NFG 10-K & 10-Q changes, risk factors and insider trading

The Company’s short-term bank loans, commercial paper, and borrowings under the Term Loan Agreement, entered into on February 14, 2024 with six lenders (the “Term Loan Agreement”), are in the form of floating rate debt or debt that may have rates fixed for short periods of time (up to six months), resulting in exposure to interest rate fluctuations in the absence of interest rate hedging transactions. The cost of long-term debt, the interest rates on the Company’s short-term bank loans, commercial paper, and borrowings under its Term Loan Agreement, and the ability of the Company to issue commercial paper are affected by its credit ratings published by S&P, Moody’s Investors Service, Inc. and Fitch Ratings, Inc. A downgrade in the Company’s credit ratings could increase borrowing costs, restrict or eliminate access to commercial paper markets, negatively impact the availability of capital from uncommitted sources, and require the Company’s subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. Additionally, $1.4$2.4 billion of the Company’s outstanding long-term debt would be subject to an interest rate increase if certain fundamental changes occur that involve a material subsidiary and result in a downgrade of a credit rating assigned to the notes below investment grade. In addition to the $1.4 billion, another $500 million of the Company’s outstanding long-term debt would be subject to an interest rate increase based solely on a downgrade of a credit rating assigned to the notes below investment grade, regardless of any additional fundamental changes.

The laws, regulations and other initiatives to address climate change may impact the Company’s financial results. It is not possible at this time to determine whether changes in the federal administration may change the regulatory focus and/or implementation of rules relating to climate change. In early 2021, the U.S. rejoined the Paris Agreement, the international effort to establish emissions reduction goals for signatory countries. Under the Paris Agreement, signatory countries are expected to submit their nationally determined contributions to curb greenhouse gas emissions and meet the agreed temperature objectives every five years. On April 22, 2021, the federal administration announced the U.S. nationally determined contribution to achieve a fifty to fifty-two percent reduction from 2005 levels in economy-wide net greenhouse gas pollution by 2030. Executive orders from the federal administration, in addition to federal,Federal, state and local legislative and regulatory initiatives proposed or adopted in an attempt to limit the effects of climate change, including greenhouse gas emissions, could have significant impacts on the energy industry including government-imposed limitations, prohibitions or moratoriums on the use and/or production of natural gas, establishment of a carbon tax and/or methane fee, lack of support for system modernization, as well as accelerated depreciation of assets and/or stranded assets.

Federal and state legislatures have from time to time considered bills that would establish a cap-and-trade program, cap-and-invest program, methane fee, carbon tax, or other similar mechanisms to provide incentive for the reduction of greenhouse gas emissions. A number of states have also adopted energy strategies or plans with goals that include the reduction of greenhouse gas emissions. For example, Pennsylvania has a methane reduction framework for the natural gas industry which has resulted in permitting changes with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. Furthermore, in 2019, the New York State legislature passed the CLCPA, which created emission reduction and electrification mandates, and could ultimately impact the Utility segment’s customer base and business. Pursuant to the CLCPA, in December 2022, New York’s Climate Action Council (“CAC”) approved a final scoping plan that includes recommendations to strategically downsize and decarbonize the natural gas system and curtail use of natural gas and natural gas appliances.appliances, Theas finalwell scoping plan was approved on December 19, 2022 and includes detailedas recommendations to meet the CLCPA’s emissions reduction targets in the transportation, buildings, electricity, industry, agriculture & forestry and waste sectors. The final scoping plan also recommends statewide and cross-sector policies relevant to gas system transition, economywide strategies, land use, local government, and adaptation and resilience. Additionally, the scoping plan recommends the implementation of a cap-and-invest program in New York. In January 2023, New York’s Governor directed the NYDEC and the New York State Energy Research and Development Authority to advance an economywide cap-and-invest program that establishes a declining cap on greenhouse gas emissions, and invests in programs to drive emissions reductions. In addition, in October 2025, a New York State court directed NYDEC to promulgate rules and regulations to ensure compliance with emissions reductions limits outlined in the CLCPA by February 6, 2026, which may include such a cap-and-invest program. If this proposed program or a similar program becomes effective and the Company becomes subject to new or revised cap-and-trade programs, cap-and-invest programs, methane charges, fees for carbon-based fuels or other similar costs or charges, the Company may experience additional costs and incremental operating expenses, which would impact our future earnings and cash flows, and may also experience decreased revenue in the event that implementation of these policies leads to reduced demand for natural gas.

In addition to the CLCPA, legislation or regulation that aims to reduce greenhouse gas emissions could also include natural gas bans, greenhouse gas emissions limits and reporting requirements, carbon taxes and/or similar fees on carbon dioxide, methane or equivalent emissions, restrictive permitting, increased efficiency standards requiring system remediation and/or changes in operating practices, and incentives or mandates to conserve energy or use renewable energy sources. For example, in May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to various exemptions. While the Company does not currently expect that this legislation will have a substantial impact on its financial results or operations, future legislation or regulation that aims to reduce natural gas demand or to impose additional operations requirements or restrictions on natural gas facilities, if effectuated, could impact our future earnings and cash flows. In addition, in December 2024 (and later amended in February 2025), New York’s Governor signed the Climate Change Superfund Act into law, which will require certain fossil fuel producers, refiners and related entities to pay into a state “climate superfund” an amount commensurate with the entity’s past global greenhouse gas emissions over a specified period of time. The NYDEC has until June 2027 to develop implementing regulations. The Act is currently the subject of multiple federal court lawsuits challenging its constitutionality.

Further, recentthe trends directedtrend toward a low-carbon economy could shift funding away from, or limit or restrict certain sources of funding for, companies focused on fossil fuel-related development or carbon-intensive investments. To the extent financial markets view climate change and greenhouse gas emissions as a financial risk, the Company’s cost of and access to capital could be negatively impacted.

