Less:
Natural gas, propane and electric costs 144.2 100.2 (24.6) 219.8 140.0 102.5 (26.0) 216.5
Operations and maintenance expenses 158.5 74.4 (0.3) 232.6 125.3 73.8 (0.3) 198.8
Depreciation and amortization 48.8 16.9 - 65.7 48.2 17.3 - 65.5
Other segment items (3)
35.7 5.2 - 40.9 33.9 5.1 - 39.0
Segment operating income $ 196.2 $ 31.7 $ 0.3 $ 228.2 $ 126.2 $ 24.4 $ 0.2 $ 150.8
Other income, net 2.0 1.4
Interest charges 68.4 36.9
Income before income taxes 161.8 115.3
Income taxes 43.2 28.1
Net Income $ 118.6 $ 87.2
Capital expenditures (4)
$ 320.2 $ 33.9 $ 1.7 $ 355.8 $ 1,095.9 $ 40.3 $ 1.8 $ 1,138.0
(1) Other revenues and other operating income (loss) amounts are attributable to eliminations and unregulated subsidiaries that own real estate leased to the Company.
(2) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.
(3) Other segment items for each reportable segment include: Regulated - Other taxes and transaction and transition costs related to the acquisition and integration of FCG; Unregulated - Other taxes.
(4) Regulated capital expenditures in 2023 include our acquisition of FCG for $922.8 million. See Note 4 for additional details.
For the Year Ended December 31, 2022
(in millions) Regulated Unregulated Other and Eliminations (1)
Total
Operating revenues, unaffiliated customers $ 422.9 $ 257.8 $ 0.3 $ 681.0
Intersegment revenues (2)
6.5 23.0 (29.8) (0.3)
429.4 280.8 (29.5) 680.7
Less:
Natural gas, propane and electric costs 127.2 162.7 (29.4) 260.5
Operations and maintenance expenses 113.0 70.0 (0.3) 182.7
Depreciation and amortization 52.7 16.3 - 69.0
Other segment items (3)
21.2 4.3 0.1 25.6
Segment operating income $ 115.3 $ 27.5 $ 0.1 $ 142.9
Other income, net 5.1
Interest charges 24.4
Income before income taxes 123.6
Income taxes 33.8
Net Income $ 89.8
Capital expenditures $ 97.6 $ 40.8 $ 2.4 $ 140.8
(1) Other revenues and other operating income (loss) amounts are attributable to eliminations and unregulated subsidiaries that own real estate leased to the Company.
Chesapeake Utilities Corporation 2024 Form 10-K Page 78
Notes to the Consolidated Financial Statements
(2) All significant intersegment revenues are billed at market rates and have been eliminated from consolidated revenues.
(3) Other segment items for each reportable segment include: Regulated - Other taxes; Unregulated - Other taxes.
As of December 31,
(in millions) 2024 2023
Identifiable Assets
Regulated Energy segment $ 3,042.9 $ 2,781.6
Unregulated Energy segment
486.4 477.4
Other businesses and eliminations 47.7 45.7
Total identifiable assets $ 3,577.0 $ 3,304.7
7. SUPPLEMENTAL CASH FLOW DISCLOSURES
Cash paid for interest and income taxes during the years ended December 31, 2024, 2023, and 2022 were as follows:
For the Year Ended December 31,
2024 2023 2022
(in millions)
Cash paid for interest $ 73.0 $ 30.5 $ 24.3
Cash (received) paid for income taxes, net of refunds $ 9.4 $ 21.9 $ (5.0)
Non-cash investing and financing activities during the years ended December 31, 2024, 2023, and 2022 were as follows:
For the Year Ended December 31,
2024 2023 2022
(in millions)
Capital property and equipment acquired on account, but not paid for as of December 31, $ 34.0 $ 33.3 $ 13.2
Common stock issued for the Retirement Savings Plan $ 1.2 $ - $ -
Common stock issued under the SICP $ 4.9 $ 3.7 $ 2.9
8. DERIVATIVE INSTRUMENTS
We use derivative and non-derivative contracts to manage risks related to obtaining adequate supplies and the price fluctuations of natural gas, electricity and propane 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. Our 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 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 December 31, 2024 and 2023, our natural gas and electric distribution operations did not have any outstanding derivative contracts.
Volume of Derivative Activity
As of December 31, 2024, the volume of our open 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 10.8 Cash flow hedges March 2027
Sharp entered into futures and swap agreements to mitigate the risk of fluctuations in wholesale propane index prices associated with the propane volumes expected to be purchased and/or sold during the heating season. Under the futures and swap agreements, Sharp will receive or pay the difference between (i) the index prices (Mont Belvieu prices in December 2024 through March 2027) and (ii) the per gallon propane contracted prices, to the extent the index prices deviate from the contracted prices. We designated and accounted for the propane swaps as cash flow hedges. The change in the fair value of the swap
Chesapeake Utilities Corporation 2024 Form 10-K Page 79
Notes to the Consolidated Financial Statements
agreements is initially recorded as a component of accumulated other comprehensive income (loss) and later recognized in our consolidated statement of income in the same period and in the same line item as the hedged transaction. We expect to reclassify approximately $0.5 million of unrealized gains related to our propane derivatives from accumulated other comprehensive income (loss) to earnings during the next 12-month period.
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 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. In August 2024, we entered into an additional interest rate swap through August 2029, at a notional amount of $50.0 million and pricing of 3.97 percent. Our interest rate swaps are cash settled monthly as the counter-party pays us the 30-day SOFR rate less the fixed rate.
We designate and account for interest rate swaps as cash flow hedges. Accordingly, unrealized gains and losses associated with the interest rate swaps are initially recorded as a component of accumulated other comprehensive income (loss). As 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.
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 included within other current assets on the consolidated balance sheets which had a balance of $1.9 million and $2.1 million as of December 31, 2024 and December 31, 2023, respectively.
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 December 31, 2024 and 2023 are as follows:
Derivative Assets
Fair Value as of
(in millions) Balance Sheet Location December 31, 2024 December 31, 2023
Derivatives designated as cash flow hedges
Propane swap agreements Derivative assets, at fair value $ 0.6 $ 0.7
Interest rate swap agreements Derivative assets, at fair value 0.1 0.3
Total Derivative Assets (1)
$ 0.7 $ 1.0
(1) Derivative assets, at fair value included $0.6 million and $1.0 million in current assets in the consolidated balance sheets at December 31, 2024 and 2023, respectively, with the remainder of the balance classified as long-term.
Derivative Liabilities
Fair Value as of
(in millions) Balance Sheet Location December 31, 2024 December 31, 2023
Derivatives designated as cash flow hedges
Propane swap agreements Derivative liabilities, at fair value $ - $ 1.1
Interest rate swap agreements Derivative liabilities, at fair value 0.1 0.2
Total Derivative Liabilities (1)
$ 0.1 $ 1.3
(1) There were no current derivative liabilities at December 31, 2024. At December 31, 2023, current derivative liabilities amounted to $0.4 million with the remainder of the balance classified as long-term.
Chesapeake Utilities Corporation 2024 Form 10-K Page 80
Notes to the Consolidated Financial Statements
The effects of gains and losses from derivative instruments and their location in the consolidated statements of income are as follows:
Amount of Gain (Loss) on Derivatives:
Location of Gain
(Loss) on Derivatives For the Year Ended December 31,
(in millions) 2024 2023 2022
Derivatives not designated as hedging instruments
Propane swap agreements Propane and natural gas costs $ - $ - $ 0.1
Derivatives designated as cash flow hedges
Propane swap agreements Revenues (0.3) 1.2 (0.4)
Propane swap agreements Propane and natural gas costs 1.3 (1.1) 3.8
Interest rate swap agreements Interest expense 0.8 0.5 -
Total $ 1.8 $ 0.6 $ 3.5
9. FAIR VALUE OF FINANCIAL INSTRUMENTS
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 as follows:
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.
Chesapeake Utilities Corporation 2024 Form 10-K Page 81
Notes to the Consolidated Financial Statements
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 December 31, 2024 and 2023, respectively:
Fair Value Measurements Using:
As of December 31, 2024 Fair Value Quoted Prices in
Active Markets
(Level 1) Significant Other
Observable
Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3)
(in millions)
Assets:
Investments-equity securities $ - $ - $ - $ -
Investments-guaranteed income fund 1.1 - - 1.1
Investments-mutual funds and other 13.3 13.3 - -
Total investments 14.4 13.3 - 1.1
Derivative assets
0.7 - 0.7 -
Total assets $ 15.1 $ 13.3 $ 0.7 $ 1.1
Liabilities:
Derivative liabilities $ 0.1 $ - $ 0.1 $ -
Fair Value Measurements Using:
As of December 31, 2023 Fair Value Quoted Prices in Active Markets (Level 1) Significant Other
Observable
Inputs
(Level 2) Significant
Unobservable
Inputs
(Level 3)
(in millions)
Assets:
Investments-equity securities $ - $ - $ - $ -
Investments-guaranteed income fund 1.5 - - 1.5
Investments-mutual funds and other 10.8 10.8 - -
Total investments 12.3 10.8 - 1.5
Derivative assets 1.0 - 1.0 -
Total assets $ 13.3 $ 10.8 $ 1.0 $ 1.5
Liabilities:
Derivative liabilities $ 1.3 $ - $ 1.3 $ -
The changes in the fair value of our Level 3 investments for the years ended December 31, 2024 and 2023 were not material. Investment income from our Level 3 investments is reflected in other income (expense), net in the consolidated statements of income.
At December 31, 2024 and 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, 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 (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 2 measurement).
Chesapeake Utilities Corporation 2024 Form 10-K Page 82
Notes to the Consolidated Financial Statements
At December 31, 2024, long-term debt, which includes the current maturities but excludes debt issuance cost, had a carrying value of $1.3 billion, compared to the estimated fair value of $1.2 billion. At December 31, 2023, long-term debt, which includes the current maturities but excludes debt issuance costs, had both a carrying value and estimated fair value of $1.2 billion. 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 2 measurement.
See Note 16, Employee Benefit Plans, for fair value measurement information related to our pension plan assets.
10. GOODWILL AND OTHER INTANGIBLE ASSETS
The carrying value of goodwill as of December 31, 2024 and 2023 was as follows:
(in millions) Regulated Energy Unregulated Energy Total Goodwill
Balance at December 31, 2023 $ 468.7 $ 39.5 $ 508.2
Reductions (1)
(0.4) (0.1) (0.5)
Balance at December 31, 2024 $ 468.3 $ 39.4 $ 507.7
(1) Adjustments to goodwill in our Regulated Energy segment attributable to purchase accounting adjustments related to our acquisition of FCG in November 2023. Adjustments in the Unregulated Energy segment relate to the sale of certain assets in our propane distribution business during 2024. See Note 4 for additional details.
