CHESAPEAKE UTILITIES CORP 10-Q

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; 27 Table of Contents • 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. 28 Table of Contents 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 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. The Company believes 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. Unless otherwise noted, EPS and Adjusted EPS information are presented on a diluted basis. 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 three months ended March 31, 2026 and 2025: Adjusted Gross Margin For the Three Months Ended March 31, 2026 (in millions) Regulated Energy Unregulated Energy Other Businesses and Eliminations Total Operating Revenues $ 249.3 $ 113.7 $ (9.9) $ 353.1 Cost of Sales: Natural gas, propane and electric costs (101.6) (55.1) 9.8 (146.9) Depreciation & amortization (16.1) (5.4) — (21.5) Operations & maintenance expenses (1) (16.7) (10.9) 0.1 (27.5) Gross Margin (GAAP) 114.9 42.3 — 157.2 Operations & maintenance expenses (1) 16.7 10.9 (0.1) 27.5 Depreciation & amortization 16.1 5.4 — 21.5 Adjusted Gross Margin (Non-GAAP) $ 147.7 $ 58.6 $ (0.1) $ 206.2 29 Table of Contents For the Three Months Ended March 31, 2025 (in millions) Regulated Energy Unregulated Energy Other Businesses and Eliminations Total Operating Revenues $ 199.6 $ 106.7 $ (7.6) $ 298.7 Cost of Sales: Natural gas, propane and electric costs (71.5) (52.2) 7.4 (116.3) Depreciation & amortization (17.6) (4.9) — (22.5) Operations & maintenance expenses (1) (13.3) (9.7) 0.3 (22.7) Gross Margin (GAAP) 97.2 39.9 0.1 137.2 Operations & maintenance expenses (1) 13.3 9.7 (0.3) 22.7 Depreciation & amortization 17.6 4.9 — 22.5 Adjusted Gross Margin (Non-GAAP) $ 128.1 $ 54.5 $ (0.2) $ 182.4 (1) Operations & maintenance expenses within the condensed 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. 2026 to 2025 Gross Margin (GAAP) Variance – Regulated Energy Gross Margin (GAAP) for the Regulated Energy segment for the three months ended March 31, 2026 was $114.9 million, an increase of $17.7 million, or 18.2 percent, compared to the same period in 2025. The increase in gross margin largely reflects incremental margin from regulatory initiatives and infrastructure programs, pipeline expansion projects, and organic growth in our natural gas distribution businesses. 2026 to 2025 Gross Margin (GAAP) Variance – Unregulated Energy Gross Margin (GAAP) for the Unregulated Energy segment for the three months ended March 31, 2026 was $42.3 million, an increase of $2.4 million, or 6.0 percent, compared to the same period in 2025. The increase in gross margin was primarily attributable to higher results from our propane distribution business largely attributable to increased customer consumption from colder year-over-year weather in our Delmarva service areas, and increased performance from Aspire Energy. 30 Table of Contents Adjusted Net Income and Adjusted EPS Three Months Ended March 31, (dollars in millions, shares in thousands (except per share data)) 2026 2025 Net Income (GAAP) $ 59.3 $ 50.9 FCG transaction and transition-related expenses, net (1) — 0.2 Adjusted Net Income (Non-GAAP) $ 59.3 $ 51.1 Weighted average common shares outstanding - diluted 24,053 23,041 Earnings Per Share - Diluted (GAAP) $ 2.47 $ 2.21 FCG transaction and transition-related expenses, net (1) — 0.01 Adjusted Earnings Per Share - Diluted (Non-GAAP) $ 2.47 $ 2.22 (1) Transaction and transition-related expenses represent non-recurring costs incurred attributable to the acquisition and integration of FCG including, but not limited to, transition services, consulting, system integration, rebranding, and legal fees. 2026 to 2025 Net Income (GAAP) Variance Net income (GAAP) for the three months ended March 31, 2026 was $59.3 million, or $ 2.47 per share, compared to $50.9 million, or $2.21 per share, for the same quarter of 2025. Net income for the three months ended March 31, 2025 included $0.2 million of transaction and transition-related expenses in connection with the acquisition and integration of FCG. Excluding these costs, net income increased by $8.2 million or 16.0 percent compared to the prior-year period. 