CHESAPEAKE UTILITIES CORP (CPK) FY 2024 MD&A

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.

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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

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(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.

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Adjusted Net Income and Adjusted EPS

(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.

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OVERVIEW AND HIGHLIGHTS

(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.

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2024 compared to 2023

Key variances in operations between 2024 and 2023 included:

* 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.

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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.

(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.

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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.

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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

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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.

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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

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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.

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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

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:

(1) Includes growth amounts for our legacy Florida operations, but excludes the effects of FCG.

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REGULATED ENERGY

(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:

(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.

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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:

(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.

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UNREGULATED ENERGY

(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:

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.

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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:

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.

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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:

In the table below, we have provided a range of our forecasted capital expenditures by segment and business line for 2025:

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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:

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.

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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.

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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:

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:

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

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•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.

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CONTRACTUAL OBLIGATIONS

We have the following contractual obligations and other commercial commitments as of December 31, 2024:

(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.

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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.

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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.