There were no goodwill impairments recognized during the three-year period ended December 31, 2024.
The carrying value and accumulated amortization of intangible assets subject to amortization as of December 31, 2024 and 2023 were as follows:
As of December 31,
2024 2023
(in millions) Gross
Carrying
Amount Accumulated
Amortization Gross
Carrying
Amount Accumulated
Amortization
Customer relationships $ 17.0 $ 8.2 $ 17.0 $ 7.1
Non-Compete agreements
3.1 2.3 3.1 1.9
Patents (1)
6.6 1.2 6.6 0.9
Other 0.3 0.3 0.3 0.2
Total $ 27.0 $ 12.0 $ 27.0 $ 10.1
(1) Includes amounts related to patented technology developed by Marlin Gas Services and the acquisition of Planet Found.
The customer relationships, non-compete agreements, patents and other intangible assets acquired in the purchases of the operating assets of several companies are being amortized over a weighted average of 14 years. Amortization expense of intangible assets for the year ended December 31, 2024, 2023 and 2022 was $1.9 million, $1.8 million and $1.5 million, respectively. Amortization expense of intangible assets is expected to be $1.8 million for 2025, $1.6 million for 2026, $1.5 million for 2027 and $1.3 million for 2028 through 2029.
11. INCOME TAXES
We file a consolidated federal income tax return. Income tax expense allocated to our subsidiaries is based upon their respective taxable incomes and tax credits. State income tax returns are filed on a separate company basis in most states where we have operations and/or are required to file. Our state returns for tax years after 2017 are subject to examination. At December 31, 2024, the 2015 through 2019 federal income tax returns are no longer under examination.
For state income tax purposes, we had NOL in various states of $99.3 million and $72.9 million as of December 31, 2024 and 2023, respectively, almost all of which will expire in 2040. Excluding NOL from discontinued operations, we have recorded deferred tax assets of $1.1 million and $1.8 million related to state NOL carry-forwards at December 31, 2024 and 2023,
Chesapeake Utilities Corporation 2024 Form 10-K Page 83
Notes to the Consolidated Financial Statements
respectively. We have not recorded a valuation allowance to reduce the future benefit of the tax NOL because we believe they will be fully utilized.
Tax Law Changes
In December 2017, the TCJA was signed into law. Substantially all of the provisions of the TCJA were effective for taxable years beginning on or after January 1, 2018. The provisions that significantly impacted us include the reduction of the corporate federal income tax rate from 35 percent to 21 percent. Our federal income tax expense for periods beginning on January 1, 2018 are based on the new federal corporate income tax rate. The TCJA included changes to the Internal Revenue Code, which materially impacted our 2017 financial statements. ASC 740, Income Taxes, requires recognition of the effects of changes in tax laws in the period in which the law is enacted. ASC 740 requires deferred tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. During 2018, we completed the assessment of the impact of accounting for certain effects of the TCJA. At the date of enactment in 2017, we re-measured deferred income taxes based upon the new corporate tax rate. See Note 18, Rates and Other Regulatory Activities, for further discussion of the TCJA's impact on our regulated businesses.
The following tables provide: (a) the components of income tax expense in 2024, 2023, and 2022; (b) the reconciliation between the statutory federal income tax rate and the Company's effective income tax rate for 2024, 2023, and 2022; and (c) the components of accumulated deferred income tax assets and liabilities at December 31, 2024 and 2023.
For the Year Ended December 31,
2024 2023 2022
(in millions)
Current Income Tax Expense
Federal $ 3.7 $ 14.7 $ 8.3
State 2.7 5.5 1.9
Other (0.4) - -
Total current income tax expense 6.0 20.2 10.2
Deferred Income Tax Expense (1)
Property, plant and equipment 33.2 17.8 15.0
Amortization of FCG goodwill 7.8 - -
Deferred gas costs (1.0) (7.7) 8.9
Pensions and other employee benefits (0.3) (1.0) 1.1
Net operating loss carryforwards (2.5) (0.4) -
Other - (0.8) (1.4)
Total deferred income tax expense 37.2 7.9 23.6
Total Income Tax Expense $ 43.2 $ 28.1 $ 33.8
(1) Includes $7.9 million, less than $0.1 million, and $7.8 million of deferred state income taxes for the years 2024, 2023, and 2022, respectively.
For the Year Ended December 31,
2024 2023 2022
(in millions)
Reconciliation of Effective Income Tax Rates
Federal income tax expense (1)
$ 34.0 $ 24.2 $ 26.0
State income taxes, net of federal benefit (2)
8.4 4.4 7.7
Other 0.8 (0.5) 0.1
Total Income Tax Expense $ 43.2 $ 28.1 $ 33.8
Effective Income Tax Rate 26.71 % 24.35 % 27.34 %
(1) Federal income taxes were calculated at 21 percent for 2024, 2023, and 2022.
(2) 2023 includes the impact of the one-time benefit associated with the reduction in the Pennsylvania state tax rate. See Item 7, Management’s Discussion and Analysis of Financial Condition and Results of Operations for an additional information.
Chesapeake Utilities Corporation 2024 Form 10-K Page 84
Notes to the Consolidated Financial Statements
As of December 31,
2024 2023
(in millions)
Deferred Income Taxes
Deferred income tax liabilities:
Property, plant and equipment $ 289.7 $ 252.1
Acquisition adjustment 5.2 5.6
Deferred gas costs 2.5 3.6
Natural gas conversion costs 4.6 4.8
Storm reserve liability 5.8 5.8
Intangible assets 6.4 -
Other 8.4 9.7
Total deferred income tax liabilities 322.6 281.6
Deferred income tax assets:
Pension and other employee benefits 5.1 5.0
Net operating loss carryforwards 1.1 1.8
Accrued expenses 4.0 3.3
Regulatory asset 6.0 4.1
Intangible assets - 2.8
Other 10.3 5.5
Total deferred income tax assets 26.5 22.5
Deferred Income Taxes $ 296.1 $ 259.1
Chesapeake Utilities Corporation 2024 Form 10-K Page 85
Notes to the Consolidated Financial Statements
12. LONG-TERM DEBT
Our outstanding long-term debt is shown below:
As of December 31,
(in millions) 2024 2023
Uncollateralized senior notes:
5.68% notes, due June 2026 $ 5.8 $ 8.7
6.39% notes, due December 2026 100.0 100.0
6.44% notes, due December 2027 100.0 100.0
6.43% notes, due May 2028 2.8 3.5
3.73% notes, due December 2028 8.0 10.0
6.45% notes, due December 2028 100.0 100.0
3.88% notes, due May 2029 25.0 30.0
5.20% notes, due October 2029 100.0 -
6.62% notes, due December 2030 100.0 100.0
3.25% notes, due April 2032 52.5 59.5
6.71% notes, due December 2033 100.0 100.0
2.98% notes, due December 2034 70.0 70.0
3.00% notes, due July 2035 50.0 50.0
2.96% notes, due August 2035 40.0 40.0
2.49% notes, due January 2037 50.0 50.0
5.43% notes, due March 2038 80.0 80.0
3.48% notes, due May 2038 50.0 50.0
3.58% notes, due November 2038 50.0 50.0
6.73% notes, due December 2038 50.0 50.0
3.98% notes, due August 2039 100.0 100.0
2.95% notes, due March 2042 50.0 50.0
Equipment security note
2.46% note, due September 2031 6.7 7.6
Less: debt issuance costs (3.6) (3.7)
Total long-term debt 1,287.2 1,205.6
Less: current maturities (25.5) (18.5)
Total long-term debt, net of current maturities $ 1,261.7 $ 1,187.1
Terms of the Senior Notes
All of our outstanding Senior 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.
Senior Notes
On November 1, 2024, we issued 5.20 percent Senior Notes due in November 2029 in the aggregate principal amount of $100.0 million. The proceeds received were used to reduce short-term borrowings under our Revolver and to fund capital expenditures. These Senior Notes have similar covenants and default provisions as our other Senior Notes, and have semi-annual interest payments due on May 1 and November 1 of each year beginning in 2025.
On November 20, 2023, we issued Senior Notes in the aggregate principal amount of $550.0 million at an average interest rate of 6.54 percent that were used to partially finance our acquisition of FCG. These notes have varying maturity dates of between three and 15 years, and the outstanding principal balance of the notes (net of annual payments on the 6.73 percent notes which begin in 2029) will be due on their respective maturity dates with interest payments payable semiannually until the principal has been paid in full. These Senior Notes have similar covenants and default provisions as our other Senior Notes.
Chesapeake Utilities Corporation 2024 Form 10-K Page 86
Notes to the Consolidated Financial Statements
On March 14, 2023, we issued 5.43 percent Senior Notes due in March 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 and to fund capital expenditures. These Senior Notes have similar covenants and default provisions as our other Senior Notes, and have an annual principal amortization payment beginning in the sixth year after the issuance.
Annual Maturities
Annual maturities and principal repayments of long-term debt are as follows:
Year 2025 2026 2027 2028 2029 Thereafter Total
(in millions)
Payments $ 25.5 $ 134.6 $ 131.7 $ 136.7 $ 157.0 $ 705.3 $ 1,290.8
Shelf Agreements
We have entered into Shelf Agreements with Prudential and MetLife with terms that extend through February 2026, however neither of such lenders have any obligation to purchase debt thereunder. At December 31, 2024, a total of $255.0 million of borrowing capacity was available under these agreements.
13. SHORT-TERM BORROWINGS
As of December 31, 2024, we are authorized by our Board of Directors to borrow up to $450.0 million of short-term debt, as required. At December 31, 2024 and 2023, we had $196.5 million and $179.9 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 5.06 percent and 5.83 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at December 31, 2024.
In August 2024, we amended and restated our revolving credit agreement, which increased the total borrowing capacity under the Revolver to $450.0 million, including $250.0 million available under the 364-day tranche which now expires in August 2025 and $200.0 million available under the five-year tranche which now expires in August 2029. We may also request increases under the Revolver of up to $50.0 million under the 364-day tranche and up to $100.0 million under the five-year tranche, with the lenders having sole discretion of whether to approve each requested increase. Borrowings under both tranches of the Revolver continue to be 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. The 364-day tranche continues to bear interest (i) based upon the SOFR, plus a 10-basis point credit spread adjustment, and an applicable margin of 1.05 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate, solely at our discretion. The five-year tranche continues to bear interest (i) based upon the SOFR, plus a 10-basis point credit spread adjustment, and an applicable margin of 1.25 percent or less, with such margin based on total indebtedness as a percentage of total capitalization or (ii) the base rate, solely at our discretion.
We also utilize interest rate swaps to manage rate risk under our Revolver. For additional information on interest rate swaps, including swaps currently in place related to our short-term borrowings, see Note 8, Derivative Instruments.