31 Table of Contents Results of Operations for the Three Months Ended March 31, 2026 Operational Highlights Our adjusted net income for the three months ended March 31, 2026 was $59.3 million, or $2.47 per share, compared to $51.1 million, or $2.22 per share, for the same period in 2025. Operating income for the first three months of 2026 was $99.4 million, an increase of $12.6 million compared to the same period in 2025. Excluding transaction and transition-related expenses associated with the acquisition and integration of FCG, operating income increased $12.3 million or 14.1 percent compared to the prior-year period. The increase in adjusted gross margin in the first quarter of 2026 was primarily driven by incremental margin from regulatory initiatives and infrastructure programs, pipeline expansion projects and natural gas organic growth, increased customer consumption resulting from year-over-year colder temperatures largely in the Company's Delmarva service areas, and improved performance at Aspire Energy. Higher operating expenses were driven largely by increased payroll, benefits and other employee-related expenses and higher facilities, maintenance costs and outside services compared to the prior-year period. Depreciation and amortization expense for the current period includes decreases related to certain regulatory items including the absence of recovered costs associated with Hurricane Michael and the impact of the FCG depreciation study. These amounts were largely offset by additional depreciation, amortization and property taxes associated with growth. 32 Table of Contents Three Months Ended March 31, Increase 2026 2025 (Decrease) (in millions, except shares (thousands) and per share data) Adjusted Gross Margin Regulated Energy segment $ 147.7 $ 128.1 $ 19.6 Unregulated Energy segment 58.6 54.5 4.1 Other Businesses and Eliminations (0.1) (0.2) 0.1 Total Adjusted Gross Margin $ 206.2 $ 182.4 $ 23.8 Operating Income Regulated Energy segment $ 71.1 $ 60.5 $ 10.6 Unregulated Energy segment 28.3 26.3 2.0 Other Businesses and Eliminations — — — Total Operating Income 99.4 86.8 12.6 Other income, net — 0.6 (0.6) Interest charges 18.7 18.1 0.6 Income Before Income Taxes 80.7 69.3 11.4 Income taxes 21.4 18.4 3.0 Net Income $ 59.3 $ 50.9 $ 8.4 Weighted Average Common Shares Outstanding: Basic 23,937 22,957 980 Diluted 24,053 23,041 1,012 Earnings Per Share of Common Stock Basic $ 2.48 $ 2.22 $ 0.26 Diluted $ 2.47 $ 2.21 $ 0.26 Adjusted Net Income and Adjusted Earnings Per Share Net Income (GAAP) $ 59.3 $ 50.9 $ 8.4 FCG transaction and transition-related expenses, net (1) — 0.2 (0.2) Adjusted Net Income (Non-GAAP) $ 59.3 $ 51.1 $ 8.2 Earnings Per Share - Diluted (GAAP) $ 2.47 $ 2.21 $ 0.26 FCG transaction and transition-related expenses, net (1) — 0.01 (0.01) Adjusted Earnings Per Share - Diluted (Non-GAAP) $ 2.47 $ 2.22 $ 0.25 (1) Transaction and transition-related expenses represent costs incurred attributable to the acquisition and integration of FCG including, but not limited to, transition services, consulting, system integration, rebranding and legal fees. 33 Table of Contents Key variances between the three months ended March 31, 2025 and March 31, 2026 included: (in millions, except per share data) Pre-tax Income Net Income Earnings Per Share Three Months Ended March 31, 2025 Adjusted Results (1) $ 69.7 $ 51.1 $ 2.22 Change in Adjusted Gross Margins: Natural gas transmission service expansions, including interim services (2) 6.9 5.1 0.21 Contributions from regulated infrastructure programs (2) 5.5 4.0 0.17 Changes in customer consumption 4.5 3.3 0.14 Rate changes associated with recent rate case activities (2) 4.1 3.0 0.13 Natural gas growth including conversions (excluding service expansions) 2.0 1.5 0.06 Increased Aspire Energy performance - rate changes and gathering fees 1.4 1.0 0.04 Change in off-system natural gas capacity sales 1.1 0.8 0.03 Absence of recovered costs associated with Hurricane Michael (3) (2.0) (1.5) (0.06) 23.5 17.2 0.72 Increased Operating Expenses (Excluding Natural Gas, Propane, and Electric Costs): Payroll, benefits and other employee-related expenses (6.6) (4.9) (0.20) Facilities expenses, maintenance costs and outside services (3.1) (2.2) (0.09) Depreciation, amortization and property taxes (1.5) (1.1) (0.05) Credit, collections and customer service costs (1.4) (1.1) (0.04) Absence of amortization of costs associated with Hurricane Michael recovery (3) 2.0 1.5 0.06 (10.6) (7.8) (0.32) Interest charges (0.6) (0.4) (0.02) Increase in shares outstanding due to 2025 and 2026 equity offerings (4) — — (0.09) Net other changes (1.3) (0.8) (0.04) (1.9) (1.2) (0.15) Three Months Ended March 31, 2026 Adjusted Results (1) $ 80.7 $ 59.3 $ 2.47 (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) The current period includes offsetting reductions in both adjusted gross margin and depreciation and amortization expense related to the absence of recovered costs associated with Hurricane Michael. (4) Reflects the impact of approximately 0.8 million common shares issued under the DRIP/DSSP and ATM program. 