Organized opposition to the natural gas industry, including exploration and production activity, pipeline expansion and replacement projects, and the extension and continued operation of natural gas distribution systems, may continue to increase as a result of, among other things, safety incidents involving natural gas facilities, and concerns raised by policymakers, financial institutions and advocacy groups about greenhouse gas emissions, hydraulic fracturing, or fossil fuels generally. This opposition may lead to increased regulatory and legislative initiatives that could place limitations, prohibitions or moratoriums on the use and development of natural gas, impose costs tied to carbon emissions, provide cost advantages to alternative energy sources, or impose mandates that increase operational costs associated with new or existing natural gas infrastructure and technology. There are also increasing litigation risks associated with climate change concerns and related disclosures. Increased litigation could cause operational delays or restrictions, and increase the Company’s operating costs. In turn, these factors could impact the competitive position of natural gas, ultimately affecting the Company’s results of operations and cash flows.

Construction of planned distribution, gathering, and transmission pipeline and storage facilities, as well as the expansion and replacement of existing facilities, and the development of new natural gas wells, is subject to various regulatory, environmental, political, legal, economic and other development risks, including the ability to obtain necessary approvals and permits from regulatory agencies on a timely basis and on acceptable terms, or at all. Existing or potential third-party opposition, such as opposition from landowner and environmental groups, which are beyond our control, could materially affect the anticipated construction of a project as well as the renewal or modification of key permits for ongoing operations. In addition, third parties could impede the Company’s acquisition, expansion or renewal of rights-of-way or land rights on a timely basis and on acceptable terms. Any delay in project development or construction may prevent a planned project from going into service when anticipated, which could cause a delay in the receipt of revenues from those facilities, result in increased project costs due to extended construction timeframes and asset write-offs, and materially impact operating results or anticipated results. Additionally, delays in pipeline construction projects or gathering facility completion could impede the Exploration and Production segment’sSeneca’s ability to transport its production, or to fulfill obligations to sell at contracted delivery points.

The Company may be adversely affected by economic conditionsconditions, including trade policies, and their impact on our suppliers and customers.

Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity could adversely affect the Company’s revenues and cash flows or restrict its future growth. Additionally, current tariffs, as well as the imposition of additional tariffs on U.S. imports of various goods and related retaliatory tariffs, as well as supply chain disruptions, and the associated costs and inflation related thereto, could have an impact on the Company’s operations. Economic conditions in the Company’s utility service territories, along with legislative and regulatory prohibitions and/or limitations on terminations of service, also impact its collections of accounts receivable. Customers of the Company’s Utility segment may have particular trouble paying their bills during periods of declining economic activity, high inflation, or high commodity prices, potentially resulting in increased bad debt expense and reduced earnings. Similarly, if reductions were to occur in funding of the federal Low Income Home Energy Assistance Program, or such funding was delayed or suspended for a prolonged period, bad debt expense could increase and earnings could decrease. In addition, exploration and production companies that are customers of the Company’s Pipeline and Storage segment may decide not to renew contracts for the same transportation capacity. Certain customers of the Company’s Exploration and Production segmentSeneca can represent a concentrated risk from time to time. Any of these events or circumstances could have or contribute to a material adverse effect on the Company’s results of operations, financial condition and cash flows.

Financial results in the Company’s ExplorationIntegrated Upstream and ProductionGathering segment are materially dependent on prices received for its natural gas production. Both short-term and long-term price trends affect the economics of exploring for, developing, producing, and gathering natural gas. Natural gas prices can be volatile and can be affected by various factors, including weather conditions, natural disasters, consumer demand, national and worldwide economic conditions, economic disruptions caused by terrorist activities, acts of war or major accidents, domestic and foreign political conditions and events, the price and availability of alternative fuels, the proximity to, and availability of, sufficient availability of and capacity on transportation and liquefaction facilities, regional and global levels of supply and demand, energy conservation measures, and government regulations. The Company sells the natural gas that it produces at a combination of current market prices, indexed prices or through fixed- price contracts. The Company hedges a substantial portion of future sales that are based on indexed prices utilizing the physical sale counterparty and/or the financial markets. The prices the Company receives depend upon factors beyond the Company’s control, including the factors affecting price mentioned above. Any prolonged reduction in natural gas prices could result in the Company reducing the level of exploration and production activity the Company otherwise would pursue, which could have a material adverse effect on its future revenues, cash flows and results of operations.

To protect itself to some extent against price volatility and to lock in fixed pricing on natural gas production for certain periods of time, the Company’s Exploration and Production segmentSeneca regularly enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may extend over multiple years, covering a substantial majority of the Company’s expected natural gas production over the course of the current fiscal year, and lesser percentages of subsequent years’ expected production. These contracts reduce exposure to subsequent price drops but can also limit the Company’s ability to benefit from increases in natural gas prices.

The nature of these hedging contracts could lead to potential liquidity impacts in scenarios of significantly increased natural gas prices if the Company has hedged its current production at prices below the current market price. Hedging collateral deposits represent the cash, letters of credit, or other eligible instruments held in Company funded margin accounts to serve as collateral for hedging positions used inat the Company’s Exploration and Production segment.Seneca. A significant increase in natural gas prices may cause certain of the Company’s outstanding derivative instrument contracts to be in a liability position creating margin calls on the Company’s hedging arrangements, which could require the Company to temporarily post significant amounts of cash collateral with our hedge counterparties. That collateral could be in excess of the Company’s available short-term liquidity under its committed credit facility and other uncommitted sources of capital, leading to potential default under certain of its hedging arrangements. That interest-bearing cash collateral is returned to us in whole or in part upon a reduction in forward market prices, depending on the amount of such reduction, or in whole upon settlement of the related derivative contract.

In the Exploration and Production segment, underUnder the Company’s hedging guidelines, natural gas derivatives contracts must be confined to the price hedging of existing and forecastforecasted production. The Company maintains a system of internal controls to monitor compliance with its guidelines. However, unauthorized speculative trades, if they were to occur, could expose the Company to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Company’s actual production of natural gas falls short of hedged volumes, the Company may incur substantial losses to cover its hedges to the extent the hedges are in a loss position.