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 December 31, 2024, we are in compliance with this covenant.
Our total available credit under the Revolver at December 31, 2024 was $250.0 million. As of December 31, 2024, we had issued $6.9 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 drawn upon by the counterparties. The letters of credit reduce the available borrowings under the Revolver.
In connection with our acquisition of FCG, we entered into a 364-day Bridge Facility commitment with Barclays Bank PLC and other lending parties for up to $965.0 million. Upon closing of the FCG acquisition in November 2023, and with the completion of other financing activities as defined in the lending agreement, this facility was terminated with no funds drawn to finance the transaction. For additional information regarding the acquisition and related financing, see Note 4, Acquisitions, Note 12, Long-Term Debt and Note 15, Stockholders Equity.
Chesapeake Utilities Corporation 2024 Form 10-K Page 87
Notes to the Consolidated Financial Statements
14. 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. 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 December 31, 2024, 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 December 31, 2024, 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:
Year Ended December 31,
(in millions) Classification 2024 2023 2022
Operating lease cost (1)
Operations expense $ 3.0 $ 3.0 $ 2.9
(1) Includes short-term leases and variable lease costs, which are not material.
The following table presents the balance and classifications of our right of use assets and lease liabilities included in our consolidated balance sheets at December 31, 2024 and 2023:
(in millions) Balance sheet classification December 31, 2024 December 31, 2023
Assets
Operating lease assets Operating lease right-of-use assets $ 10.5 $ 12.4
Liabilities
Current
Operating lease liabilities Other accrued liabilities $ 2.4 $ 2.4
Noncurrent
Operating lease liabilities Operating lease - liabilities 8.7 10.6
Total lease liabilities $ 11.1 $ 13.0
The following table presents our weighted-average remaining lease term and weighted-average discount rate for our operating leases at December 31, 2024 and 2023:
December 31, 2024 December 31, 2023
Weighted-average remaining lease term (in years)
Operating leases 7.7 8.1
Weighted-average discount rate
Operating leases 3.5 % 3.5 %
The following table presents additional information related to cash paid for amounts included in the measurement of lease liabilities included in our consolidated statements of cash flows at December 31, 2024, 2023 and 2022:
Chesapeake Utilities Corporation 2024 Form 10-K Page 88
Notes to the Consolidated Financial Statements
Year Ended December 31,
(in millions) 2024 2023 2022
Operating cash flows from operating leases $ 2.9 $ 2.9 $ 2.9
The following table presents the future undiscounted maturities of our operating and financing leases at December 31, 2024 and for each of the next five years and thereafter:
(in millions) Operating Leases (1)
2025 $ 2.6
2026 1.9
2027 1.6
2028 1.2
2029 1.1
Thereafter 4.1
Total lease payments 12.5
Less: Interest (1.4)
Present value of lease liabilities $ 11.1
(1) Operating lease payments include $2.0 million related to options to extend lease terms that are reasonably certain of being exercised.
15. STOCKHOLDERS' EQUITY
Common Stock Issuances
In November 2023, in connection with our acquisition of FCG, we completed an overnight offering resulting in the issuance of 4.4 million shares of our common stock at a price per share of $82.72 (net of underwriter discounts and commissions). We received net proceeds of $366.4 million which were used to partially finance the acquisition.
We maintain an effective shelf registration statement with the SEC for the issuance of shares under our DRIP and other plans. Depending on our capital needs and subject to market conditions, we may issue additional shares under the direct stock purchase component of the DRIP in addition to other possible debt and equity offerings. For the year ended December 31, 2024, we received net proceeds of $72.5 million associated with shares issued under the direct stock purchase and waiver components of the DRIP. There were no issuances under the DRIP in 2023. In November 2024, we established a new ATM program under which we may sell shares of our common stock up to an aggregate offering price of $100.0 million. This current ATM program is active through November 2027 and there were no issuances under the program in 2024. Our previous ATM equity program, which allowed us to issue and sell shares of our common stock up to an aggregate offering price of $75.0 million, expired in June 2023.
Accumulated Other Comprehensive Income (Loss)
Defined benefit pension and postretirement plan items, unrealized gains (losses) of our propane swap agreements designated as commodity contract 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 balances of accumulated other comprehensive income (loss) components for the years ended December 31, 2024 and 2023. All amounts in the following tables are presented net of tax.
Chesapeake Utilities Corporation 2024 Form 10-K Page 89
Notes to the Consolidated Financial Statements
Defined Benefit Pension and Postretirement Plan Items Commodity Contract Cash Flow Hedges Interest Rate Swap Cash Flow Hedges Total
(in millions)
As of December 31, 2022 $ (2.5) $ 1.1 $ - $ (1.4)
Other comprehensive income (loss) before reclassifications (0.1) (1.4) 0.5 (1.0)
Amounts reclassified from accumulated other comprehensive income (loss) - - (0.4) (0.4)
Net current-period other comprehensive income (loss) (0.1) (1.4) 0.1 (1.4)
As of December 31, 2023 (2.6) (0.3) 0.1 (2.8)
Other comprehensive income (loss) before reclassifications 0.5 1.4 0.5 2.4
Amounts reclassified from accumulated other comprehensive income (loss) - (0.7) (0.6) (1.3)
Net current-period other comprehensive income (loss) 0.5 0.7 (0.1) 1.1
As of December 31, 2024 $ (2.1) $ 0.4 $ - $ (1.7)
Deferred gains or losses for our commodity contract and interest rate swap cash flow hedges are recognized in earnings upon settlement and are included in the effects of gains and losses from derivative instruments. See Note 8, Derivative Instruments, for additional details. Amortization of the net loss related to the defined benefit pension plan and postretirement plans is included in the computation of net periodic costs (benefits). See Note 16, Employee Benefit Plans, for additional details.
16. EMPLOYEE BENEFIT PLANS
We measure the assets and obligations of the defined benefit pension plans and other postretirement benefits plans to determine the plans’ funded status as of the end of the year. The changes in funded status that occurred during the year that are not recognized as part of net periodic benefit costs are recorded as a component of other comprehensive income (loss) or a regulatory asset.
Defined Benefit Pension Plans
At December 31, 2024 we sponsored two defined benefit pension plans: the FPU Pension Plan and the Chesapeake Supplemental Executive Retirement Plan ("SERP").
The FPU Pension Plan, a qualified plan, covers eligible FPU non-union employees hired before January 1, 2005 and union employees hired before the respective union contract expiration dates in 2005 and 2006. The FPU Pension Plan was frozen with respect to additional years of service and compensation, effective December 31, 2009.
The Chesapeake SERP, a nonqualified plan, is comprised of two sub-plans. The first sub-plan was frozen with respect to additional years of service and additional compensation as of December 31, 2004. The second sub-plan provides fixed payments for several executives who joined the Company as a result of an acquisition and whose agreements with the Company provided for this benefit.
The unfunded liability for all plans at both December 31, 2024 and 2023, is included in the other pension and benefit costs liability in our consolidated balance sheets.
Chesapeake Utilities Corporation 2024 Form 10-K Page 90
Notes to the Consolidated Financial Statements
The following schedules set forth the funded status at December 31, 2024 and 2023 and the net periodic cost (benefit) for the years ended December 31, 2024, 2023 and 2022 for the FPU Pension Plan and the Chesapeake SERP:
FPU
Pension Plan Chesapeake
SERP
2024 2023 2024 2023
(in millions)
Change in benefit obligation:
Benefit obligation - beginning of year $ 49.7 $ 49.9 $ 1.6 $ 1.7
Interest cost 2.4 2.5 0.1 0.1
Actuarial (gain) loss (2.0) 0.5 - -
Benefits paid (4.6) (3.2) (0.2) (0.2)
Benefit obligation - end of year 45.5 49.7 1.5 1.6
Change in plan assets:
Fair value of plan assets - beginning of year 49.5 46.2 - -
Actual return on plan assets 4.2 6.5 - -
Employer contributions - - 0.2 0.2
Benefits paid (4.6) (3.2) (0.2) (0.2)
Fair value of plan assets - end of year 49.1 49.5 - -
Accrued pension funded status $ 3.6 $ (0.2) $ (1.5) $ (1.6)
Assumptions:
Discount rate 5.50 % 5.00 % 5.40 % 4.88 %
Expected return on plan assets 6.00 % 6.00 % - % - %
FPU
Pension Plan Chesapeake
SERP
For the Years Ended December 31, 2024 2023 2022 2024 2023 2022
(in millions)
Components of net periodic pension (benefit) cost:
Interest cost $ 2.4 $ 2.5 $ 1.8 $ 0.1 $ 0.1 $ 0.1
Expected return on assets (2.9) (2.7) (3.4) - - -
Amortization of actuarial loss 0.3 0.4 0.5 - - -
Total periodic (benefit) cost $ (0.2) $ 0.2 $ (1.1) $ 0.1 $ 0.1 $ 0.1
Assumptions:
Discount rate 5.00 % 5.25 % 2.75 % 4.88 % 5.00 % 2.50 %
Expected return on plan assets 6.00 % 6.00 % 6.00 % - % - % - %
Chesapeake Utilities Corporation 2024 Form 10-K Page 91
Notes to the Consolidated Financial Statements
Our funding policy provides that payments to the trust of each qualified plan shall be equal to at least the minimum funding requirements of the Employee Retirement Income Security Act of 1974. The following schedule summarizes the allocation of assets of the FPU Pension Plan, by investment type, at December 31, 2024, 2023 and 2022:
FPU Pension Plan
At December 31, 2024 2023 2022
Asset Category
Equity securities 31 % 50 % 53 %
Debt securities 67 49 38
Other 2 1 9
Total 100 % 100 % 100 %
The investment policy of the FPU Pension Plan is designed to provide the capital assets necessary to meet the financial obligations of the plan. The investment goals and objectives are to achieve investment returns that, together with contributions, will provide funds adequate to pay promised benefits to present and future beneficiaries of the plan, earn a competitive return to increasingly fund a large portion of the plan’s retirement liabilities, minimize pension expense and cumulative contributions resulting from liability measurement and asset performance, and maintain the appropriate mix of investments to reduce the risk of large losses over the expected remaining life of the plan.
The following target allocation of asset classes is intended to produce a rate of return sufficient to meet the FPU Pension Plan’s goals and objectives:
Asset Allocation Strategy
Asset Class Target Range (+/-)
Domestic Equities (Large Cap, Mid Cap and Small Cap) 27 % 7 %
Fixed Income (Inflation Bond and Taxable Fixed) 68 % 4 %
Foreign Equities (Developed and Emerging Markets) 3 % 1 %
Cash 2 % 2 %
Due to periodic contributions and different asset classes producing varying returns, the actual asset values may temporarily move outside of the intended ranges. The investments are monitored on a quarterly basis, at a minimum, for asset allocation and performance.