34 Table of Contents Summary of Key Factors Recently Completed and Ongoing Major Projects and Initiatives We continuously 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 all major projects and initiatives that are currently underway or recently completed. Our practice is to add incremental margin associated with new projects and regulatory initiatives to this table once negotiations or details are substantially final and/or the associated earnings can be estimated. Major projects and initiatives that have generated consistent year-over-year adjusted gross margin contributions are removed from the table at the beginning of the next calendar year. Adjusted Gross Margin Three Months Ended Year Ended Estimate for March 31, December 31, Fiscal (in millions) 2026 2025 2025 2026 2027 Pipeline Expansions: St. Cloud / Twin Lakes Expansion $ 1.0 $ 0.1 $ 2.9 $ 3.8 $ 3.8 Wildlight 1.1 0.5 2.6 4.3 4.3 Worcester Resiliency Upgrade 0.4 — 0.3 1.5 17.1 Boynton Beach 0.9 0.5 3.0 3.4 3.4 New Smyrna Beach 0.6 — 1.6 2.6 2.6 Central Florida Reinforcement 1.1 0.3 2.6 4.3 4.3 Renewable Natural Gas Supply Projects 1.3 — 2.5 5.4 6.4 Miami Inner Loop 1.9 — 2.8 7.6 7.6 Duncan Plains — — — — 1.1 Total Pipeline Expansions 8.3 1.4 18.3 32.9 50.6 Regulatory Initiatives: Florida GUARD program 2.4 1.5 7.1 10.1 13.0 FCG SAFE Program 2.8 1.7 8.4 12.7 16.4 Capital Cost Surcharge Programs 2.3 1.5 5.7 9.0 10.1 Electric Storm Protection Plan 3.3 1.1 6.4 10.7 11.0 Florida Mandatory Relocates 0.5 — — 1.5 1.5 Maryland Rate Case (1) 1.3 — 1.5 3.5 3.5 Delaware Rate Case (1) 2.1 0.8 4.7 6.1 6.1 Electric Rate Case (1) 2.2 0.7 7.3 8.6 9.1 Florida City Gas Rate Case — — — TBD TBD Total Regulatory Initiatives 16.9 7.3 41.1 62.2 70.7 Total $ 25.2 $ 8.7 $ 59.4 $ 95.1 $ 121.3 (1) Includes adjusted gross margin attributable to interim and permanent rates. See additional information provided below. Detailed 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 approximately $0.6 million in 2026 and annually 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 35 Table of Contents 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. For the three months ended March 31, 2026, these projects generated incremental adjusted gross margin of $0.9 million. We expect this expansion to generate approximately $3.2 million in 2026 and annually 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, and construction was completed in 2025. The project generated incremental adjusted gross margin of $0.6 million for the three months ended March 31, 2026, and is expected to contribute adjusted gross margin of approximately $4.3 million in 2026 and annually 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, Delaware 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 commenced shortly after approval and is well underway. The weather during the first quarter resulted in several brief slowdowns which had a cumulative impact on the overall timeline. Project construction and commissioning are expected to be complete in the latter part of the year with the FERC approval process to immediately follow. The Company expects to receive full approval for in-service of the facility by the beginning of 2027. The project generated adjusted gross margin of $0.4 million for the three months ended March 31, 2026. The project is expected to contribute adjusted gross margin of approximately $1.5 million in 2026 and $17.1 million in 2027 and annually 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 incremental adjusted gross margin of $1.0 million for the three months ended March 31, 2026, and are expected to contribute adjusted gross margin of approximately $6.0 million in 2026 and annually 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 March 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 incremental adjusted gross margin of $0.8 million for the three months ended March 31, 2026, and both projects are expected to contribute total adjusted gross margin of approximately $4.3 million in 2026 and annually thereafter. 36 Table of Contents 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 $1.3 million for the three months ended March 31, 2026, and are projected to generate total adjusted gross margin of approximately $5.4 million in 2026 and $6.4 million annually 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 $1.9 million for the three months ended March 31, 2026 and is expected to contribute adjusted gross margin of approximately $7.6 million in 2026 and annually 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 $1.1 million in 2027 and approximately $2.1 million annually thereafter. 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 t he three months ended March 31, 2026 , there was $0.9 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. 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 t he three months ended March 31, 2026 , there was $1.1 million of incremental 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 enable FCG to accelerate remediation related to problematic pipe and facilities consisting of obsolete and exposed pipe. These modifications will improve the safety and reliability of service to FCG's customers and result in an estimated additional $50.0 million in capital expenditures associated with the SAFE Program, increasing the total projected capital expenditures to approximately $255.0 million over a 10-year period. The Florida PSC approved the modifications in September 2024. 