CHESAPEAKE UTILITIES CORP (CPK)

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

Management’s Discussion and Analysis of Financial Condition and Results of Operations is designed to provide a reader of the financial statements with a narrative report on our financial condition, results of operations and liquidity. This discussion and analysis should be read in conjunction with the attached unaudited condensed consolidated financial statements and notes thereto and our Annual Report on Form 10-K for the year ended December 31, 2025, including the audited consolidated financial statements and notes thereto.

Safe Harbor for Forward-Looking Statements

We make statements in this Quarterly Report on Form 10-Q (this "Quarterly Report") that do not directly or exclusively relate to historical facts. Such statements are “forward-looking statements” within the meaning of Section 27A of the Securities Act of 1933, as amended, Section 21E of the Securities Exchange Act of 1934, as amended, and the Private Securities Litigation Reform Act of 1995. One can typically identify forward-looking statements by the use of forward-looking words, such as “project,” “believe,” “expect,” “anticipate,” “intend,” “plan,” “estimate,” “continue,” “potential,” “forecast” or other similar words, or future or conditional verbs such as “may,” “will,” “should,” “would” or “could.” These statements represent our intentions, plans, expectations, assumptions and beliefs about future financial performance, business strategy, projected plans and objectives of the Company. Forward-looking statements speak only as of the date they are made or as of the date indicated and we do not undertake any obligation to update forward-looking statements as a result of new information, future events or otherwise. These statements are subject to many risks and uncertainties. In addition to the risk factors described under Item 1A., Risk Factors in our 2025 Annual Report on Form 10-K, the following important factors, among others, could cause actual future results to differ materially from those expressed in the forward-looking statements:

•state and federal legislative and regulatory initiatives that affect cost and investment recovery, have an impact on rate structures, and affect the speed and the degree to which competition enters the electric and natural gas industries;

•the outcomes of regulatory, environmental and legal matters, including whether pending matters are resolved within current estimates and within expected times, and whether the related costs are adequately covered by insurance or recoverable in rates;

•the impact of climate change, including the impact of greenhouse gas emissions or other legislation or regulations intended to address climate change;

•the impact of significant changes to tax regulations and rates;

•the timing of certification authorizations associated with new capital projects and the ability to construct facilities at or below estimated costs, and within estimated timeframes;

•changes in environmental and other laws and regulations to which we are subject and environmental conditions of property that we now, or may in the future, own or operate;

•changes in the current political environment, including the effects the Presidential administration could have on energy policy, the economy and consumer confidence;

•possible increased federal, state and local regulation of the safety of our operations;

•the availability and reliability of adequate technology, including our ability to adapt to technological advances, effectively implement new technologies and manage the related costs;

•the inherent hazards and risks involved in transporting and distributing natural gas, electricity and propane;

•the economy in our service territories or markets, the nation, and worldwide, including the impact of economic conditions (which we do not control) such as the risk and uncertainties associated with tariffs and trade wars, on demand for natural gas, electricity, propane or other fuels;

•risks related to cyber-attacks or cyber-terrorism that could disrupt our business operations or result in failure of information technology systems or result in the loss or exposure of confidential or sensitive customer, employee or Company information;

•issues relating to the implementation and effective use of technologies to support our business, including artificial intelligence;

•adverse weather conditions, including the effects of hurricanes, ice storms and other damaging weather events;

•customers' preferred energy sources and our expectations regarding customer consumption;

•industrial, commercial and residential growth or contraction in our markets or service territories;

•the effect of competition on our businesses from other energy suppliers and alternative forms of energy;

•the timing and extent of changes in commodity prices and interest rates;

•the effect of spot, forward and future market prices on our various energy businesses;

•the extent of our success in connecting natural gas and electric supplies to our transmission systems, establishing and maintaining key supply sources, and expanding natural gas and electric markets;

•the creditworthiness of counterparties with which we are engaged in transactions;

•the capital-intensive nature of our regulated energy businesses;

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•our ability to access the credit and capital markets to execute our business strategy, including our ability to obtain financing on favorable terms, which can be affected by various factors, including credit ratings and general economic conditions;