Chesapeake Utilities Corporation 2024 Form 10-K Page 92
Notes to the Consolidated Financial Statements
At December 31, 2024 and 2023, the assets of the FPU Pension Plan were comprised of the following investments:
As of December 31,
Asset Category 2024 2023
(in millions)
Mutual Funds - Equity securities
U.S. Large Cap (1)
$ 10.6 $ 15.4
U.S. Mid Cap (1)
3.2 4.3
U.S. Small Cap (1)
- 2.5
International (2)
1.3 2.5
15.1 24.7
Mutual Funds - Debt securities
Fixed income (3)
32.8 24.2
32.8 24.2
Mutual Funds - Other
Guaranteed deposit (4)
1.2 0.6
1.2 0.6
Total Pension Plan Assets at fair value (5)
$ 49.1 $ 49.5
(1) Includes funds that invest primarily in United States common stocks.
(2) Includes funds that invest primarily in foreign equities and emerging markets equities.
(3) Includes funds that invest in fixed income securities.
(4) Includes investment in a group annuity product issued by an insurance company.
(5) All investments in the FPU Pension Plan are classified as Level 1 within the Fair Value hierarchy exclusive of the Guaranteed Deposit Account which is classified as Level 3.
At December 31, 2024 and 2023, our pension plan investments were classified under the same fair value measurement hierarchy (Level 1 through Level 3) described under Note 9, Fair Value of Financial Instruments. The Level 3 investments were recorded at fair value based on the contract value of annuity products underlying guaranteed deposit accounts, which was calculated using discounted cash flow models. The contract value of these products represented deposits made to the contract, plus earnings at guaranteed crediting rates, less withdrawals and fees. Certain investments that were measured at net asset value per share have not been classified in the fair value hierarchy and are presented in the table above to reconcile to total pension plan assets.
The changes in the fair value within our pension assets for Level 3 investments for the years ended December 31, 2024 and 2023 were not material.
Other Postretirement Benefits Plans
We sponsor two unfunded defined benefit postretirement health plans: the Chesapeake Utilities Postretirement Plan ("Chesapeake Postretirement Plan") and the FPU Medical Plan. At December 31, 2024 and 2023, the total obligation of the Chesapeake Postretirement Plan was $0.9 million and $1.1 million, respectively. The total obligation of the FPU Medical Plan was $0.3 million and $0.4 million as of December 31, 2024 and 2023, respectively.
Net periodic postretirement benefit costs for the Chesapeake Postretirement Plan and the FPU Medical Plan were not material for the years ended December 31, 2024, 2023, and 2022.
Amounts Not Yet Reflected in Periodic Benefit Cost
As of December 31, 2024, there was $9.2 million not yet reflected in net periodic postretirement benefit costs and included in accumulated other comprehensive income (loss) or as a regulatory asset. Net losses of $7.1 million and $1.3 million attributable to the FPU Pension Plan and Chesapeake Postretirement Plan, respectively, comprised most of this amount with $2.6 million recorded in accumulated other comprehensive income (loss) and $5.8 million recorded as a regulatory asset at December 31, 2024.
Pursuant to a Florida PSC order, FPU continues to record as a regulatory asset the portion of the unrecognized pension and postretirement benefit costs after the merger with Chesapeake Utilities related to its regulated operations.
Chesapeake Utilities Corporation 2024 Form 10-K Page 93
Notes to the Consolidated Financial Statements
Assumptions
The assumptions used for the discount rate to calculate the benefit obligations were based on the interest rates of high-quality bonds in 2024, considering the expected lives of each of the plans. In determining the average expected return on plan assets for the FPU Pension Plan, various factors, such as historical long-term return experience, investment policy and current and expected allocation, were considered. Since the FPU Pension Plan is frozen with respect to additional years of service and compensation, the rate of assumed compensation increases is not applicable.
The health care inflation rate for 2024 used to calculate the benefit obligation is 5 percent for medical and 6 percent for prescription drugs for the Chesapeake Postretirement Plan; and 5 percent for both medical and prescription drugs for the FPU Medical Plan.
Estimated Future Benefit Payments
In 2025, we do not expect to contribute to the FPU Pension Plan, and total payments of $0.3 million are expected for the Chesapeake SERP, Chesapeake Postretirement Plan and FPU Medical Plan combined.
The schedule below shows the estimated future benefit payments for the FPU Pension Plan. Estimated payments related to the Chesapeake SERP, Chesapeake Postretirement Plan and FPU Medical Plan are not material.
FPU Pension
Plan (1)
(in millions)
2025 $ 3.6
2026 $ 3.7
2027 $ 3.6
2028 $ 3.7
2029 $ 3.6
Years 2030 through 2034 $ 17.6
(1) The pension plan is funded; therefore, benefit payments are expected to be paid out of the plan assets.
Retirement Savings Plan
We sponsor a 401(k) Retirement Savings Plan which is offered to all eligible employees who have completed three months of service. We match 100 percent of eligible participants’ pre-tax contributions to the Retirement Savings Plan up to a maximum of six percent of eligible compensation. The employer matching contribution is made in cash and is invested based on a participant’s investment directions. In addition, we may make a discretionary supplemental contribution to participants in the plan, without regard to whether or not they make pre-tax contributions. Any supplemental employer contribution is generally made in our common stock. With respect to the employer match and supplemental employer contribution, employees are 100 percent vested after two years of service or upon reaching 55 years of age while still employed by us. New employees who do not make an election to contribute and do not opt out of the Retirement Savings Plan will be automatically enrolled at a deferral rate of three percent, and the automatic deferral rate will increase by one percent per year up to a maximum of ten percent. All contributions and matched funds can be invested among the mutual funds available for investment.
Employer contributions to our Retirement Savings Plan totaled $8.4 million, $6.6 million, and $6.2 million for the years ended December 31, 2024, 2023 and 2022, respectively. As of December 31, 2024, there were 788,495 shares of our common stock reserved to fund future contributions to the Retirement Savings Plan.
Non-Qualified Deferred Compensation Plan
Members of our Board of Directors and officers of the Company are eligible to participate in the Non-Qualified Deferred Compensation Plan. Directors can elect to defer any portion of their cash or stock compensation and officers can defer up to 80 percent of their 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 six percent of their compensation, provided it does not duplicate a match they receive in the Retirement Savings Plan. Stock bonuses are not eligible for matching contributions. Participants are able to elect the payment of deferred compensation to begin on a specified future date or upon separation from service. Additionally, participants can elect to receive payments upon the earlier or later of a fixed date or separation from service. The payments can be made in one lump sum or annual installments for up to 15 years.
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 cash compensation may be invested by the participants
Chesapeake Utilities Corporation 2024 Form 10-K Page 94
Notes to the Consolidated Financial Statements
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. Deferred stock compensation may not be diversified. The participants are credited with dividends on their deferred common stock units in the same amount that is received by all other stockholders. Such dividends are reinvested into additional deferred common stock units. Assets held in the Rabbi Trust, recorded as Investments on the consolidated balance sheets, had a fair value of $14.4 million and $12.3 million at December 31, 2024 and 2023, respectively. The assets of the Rabbi Trust are at all times subject to the claims of our general creditors.
Deferrals of officer base compensation and cash bonuses and directors’ cash retainers are paid in cash. All deferrals of executive performance shares and directors' stock retainers are made in the form of deferred common stock units and are paid out in shares of our common stock, on a one-for-one basis, except that cash is paid in lieu of fractional shares. The value of our stock held in the Rabbi Trust is classified within the stockholders’ equity section of the consolidated balance sheets and has been accounted for in a manner similar to treasury stock. The amounts recorded under the Non-Qualified Deferred Compensation Plan totaled $9.8 million and $9.1 million at December 31, 2024 and 2023, respectively, which are also shown as a deduction against stockholders' equity in the consolidated balance sheets.
17. SHARE-BASED COMPENSATION PLANS
Our key employees and non-employee directors have been granted share-based awards through our SICP, which has awards outstanding under the current 2023 plan and the previous 2013 plan. 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 expected to be issued at the end of the service period. We have 524,579 shares of common stock reserved for issuance under the SICP.
The table below presents the amounts included in net income related to share-based compensation expense for the awards granted under the SICP for the years ended December 31, 2024, 2023 and 2022:
For the Year Ended December 31,
2024 2023 2022
(in millions)
Awards to key employees $ 7.5 $ 6.7 $ 5.5
Awards to non-employee directors 0.9 0.9 1.0
Total compensation expense 8.4 7.6 6.5
Less: tax benefit (2.2) (1.9) (1.7)
Share-based compensation expense included in net income $ 6.2 $ 5.7 $ 4.8
Officers and Key Employees
Our Compensation Committee is authorized to grant 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 and key employees of the Company, contingent upon various performance goals and subject to SEC transfer restrictions.
We currently have several outstanding multi-year performance awards under various plans, which are based 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. For the market-based conditions, we used a Monte Carlo valuation to estimate the fair value of each share granted.
Chesapeake Utilities Corporation 2024 Form 10-K Page 95
Notes to the Consolidated Financial Statements
The table below presents the summary of the stock activity for awards to all officers and key employees:
(in thousands, except per share data) Number of
Shares Weighted Average
Fair Value
Outstanding - December 31, 2022
204 $ 103.17
Granted 81 126.06
Vested (68) 91.59
Expired (2) 94.64
Forfeited (2) 113.44
Outstanding - December 31, 2023
213 117.74
Granted 110 105.21
Vested (43) 103.95
Expired (27) 86.24
Forfeited - -
Outstanding - December 31, 2024
253 $ 117.96
During the year ended December 31, 2024, we granted awards of 110 thousand shares of common stock to officers and key employees under the SICP, including awards granted in February 2024. The shares granted are multi-year awards that will vest no later than the three-year service period ending December 31, 2026.
The aggregate intrinsic value of the SICP awards granted was $30.8 million, $22.5 million, and $24.1 million at December 31, 2024, 2023 and 2022, respectively. At December 31, 2024, there was $6.1 million of unrecognized compensation cost related to these awards, which is expected to be recognized through 2026.
In March 2024, 2023 and 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 March 2024, 2023 and 2022 for the performance periods ended December 31, 2023, 2022, and 2021. We paid the balance of such awarded shares to each such executive officer and remitted the cash equivalent of the withheld shares to the appropriate taxing authorities. The below table presents the number of shares withheld and amounts remitted:
For the Year Ended December 31,
2024 2023 2022
(dollars in millions, shares in thousands)
Shares withheld to satisfy tax obligations 14 20 22
Amounts remitted to tax authorities to satisfy obligations $ 1.5 $ 2.5 $ 2.8
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 or less.