The Company accounts for its exploration and production activities under the full cost method of accounting. Each quarter, the Company must perform a “ceiling test” calculation, comparing the level of its unamortized investment in exploration and production properties to the present value of the future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses a 12-month historical average price for commodity pricing (based on first day of the month prices and adjusted for hedging) as well as the SEC mandated discount rate. If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be “impaired,” and the full cost authoritative accounting and reporting guidance require that the investment must be written down to the calculated net present value. Such an instance would require the Company to recognize an immediate expense in that quarter, and its earnings would be reduced. Depending on the magnitude of any decrease in average prices, that charge could be material. Under the Company’s existing indenture covenants, an impairment will restrict the Company’s ability to issue incremental long-term unsecured indebtedness for a period of time, beginning with the fourth calendar month following the impairment and ending not later than June 13, 2025, the maturity date of the Company’s remaining indebtedness outstanding under its 1974 indenture. In addition, because an impairment results in a charge to retained earnings, it lowers the Company’s total capitalization, all other things being equal, and increases the Company’s debt to capitalization ratio. AsAlthough the Company’s committed credit facility’s debt to capitalization covenant excludes 50% of aggregate ceiling test impairments occurring on or after July 1, 2018, up to a result,total anof impairment$400 million, impairments in excess of such amounts can impact the Company’s ability to maintain compliance with thethis debt to capitalization covenantcovenant. set forth in its committed credit facility. The Company recorded a pre-tax impairment underFor the ceilingfiscal test during the quarter ended June 30, 2024 in the amount of $200.7 million, and during the quarteryear ended September 30, 2024 in the amount of $263.0 million. Looking ahead, the first day of the month Henry Hub spot price for natural gas in October and November 2024 was $2.66 per MMBtu and $1.87 per MMBtu, respectively. Given the October and November prices, and the expectedquarter replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation atended December 31, 2024, the Company expectsrecorded topre-tax recordimpairments aunder the ceiling test impairmentof $463.7 million and $108.3 million, respectively. Depending on a number of factors, including fluctuations in or subtractions from proved reserves, increases in development costs for theundeveloped quarter ending December 31, 2024,reserves, and couldsignificant fluctuations in natural gas prices, the Company may record additional ceiling test impairments in fiscalfuture 2025.periods.

Our businesses depend on natural gas gathering, storage, and transmission facilities, including third-party midstream facilities that are not within our control. OurSeneca, Explorationas andwell Productionas andour Utility segmentssegment, have entered into long-term agreements with midstream providers for natural gas gathering, storage, and/or transportation services. The disruption or unavailability of the midstream facilities required to provide these services, due to maintenance, mechanical failures, accidents, weather, regulatory requirements and/or other operational hazards, could negatively impact our ability to market and/or deliver our products, especially if such disruption were to last for an extended period of time. In addition, any substantial disruptions to the services provided by our midstream providers could cause us to curtail a significant amount of our production or could impair our ability to deliver natural gas to our utility customers and could have a material adverse effect on the Company’s results of operations, financial condition, and cash flows. Furthermore, as substantially all of our production is transported from the well pad to interconnections with various FERC-regulated pipelines through our affiliated gathering facilities, such a production curtailment could result in significantly reduced throughput on those facilities, adversely affecting revenues and cash flows of our Integrated Upstream and Gathering segment.

The Company relies on information technology and operational technology systems to process, transmit, and store information, to manage and support a variety of business processes and activities, and to comply with regulatory, legal, and tax requirements. The Company’s information technology and operational technology systems, some of which are dependent on third party business partners, may be vulnerable to damage, interruption, or shutdown due to any number of causes outside of our control such as catastrophic events, natural disasters, fires, power outages, systems failures, telecommunications failures, and employee error or malfeasance. In addition, the Company’s information technology and operational technology systems and those of our third partythird-party business partners are subject to cybersecurity threats and attacks, including attempts by others to gain unauthorized access, or to otherwise introduce malicious software or software vulnerabilities. These attempts might be the result of industrial or other espionage, or actions by hackers seeking to harm the Company, its services or customers. These more sophisticated cyber-related attacks, as well as cybersecurity failures resulting from human error, pose a risk to the security and accessibility of the Company’s systems and networks and the confidentiality, availability and integrity of the Company’s and its customers’ data. That data may be considered sensitive, confidential, or personal information that is subject to privacy and security laws, regulations and directives. While the Company employs controls to maintain and protect its information technology and operational technology systems, the Company may be vulnerable to disruptions, cybersecurity incidents, lost or corrupted data, programming errors and employee errors and/or malfeasance that could lead to interruptions to the Company’s business operations or the unauthorized access, use, disclosure, modification or destruction of sensitive, confidential or personal information. Cybersecurity threats or attempts to breach the Company’s network security may result in disruption of the Company’s business operations and services, delays in production, theft of sensitive and valuable data, damage to our physical systems, malicious alteration or corruption of data or systems, costs related to remediation or the payment of ransom, and litigation including individual claims or consumer class actions, commercial litigation, administrative, and civil or criminal investigations or actions, regulatory intervention and sanctions or fines, investigation and remediation costs and reputational harm. Significant expenditures may be required to remedy system disruptions, cybersecurity incidents, or breaches or address cybersecurity threats, including restoration of customer service and enhancement of information technology and operational technology systems. We have invested in the protection of data and information technology, and actively work to enhance our business continuity and disaster recovery capabilities; however, there can be no assurance that our efforts will be successful.

There are many risks in developing natural gas, including numerous uncertainties inherent in estimating quantities of proved natural gas reserves and in projecting future rates of production and timing of development expenditures. The future success of the Company’s ExplorationIntegrated and ProductionUpstream and Gathering segmentssegment depends on its ability to develop additional natural gas reserves that are economically recoverable, and its failure to do so may negatively impact the Company’s financial outlook for thesethis businesses.segment. The total and timing of actual future production may vary significantly from reserves and production estimates. The Company’s drilling of development wells can involve significant risks, including those related to timing, success rates, and cost overruns, and these risks can be affected by lease and rig availability, completion crew and related equipment availability, geology, and other factors. Drilling for natural gas and related investments in supporting facilities can be unprofitable, not only from non-productive wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, competition and cost to acquire mineral rights, weather conditions, governmental requirements, including completion of environmental impact analyses and compliance with other environmental laws and regulations, and shortages or delays in the delivery of equipment and services can delay drilling operations or result in their cancellation. The cost of drilling, completing, and operating wells, as well as the development of related exploration and production assets, is significant and often uncertain. New wells and related assets may not be successful or the Company may not recover all or any portion of its investment. Production can also be delayed or made uneconomic if there is insufficient gathering and transportation capacity available at an economic price to get that production to a location where it can be profitably sold. Without continued successful exploitationexploration or acquisition activities, the Company’s reserves and revenues will decline as a result of its current reserves being depleted by production. The Company cannot make assurances that it will be able to find or acquire additional reserves at acceptable costs.