•the ability to successfully execute, manage and integrate a merger, acquisition or divestiture of assets or businesses and the related regulatory or other conditions associated with the merger, acquisition or divestiture;

•the impact on our costs and funding obligations, under our pension and other postretirement benefit plans, of potential downturns in the financial markets, lower discount rates, and costs associated with health care legislation and regulation;

•the ability to continue to hire, train and retain appropriately qualified personnel;

•the availability of, and competition for, qualified personnel supporting our natural gas, electricity and propane businesses;

•the effect of accounting pronouncements issued periodically by accounting standard-setting bodies; and

•the impacts associated with a pandemic, including the duration and scope of the pandemic the corresponding impact on our supply chains, our personnel, our contract counterparties, general economic conditions and growth, the financial markets and any costs to comply with governmental mandates.

Introduction

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, our 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.

Due to the seasonality of our business, results for interim periods are not necessarily indicative of results for the entire fiscal year. Revenue and earnings are typically greater during the first and fourth quarters, when consumption of energy is normally highest due to colder temperatures.

Sustainability Across the Company

Our focus on sustainability is supported and shared across the organization by the dedication and efforts of our BOD and its Committees, as well as the entrepreneurship and dedication of our team. As stewards of long-term enterprise value, our BOD is committed to overseeing the sustainability of the Company, its environmental stewardship initiatives, its safety and operational compliance practices.

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These commitments guide our mission to deliver energy that makes life better for the people and communities we serve. They impact every aspect of the relationships we have with our stakeholders. Within our 2025 Annual Report to Shareholders, we continued to highlight our ongoing efforts related to these commitments. We encourage our investors to review the 2025 Annual Report to Shareholders, as well as our prior micro and consolidated sustainability reports, which can be accessed on our website.

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 res

[Excerpt truncated for page length; source filing is linked above.]

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 currently serves approximately 125,000 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. 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 RSAM with a $25.0 million reserve amount. The RSAM was 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 was subject to review and approval by the Florida PSC. In February 2026, the Florida PSC approved a $6.8 million reserve imbalance to be amortized over the remaining life of the assets, with the revised depreciation rates effective as of January 1, 2025.

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

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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.

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, 2025, 2024 and 2023:

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.

2025 to 2024 Gross Margin (GAAP) Variance – Regulated Energy

Gross Margin (GAAP) for the Regulated Energy segment for 2025 was $368.4 million, an increase of $26.6 million, or 7.8 percent, compared to 2024. Higher gross margin largely reflects incremental margin from regulatory initiatives and infrastructure programs, pipeline expansion projects and natural gas organic growth.

2024 to 2023 Gross Margin (GAAP) Variance – Regulated Energy

Gross Margin (GAAP) for the Regulated Energy segment for the year ended December 31, 2024 compared to 2023 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, 2024, which is incorporated herein by reference.

2025 to 2024 Gross Margin (GAAP) Variance – Unregulated Energy

Gross Margin (GAAP) for the Unregulated Energy segment for 2025 was $84.7 million, an increase of $6.5 million, or 8.3 percent, compared to 2024. Higher gross margin resulted primarily from increased CNG, RNG and LNG services, and increased customer consumption.

2024 to 2023 Gross Margin (GAAP) Variance – Unregulated Energy

Gross Margin (GAAP) for the Unregulated Energy segment for the year ended December 31, 2024 compared to 2023 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, 2024, 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 14 for additional details on the acquisition and related equity offering.

2025 to 2024 Net Income (GAAP) Variance

Net income (GAAP) for the year ended December 31, 2025 was $140.3 million, or $5.97 per share, compared to $118.6 million, or $5.26 per share in 2024. Net income for the years ended December 31, 2025 and 2024 included $0.8 million and $2.9 million, respectively, of transaction and transition-related expenses in connection with the acquisition and integration of FCG. Excluding these costs, net income increased by $19.6 million.

2024 to 2023 Net Income (GAAP) Variance

Net income (GAAP) for the year ended December 31, 2024 compared to 2023 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, 2024, 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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2025 compared to 2024

Key variances in operations between 2025 and 2024 included:

(1) 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.