Our directors receive an annual retainer of shares of common stock under the SICP for services rendered through the subsequent Annual Meeting of Stockholders. Accordingly, our directors that served on the Board as of May 2024 and 2023 each received 995 and 765 shares of common stock, respectively, with a weighted average fair value of $110.53 and $124.12 per share, respectively.
At December 31, 2024, there was $0.3 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 2025.
Chesapeake Utilities Corporation 2024 Form 10-K Page 96
Notes to the Consolidated Financial Statements
18. 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 subsidiaries, are subject to regulation (excluding cost of service) by the Florida PSC and Public Utilities Commission of Ohio, respectively.
Delaware
In September 2023, the Delaware Division submitted the Energy Efficiency Rider application for natural gas with the Delaware PSC after obtaining an affirmative recommendation from the Delaware Energy Efficiency Advisory Council (“EEAC”). The application is the first in the state and applies to a portfolio of four programs which customers can participate (and allow for recovery), including Home Energy Counseling, Home Performance with Energy Star, Assisted Home Performance with Energy Star, and a standard Offer Program. In April 2024, all programs, with the exception of the Offer Program, were approved by the PSC and rates became effective May 1, 2024.
Delaware Natural Gas Rate Case: In August 2024, our Delaware natural gas division filed an application for a natural gas rate case with the Delaware PSC. In connection with the application, we are seeking approval of the following: (i) permanent rate relief of approximately $12.1 million with a ROE of 11.5 percent; (ii) proposed changes to depreciation rates which were part of a depreciation study also submitted with the filing; and (iii) authorization to make certain changes to tariffs. Annualized interim rates were approved by the Delaware PSC in the amount of $2.5 million and became effective in October 2024. The hearing for the proceeding has been scheduled for May 2025, and the outcome of the application is subject to review and approval by the Delaware PSC.
Maryland
Maryland Natural Gas Rate Case: In January 2024, our natural gas distribution businesses in Maryland, CUC-Maryland Division, Sandpiper Energy, Inc., and Elkton Gas Company (collectively, “Maryland natural gas distribution businesses”) filed a joint application for a natural gas rate case with the Maryland PSC. In connection with the application, we sought approval of the following: (i) permanent rate relief of approximately $6.9 million with a ROE of 11.5 percent; (ii) authorization to make certain changes to tariffs to include a unified rate structure and to consolidate the Maryland natural gas distribution businesses (CUC-Maryland Division, Sandpiper Energy, and Elkton Gas) which we anticipate will be called Chesapeake Utilities of Maryland, Inc.; and (iii) authorization to establish a rider for recovery of the costs associated with our new technology systems. In August 2024, the Maryland natural gas distribution businesses, the Maryland Office of Peoples' Counsel ("OPC") and PSC Staff reached a settlement agreement which provided for, among other things, an increase in annual base rates of $2.6 million. In September 2024, the Maryland Public Utility Judge issued an order approving the settlement agreement in part. The $2.6 million increase in annual base rates was approved and the Company filed the Phase II filing in November 2024 to determine rate design across the Maryland natural gas distribution businesses, consolidation of the applicable tariffs and recovery of technology costs. The hearing has been scheduled for March 2025 and the outcome of the application is subject to review and approval by the Maryland PSC.
Maryland Natural Gas Depreciation Study: In January 2024, our Maryland natural gas distribution businesses filed a joint petition for approval of their proposed unified depreciation rates with the Maryland PSC. A settlement agreement between the Company, PSC staff and the OPC was reached and the final order approving the settlement agreement went into effect in July 2024, with new depreciation rates effective as of January 1, 2023. The approved depreciation resulted in an annual reduction in depreciation expense of approximately $1.2 million.
Florida
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, Florida. The project enables us to meet the significant growing demand for service in Yulee, Florida. The agreement enables us to construct the project during the 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 gas injection interconnect with associated facilities. Phase two will consist of two additional pipeline extensions. The various phases of the project commenced in the first quarter of 2023, with construction on the overall project continuing through 2025. The petition was approved by the Florida PSC in November 2022.
Chesapeake Utilities Corporation 2024 Form 10-K Page 97
Notes to the Consolidated Financial Statements
FCG Natural Gas Rate Case: In May 2022, FCG filed a general base rate increase with the Florida PSC based on a projected 2023 test year. In June 2023, the Florida PSC issued an order approving a single total base revenue increase of $23.3 million (which included an incremental increase of $14.1 million, a previously approved increase of $3.8 million for a liquefied natural gas facility, and $5.3 million to transfer the SAFE investments from a rider clause to base rates), with new rates becoming effective as of May 1, 2023. The Florida PSC also approved FCG's proposed RSAM with a $25.0 million reserve amount, continuation and expansion of the capital SAFE program, implementation of an automated metering infrastructure pilot, and continuation of the storm damage reserve with a target reserve of $0.8 million. In June 2023, the Florida OPC filed a motion for reconsideration of the PSC’s approval of RSAM, which was denied in September 2023. In July 2023, the Florida OPC filed a notice of appeal with the Florida Supreme Court, which is pending. The Florida OPC filed their initial brief in January 2024 with answer briefs filed in April 2024. Oral arguments in the case were held in December 2024.
The RSAM is recorded as either an increase or decrease to accrued removal costs which is reflected on the Company’s balance sheets and a corresponding increase or decrease to depreciation and amortization expense. In order to earn the targeted regulatory ROE in each reporting period subject to the conditions of the effective rate agreement, RSAM is calculated using a trailing thirteen-month average of rate base and capital structure in conjunction with the trailing twelve month regulatory base net operating income, which primarily includes the base portion of rates and other revenues, net of operations and maintenance expenses, depreciation and amortization, interest and tax expenses. In general, the net impact of these income statement line items is adjusted, in part, by RSAM or its reversal to earn the targeted regulatory ROE. For the year ended December 31, 2024 and 2023, the Company recorded decreases to asset removal costs and depreciation expense of $15.5 million and $5.1 million, respectively, as a result of the RSAM adjustment. At December 31, 2024, the RSAM reserve had been completely utilized.
In February 2025, FCG filed a depreciation study with the Florida PSC. The application is requesting approval of revised annual depreciation rates, as well as a reduction related to a reserve imbalance that would be amortized over a two-year period. The outcome of the application is subject to review and approval by the Florida PSC.
Storm Protection Plan: In 2020, the Florida PSC implemented the Storm Protection Plan ("SPP") and Storm Protection Plan Cost Recovery Clause ("SPPCRC") rules, which requires 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 SPPCRC rules allow the utility to file for recovery of associated costs for the SPP. Our Florida electric distribution operations' SPP was filed during the first quarter of 2022 and approved in the fourth quarter of 2022, with modifications, by the Florida PSC. Rates associated with this initiative were effective in January 2023. The Florida PSC voted to approve the projections in November 2023. In October 2024, the Florida PSC approved the Company's projected 2025 SPP costs of $20.4 million for both capital and operating expenses.
GUARD: In February 2023, FPU filed a petition with the Florida PSC for approval of the GUARD program. GUARD is a ten-year program to enhance the safety, reliability, and accessibility of portions of our natural gas distribution system. We identified various categories of projects to be included in GUARD, which include 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 maintenance and repair equipment and system reliability projects. In August 2023, the Florida PSC approved the GUARD program, which included $205.0 million of capital expenditures projected to be spent over a 10-year period.
FCG SAFE Program: In June 2023, the Florida PSC issued the approval order for the continuation of the SAFE program beyond its 2025 expiration date and inclusion of 150 miles of additional mains and services located in rear property easements. The SAFE program is designed to relocate certain mains and facilities associated with rear lot easements to street front locations to improve FCG's ability to inspect and maintain the facilities and reduce opportunities for damage and theft. In the same order, the Florida PSC approved a replacement of 160 miles of pipe that was used in the 1970s and 1980s and shown through industry research to exhibit premature failure in the form of cracking. The program includes projected capital expenditures of $205.0 million over a 10-year period.
In April 2024, FCG filed a petition with the Florida PSC to more closely align the SAFE Program with FPU's GUARD program. Specifically, the requested modifications will enable FCG to accelerate remediation related to problematic pipes and facilities consisting of obsolete and exposed pipes. These efforts will serve to improve the safety and reliability of service to FCG's customers and the modifications will increase the total projected capital expenditures to $50.0 million in capital expenditures associated with the SAFE Program, which would increase the total projected capital expenditures to approximately $255.0 million over a 10-year period. The Florida PSC approved the modifications in September 2024.
Newberry Expansion: In April 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreement with FPU for an additional 8,000 Dt/d of firm service in the Newberry, Florida area. The petition was approved by the Florida PSC in the third quarter of 2023. Peninsula Pipeline will construct a pipeline extension, which will be used by FPU to support the development of a natural gas distribution system to provide gas service to the City of Newberry. A filing to address the acquisition and conversion of existing Company owned propane community gas systems in Newberry was made in November 2023. The Florida PSC approved it in April 2024, and conversions of the community gas systems commenced in the second quarter of 2024.
Chesapeake Utilities Corporation 2024 Form 10-K Page 98
Notes to the Consolidated Financial Statements
East Coast Reinforcement Projects: In December 2023, Peninsula Pipeline filed a petition with the Florida PSC for approval of its Transportation Service Agreements with FPU for projects that will support additional supply to communities on the East Coast of Florida. The projects are driven by the need for increased supply to coastal portions of the state that are experiencing significant population growth. Peninsula Pipeline will construct several pipeline extensions which will support FPU’s distribution system in the areas of Boynton Beach and New Smyrna Beach with an additional 15,000 Dts/d and 3,400 Dts/d, respectively. The Florida PSC approved the projects in March 2024. Construction is projected to be complete in the second and fourth quarters of 2025 for New Smyrna Beach and Boynton Beach, respectively.
Central Florida Reinforcement Projects: In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for its Transportation Service Agreements with FPU for projects that will support additional supply to communities located in Central Florida. The projects are driven by the need for increased supply to communities in central Florida that are experiencing significant population growth. Peninsula Pipeline will construct several pipeline extensions which will support FPU's distribution system around the Plant City and Lake Mattie areas of Florida with an additional 5,000 Dts/d and 8,700 Dts/d, respectively. The Florida PSC approved the projects in May 2024. The Plant City project was completed in the fourth quarter of 2024, and the Lake Mattie project is projected to be completed during the fourth quarter of 2025.
Renewable Natural Gas Supply Projects: In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of Transportation Service Agreements with FCG for projects that will support the transportation of additional renewable energy supply to FCG. The projects, located in Florida’s Brevard, Indian River and Miami-Dade counties, will bring renewable natural gas produced from local landfills into FCG’s natural gas distribution system. Peninsula Pipeline will construct several pipeline extensions which will support FCG's distribution system in Brevard County, Indian River County, and Miami-Dade County. Benefits of these projects include increased gas supply to serve expected FCG growth, strengthened system reliability and additional system flexibility. The Florida PSC approved the petition at its July 2024 meeting with the projects estimated to be completed in the first half of 2025.