Approximately half of the Company’s active workforce is represented by collective bargaining units in New York and Pennsylvania. These labor agreements are negotiated periodically, and therefore, the Company is subject to the risk that such agreements may not be able to be renewed on reasonably satisfactory terms, on anticipated timelines, or at all. For example, the Company is currently negotiating with two collective bargaining units in New York for agreements that expire in February 2025. In connection with the negotiation of such collective bargaining agreements, or in futureother matters involving collective bargaining units representing the Company’s workforce, the Company could experience, among other things, strikes, work stoppages, slowdowns or lockouts, which could cause a disruption of the Company’s operations, impact the Company’s ability to fully execute operational plans, and have a material adverse effect on the Company’s results of operations and financial condition.

Various state legislative and regulatory initiatives regarding the exploration and production business have been proposed or adopted in the northeast United States affecting the Marcellus and Utica Shale gas plays. These initiatives include potential new or updated statutes and regulations governing the drilling, casing, cementing, testing, monitoring and abandonment of wells, the protection of water supplies and restrictions on water use and water rights, hydraulic fracturing operations, increased setback requirements, surface owners’ rights and damage compensation, the spacing of wells, use and disposal of potentially hazardous materials, and environmental and safety issues regarding natural gas pipelines. New permitting fees and/or severance taxes for natural gas production are also possible. Additionally, legislative initiatives in the U.S. Congress and environmental and health studies, proceedings or rule-making initiatives at federal, state or local agencies focused on the hydraulic fracturing process, the use of underground injection control wells for produced water disposal, and related operations could result in operational delays or prohibitions and/or additional permitting, compliance, reporting and disclosure requirements, which could lead to increased operating costs and increased risks of litigation for the Company.

The Company’s earnings and cash flow may be impacted by the amount of income or expense it expends or records for employee benefit plans. This is particularly true for pension and other post-retirement benefit plans, which are dependent on actual plan asset returns and factors used to determine the value and current costs of plan benefit obligations. In addition, if medical costs rise at a rate faster than the general inflation rate, the Company might not be able to mitigate the rising costs of medical benefits. Increases to the costs of pension, other post-retirement and medical benefits could have an adverse effect on the Company’s financial results. The Company’s earnings and cash flows may also be impacted by the rate treatment of certain income and expense activity, including the crediting of employee benefit plan trust income to ratepayers by reducing delivery rates and customer revenues, and the refund of regulatory liability balances. The application of current rate treatment is subject to change in a future rate proceeding.

The Company is a diversified energy company engaged principally in the production, gathering, transportation, storage and distribution of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian Basin. Current exploration and production development activities are focused primarily in the Marcellus and Utica shales, geological formations that are present in the Appalachian region of the United States. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian Basin to markets in the eastern United States and Canada. The Company’s efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas customers in the Appalachian Basin. In addition to expansion projects, the Company continues to focus on the ongoing modernization of its regulated Pipeline and Storage and Utility assets. The Company reports financial results for four business segments: Exploration and Production, Pipeline and Storage, Gathering, and Utility.

4.Other Matters, including: (a) details regarding the status of Supply Corporation and Empire’s Northern Access project; (b) 20242025 and projected 20252026 funding for the Company’s pension and other post-retirement benefits; (cb) disclosures and tables concerning market risk sensitive instruments; (dc) rate matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions; (ed) environmental matters; (e) new authoritative accounting and financial reporting guidance; and (f) effects of inflation.

The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report, which includes a comparison of our Results of Operations and Capital Resources and Liquidity for fiscal 20242025 and fiscal 2023.2024. For a discussion of the Company’s earnings, refer to the Results of Operations section below. A discussion of changes in the Company’s results of operations from fiscal 20222023 to fiscal 20232024 for the Utility segment, the Pipeline and Storage segment, and All Other and Corporate operations has been omitted from this Form 10-K, but may be found in Item 7, MD&A, of the Company’s Form 10-K for the fiscal year ended September 30, 2023,2024, filed with the SEC on November 17,22, 2023.2024. Changes in the Integrated Upstream and Gathering segment’s results of operations from fiscal 2023 to fiscal 2024 have been included in this Form 10-K, which has been recast to reflect the treatment of the previously reported Exploration and Production segment and Gathering segment as one operating segment as a result of the Company’s change in segment reporting discussed above.

The Company’s ExplorationIntegrated Upstream and ProductionGathering segment continues to grow, as evidenced by a 5% growth in proved reserves from the prior year to a total of 4,7534,981 Bcfe at September 30, 2024.2025. Production increased 19.834 Bcfe, or 5%,9%, during the fiscal year ended September 30, 20242025 to a total of 392.2427 Bcfe, and is expected to increase again in fiscal 2025.2026.

The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation’s system, referred to as the Tioga Pathway Project, which is an expansion and modernization project that would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC (“Transco”) capacity lease, providing access to Mid-Atlantic markets. SupplyOn CorporationMay filed5, a2025, FERC issued the Section 7 (b)/7(c) application with FERCcertificate for the projectproject. Construction on August 21, 2024. Thethe Tioga Pathway Project is expected to commence in early calendar 2026. This project has a target in-service date in late calendar 2026 and a preliminary cost estimate of approximately $101 million. The Tioga Pathway Project is discussed in more detail in the Capital Resources and Liquidity section that follows.