37 Table of Contents 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. In March 2026, Eastern Shore submitted an annual true-up 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. There was a slight decrease to the revenue requirement of the currently effective surcharge as a result of the true-up. The FERC issued an order approving the surcharge as filed effective April 1, 2026. For t he three months ended March 31, 2026 , there was $0.8 million of incremental adjusted gross margin generated pursuant to the program. Eastern Shore expects to generate 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 three months ended March 31, 2026, this initiative generated additional adjusted gross margin of $2.2 million and is expected to generate $10.7 million of adjusted gross margin in 2026 and $11.0 million in 2027. We expect continued investment under the SPP going forward. 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 Florida PSC approved the petition in February 2026, with the surcharge effective in March 2026. For the three months ended March 31, 2026, there was $0.5 million of adjusted gross margin generated. The projected total revenue for both 2026 and 2027 is $0.5 million for FPU and $1.0 million for FCG. 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 September 2024, the Maryland Public Utility Judge approved a $2.6 million increase in annual base rates, which was followed by the Company submitting 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. In March 2025 the 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 three months ended March 31, 2026, there was $1.3 million of incremental adjusted gross margin generated and the proceeding is expected to result in additional adjusted gross margin of approximately $3.5 million in 2026 and 2027. 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) 38 Table of Contents 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 all interested parties 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 and approved tariff-related changes including rate design were effective as of October 15, 2025. For the three months ended March 31, 2026, there was $1.3 million of incremental adjusted gross margin generated and final rates are expected to generate approximately $6.1 million of adjusted gross margin in 2026 and 2027. 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. 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 three months ended March 31, 2026, there was $1.5 million of incremental 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. FCG Rate Case In April 2026, Florida City Gas filed a petition with the Florida PSC. In connection with the application, we are seeking approval of the following: (i) interim rate relief of approximately $16.2 million, subject to refund, pending the outcome of the rate case proceeding; (ii) general base rate increase of $46.9 million with a ROE of 11.25 percent based on a 2027 projected test year; (iii) reclassification of approximately $16.4 million in the existing SAFE program revenues from surcharge recovery to base rates; (iv) authorization to retain the unamortized portion of the previously approved acquisition adjustment; and (v) further implementation of the advanced metering infrastructure (“AMI”). 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. In February 2026, the Florida PSC approved a $6.8 million reserve imbalance to be amortized over the remaining life of the assets. 39 Table of Contents Other Major Factors Influencing Adjusted Gross Margin Weather Impact For the three months ended March 31, 2026, increased customer consumption, which includes the effects of colder weather conditions, largely in our Delmarva service areas, compared to the prior-year period resulted in a $4.5 million increase in adjusted gross margin. The following table summarizes HDD and CDD variances from the 10-year average HDD/CDD ("Normal") for the three months ended March 31, 2026 and 2025. Three Months Ended March 31, 2026 2025 Variance Delmarva Peninsula Actual HDD 2,348 2,210 138 10-Year Average HDD ("Normal") 2,085 2,146 (61) Variance from Normal 263 64 Florida Actual HDD 594 580 14 10-Year Average HDD ("Normal") 471 483 (12) Variance from Normal 123 97 Florida City Gas Actual HDD 357 300 57 10-Year Average HDD ("Normal") 229 221 8 Variance from Normal 128 79 Ohio Actual HDD 3,022 3,087 (65) 10-Year Average HDD ("Normal") 2,751 2,801 (50) Variance from Normal 271 286 Florida Actual CDD 226 189 37 10-Year Average CDD ("Normal") 220 217 3 Variance from Normal 6 (28) Natural Gas