St. Cloud Project Amendment: In February 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of an amendment to its Transportation Service Agreement with FPU for a project that will support additional supply to communities in the St. Cloud, Florida area. The project is driven by the need to expand gas service to future communities that are expected in that area. Peninsula Pipeline will construct pipeline expansions that will allow FPU to serve the expected new growth. The expansion will provide FPU with an additional 10,000 Dts/d. The Florida PSC approved the project in May 2024, and it is expected to be complete in the fourth quarter of 2025.
Pioneer Supply Header Pipeline Project: In March 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of Firm Transportation Service Agreements with both FCG and FPU for a project that will support greater supply growth of natural gas service in southeast Florida. The project consists of the transfer of a pipeline asset from FCG to Peninsula Pipeline. Peninsula Pipeline will proceed to provide transportation service to both FCG and FPU using the pipeline asset, which supports continued customer growth and system reinforcement of these distribution systems. The Florida PSC approved the petition in July 2024 and the project was completed in September 2024.
Miami Inner Loop Projects: In September 2024, Peninsula Pipeline filed a petition with the Florida PSC for approval of the Transportation Service Agreement with FCG for a series of projects that will enhance the infrastructure in Miami-Dade County. The proposed expansion consists of the development of several pipeline projects to support growth and support FCG's distribution system in the area and also enhance FCG's ability to obtain gas from various access points in the Miami-Dade County area. The project was approved in February 2025.
FPU Electric Rate Case: In August 2024, our Florida Electric division filed a petition with the Florida PSC seeking a general base rate increase of $12.6 million with a ROE of 11.3 percent based on a 2025 projected test year. Annualized interim rates of approximately $1.8 million, were approved with an effective date of November 1, 2024. The outcome of the application is subject to review and approval by the Florida PSC. The hearings for the approval of the revenue requirement and rates are scheduled to occur in March 2025.
Eastern Shore
Worcester Resiliency Upgrade: In August 2023, Eastern Shore filed an application with the FERC requesting authorization to construct the Worcester Resiliency Upgrade, which consists of a mixture of storage and transmission facilities in Sussex County, DE and Wicomico, Worcester, and Somerset Counties in Maryland. The project will provide long-term incremental supply necessary to support the growing demand of the participating shippers. In January 2025, the FERC approved the project, and construction is expected to be complete in the third quarter of 2025.
Capital Cost Surcharge: In December 2024, Eastern Shore submitted a filing with the FERC regarding a capital cost surcharge to recover capital costs associated with the replacement of existing Eastern Shore facilities because of mandated highway relocation projects as well as compliance with a PHMSA regulation. The capital cost surcharge mechanism was approved in Eastern Shore's last rate case. In conjunction with the filing of this surcharge, a cumulative adjustment to the existing surcharge
Chesapeake Utilities Corporation 2024 Form 10-K Page 99
Notes to the Consolidated Financial Statements
to reflect additional depreciation was included. The FERC issued an order approving the surcharge as filed in December 2024. The combined revised surcharge became effective January 1, 2025.
Various Jurisdictional Activity Related to the Joint Customer Information System Project
In 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, however, the Florida PSC approved capitalization of these expenses in lieu of establishment of regulatory assets. Additionally, our Delaware Division has the ability to defer these costs as a regulatory asset. Implementation of the CIS began during the first quarter of 2023 and went into service during the fourth quarter of 2024.
TCJA
In connection with the TCJA, which was signed into law in December 2017, customer rates for our regulated businesses were adjusted as applicable as approved by the regulators. Regulatory liabilities related to accumulated deferred income taxes (“ADIT”) associated with the TCJA amounted to $84.6 million and $85.8 million at December 31, 2024 and 2023, respectively. With the exception of the ADIT balance of $34.2 million attributable to Eastern Shore, such amounts are being amortized in accordance with approvals received from the Delaware, Maryland, and Florida PSCs in 2018 and 2019. The ADIT balance attributable to Eastern Shore will be addressed in its next rate case filing.
Chesapeake Utilities Corporation 2024 Form 10-K Page 100
Notes to the Consolidated Financial Statements
Regulatory Assets and Liabilities
At December 31, 2024 and 2023, our regulated utility operations recorded the following regulatory assets and liabilities included in our consolidated balance sheets, including amounts attributable to FCG. These assets and liabilities will be recognized as revenues and expenses in future periods as they are reflected in customers’ rates.
As of December 31,
2024 2023
(in millions)
Regulatory Assets
Under-recovered purchased fuel, electric, gas and conservation cost recovery (1) (2)
$ 9.7 $ 13.7
Under-recovered GRIP revenue (3)
1.6 1.8
Deferred postretirement benefits (4)
7.7 10.8
Deferred conversion and development costs (1)
20.6 21.5
Acquisition adjustment (5)
29.6 31.9
Deferred storm costs (6)
11.1 19.4
Deferred rate case expenses - current 1.2 1.2
Other 19.8 15.6
Total Regulatory Assets $ 101.3 $ 115.9
Regulatory Liabilities
Over-recovered purchased fuel and conservation cost recovery (1)
$ 15.5 $ 12.3
Storm reserve (7)
2.1 1.9
Accrued asset removal cost (8)
77.9 86.5
Deferred income taxes due to rate change (9)
102.6 105.1
Other 2.0 3.2
Total Regulatory Liabilities $ 200.1 $ 209.0
(1) We are allowed to recover the asset or are required to pay the liability in rates. We do not earn an overall rate of return on these assets.
(2) Includes amounts being recovered over a three-year period primarily concentrated in our electric division. Per Florida PSC approval, our electric division was allowed to recover these amounts over an extended period of time in an effort to reduce the impact of increased commodity prices to our customers. Recovery of these costs began in January 2023.
(3) The Florida PSC allowed us to recover through a surcharge, capital and other program-related-costs, inclusive of an appropriate return on investment, associated with accelerating the replacement of qualifying gas distribution mains and services (defined as any material other than coated steel or plastic) in FPU’s natural gas distribution operations, Fort Meade division and Chesapeake Utilities’ CFG division. We are allowed to recover the asset or are required to pay the liability in rates related to GRIP.
(4) The Florida PSC allowed FPU to treat as a regulatory asset the portion of the unrecognized costs pursuant to ASC Topic 715, Compensation - Retirement Benefits, related to its regulated operations. This balance also includes the portion of pension settlement expense associated with the termination of the Chesapeake Pension Plan pursuant to an order from the FERC and the respective PSCs that allowed us to defer Eastern Shore, Delaware and Maryland Divisions' portion. See Note 16, Employee Benefit Plans, for additional information.
(5) We are allowed to include the premiums paid in various natural gas utility acquisitions in Florida in our rate bases and recover them over a specific time period pursuant to the Florida PSC approvals. We paid $34.2 million of the premium in 2009, including a gross up for income tax, because it is not tax deductible, and $0.7 million of the premium paid by FPU in 2010. For additional information, see Florida Natural Gas Rate Case discussion above.
(6) The Florida PSC authorized us to recover regulatory assets (including interest) associated with the recovery of Hurricanes Michael and Dorian storm costs which will be amortized between 6 and 10 years. Recovery of these costs includes a component of an overall return on capital additions and regulatory assets.
(7) We have storm reserves in our Florida regulated energy operations that allow us to collect through rates amounts to be used against general claims, storm restoration costs and other losses as they are incurred.
(8) See Note 2, Summary of Significant Accounting Policies, for additional information on our asset removal cost policies.
(9) We recorded a regulatory liability for our regulated businesses related to the revaluation of accumulated deferred tax assets/liabilities as a result of the TCJA. The liability will be amortized over a period between 5 to 80 years based on the remaining life of the associated property. Based upon the regulatory proceedings, we will pass back the respective portion of the excess accumulated deferred taxes to rate payers. See Note 11, Income Taxes, for additional information.
19. 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.
Chesapeake Utilities Corporation 2024 Form 10-K Page 101
Notes to the Consolidated Financial Statements
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 December 31, 2024 and 2023, we had approximately $3.2 million and $3.6 million, respectively, in environmental liabilities, related to the former MGP sites, and related regulatory assets of $0.3 million and $0.5 million at the respective balance sheet dates for future recovery of environmental costs from 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.
Remediation is ongoing for the MGP's in Winter Haven and Key West in Florida and in Seaford, Delaware. The remaining clean-up costs are estimated to range from $0.3 million to $0.8 million for these three sites. The Environmental 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 site. The remaining remediation expenses for the Sanford MGP site are not material.
The remedial actions approved by the Florida Department of Environmental Protection have been implemented on the east parcel of our West Palm Beach Florida site. Similar actions have been initiated on the site's west parcel, and construction of the systems required to remediate the site are now complete with remediation activities underway at December 31, 2024. Remaining remedial costs for West Palm Beach, including completion of the construction of the system start-up on the West Parcel, and continued operation and maintenance, are estimated to take between five and fifteen years of operation, maintenance and monitoring, and final site work for closeout of the property is estimated to be between $2.8 million and $5.2 million.
20. OTHER COMMITMENTS AND CONTINGENCIES
Natural Gas, Electric and Propane Supply
In March 2023, 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 in April 2023 and expire in March 2026.
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 commenced in November 2020 and expire in October 2030.
Florida Natural Gas 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.
Chesapeake Utilities Corporation 2024 Form 10-K Page 102
Notes to the Consolidated Financial Statements
FPU’s electric supply contracts require FPU to maintain an acceptable standard of creditworthiness. 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 standard, it must provide an Adequate Assurance of Performance which can include an irrevocable letter of credit, a prepayment, a security interest in an asset, or a performance bond or guaranty. As of December 31, 2024, FPU was in compliance with all of the requirements of its 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.
The total purchase obligations for natural gas, electric and propane supplies are as follows:
Year 2025 2026-2027 2028-2029 Beyond 2029 Total
(in millions)
Purchase Obligations $ 90.2 $ 103.6 $ 73.7 $ 119.4 $ 386.9
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 December 31, 2024 was $38.0 million. The aggregate amount guaranteed related to our subsidiaries at December 31, 2024 was approximately $28.4 million with the guarantees expiring on various dates through November 2025. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at December 31, 2024 was $5.2 million.
As of December 31, 2024, we have issued letters of credit totaling approximately $6.9 million related to various transportation, transmission, capacity and storage agreements as well as our primary insurance carriers. These letters of credit have various expiration dates through October 2025 and to date, none have been used. We do not anticipate that the counterparties will draw upon these letters of credit, and we expect that they will be renewed to the extent necessary in the future.
Chesapeake Utilities Corporation 2024 Form 10-K Page 103
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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE.