(2) Refer to Major Projects and Initiatives table for additional information.

(3) Reflects the impact of common shares issued under the DRIP and ATM program.

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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 attributable to interim rates during 2024 and 2025. See additional information provided below.

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Discussion of Major Projects and Initiatives

Pipeline Expansions

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. We expect this extension to generate annual adjusted gross margin of $0.6 million in 2026 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 second quarter of 2026. We expect this expansion to generate approximately $3.2 million of adjusted gross margin in 2026 and thereafter.

For the year ended December 31, 2025, these projects generated additional adjusted gross margin of $2.3 million.

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, and construction was completed in 2025. The project generated additional adjusted gross margin of $1.1 million for the year ended December 31, 2025, and is expected to contribute adjusted gross margin of approximately $4.3 million in 2026 and thereafter.

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. Conversions of the community gas systems commenced in the second quarter of 2024 and are projected to be complete in the first quarter of 2026. The project generated additional adjusted gross margin of $1.2 million for the year ended December 31, 2025, and is expected to contribute adjusted gross margin of approximately $2.6 million in 2026 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.

In June 2025, Eastern Shore filed a limited amended application with the FERC requesting revised initial transportation rates for the project. The revised rates reflected increased capital costs associated with unanticipated changes in global markets and supply chains, including the availability of skilled laborers with the requisite certifications to work on this project. Eastern Shore requested expedited action by the FERC in relation to this matter and an approved order was issued in July 2025. Construction is underway and the project is expected to be placed into service in mid-2026. The project generated adjusted

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gross margin of $0.3 million for the year ended December 31, 2025, and is expected to contribute adjusted gross margin of approximately $10.6 million in 2026 and $17.1 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. New Smyrna Beach was placed into service during May 2025 and construction is projected to be complete for Boynton Beach in the second quarter of 2026. The projects generated adjusted gross margin of $4.6 million for the year ended December 31, 2025, and are expected to contribute adjusted gross margin of approximately $6.0 million in 2026 and thereafter.

Central Florida Reinforcement Projects (Plant City and Lake Mattie)

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's extensions support FPU’s distribution system around the Plant City and Lake Mattie area's 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 went into service in July 2025. The projects generated additional adjusted gross margin of $2.5 million for the year ended December 31, 2025, and are expected to contribute adjusted gross margin of approximately $4.3 million in 2026 and 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 additional adjusted gross margin of $1.5 million for the year ended December 31, 2025, and is expected to contribute adjusted gross margin of approximately $1.9 million in 2026 and thereafter.

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. In October 2025, the Florida PSC approved amendments to the Transportation Service Agreements that were filed to include Peninsula Pipeline as a party to the related interconnection agreements. The projects are underway and are estimated to be completed in the second half of 2026. These three renewable projects generated adjusted gross margin of $2.5 million for the year ended December 31, 2025, and are projected to generate total adjusted gross margin of approximately $5.4 million in 2026 and $6.4 million thereafter.

Miami Inner Loop Pipeline 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 gas infrastructure in Miami-Dade County. The proposed expansion consists of the development of several pipeline projects to support growth and FCG's distribution system, as well as enhance FCG's access to gas from various points in the Miami-Dade County area. The expansion was approved in February 2025 and interim services began in August 2025 with permanent facilities expected to be in service by the second quarter of 2026. The project generated adjusted gross margin of $2.8 million for the year ended December 31, 2025, and is expected to contribute adjusted gross margin of approximately $7.6 million in 2026 and thereafter.

Duncan Plains Pipeline Project

In July 2025, Aspire Energy Express entered into an agreement with American Electric Power to construct and operate an intrastate natural gas pipeline in central Ohio to serve a new fuel-cell facility, which will provide on-site electric power to a data center. This new transmission infrastructure is expected to be in service in the first half of 2027 and is expected to contribute adjusted gross margin of approximately $1.5 million in 2027.