As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its exploration and production properties and that book value is subject to a quarterly ceiling test. TheIn Companyaddition recordedto cumulativethe non-cash impairment charges under the ceiling test that the Company recorded during fiscal 2024, the Company recorded a non-cash impairment charge under the ceiling test during the quarter ended December 31, 2024 of $463.7$108.3 million ($336.4$79.1 million after-tax). LookingAt ahead,September 30, 2025, June 30, 2025 and March 31, 2025, the firstceiling dayexceeded the book value of the monthexploration Henryand Hubproduction spotproperties, priceand forthus, naturaldid gasnot result in Octoberan 2024impairment andcharge Novemberin 2024any was $2.66 per MMBtu and $1.87 per MMBtu, respectively. Givenof these prices, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation for the next quarter, the Company expects to experience a ceiling test impairment for the quarter ending December 31, 2024, and could record additional ceiling test impairments in fiscal 2025.quarters. Please refer to the Critical Accounting Estimates section below for more details on this matter and a sensitivity analysis concerning commodity price changes.

The Company began repurchasing outstanding shares of its common stock during the quarter ended March 31, 2024 under a share repurchase program authorized by the Company’s Board of Directors. The program authorizes the Company to repurchase up to an aggregate amount of $200 million of its outstanding common stock in the open market or through privately negotiated transactions. During fiscal 2024,2025, the Company executed transactions to repurchase 1,146,259828,720 shares at an average price of $56.32$64.37 per share.share, Withfor a total cost of $53.8 million (including broker fees and excise taxes,taxes). From inception to September 30, 2025, the Company has repurchased 1,974,979 shares under the share repurchase program at an average price of $59.70, for a total cost of these$119.0 million (including broker fees and excise taxes). In light of the Company’s agreement to acquire CenterPoint Ohio’s natural gas utility, repurchases amountedunder tothe $65.2program million.have been suspended. The program has no fixed expiration date. These matters are discussed further in the Capital Resources and Liquidity section that follows.

The Company expects to use cash on hand, cash from operations, and short-term and/or long-term borrowings, and equity financing as needed,needed to meet its financing needs for fiscal 2025,2026, including the redemptionrepayment of twoa of$300.0 million delayed draw term loan that matures in February 2026 and any potential funding for the Company’sCenterPoint long-termOhio debt maturities totaling $500.0 million that are scheduled to mature in 2025.acquisition. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures, volatile interest rates and athe changeongoing inimpacts administration at theof federal level,policy changes, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs.

Exploration and Development Costs. In the Company’s ExplorationIntegrated Upstream and ProductionGathering segment, upstream property acquisition, exploration and development costs are capitalizedaccounted for under the full cost method of accounting, with natural gas properties in the Appalachian region being the primary component after the fiscal 2022 sale of the Company’s California exploration and production properties.accounting. Under this accounting methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves attributable to a cost center.

In addition to depletion under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying an unweighted arithmetic average of the first day of the month commodity prices for each month within the twelve-month period prior to the end of the reporting period (as adjusted for hedging) to estimated future production of proved reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures, which are based on current costs, associated with future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in natural gas prices. The ceiling is then compared to the capitalized cost of exploration and production properties less accumulated depletion and related deferred income taxes. If the capitalized costs of exploration and production properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment charge must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. TheAt September 30, 2025, the ceiling exceeded the book value of the exploration and production properties exceededby theapproximately ceiling$1.1 at September 30, 2024 as well as June 30, 2024, resulting in a cumulative non-cash impairment charge of $463.7 millionbillion ($336.4 million after-tax) for the year ended September 30, 2024.. The 12-month average of the first day of the month price for natural gas for each month during 2024,2025, based on the quoted Henry Hub spot price for natural gas, was $2.21$3.10 per MMBtu. (Note: Because actual pricing of the Company’s producing properties varyvaries depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for 2024.2025. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) TheIn followingregard table illustratesto the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the additional impairment that the Company would have recorded at September 30, 2024 if natural gas prices were $0.25 per MMBtu lower than the average prices in the twelve-month period used at September 30, 20242025 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company’s exploration and production properties by approximately $677.2 million (all amounts are presented after-tax)., Thesewhich would not have resulted in an impairment charge. This calculated amountsamount areis based solely on price changes and dodoes not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

The Company’s earnings were $77.5$518.5 million in 20242025 compared to earnings of $476.9$77.5 million in 2023.2024. The decreaseincrease in earnings of $399.4$441.0 million was primarily the result of acurrent lossyear earnings recognized in the ExplorationIntegrated Upstream and ProductionGathering segment compared to earnings in thea prior year loss combined with lowerhigher earnings in the Pipeline and StorageStorage, segment. Higher earnings in theand Utility segmentsegments. andA the Gathering segment, along with a lowerhigher loss in the Corporate category,category partially offset these decreases.increases. In the discussion that follows, all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings were impacted by the following events in 2025 and 2024:

•Non-cash impairment charges of $473.1 million ($343.2 million after-tax) recorded during 2024 in the ExplorationIntegrated Upstream and ProductionGathering segment, consisting mostly of ceiling test impairment charges of $463.7 million ($336.4 million after-tax). The remaining charges are related to impairments of certain water disposal assets.

ExplorationIntegrated Upstream and ProductionGathering Operating Revenues

Operating revenues for the ExplorationIntegrated Upstream and ProductionGathering segment increased $2.6$4.3 million in 2024 as compared with 2023. Gas production revenue after hedging increased $7.3 million primarily due to a 19.8 Bcf increase in gas production offset by a $0.11 per Mcf decrease in the weighted average realized price of gas after hedging. The increase in gas production was largely due to new Marcellus and Utica wells in the Appalachian region. Gathering revenue increased $1.6 million driven primarily by an increase in gathered volume in this segment’s eastern development areas (Trout Run and Tioga). The increase in gathered volume can be attributed to an increase in gross natural gas production by producers connected to the gathering systems. Partially offsetting this increase, other revenue decreased $4.7 million due to the non-recurrence of temporary capacity release revenue for a portion of this segment’s transportation capacity in 2023.

The risk factors in Item 1A of the Company’s 2025 Form 10-K, as amended by Item 1A of Part II of the Company's Form 10-Q for the quarter ended December 31, 2025, have not materially changed.changed other than as set forth below. The risk factors presented below supersede the corresponding risk factors in the 2025 Form 10-K and the December 31, 2025 Form 10-Q and should otherwise be read in conjunction with all of the risk factors disclosed in those reports.