Distribution Growth The average number of residential customers served on the Delmarva Peninsula, by FPU and by FCG increased by approximately 3.3 percent, 2.2 percent, and 2.0 percent, respectively, for the three months ended March 31, 2026. The details of the adjusted gross margin increase are provided in the following table: Three Months Ended March 31, 2026 (in millions) Delmarva Peninsula Florida Customer Growth: Residential $ 0.5 $ 0.8 Commercial and industrial — 0.7 Total Customer Growth $ 0.5 $ 1.5 40 Table of Contents Regulated Energy Segment For the quarter ended March 31, 2026 compared to the quarter ended March 31, 2025: Three Months Ended March 31, 2026 2025 Change (in millions) Revenue $ 249.3 $ 199.6 $ 49.7 Regulated natural gas and electric costs 101.6 71.5 30.1 Adjusted gross margin (1) (2) 147.7 128.1 19.6 Operations & maintenance 49.3 39.4 (9.9) Depreciation, amortization and property taxes (2) 25.0 25.9 0.9 Other taxes 2.3 2.0 (0.3) FCG transaction and transition-related expenses (3) — 0.3 0.3 Total operating expenses 76.6 67.6 (9.0) Operating income $ 71.1 $ 60.5 $ 10.6 (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) The current period includes offsetting reductions in both adjusted gross margin and depreciation and amortization expense related to the absence of recovered costs associated with Hurricane Michael. See Key variances table above for additional information. (3) Transaction and transition-related expenses represent costs incurred attributable to the acquisition and integration of FCG including, but not limited to, transition services, consulting, system integration, rebranding and legal fees. Operating income for the Regulated Energy segment for the first quarter of 2026 was $71.1 million, an increase of $10.6 million, over the same period in 2025. Excluding transaction and transition-related expenses associated with the acquisition and integration of FCG, operating income increased $10.3 million, or 16.9 percent, compared to the same period in 2025. Higher operating income reflects incremental margin from 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, the increase in total operating expenses of $9.3 million was largely attributable to higher expenses associated with payroll, benefits and other employee related expenses, higher facilities, maintenance costs and outside services, and increased costs related to credit, collections and customer service. Depreciation and amortization expense for the current period includes decreases related to certain regulatory items including the absence of recovered costs associated with Hurricane Michael and the impact of the FCG depreciation study. These amounts were largely offset by additional depreciation, amortization and property taxes associated with growth. 41 Table of Contents Items contributing to the quarter-over-quarter increase in adjusted gross margin are listed in the following table: (in millions) Natural gas transmission service expansions, including interim services $ 6.9 Contributions from regulated infrastructure programs 5.5 Rate changes associated with recent rate case activities (1) 4.1 Natural gas growth including conversions (excluding service expansions) 2.0 Changes in customer consumption 1.7 Adjusted gross margin from off-system natural gas capacity sales 1.1 Absence of recovered costs associated with Hurricane Michael (2) (2.0) Other variances 0.3 Quarter-over-quarter increase in adjusted gross margin $ 19.6 (1) Includes adjusted gross margin contributions from permanent base rates. Refer to Major Projects discussion for additional information. (2) The current period includes offsetting reductions in both adjusted gross margin and depreciation and amortization expense related to the absence of recovered costs associated with Hurricane Michael. The following narrative discussion provides further detail and analysis of the significant items in the table above: Natural Gas Transmission Service Expansions, including interim services We generated increased adjusted gross margin of $6.9 million for the three months ended March 31, 2026 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 $5.5 million for the three months ended March 31, 2026. The increase in adjusted gross margin was primarily related to FCG's SAFE program, Florida's GUARD program, Eastern Shore's Capital Cost Surcharge program, and FPU Electric's SPP. Refer to Note 5, Rates and Other Regulatory Activities , in the condensed 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 $4.1 million for the three months ended March 31, 2026. Refer to Note 5, Rates and Other Regulatory Activities , in the condensed consolidated financial statements for additional information. Natural Gas Distribution Customer Growth We generated additional adjusted gross margin of $2.0 million from natural gas