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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, 2025, we generated $10.9 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 $28.5 million in 2026, and $29.7 million in 2027 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 $205.0 million of capital expenditures projected to be spent over a 10-year period. For the year ended December 31, 2025, there was $3.5 million of incremental adjusted gross margin generated pursuant to the program. The program is expected to generate $10.1 million of adjusted gross margin in 2026 and $13.0 million in 2027.

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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 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. For the year ended December 31, 2025, there was $4.6 million of additional adjusted gross margin generated pursuant to the program. The program is expected to generate $12.7 million of adjusted gross margin in 2026 and $16.4 million in 2027.

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 2025, 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 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 2025. The combined revised surcharge became effective January 1, 2026. For the year ended December 31, 2025, there was $2.5 million of incremental adjusted gross margin generated pursuant to the program. Eastern Shore expects to produce adjusted gross margin of approximately $9.0 million in 2026 and $10.1 million in 2027 from relocation projects, which is ultimately dependent upon the timing of filings and the completion of construction.

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 and approved in 2022, with modifications, by the Florida PSC. Rates associated with this initiative were effective in January 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. Our Florida electric distribution operations filed an updated SPP plan in January 2025 which was approved in June 2025, with modifications by the Florida PSC. For the year ended December 31, 2025, this initiative generated incremental adjusted gross margin of $3.2 million, and is expected to generate $9.1 million in 2026. We expect continued investment under the SPP going forward.

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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, the “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; 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 OPC and PSC staff reached a settlement 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 related settlement agreement in part. The $2.6 million increase in annual base rates was approved, and the Company filed a 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 was held in March 2025, during which Phase II was approved, including an additional $0.9 million in revenue requirement, for a total cumulative increase of $3.5 million. A final order was issued in April 2025 and included approval of the consolidation of the operations and the assets of CUC-Maryland Division, Sandpiper Energy, and Elkton Gas into one entity which was renamed and operates as Chesapeake Utilities of Maryland, Inc. For the year ended December 31, 2025, there was $1.5 million of adjusted gross margin generated pursuant to the program. The program is expected to generate $3.5 million of adjusted gross margin in 2026 and in 2027.

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 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 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. A settlement among the Company, PSC staff and the Delaware Division of the Public Advocate was reached and approved by the Delaware PSC in June 2025 providing an annual revenue increase of $6.1 million, as well as dividing the rate case into two phases. Rates set to recover the approved components of the increase were effective in March 2025. In October 2025, a settlement was reached for Phase II of the rate case addressing tariff-related changes including rate design and approved by the Delaware Public Service Commission with rates effective as of October 15, 2025. For the year ended December 31, 2025, there was $4.1 million of additional adjusted gross margin generated and final rates are expected to generate approximately $6.1 million of adjusted gross margin in 2026 and in 2027.

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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. In March 2025, the Florida PSC approved the permanent rate increase, but the order was subsequently protested. In May 2025, the Company reached a settlement agreement with the interested parties to resolve all outstanding issues. This settlement which was approved by the Florida PSC in July 2025, provides for a total base rate increase of approximately $8.6 million on an annual basis, with $1.0 million of the increase deferred from the first year's base rate increase and recovered over three years. A step-up rate increase was also approved for up to $0.7 million, upon completion of the purchase and refurbishment of certain substations, which is expected to be completed in December 2026. For the year ended December 31, 2025, there was $7.0 million of additional adjusted gross margin generated and final rates are expected to generate approximately $8.6 million of adjusted gross margin in 2026 and $9.1 million in 2027.

Florida Mandatory Relocates

In October 2025, FPU and FCG filed a joint petition for approval to establish a recovery surcharge for actual, estimated and projected relocation costs pursuant to the Florida Administrative Code which enables companies to recover the costs associated with relocating or reconstructing facilities that have been required by governmental entities. The projected revenue requirement for 2026 is $0.5 million for FPU and $1.0 million for FCG. The Florida PSC approved the petition in February 2026, with the surcharge effective in March 2026.