Supply Corporation has also announced that it expects to serve as the transporter of 205,000 Dth per day of natural gas supplies to the Shippingport Power Station,Station a natural gas power generation facility under developmentsite in Beaver County, Pennsylvania, which will support a co-located data center that is currently under development. The project obtained FERC authorization under the Commission’s prior notice regulations on November 7, 2025 and construction commenced in March 2026.

Supply Corporation has also developed its Line N System Upgrade Project, which will consist of modernization of primarily 1960’s era pipeline in Beaver County, Pennsylvania, as well as minor compressor station and facility upgrades.upgrades, Into Aprilcreate 2026,approximately 294,000 Dth per day of additional natural gas transportation capacity (1) from a new interconnection on the southern portion of Supply Corporation's Line N system in Greene County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Mercer and (2) from an existing Supply Corporation interconnection with Texas Eastern Transmission, LP at Holbrook to a new interconnection at the Shippingport Industrial Park in Shippingport, Pennsylvania. Supply Corporation executed a long-term precedent agreementagreements with atwo shippershippers for 100% of the incremental capacity created by the project. The project has a projected in-service date of late calendar 2028. The Tioga Pathway Project, Shippingport Lateral Project and Line N System Upgrade Project are all discussed in more detail in the Capital Resources and Liquidity section that follows.

From a rate perspective, Distribution Corporation, in its New York jurisdiction, reached a settlement with the parties to its rate case proceeding. On December 19, 2024, the NYPSC issued an order approving the settlement. The settlement, effective January 1, 2025, established a three-year rate plan that reflects a return on equity of 9.7% and authorized a revenue requirement increase of $57.3 million in fiscal 2025, an additional revenue requirement increase of $15.8 million in fiscal 2026, and an additional revenue requirement increase of $12.7 million in fiscal 2027. The settlement also included standard make-whole language allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024. In addition, on May 5, 2026, Distribution Corporation filed a petition with the NYPSC for authorization to implement a system modernization tracker reconciliation mechanism through which qualified leak prone pipe removal costs incurred by the Company would be tracked and recovered. The petition remains pending with the Commission.

In Distribution Corporation's Pennsylvania jurisdiction, Distribution Corporation made a filing with the PaPUC on January 28, 2026 seeking an increase in its annual base rate operating revenues of $19.7 million with a proposed effective date of March 29, 2026. The Company is proposing, among other things, a new residential energy efficiency pilot program and to make permanent its weather normalization adjustment mechanism. The Company is also proposing reactivation of the OPEB surcredit to refund $7.2 million for customer bill relief. As reflected in a February 19, 2026 PaPUC Order, the filing was suspended until October 29, 2026 by operation of law unless directed otherwise by the PaPUC. Final briefs were submitted in the case on July 1, 2026. A decision is generally anticipated from the administrative law judge in August 2026.

Supply Corporation filed an NGA Section 4 rate case at FERC on April 30, 2026 proposing rate increases to be effective November 1, 2026. Supply Corporation's filing requests an annual cost of service of approximately $404 million, an increase of approximately $95 million from Supply Corporation's settlement of its 2023 rate proceeding. By regulation, the proposed rates will become effective November 1, 2026 subject to refund, unless the parties in the case reach a settlement. In addition, on March 17, 2025, FERC approved an amendment to Empire's 2019 rate case settlement. This settlement amendment is estimated to decrease Empire's revenues on a yearly basis by approximately $0.5 million. For further discussion of these and other rate matters, refer to the Rate Matters section below.

On October 20, 2025, the Company entered into the Purchase Agreement with CenterPoint Energy Resources Corp. (the “Seller”), pursuant to which, among other things, the Company agreed to acquire from the Seller all of the issued and outstanding equity interests of CenterPoint Ohio for an aggregate purchase price of $2.62 billion, subject to customary adjustments, as provided in the Purchase Agreement. This acquisition will add significant regulated scale for the Company, doubling the size of the Company’s gas utility rate base, while expanding its operations beyond New York and Pennsylvania into the neighboring state of Ohio, a state with a constructive regulatory and political environment that is supportive of natural gas. Closing is expected to occur inon theOctober fourth1, quarter of calendar 2026, pending completion of a review with the PUCO and other customary closing conditions.2026. The purchase price will include a combination of $1.42 billion in cash and a $1.2 billion promissory note to be issued by the Company to the Seller at closing. The promissory note, which was part of the Seller’s desired transaction structure and was incorporated into the Company’s business valuation, will have a maturity date of 364 days post-closing and will carry an interest rate of 6.5%. Permanent financing, inclusive of the amount to repay the promissory note, is expected to consist of long-term debt and common equity, along with expected future free cash flow. In that regard, on December 17, 2025, the Company completed the issuance and sale, in a private placement, of 4,402,513 shares of the Company's common stock, par value $1.00 per share, at a price of $79.50 per share. After deducting placement fees, the net proceeds to the Company amounted to $338.4 million. Furthermore, as discussed in Note 7 – Capitalization, the Company issued $1.5 billion of long-term debt on June 10, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $1,481.2 million. After redeeming certain notes scheduled to mature on October 1, 2026 with a portion of the net proceeds, the Company invested the remaining net proceeds from the debt issuance in temporary cash investments and expects to use that cash to fund a substantial portion of the purchase price at closing.

In connection with the Purchase Agreement, the Company isentered a party tointo commitment letters for a 364-day senior unsecured term loan facility related to the consideration to be paid at closing, and a senior unsecured bridge loan facility related to repayment of the promissory note. The commitment letters are supported by the Commitment Parties and additional banks, all of which are lenders under the Company’s primary credit facility. Together,The thecombination commitmentof lettersboth facilities was designed to fully support any portion of the aggregate purchase price that hashad not been permanently financed. Given the permanent financing in place, as mentioned in the previous paragraph, the Company terminated the 364-day term loan facility commitment letter effective June 10, 2026. The remaining commitment under the senior unsecured bridge loan facility commitment letter is currently $1.10 billion.