customer growth. Adjusted gross margin increased by $1.5 million for our Florida natural gas distribution service territories and $0.5 million on the Delmarva Peninsula for the three months ended March 31, 2026, as compared to the same period in 2025, due to residential customer growth in these service areas, as well as growth attributable to commercial and industrial customers. Changes in Customer Consumption Customer consumption, inclusive of weather-related consumption, increased adjusted gross margin by $1.7 million for the three months ended March 31, 2026. Adjusted Gross Margin from Off-system Natural Gas Capacity Sales Off-system natural gas capacity sales increased adjusted gross margin by $1.1 million for the three months ended March 31, 2026. Absence of Recovered Costs Associated with Hurricane Michael There is no impact to earnings as this $2.0 million decrease in adjusted gross margin for the three months ended March 31, 2026, is offset by a corresponding decrease in depreciation and amortization expense for the period. 42 Table of Contents Operating Expenses Items contributing to the quarter-over-quarter increase in operating expenses are listed in the following table: (in millions) Payroll, benefits and other employee-related expenses $ (5.0) Facilities expenses, maintenance costs and outside services (2.7) Credit, collections and customer service costs (1.4) Depreciation, amortization and property tax costs (1.1) Absence of amortization of costs associated with Hurricane Michael recovery (1) 2.0 Other variances (0.8) Quarter-over-quarter increase in operating expenses $ (9.0) (1) The current period includes offsetting reductions in both adjusted gross margin and depreciation and amortization expense related to the absence of recovered costs associated with Hurricane Michael. 43 Table of Contents Unregulated Energy Segment For the quarter ended March 31, 2026 compared to the quarter ended March 31, 2025: Three Months Ended March 31, 2026 2025 Change (in millions) Revenue $ 113.7 $ 106.7 $ 7.0 Unregulated propane and natural gas costs 55.1 52.2 2.9 Adjusted gross margin (1) 58.6 54.5 4.1 Operations & maintenance 23.6 21.9 (1.7) Depreciation, amortization and property tax costs 5.8 5.5 (0.3) Other taxes 0.9 0.8 (0.1) Total operating expenses 30.3 28.2 (2.1) Operating income $ 28.3 $ 26.3 $ 2.0 (1) Adjusted Gross Margin is a non-GAAP measure utilized by management to review business unit performance. For a more detailed discussion on the differences between Gross Margin (GAAP) and Adjusted Gross Margin, see the Reconciliation of GAAP to Non-GAAP Measures presented above. Operating results for the Unregulated Energy segment for the three months ended March 31, 2026 reflect a $2.0 million increase compared to the same period in 2025. The increase in adjusted gross margin in the Unregulated Energy segment during the first quarter of 2026 was primarily due to increased consumption in our propane distribution business which was impacted by colder weather in the Delmarva service areas as well as improved performance from Aspire Energy. The increase in operating expenses included higher payroll, benefits and other employee-related expenses, increased facilities, maintenance and outside service costs, and higher depreciation, amortization and property tax costs compared to the prior-year period. Items contributing to the quarter-over-quarter increase in adjusted gross margin are listed in the following table: (in millions) Propane Operations Increased propane customer consumption $ 2.4 Aspire Energy Increased performance from Aspire Energy - rate changes and gathering fees 1.4 Increased customer consumption 0.4 Other variances (0.1) Quarter-over-quarter increase in adjusted gross margin $ 4.1 The following narrative discussion provides further detail and analysis of the significant items in the table above. Propane Operations • Propane customer consumption - Adjusted gross margin increased by $2.4 million due to increased customer consumption resulting primarily from colder year-over-year weather in our Delmarva service areas. Aspire Energy • Increased performance from Aspire Energy - Adjusted gross margin increased by $1.4 million compared to the prior-year period due to negotiated rate changes and increased gathering fees. • Increased customer consumption - Adjusted gross margin increased by $0.4 million due to increased customer consumption during the current year primarily related to year-over-year colder weather in our Ohio service area. Operating Expenses Items contributing to the quarter-over-quarter increase in operating expenses are listed in the following table: 44 Table of Contents (in millions) Payroll, benefits and other employee-related expenses $ (1.6) Facilities expenses, maintenance costs and outside services (0.4) Other variances (0.1) Quarter-over-quarter increase in operating expenses $ (2.1) OTHER INCOME, NET For the quarter ended March 31, 2026 compared to the quarter ended March 31, 2025 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, was not material in the first quarter of 2026 compared to $0.6 million during the prior-year period. INTEREST CHARGES For the quarter ended March 31, 2026 compared to the quarter ended March 31, 2025 Interest charges for the quarter ended March 31, 2026 increased by $0.6 million compared to the same period in 2025, attributable primarily to the Senior Notes issued in August and September 2025. Interest expense on Revolver borrowings slightly offset the interest charges increase due to lower average outstanding borrowings and a steady weighted-average interest rate of 5.1 percent for the quarters ended March 31, 2026 and 2025. Increased interest charges were also offset by higher capitalized interest during the current period of $1.4 million associated with capital projects. INCOME TAXES For the quarter ended March 31, 2026 compared to the quarter ended March 31, 2025 Income tax expense was $21.4 million and $18.4 million for the quarters ended March 31, 2026 and March 31, 2025, respectively, resulting in an effective income tax rate of 26.5 percent and 26.6 percent, respectively, during the periods then ended. F INANCIAL P OSITION , L IQUIDITY AND C APITAL R ESOURCES 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, which we believe will provide sufficient liquidity to fund our current obligations, debt service requirements and capital expenditures over the next twelve months. 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 for the issuance of common stock in various types of equity offerings, including pursuant to our DRIP/DSPP and ATM 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/DSPP 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 $121.9 million for the three months ended March 31, 2026. 45 Table of Contents In the table below, we have provided the range of our forecasted capital expenditures for 2026: 2026 (in millions) Low High Regulated distribution $ 110.0 $ 120.0 Regulated transmission 135.0 145.0 Regulated infrastructure 90.0 100.0 Unregulated business 25.0 35.0 Technology 90.0 100.0 Total 2026 Forecasted Capital Expenditures $ 450.0 $ 500.0 The 2026 projection excludes potential acquisitions due to their opportunistic nature. 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 political and 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, in our 2025 Annual Report on Form 10-K. 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 table presents our capitalization, excluding and including short-term borrowings, as of March 31, 2026 and December 31, 2025: March 31, 2026 December 31, 2025 (in millions) Long-term debt, net of current maturities $ 1,325.3 45 % $ 1,327.1 45 % Stockholders’ equity 1,651.7 55 % 1,598.5 55 % Total capitalization, excluding short-term debt $ 2,977.0 100 % $ 2,925.6 100 % March 31, 2026 December 31, 2025 (in millions) Short-term debt $ 199.6 6 % $ 158.0 5 % Long-term debt, including current maturities 1,459.9 44 % 1,461.7 45 % Stockholders’ equity 1,651.7 50 % 1,598.5 50 % Total capitalization, including short-term debt $ 3,311.2 100 % $ 3,218.2 100 % Our target ratio of equity to total capitalization, including short-term borrowings, is between 50 and 60 percent. Our equity to total capitalization ratio, including short-term borrowings, was 50 percent as of March 31, 2026. 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. 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, subject to an effective shelf registration statement. For the three months ended March 31, 2026 and 2025, we received net proceeds of $5.1 million and $19.8 million, respectively, associated with shares issued under the DRIP/DSPP as well as shares issued under our ATM program. 46 Table of Contents Shelf Agreements We have entered into Shelf Agreements with Prudential and MetLife with terms that extend through February 2026 and June 2030, respectively, however neither of such lenders have any obligation to purchase debt thereunder. In June 2025, we amended our Shelf Agreement with MetLife to expand the total borrowing capacity and extend the term of the agreement for an additional five years. At March 31, 2026, a total of $343.3 million of borrowing capacity was available under these Shelf Agreements. 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. Short-term Borrowings As of March 31, 2026, we are authorized by our BOD to borrow up to $450.0 million of short-term debt, as required. At March 31, 2026 and December 31, 2025, we had $199.6 million and $158.0 million, respectively, of short-term borrowings outstanding at a weighted average interest rate of 4.66 percent and 4.73 percent, respectively. There were no borrowings outstanding under the sustainable investment sublimit of the 364-day tranche at March 31, 2026. 