Florida City Gas Rate Case

In February 2026, FCG provided notice to the Florida PSC of its intent to file a petition seeking a general rate base increase based on a 2027 projected test year. The rate case filing is expected to be submitted in April 2026 and the outcome of the application will be subject to review and approval by the Florida PSC.

FCG Depreciation Study

In February 2025, FCG filed a depreciation study with the Florida PSC. The application requested 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 was subject to review and approval by the Florida PSC. In February 2026, the Florida PSC approved a $6.8 million reserve imbalance to be amortized over the remaining life of the assets, with the revised depreciation rates effective as of January 1, 2025.

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Other Major Factors Influencing Adjusted Gross Margin

Weather Impact

In 2025, increased customer consumption, which includes the effects of colder weather, largely in the Company's Ohio, Delmarva and Florida service areas, compared to the prior year resulted in a $9.5 million increase in adjusted gross margin. The following table summarizes HDD and CDD variances from the 10-year average HDD/CDD ("Normal") for the years ended 2025 compared to 2024, and 2024 compared to 2023.

HDD and CDD Information

Natural Gas Distribution Growth

The average number of residential customers served on the Delmarva Peninsula, by FPU and by FCG increased by approximately 4.1 percent, 3.6 percent and 2.2 percent, respectively, during 2025.

The increase in adjusted gross margin resulting from customer growth is provided in the following table:

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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) Includes the absence of an RSAM adjustment from FCG which represented a $15.5 million benefit during the year ended December 31, 2024.

(3) 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.

(4) Operating results for FCG are included from the acquisition date (November 30, 2023).

2025 compared to 2024

Operating income for the Regulated Energy segment for 2025 was $222.0 million, an increase of $25.8 million compared to 2024. Excluding transaction and transition-related expenses associated with the acquisition of FCG, operating income increased $23.0 million or 11.5 percent compared to the prior year. Higher operating income reflects incremental margin from our regulatory initiatives and infrastructure programs, pipeline expansion projects and organic growth in our natural gas distribution businesses. Excluding the transaction and transition-related expenses described above, operating expenses increased by $31.8 million compared to the prior year primarily attributable to higher depreciation, amortization and property taxes and increased facilities expenses, maintenance costs and outside services. Increases in depreciation are attributable to growth projects and the absence of an RSAM adjustment from FCG which represented a $15.5 million benefit 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 both interim and permanent base rates. Refer to Major Projects discussion for additional information.

The following narrative discussion provides further detail and analysis of the significant variances in adjusted gross margin detailed above.

Natural Gas Transmission Service Expansions, including interim services

We generated increased adjusted gross margin of $18.8 million for the year ended December 31, 2025 from natural gas transmission service expansions of Peninsula Pipeline and Eastern Shore.

Contributions from Regulated Infrastructure Programs

Regulated infrastructure programs generated incremental adjusted gross margin of $13.8 million for the year ended December 31, 2025. The increase in adjusted gross margin was primarily related to FCG's SAFE program, Florida's GUARD

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program, FPU Electric's SPP, and Eastern Shore's Capital Cost Surcharge program. Refer to Note 17, Rates and Other Regulatory Activities, in the consolidated financial statements for additional information.

Rate Changes Associated with Recent Rate Case Activities

Rate changes associated with the Delaware and Maryland natural gas rate cases and Florida Electric base rate case contributed additional adjusted gross margin of $12.6 million for the year ended December 31, 2025. Refer to Note 17, 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 $7.4 million from natural gas customer growth. Adjusted gross margin increased by $5.6 million for our Florida natural gas distribution businesses and $1.8 million on the Delmarva Peninsula compared to 2024, due primarily to residential customer growth of 2.8 percent and 4.1 percent in Florida and on the Delmarva Peninsula, respectively.

Increased Customer Consumption

Customer consumption, inclusive of weather-related consumption, increased adjusted gross margin by $2.4 million for the year ended December 31, 2025.

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.

2024 compared to 2023

The results for the Regulated Energy segment for the year ended December 31, 2024 compared to 2023 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, 2024, which is incorporated herein by reference.

UNREGULATED ENERGY

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(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.