As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its exploration and production properties and that book value is subject to a quarterly ceiling test. The Company recorded a non-cash impairment charge under the ceiling test during the quarter ended December 31, 2024 of $108.3 million ($79.1 million after-tax). At MarchJune 31,30, 2026, the ceiling exceeded the book value of the exploration and production properties, and thus, did not result in an impairment charge in the quarter ended MarchJune 31,30, 2026. Please refer to the Critical Accounting Estimates section below for more details on this matter and a sensitivity analysis concerning commodity price changes.

The Company expects to use cash from operations, equity proceeds,operations and short-term and/or long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2026, including any potential funding for the CenterPoint Ohio acquisition and the repayment of its $300.0 million of 5.50% notes with a maturity date in October 2026. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures, volatile interest rates and the ongoing impacts of federal policy changes, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs.

Exploration and Development Costs. The Company, in its Integrated Upstream and Gathering segment, follows the full cost method of accounting for determining the book value of its exploration and production properties. In accordance with the full cost methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company's exploration and production reserves based on an unweighted arithmetic average of first day of the month commodity prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s exploration and production properties at the balance sheet date. The present value of future revenues is calculated using a 10% discount factor. If the book value of the exploration and production properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of such properties to the calculated ceiling. At MarchJune 31,30, 2026, the ceiling exceeded the book value of the exploration and production properties by approximately $1.6$1.4 billion (after-tax). The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended MarchJune 31,30, 2026, based on the quoted Henry Hub spot price for natural gas, was $3.72$3.64 per MMBtu. (Note: Because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for the twelve months ended MarchJune 31,30, 2026. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices in the twelve-month period used at MarchJune 31,30, 2026 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's exploration and production properties by approximately $1.2$1.0 billion (after-tax), which would not have resulted in an impairment charge. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

The Company's earnings were $247.7$138.6 million for the quarter ended MarchJune 31,30, 2026 compared to earnings of $216.4$149.8 million for the quarter ended MarchJune 31,30, 2025. The increasedecrease in earnings of $31.3$11.2 million is primarily the result of highera loss in the Corporate category and lower earnings in the Integrated Upstream and Gathering segment.

The Company's earnings were $429.3$567.9 million for the sixnine months ended MarchJune 31,30, 2026 compared to earnings of $261.3$411.2 million for the sixnine months ended MarchJune 31,30, 2025. The increase in earnings of $168.0$156.7 million is primarily the result of higher earnings in the Integrated Upstream and Gathering segment.

The Company's earnings for the sixnine months ended MarchJune 31,30, 2025 included non-cash impairment charges of $141.8 million ($103.6 million after-tax) in the Integrated Upstream and Gathering segment, consisting mostly of ceiling test impairment charges of $108.3 million ($79.1 million after-tax), as discussed above. The remaining charges are related to the impairment of certain water disposal assets. Note that all amounts used in earnings discussions are after-tax amounts, unless otherwise noted.

Operating revenues for the Integrated Upstream and Gathering segment increaseddecreased $43.6$3.9 million for the quarter ended MarchJune 31,30, 2026 as compared with the quarter ended MarchJune 31,30, 2025. Gas production revenue after hedging increaseddecreased $41.0$9.4 million due to the impact of a $0.517.3 Bcf decrease in natural gas production, offset by a $0.10 per Mcf increase in the weighted average price of natural gas after hedging, partially offset by a 3.5 Bcf decrease in natural gas production.hedging. The decrease in natural gas production was largely due to weather-driven completion delays and natural gas production declines on producing wells, partially offset by production from recently turned-in-line wells. In addition, otherOther revenue increased $3.3$4.3 million primarily due to changes in segment reporting. The change in segment reporting is fully offset in other operating expenses. Slightly offsetting these increases, gatheringGathering revenue decreasedalso $0.6increased million$1.2 asmillion, aprimarily result of natural production declines by producers connecteddue to insurance proceeds received during the Tioga and Trout Run gathering systems.period.

Operating revenues for the Integrated Upstream and Gathering segment increased $114.5$110.7 million for the sixnine months ended MarchJune 31,30, 2026 as compared with the sixnine months ended MarchJune 31,30, 2025. Gas production revenue after hedging increased $109.6$100.3 million due to the impact of a $0.42$0.32 per Mcf increase in the weighted average price of natural gas after hedging, coupled with ana 8.00.7 Bcf increase in natural gas production. The increase in natural gas production was largely due to the timing of new wells brought onlineonline, partially offset by natural gas production declines on producing wells. In addition, other revenue increased $6.2$10.5 million primarily due to changes in segment reporting. The change in segment reporting is fully offset in other operating expenses. Slightly offsetting these increases, gathering revenue decreased $1.3 million as a result of natural production declines by producers connected to the Tioga and Trout Run gathering systems.

The Integrated Upstream and Gathering segment's earnings for the quarter ended MarchJune 31,30, 2026 were $152.0$111.9 million, ana increasedecrease of $27.8$4.8 million when compared with earnings of $124.2$116.7 million for the quarter ended MarchJune 31,30, 2025. The $27.8$4.8 million increasedecrease can be attributed to the following factors:

(1)The decrease in interest expense iswas mainly attributed to lower short-term and long-term intercompany borrowings.

(62)The increasedecrease in income tax expense was primarily driven by an increase in state tax expense due to higherlower pre-tax income.

The Integrated Upstream and Gathering segment's earnings for the sixnine months ended MarchJune 31,30, 2026 were $276.1$388.0 million, an increase of $171.6$166.8 million when compared with earnings of $104.5$221.2 million for the sixnine months ended MarchJune 31,30, 2025. The $171.6$166.8 million increase can be attributed to the following factors:

(2)The decrease in interest expense iswas mainly attributed to lower short-term and long-term intercompany borrowings.

(3)Represents the segment's share of the premiums paidincurred byin connection with the CompanyCompany's toredemption redeemof long-term debt during the sixnine months ended MarchJune 31,30, 2025.2025, partially offset by premiums incurred on a long-term debt redemption during the nine months ended June 30, 2026.

(4)The increase was due to a $1.0 million earnings reduction associated with the remeasurement of state deferred income taxes for the sixnine months ended MarchJune 31,30, 2025.