None.

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ITEM 9A. CONTROLS AND PROCEDURES
ITEM 9A. CONTROLS AND PROCEDURES.
EVALUATION OF DISCLOSURE CONTROLS AND PROCEDURES
Our Chief Executive Officer and Chief Financial Officer, with the participation of other Company officials, have evaluated our “disclosure controls and procedures” (as such term is defined under Rule 13a-15(e) and Rule 15d-15(e) promulgated under the Securities Exchange Act of 1934, as amended) as of December 31, 2024. Based upon their evaluation, our Chief Executive Officer and Chief Financial Officer concluded that our disclosure controls and procedures were effective as of December 31, 2024.
CHANGE IN INTERNAL CONTROLS
During the fourth quarter of 2024, we implemented a new customer billing system. Throughout the system implementation, we appropriately considered internal controls over financial reporting. The implementation did not result in a change in the design or operations of our internal controls over financial reporting that has materially affected, or is reasonably likely to materially affect, our internal controls over financial reporting.
CEO AND CFO CERTIFICATIONS
Our Chief Executive Officer and Chief Financial Officer have filed with the SEC the certifications required by Section 302 of the Sarbanes-Oxley Act of 2002 as Exhibits 31.1 and 31.2 to our Annual Report on Form 10-K for the fiscal year ended December 31, 2024. In addition, on June 6, 2024 our Chief Executive Officer certified to the NYSE that he was not aware of any violation by us of the NYSE corporate governance listing standards.
MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management is responsible for establishing and maintaining adequate internal control over financial reporting, as such term is defined in Rule 13a-15(f) of the Exchange Act. A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. A company’s internal control over financial reporting includes those policies and procedures that: (i) pertain to the maintenance of records which in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with GAAP and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Under the supervision and with the participation of management, including the Chief Executive Officer and Chief Financial Officer, our management conducted an evaluation of the effectiveness of its internal control over financial reporting based on the criteria established in an updated report entitled “Internal Control - Integrated Framework,” issued in May 2013 by the Committee of Sponsoring Organizations of the Treadway Commission. The scope of this assessment at December 31, 2024 included FCG, which was acquired on November 30, 2023.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Our management has evaluated and concluded that our internal control over financial reporting was effective as of December 31, 2024.
Our independent registered public accounting firm, Baker Tilly US, LLP, has audited the effectiveness of our internal control over financial reporting as of December 31, 2024, as stated in its attestation report which appears under Part II, Item 8. Financial Statements and Supplementary Data.
Chesapeake Utilities Corporation 2024 Form 10-K Page 104
Table of Content

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ITEM 9B. OTHER INFORMATION
ITEM 9B. OTHER INFORMATION.
None.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
ITEM 10. DIRECTORS, EXECUTIVE OFFICERS OF THE REGISTRANT AND CORPORATE GOVERNANCE.
We maintain a Code of Ethics that applies to our Principal Executive Officer, President, Principal Financial Officer, Principal Accounting Officer, Treasurer, Assistant Treasurer, Corporate Controller and persons performing similar functions, which is a “code of ethics” as defined by applicable rules of the SEC. This Code of Ethics is publicly available on our website at https://www.chpk.com. If we make any amendments to this code other than technical, administrative or other non-substantive amendments, or grant any waivers, including implicit waivers, from a provision of this code to the individuals and roles noted above, or persons performing similar functions, we intend to disclose the nature of the amendment or waiver, its effective date and to whom it applies by posting such information on our website at the address and location specified above.
We also maintain an insider trading policy governing the purchase, sale, and other dispositions of the Company's securities by directors, senior management, and employees. A copy of the insider trading policy is filed as an exhibit to this Annual Report.
The remaining information required by this Item is incorporated herein by reference to the sections of our Proxy Statement (which we intend to file with the SEC within 120 days after the close of our fiscal year) captioned “Election of Directors (Proposal 1),” “Governance Trends and Director Education,” “Corporate Governance Practices,” “Board of Directors and its Committees” and “Delinquent Section 16(a) Reports.”

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ITEM 11. EXECUTIVE COMPENSATION
ITEM 11. EXECUTIVE COMPENSATION.
The information required by this Item is incorporated herein by reference to the sections of our Proxy Statement (which we intend to file with the SEC within 120 days after the close of our fiscal year) captioned “Director Compensation,” “Executive Compensation” and “Compensation Discussion and Analysis.”

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS.
The information required by this Item is incorporated herein by reference to the sections of our Proxy Statement (which we intend to file with the SEC within 120 days after the close of our fiscal year) captioned “Security Ownership of Certain Beneficial Owners and Management” and “Equity Compensation Plan Information.”

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE.
The information required by this Item is incorporated herein by reference to the section of our Proxy Statement (which we intend to file with the SEC within 120 days after the close of our fiscal year) captioned “Corporate Governance Practices” and “Director Independence.”

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ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES
ITEM 14. PRINCIPAL ACCOUNTING FEES AND SERVICES.
The information required by this Item is incorporated herein by reference to the portion of the Proxy Statement (which we intend to file with the SEC within 120 days after the close of our fiscal year) captioned “Fees and Services of the Company's Independent Auditors.” Baker Tilly US, LLP, PCAOB ID: (23) serves as the Company's independent auditors.
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PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES.
The following documents are filed as part of this Annual Report:
(a)(1) All of the financial statements, reports and notes to the financial statements included in Item 8 of Part II of this Annual Report on Form 10-K.
(a)(2) Schedule II-Valuation and Qualifying Accounts.
(a)(3) The Exhibits below.
• Exhibit 1.1
Equity Distribution Agreement, dated November 22, 2024, by and between Chesapeake Utilities Corporation and each of RBC Capital Markets, LLC, Barclays Capital Inc., Janney Montgomery Scott LLC, Ladenburg Thalmann & Co. Inc., Guggenheim Securities, LLC, Citizens JMP Securities, LLC, M&T Securities, Inc., Maxim Group LLC, PNC Capital Markets LLC, and Siebert Williams Shank & Co., LLC is incorporated herein by reference to Exhibit 1.1 of our Current Report on Form 8-K, filed November 22, 2024, File No. 001-11590.
• Exhibit 2.1
Stock Purchase Agreement, dated September 26, 2023, by and among Florida Power & Light Company and Chesapeake Utilities Corporation is incorporated by reference to Exhibit 2.1 of our Current Report on Form 8-K, filed with the SEC on September 27, 2023, File No. 001-11590.
• Exhibit 3.1
Amended and Restated Certificate of Incorporation of Chesapeake Utilities Corporation is incorporated by reference to Exhibit 3.1 of our Quarterly Report on Form 10-Q for the period ended June 30, 2010, File No. 001-11590.
• Exhibit 3.2
Certificate of Amendment to the Amended and Restated Certificate of Incorporation of Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 3.1 of our Current Report on Form 8-K, filed May 9, 2017, File No. 001-11590.
• Exhibit 3.3
Certificate of Elimination of Series A Participating Cumulative Preferred Stock of Chesapeake Utilities Corporation, is incorporated herein by reference to Exhibit 3.6 of our Annual Report on Form 10-K for the year ended December 31, 2017, File No. 001-11590.
• Exhibit 3.4
Amended and Restated Bylaws of Chesapeake Utilities Corporation, effective May 3, 2023, are incorporated herein by reference to Exhibit 3.1 of our Current Report on Form 8-K, filed May 3, 2023, File No. 001-11590.
• Exhibit 4.1
Note Purchase Agreement, dated November 1, 2024, by and among Chesapeake Utilities Corporation and the purchasers party thereto is incorporated by reference to Exhibit 4.1 of our Current Report on Form 8-K filed November 4, 2024, File No. 001-11590.
• Exhibit 4.2
Note Purchase Agreement, dated November 20, 2023, by and among Chesapeake Utilities Corporation and the purchasers party thereto is incorporated by reference to Exhibit 4.1 of the Company’s Current Report on Form 8-K filed with the SEC on November 21, 2023, File No. 001-11590.
• Exhibit 4.3 Note Purchase Agreement, dated August 25, 2021, by and among Chesapeake Utilities Corporation, MetLife Insurance K.K., Thrivent Financial For Lutherans, CMFG Life Insurance Company, and American Memorial Life Insurance Company. †
• Exhibit 4.4 Note Purchase Agreement dated November 19, 2019, by and among Chesapeake Utilities Corporation, The Guardian Life Insurance Company of America, The Guardian Insurance & Annuity Company, Inc., Berkshire Life Insurance Company of America, Thrivent Financial for Lutherans, United of Omaha Life Insurance Company, and CMFG Life Insurance Company.†
• Exhibit 4.5 Master Note Agreement dated March 2, 2017, by and among Chesapeake Utilities Corporation, NYL Investors LLC, and the other purchasers thereto.†
• Exhibit 4.6 First Amendment to Master Note Agreement dated November 15, 2018, by and among Chesapeake Utilities Corporation, NYL Investors LLC, and the other purchasers thereto.†
• Exhibit 4.7 Private Shelf Agreement, dated March 2, 2017, by and among Chesapeake Utilities Corporation, Metropolitan Life Insurance Company, and MetLife Investment Management, LLC, and the other purchasers thereto.†
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• Exhibit 4.8 First Amendment to Private Shelf Agreement, dated May 14, 2020, by and among Chesapeake Utilities Corporation, Metropolitan Life Insurance Company, and MetLife Investment Management, LLC, and the other purchasers thereto. †
• Exhibit 4.9
Second Amendment to Private Shelf Agreement, dated February 21, 2023, by and among Chesapeake Utilities Corporation, Metropolitan Life Insurance Company, and MetLife Investment Management, LLC Second Amendment to Private Shelf Agreement dated February 21, 2023, by and among Chesapeake Utilities Corporation, Metropolitan Life Insurance Company, and MetLife Investment Management, LLC is incorporated by reference to Exhibit 4.11 of our Annual Report on Form 10-K for the year ended December 31, 2022, File No. 001-11590.