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 12, Derivative Instruments . The availability of funds under the Revolver is subject to conditions specified in the credit agreement, all of which we currently satisfy. These conditions include our compliance with financial covenants and the continued accuracy of representations and warranties contained in the Revolver's loan documents. We are required by the financial covenants in the Revolver to maintain, at the end of each fiscal year, a funded indebtedness ratio of no greater than 65 percent. As of March 31, 2026, we were in compliance with this covenant. Our total available credit under the Revolver at March 31, 2026 was $245.6 million. As of March 31, 2026, 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. Long-Term Debt 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. 47 Table of Contents Cash Flows The following table provides a summary of our operating, investing and financing cash flows for the three months ended March 31, 2026 and 2025: Three Months Ended March 31, (in millions) 2026 2025 Net cash provided by (used in): Operating activities $ 118.0 $ 85.0 Investing activities (141.7) (113.1) Financing activities 26.6 20.9 Net increase (decrease) in cash and cash equivalents 2.9 (7.2) Cash and cash equivalents—beginning of period 1.8 7.9 Cash and cash equivalents—end of period $ 4.7 $ 0.7 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 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. During the three months ended March 31, 2026, net cash provided by operating activities was $118.0 million. Operating cash flows were primarily impacted by the following: • Net income, adjusted for non-cash adjustments, provided a $89.1 million source of cash; • An increased level of deferred taxes associated largely with incremental tax depreciation from growth investments resulted in a source of cash of $20.0 million; and • Working capital changes resulted in a $8.8 million source of cash. Cash Flows Used in Investing Activities Net cash used in investing activities totaled $141.7 million during the three months ended March 31, 2026, primarily attributable to $141.9 million related to new capital expenditures. Cash Flows Provided by Financing Activities Net cash provided by financing activities totaled $26.6 million during the three months ended March 31, 2026 and was largely impacted by the following: • Net borrowings under the Revolver of $42.0 million; and • A $16.2 million use of cash for dividend payments in 2026. 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 March 31, 2026 was $81.0 million. The aggregate amount guaranteed related to our subsidiaries at March 31, 2026 was $52.4 million , with the guarantees expiring on various dates through March 2027 . In addition, the BOD authorized us to issue specific purpose corporate guarantees. The amount of specific purpose guarantees outstanding at March 31, 2026 was $4.0 million. As of March 31, 2026, we have issued letters of credit totaling $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 throu gh October 2026 and to date, none have been used. We do not anticipate that the counterparties will draw upon these letters of credit and we expect that they will be renewed to the extent necessary in the future. Additional information is presented in Note 7 , Other Commitments and Contingencies, in the condensed consolidated financial statements. 48 Table of Contents Contractual Obligations There has been no material change in the contractual obligations presented in our 2025 Annual Report on Form 10-K. Rates and Regulatory Matters Our natural gas distribution operations in Delaware, Maryland and Florida and electric distribution operation in Florida are subject to regulation by the respective state PSC; Eastern Shore is subject to regulation by the FERC; and Peninsula Pipeline and Aspire Energy Express, our intrastate pipeline subsidiaries, are subject to regulation (excluding cost of service) by the Florida PSC and Public Utilities Commission of Ohio, respectively. We regularly are involved in regulatory matters in each of the jurisdictions in which we operate. Our significant regulatory matters are fully described in Note 5 , Rates and Other Regulatory Activities , to the condensed consolidated financial statements in this Quarterly Report on Form 10-Q. Recent Authoritative Pronouncements on Financial Reporting and Accounting Recent accounting developments, applicable to us, and their expected impact on our financial position, results of operations and cash flows, are described in Note 1 , Summary of Accounting Policies , to the condensed consolidated financial statements in this Quarterly Report on Form 10-Q.