(6)The increase in lease operating expensesexpense was primarily the result of additional third-party gathering and transportation costs combined with higher road maintenance and repair costs.

(7)The increase in other operating expenses iswas mainly attributed to a change in segment reporting combined with higher gathering operation and maintenance and higher abandonment accretion expense. These were partially offset by higherlower abandonment costs recognized during the sixnine months ended MarchJune 31,30, 2025.2026 and lower personnel costs.

Operating revenues for the Pipeline and Storage segment increased $1.9$1.0 million for the quarter ended MarchJune 31,30, 2026 as compared with the quarter ended MarchJune 31,30, 2025. The increase in operating revenue was primarily driven by higheran otherincrease in storage revenues of $0.9$0.7 million,million along withand an increase in transportation revenues of $0.6 millionmillion, andpartially anoffset by lower other revenues of $0.3 million. The increase in storage revenues ofwas $0.4primarily million.attributable to remarketed capacity that became available through customer contract negotiations and rate increases on existing contracts, partially offset by revisions to existing contracts. The increase in othertransportation revenues primarily reflects an adjustment to match electric surcharge revenues with electric power costs recorded in operation and maintenance.maintenance The increase in transportation revenues was primarily attributable to new long-term contractsexpense and rate increases on existing contracts, partially offset by revisions to existing contracts. The increase in storage revenues was primarily attributable to rate increases and deliverability enhancements on existing contracts.

Transportation volume for the quarter and sixnine months ended MarchJune 31,30, 2026 increased by 12.31.1 Bcf and 23.524.6 Bcf, respectively, from the prior year's quarter and sixnine month periods. The increase in transportation volume for both the quarter andended sixJune 30, 2026 is primarily driven by a modest increase in shipper demand. The increase in transportation volume for the nine months ended MarchJune 31,30, 2026 is primarily due to increased utilization resulting from colder weather.weather, as well as an increase in shipper demand. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

The Pipeline and Storage segment’s earnings for the quarter ended MarchJune 31,30, 2026 were $31.6$28.7 million, a decrease of $0.1$0.2 million when compared with earnings of $31.7$28.9 million for the quarter ended MarchJune 31,30, 2025. The $0.1$0.2 million decrease can be attributed to the following factors:

Operating revenues for the Utility segment increased $82.2$8.0 million for the quarter ended MarchJune 31,30, 2026 as compared with the quarter ended MarchJune 31,30, 2025. This increase resulted from a $77.3$7.5 million increase in retail gas sales revenue, a $3.1 million increase in transportation revenue and a $1.9 million increase in other revenue. The increase in retail gas sales revenue and a $0.8 million increase in other revenue, partially offset by a $0.3 million decrease in transportation revenue. The increase in retail gas sales revenue reflects higher base delivery rates effective October 1, 2025 from the impact of the implementation of year two of Distribution Corporation's three-year rate settlement in its New York jurisdiction. Additional details regarding the base rate regulatory proceeding can be found in the Rate Matters section below. The increase in retail gas sales revenue alsowas reflectspartially higheroffset by lower revenues collected from customers for purchased gas costs resulting mainly from ana 1.3 Bcf decrease in throughput mainly due to warmer weather, partially offset by a slight increase in the cost of gas sold (per Mcf) as well as a 1.0 Bcf increase in throughput mainly due to colder weather.. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation's earnings are not impacted by fluctuations in gas costs. Purchased gas expense recorded on the consolidated income statement matches the revenues collected from customers. Retail gas sales revenue and transportation revenue were also impacted by ana $1.2 million increase to revenue from a distribution system improvement charge (“DISCDSIC”) modernization tracker in Pennsylvania that became effective in January 2025. For further discussion of the DSIC tracker, refer to the Rate Matters section below. The increasedecrease in transportation revenue alsowas reflectsprimarily due to a 0.41.1 Bcf increasedecrease in throughput due primarily to colderwarmer weather.weather, partially offset by increases to revenue from the DSIC tracker discussed above. The increase in other revenue was primarily due to certain net positive revenue adjustments as a result of operational performance of safety performance measures in accordance with the rate settlement ($0.8 million), as well as increases in late payment charges billed to customers ($0.5$0.4 million) and capacitygains releasefrom revenuescertain vehicle sales ($0.4 million).

Operating revenues for the Utility segment increased $112.9$120.8 million for the sixnine months ended MarchJune 31,30, 2026 as compared with the sixnine months ended MarchJune 31,30, 2025. This increase resulted from a $105.9$113.5 million increase in retail gas sales revenue, a $4.7$4.4 million increase in transportation revenue and a $2.2$3.0 million increase in other revenue. The increase in retail gas sales revenue and transportation revenue reflects higher base delivery rates effective October 1, 2025 from the impact of the implementation of year two of Distribution Corporation's three-year rate settlement in its New York jurisdiction, as discussed above. The increase in retail gas sales revenue also reflects higher revenues collected from customers for purchased gas costs resulting from an increase in the cost of gas sold (per Mcf) as well as a 5.03.7 Bcf increase in throughput mainly due to colder weather. Retail gas sales revenue and transportation revenue were also impacted by ana $4.9 million increase to revenue from the DISCDSIC modernization tracker in Pennsylvania, as discussed above. The increase in transportation revenue also reflects a 3.12.0 Bcf increase in throughput due primarily to colder weather. The increase in other revenue was primarily due to increases in late payment charges billed to customers ($1.3 million) and capacity release revenues ($0.7 million), as well as certain net positive revenue adjustments as a result of operational performance of safety performance measures in accordance with the rate settlement ($0.8 million), as well as increases in late payment charges billed to customers ($0.8 million) and capacity release revenues ($0.6 million).

The Utility segment’s earnings for the quarter ended MarchJune 31,30, 2026 were $65.3$5.7 million, an increase of $1.8$0.7 million million when compared with earnings of $63.5$5.0 million for the quarter ended MarchJune 31,30, 2025. The increase can be attributed to the following factors:

(2)The increase in operating expenses is largely attributable to higher personnel costs and higher uncollectible expenses as a result of higher operating revenue.revenue, as well as higher costs for personnel, materials and outside services.