2025 Compared to 2024

Operating income for the Unregulated Energy segment for 2025 increased by $1.9 million or 6.0 percent compared to 2024. Adjusted gross margin in the Unregulated Energy segment increased primarily due to increased levels of virtual pipeline services and increased customer consumption in our propane operations and at Aspire. These increases were partially offset by a change in propane margin and service fees. The increase in operating expenses included higher payroll, benefits and other employee-related expenses, increased facilities, maintenance and outside services costs, and higher depreciation and vehicle 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 $4.5 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 2025.

•Propane margins and fees - Adjusted gross margin declined by $1.4 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.

CNG/RNG/LNG Transportation and Infrastructure

•Increased demand of virtual pipeline services - Adjusted gross margin increased by $10.7 million over 2024 largely due to increased demand for CNG and RNG hold services.

Aspire Energy

•Increased customer consumption - Adjusted gross margin increased by $2.6 million due to increased customer consumption related to the effects of colder weather in our Ohio service area and resulting from higher 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:

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2024 compared to 2023

The results for the Unregulated Energy segment for the year ended December 31, 2024 compared to 2023 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, 2024, which is incorporated by reference.

OTHER INCOME, NET

2025 Compared to 2024

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 $9.6 million and $2.0 million for 2025 and 2024, respectively. The increase in 2025 was largely attributable to higher gains on asset sales compared to the prior year.

INTEREST CHARGES

2025 Compared to 2024

Interest charges for 2025 increased by $4.1 million compared to the same period in 2024. This increase is primarily attributable to the Senior Notes issued in August and September 2025. Increased interest expense was partially offset by lower average outstanding Revolver borrowings, a lower weighted-average interest rate, and higher capitalized interest of $1.6 million associated with growth capital projects compared to the prior year. The weighted-average interest rate on our Revolver borrowings was 5.17 percent for the year ended December 31, 2025 compared to 5.68 percent during the prior year.

INCOME TAXES

2025 Compared to 2024

Income tax expense was $52.7 million for 2025 compared to $43.2 million for 2024. Our effective income tax rates were 27.3 percent and 26.7 percent for the years ended December 31, 2025 and 2024, respectively.

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 $470.4 million in 2025.

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The following table shows total capital expenditures for the year ended December 31, 2025 by segment and by business line:

In the table below, we have provided a range of our forecasted capital expenditures by category for 2026:

The 2026 forecast excludes potential acquisitions due to their opportunistic nature.

The Company continues to affirm its capital guidance for the five-year period ended 2028 of $1.5 billion to $1.8 billion, and projects capital expenditures of $450.0 million to $500.0 million for 2026.

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. The timing of capital expenditures can vary based on delays in regulatory approvals, securing environmental approvals and other permits. The regulatory application and approval process has lengthened in the past few years, and we expect this trend to continue.

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Capital Structure

We are committed to maintaining a sound capital structure and strong credit ratings. 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, 2025 and 2024 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 may, from time to time, allow our capital structure to fall below the target range to align the completion of large capital projects with the respective permanent financing.

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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.

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. For the year ended December 31, 2025 and 2024, we received net proceeds of $123.2 million and $72.5 million, respectively, associated with shares issued under the DRIP and our ATM program.

Shelf Agreements

We have entered into Shelf Agreements with Prudential and MetLife, however neither of such lenders have any obligation to purchase debt thereunder. We amended these agreements with Prudential and MetLife in February 2026 and June 2025, respectively, to expand the total borrowing capacity and extend the term of the agreements. As of the February 2026 amendment, a total of $343.3 million of borrowing capacity was available under these agreements with terms that extend through February 2029 and June 2030, respectively.

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.

In August 2025, we entered into a Note Purchase Agreement for the issuance of Senior Notes in the aggregate principal amount of $200.0 million with an initial funding of $150.0 million in August 2025 and an additional $50.0 million in September 2025. These Senior Notes have an average interest rate of 5.04 percent consisting of $60.0 million of 4.88 percent notes due in August 2028, $50.0 million of 5.02 percent notes due in September 2030, and $90.0 million of 5.16 percent notes due in August 2031. The proceeds received were used to reduce short-term borrowings under our Revolver and to fund capital expenditures. The outstanding principal balance of the Senior Notes will be due on their respective maturity dates with interest payments payable semiannually beginning in 2026 until the principal has been paid in full. These Senior Notes have similar covenants and default provisions as our other 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.