• Exhibit 4.10 Private Shelf Agreement dated October 8, 2015, by and among Chesapeake Utilities Corporation, PGIM, Inc. (formerly known as Prudential Investment Management Inc.), and the other purchasers thereto. †
• Exhibit 4.11 First Amendment to Private Shelf Agreement dated September 14, 2018, between Chesapeake Utilities Corporation, as issuer, and PGIM, Inc. (formerly known as Prudential Investment Management, Inc.), and other purchasers that may become party thereto. †
• Exhibit 4.12 Third Amendment to Private Shelf Agreement dated February 8, 2023, between Chesapeake Utilities Corporation, as issuer, and PGIM, Inc. (formerly known as Prudential Investment Management, Inc.), and other purchasers thereto. †
• Exhibit 4.13 Note Purchase Agreement dated September 5, 2013, by and among Chesapeake Utilities Corporation, PAR U Hartford Life & Annuity Comfort Trust, The Prudential Insurance Company of America, The Gibraltar Life Insurance Co., Ltd., The Penn Mutual Life Insurance Company, Thrivent Financial for Lutherans, United of Omaha Life Insurance Company, and Companion Life Insurance Company.†
• Exhibit 4.14 Note Agreement dated June 29, 2010, among Chesapeake Utilities Corporation, as issuer, Metropolitan Life Insurance Company and New England Life Insurance Company.†
• Exhibit 4.15
Description of Chesapeake Utilities Corporation's Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934, as amended, is incorporated by reference to Exhibit 4.10 of our Annual Report on Form 10-K for the year ended December 31, 2021, File No. 001-11590.
• Exhibit 10.1*
Chesapeake Utilities Corporation Cash Bonus Incentive Plan, effective January 1, 2015, is incorporated herein by reference to our Proxy Statement dated March 31, 2015, in connection with our Annual Meeting held on May 6, 2015, File No. 001-11590.
• Exhibit 10.2*
Non-Qualified Deferred Compensation Plan, effective January 1, 2014, is incorporated herein by reference to Exhibit 10.8 of our Annual Report on Form 10-K for the year ended December 31, 2013, File No. 001-11590.
• Exhibit 10.3*
Second Amendment to the Non-Qualified Deferred Compensation Plan, effective October 2, 2023, is incorporated by reference to Exhibit 10.33 of our Annual Report on Form 10-K for the year ended December 31, 2023, File No. 001-11590.
• Exhibit 10.4*
Chesapeake Utilities Corporation Supplemental Executive Retirement Plan, as amended and restated effective January 1, 2009, is incorporated herein by reference to Exhibit 10.27 of our Annual Report on Form 10-K for the year ended December 31, 2008, File No. 001-11590.
• Exhibit 10.5*
First Amendment to the Chesapeake Utilities Corporation Supplemental Executive Retirement Plan as amended and restated effective January 1, 2009, is incorporated herein by reference to Exhibit 10.30 of our Annual Report on Form 10-K for the year ended December 31, 2010, File No. 001-11590.
• Exhibit 10.6
Loan Agreement dated April 24, 2020, between Chesapeake Utilities Corporation and PNC Bank, National Association is incorporated herein by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, File No. 001-11590.
• Exhibit 10.7
Revolving Line of Credit Note dated April 24, 2020 issued by Chesapeake Utilities Corporation in favor of PNC Bank, National Association is incorporated herein by reference to Exhibit 10.5 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, File No. 001-11590.
• Exhibit 10.8
Loan Agreement dated April 27, 2020, between Chesapeake Utilities Corporation and Bank of America, N.A. is incorporated herein by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, File No. 001-11590.
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• Exhibit 10.9
Promissory Note dated April 22, 2020, issued by Chesapeake Utilities Corporation and in favor of Bank of America, N.A. is incorporated herein by reference to Exhibit 10.6 to our Quarterly Report on Form 10-Q for the quarter ended March 31, 2020, File No. 001-11590.
• Exhibit 10.10
Credit Agreement dated May 29, 2020, between Chesapeake Utilities Corporation and Citizens Bank National Association is incorporated herein by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, File No. 001-11590.
• Exhibit 10.11
Form of Revolving Loan Note in favor of Citizens Bank National Association is incorporated herein by reference to Exhibit 10.3 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, File No. 001-11590.
• Exhibit 10.12
Loan Agreement dated May 6, 2020 between Chesapeake Utilities Corporation and Royal bank of Canada is incorporated herein by reference to Exhibit 10.2 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, File No. 001-11590.
• Exhibit 10.13
Form of Revolving Credit Note in favor of Royal Bank of Canada is incorporated herein by reference to Exhibit 10.4 to our Quarterly Report on Form 10-Q for the quarter ended June 30, 2020, File No. 001-11590.
• Exhibit 10.14
Credit Agreement, dated September 30, 2020, by and between Chesapeake Utilities Corporation, PNC Bank, National Association, and several other financial institutions named therein is incorporated herein by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2020, File No. 001-11590.
• Exhibit 10.15
Amended and Restated Credit Agreement, dated August 12, 2021, to Credit Agreement dated September 30, 2020, among Chesapeake Utilities Corporation, PNC Bank, National Association, and several other financial institutions named therein is incorporated herein by reference to Exhibit 10.1 to our Quarterly Report on Form 10-Q for the quarter ended September 30, 2021, File No. 001-11590.
• Exhibit 10.16
Second Amended and Restated Credit Agreement, dated August 6, 2024, among Chesapeake Utilities Corporation, PNC Bank, National Association and several other financial institutions is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the period ended June 30, 2024, File No. 001-11590.
• Exhibit 10.17
Second Amendment to Amended and Restated Credit Agreement, dated August 9, 2023, to Credit Agreement dated September 30, 2020 among Chesapeake Utilities Corporation and PNC Bank, National Association, and several other financial institutions is incorporated herein by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the period ended September 30, 2023, File No. 001-11590.
• Exhibit 10.18*
Executive Employment Agreement, dated December 16, 2021, by and between Chesapeake Utilities Corporation and Jeffrey S. Sylvester is incorporated by reference to Exhibit 10.1 to our Current Report on Form 8-K filed on December 20, 2021, File No. 001-11590.
• Exhibit 10.19*
Executive Employment Agreement, dated December 16, 2021, by and between Chesapeake Utilities Corporation and Jeffry M. Householder is incorporated by reference to Exhibit 10.2 to our Current Report on Form 8-K filed on December 20, 2021, File No. 001-11590.
• Exhibit 10.20*
Executive Employment Agreement, dated December 16, 2021, by and between Chesapeake Utilities Corporation and Beth W. Cooper is incorporated by reference to Exhibit 10.3 to our Current Report on Form 8-K filed on December 20, 2021, File No. 001-11590.
• Exhibit 10.21*
Executive Employment Agreement, dated December 16, 2021, by and between Chesapeake Utilities Corporation and James F. Moriarty is incorporated by reference to Exhibit 10.4 to our Current Report on Form 8-K filed on December 20, 2021, File No. 001-11590.
• Exhibit 10.22*
Executive Employment Agreement, dated December 16, 2021, by and between Chesapeake Utilities Corporation and Kevin J. Webber is incorporated by reference to Exhibit 10.5 to our Current Report on Form 8-K filed on December 20, 2021, File No. 001-11590.
• Exhibit 10.23*
Form of Amendment to the Executive Employment Agreement, effective October 2, 2023, for each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty, Kevin J. Webber and Jeffrey S. Sylvester is incorporated by reference to Exhibit 10.34 to our Annual Report on Form 10-K for the year ended December 31, 2023, File No. 001-11590.
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• Exhibit 10.24*
Form of Performance Share Agreement, effective February 23, 2022, by and between Chesapeake Utilities Corporation and each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty, Kevin J. Webber, and Jeffrey S. Sylvester is incorporated herein by reference to Exhibit 10.34 to our Annual Report on Form 10-K for the year ended December 31, 2021, File No. 001-11590.
• Exhibit 10.25*
Form of Performance Share Agreement dated February 22, 2023 by and between Chesapeake Utilities Corporation and each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty, Kevin Webber and Jeffrey S. Sylvester is incorporated herein by reference to Exhibit 10.16 to our Annual Report on Form 10-K for the year ended December 31, 2022. File No. 001-11590.
• Exhibit 10.26*
Form of Performance Share Agreement, effective February 20, 2024, by and between Chesapeake Utilities Corporation and each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty, Kevin J. Webber, and Jeffrey S. Sylvester is incorporated by reference to Exhibit 10.1 of our Quarterly Report on Form 10-Q for the period ended March 31, 2024, File No. 001-11590.
• Exhibit 10.27*
Form of Performance Share Agreement dated February 25, 2025 for the period 2024-2026, pursuant to Chesapeake Utilities Corporation 2023 Stock and Incentive Compensation Plan by and between Chesapeake Utilities Corporation and each of Jeffry M. Householder, Beth W. Cooper, James F. Moriarty, Kevin Webber and Jeffrey S. Sylvester is filed herewith.
• Exhibit 10.28*
Chesapeake Utilities Corporation 2013 Stock and Incentive Compensation Plan, as approved by stockholders and effective May 2, 2013 is incorporated by reference to Appendix A of our Proxy Statement dated April 2, 2013 in connection with our Annual Meeting held on May 2, 2013, File No. 001-11590.
• Exhibit 10.29*
Chesapeake Utilities Corporation 2023 Stock and Incentive Compensation Plan as approved by stockholders and effective on May 3, 2023 is incorporated herein by reference to Exhibit 10.1 to our Registration Statement on Form S-8 filed May 3, 2023, File No. 001-11590.
• Exhibit 19
Chesapeake Utilities Corporation’s Securities Trades by Company Personnel and Related Persons Policy Statement is filed herewith.
• Exhibit 21
Subsidiaries of the Registrant is filed herewith.
• Exhibit 23.1
Consent of Independent Registered Public Accounting Firm is filed herewith.
• Exhibit 31.1
Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d - 14(a), is filed herewith.
• Exhibit 31.2
Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to Exchange Act Rule 13a-14(a) and 15d - 14(a), is filed herewith.
• Exhibit 32.1
Certificate of Chief Executive Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, is furnished herewith.
• Exhibit 32.2
Certificate of Chief Financial Officer of Chesapeake Utilities Corporation pursuant to 18 U.S.C. Section 1350, is furnished herewith.
• Exhibit 97
Chesapeake Utilities Corporation Incentive-Based Compensation Clawback Policy effective October 2, 2023, is incorporated by reference to Exhibit 97 of our Annual Report on Form 10-K for the year ended December 31, 2023, File No. 001-11590.
• Exhibit 101.INS XBRL Instance Document is filed herewith.
• Exhibit 101.SCH XBRL Taxonomy Extension Schema Document is filed herewith.
• Exhibit 101.CAL XBRL Taxonomy Extension Calculation Linkbase Document is filed herewith.
• Exhibit 101.DEF XBRL Taxonomy Extension Definition Linkbase Document is filed herewith.
• Exhibit 101.LAB XBRL Taxonomy Extension Label Linkbase Document is filed herewith.
• Exhibit 101.PRE XBRL Taxonomy Extension Presentation Linkbase Document is filed herewith.
• Exhibit 104 Cover Page Interactive Data File - formatted in Inline XBRL and contained in Exhibit 101.
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* Management contract or compensatory plan or agreement.
† These agreements have not been filed herewith pursuant to Item 601(b)(4)(v) of Regulation S-K under the Securities Act of 1933, as amended. We hereby agree to furnish copies to the SEC upon request.
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