Short-Term Borrowings

We are authorized by our BOD to borrow up to $450.0 million of short-term debt, as required. At December 31, 2025 and 2024, we had $158.0 million and $196.5 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 4.73 percent and 5.06 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at December 31, 2025.

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 and $200.0 million available under the five-year tranche which expires in August 2029. In August 2025, we exercised an option under the Revolver to extend the 364-day tranche through August 2026. All other terms and conditions of the agreement remain unchanged. 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, 2025, we are in compliance with this covenant.

Our total available credit under the Revolver at December 31, 2025 was $287.2 million. As of December 31, 2025, we had issued $4.8 million in letters of credit to various counterparties under the Revolver. These letters of credit are not included in the outstanding short-term borrowings and we do not anticipate that they will be 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 14, 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, 2025, 2024 and 2023 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, 2025, 2024 and 2023:

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 2025, net cash provided by operating activities was $233.7 million. Operating cash flows were primarily impacted by the following:

•Net income, adjusted for non-cash adjustments, provided a $244.4 million source of cash;

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•An increased level of deferred taxes and investment tax credits which includes incremental tax depreciation from growth investments resulted in a source of cash of $28.8 million; partially offset by

•Net changes in assets and liabilities resulted in a use of cash of $39.5 million mainly due to an increase in net receivables, accrued revenue and regulatory assets.

Cash Flows Used in Investing Activities

Net cash used in investing activities totaled $435.7 million during the year ended December 31, 2025, largely driven by $448.6 million for new capital expenditures partially offset by $12.9 million of proceeds from asset sales.

Cash Flows Provided by Financing Activities

Net cash provided by financing activities totaled $195.9 million for the year ended December 31, 2025. This source of cash was largely related to:

•A net increase in long-term debt borrowings resulting in a net source of cash of $173.6 million, including $199.1 million from issuances partially offset by long-term repayments of $25.5 million;

•Net proceeds of $123.0 million from the issuance of common stock under the DRIP and ATM program; partially offset by the following:

•Net repayments under the Revolver of $39.4 million, and

•A $60.7 million use of cash for dividend payments in 2025.

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CONTRACTUAL OBLIGATIONS

We have the following contractual obligations and other commercial commitments as of December 31, 2025:

(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 $73.0 million, $123.4 million, $86.6 million and $98.2 million, respectively, for the periods indicated above. Expected interest payments for all periods total $381.2 million.

(2) See Item 8, Financial Statements and Supplementary Data, Note 2, Summary of Significant Accounting Policies, for additional information.

(3) See Item 8, Financial Statements and Supplementary Data, Note 19, 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 15, Employee Benefit Plans, for additional information on the plans.

(5) The FPU Pension Plan was in a over funded position at December 31, 2025. 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. See Item 8, Financial Statements and Supplementary Data, Note 15, Employee Benefit Plans, for further information on the plans. Additionally, the Contractual Obligations table above includes deferred compensation obligations totaling $17.2 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 BOD 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, 2025 was $62.0 million. The aggregate amount guaranteed related to our subsidiaries at December 31, 2025 was approximately $41.1 million with the guarantees expiring on various dates through March 2026. In addition, the Board has authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at December 31, 2025 was $4.0 million.

As of December 31, 2025, we have issued letters of credit totaling approximately $4.8 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 2026. There have been no draws on these letters of credit as of December 31, 2025. 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 19, 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.

Regulatory Assets and Liabilities

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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 2025, 2024 and 2023 indicated that goodwill was not impaired. At December 31, 2025, our goodwill balance totaled $507.5 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 15, 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.

At December 31, 2025, actuarial assumptions include expected long-term rates of return on plan assets for FPU's pension plan of 5.50 percent and a discount rate of 5.25 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

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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.