NATIONAL FUEL GAS CO 10-Q

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations OVERVIEW Please note that this overview is a high-level summary of items that are discussed in greater detail in subsequent sections of this report. 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. 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 three business segments. For a discussion of the Company's earnings, refer to the Results of Operations section below. 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, is an expansion and modernization project in northwest Tioga County, Pennsylvania. On May 5, 2025, FERC issued the Section 7(b)/7(c) certificate for the project and on January 8, 2026, FERC issued the Notice to Proceed with Construction. Construction on the Tioga Pathway Project is expected to commence in February 2026. This project has a target in-service date in late calendar 2026. Supply Corporation has also announced that it expects to serve as the transporter of natural gas supplies to the Shippingport Power Station, a natural gas power generation facility under development in Beaver County, Pennsylvania. The project obtained FERC authorization under the Commission’s prior notice regulations on November 7, 2025. The Tioga Pathway Project and the Shippingport Lateral Project are both 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, 26 Table of Content 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 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. 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 in the fourth quarter of calendar 2026, pending completion of a notice filing and review with the PUCO, Hart-Scott-Rodino review, and other customary closing conditions. 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, will 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 $338.6 million. In connection with its entry into the Purchase Agreement, the Company entered into a senior unsecured bridge loan facility commitment letter supported by the Commitment Parties, as well as a 364-day term loan facility commitment letter supported by the Commitment Parties and additional banks, all of which are lenders under the Company’s primary credit facility. The combination of both facilities fully supports any portion of the purchase price that has not been permanently financed. 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 December 31, 2025, 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 December 31, 2025. 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, and short-term and/or long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2026, including the repayment of a $300.0 million delayed draw term loan scheduled to mature in February 2026 that was repaid in January 2026 and any potential funding for the CenterPoint Ohio 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 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. CRITICAL ACCOUNTING ESTIMATES For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2025 Form 10-K. There have been no material changes to that disclosure other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K. 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 27 Table of Content 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 December 31, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $1.3 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 December 31, 2025, based on the quoted Henry Hub spot price for natural gas, was $3.39 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 December 31, 2025. 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 December 31, 2025 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's exploration and production properties by approximately $953.5 million (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. It is difficult to predict what factors could lead to future non-cash impairments under the SEC's full cost ceiling test. Fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in natural gas prices have an impact on the amount of the ceiling at any point in time. For a more complete discussion of the full cost method of accounting, refer to "Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2025 Form 10-K. RESULTS OF OPERATIONS Earnings The Company's earnings were $181.6 million for the quarter ended December 31, 2025 compared to earnings of $45.0 million for the quarter ended December 31, 2024. The increase in earnings of $136.6 million is primarily the result of current year earnings recognized in the Integrated Upstream and Gathering segment compared to a prior year loss combined with higher earnings in the Utility segment. A higher loss in the Corporate category and lower earnings in the Pipeline and Storage segment partially offset these increases. The Company's earnings for the quarter ended December 31, 2024 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). 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. Earnings (Loss) by Segment Three Months Ended December 31, (Thousands) 2025 2024 Increase (Decrease) Integrated Upstream and Gathering $ 124,047 $ (19,632) $ 143,679 Pipeline and Storage 31,219 32,454 (1,235) Utility 34,090 32,499 1,591 Total Reportable Segments 189,356 45,321 144,035 All Other (122) (193) 71 Corporate (7,589) (142) (7,447) Total Consolidated $ 181,645 $ 44,986 $ 136,659 28 Table of Content Integrated Upstream and Gathering Integrated Upstream and Gathering Operating Revenues Three Months Ended December 31, (Thousands) 2025 2024 Increase (Decrease) Gas Produced in Appalachia (after Hedging) $ 315,855 $ 247,187 $ 68,668 Gathering 2,767 3,448 (681) Other 4,601 1,673 2,928 $ 323,223 $ 252,308 $ 70,915 Production Volumes Three Months Ended December 31, 2025 2024 Increase (Decrease) Gas Production (MMcf) 109,181 97,717 11,464 Average Prices Three Months Ended December 31, 2025 2024 Increase (Decrease) Average Gas Price/Mcf Weighted Average $ 2.77 $ 2.23 $ 0.54 Weighted Average After Hedging $ 2.89 $ 2.53 $ 0.36 2025 Compared with 2024 Operating revenues for the Integrated Upstream and Gathering segment increased $70.9 million for the quarter ended December 31, 2025 as compared with the quarter ended December 31, 2024. Gas production revenue after hedging increased $68.7 million due to the impact of a $0.36 per Mcf increase in the weighted average price of natural gas after hedging, combined with a 11.5 Bcf increase in natural gas production. The increase in natural gas production was largely due to pads recently turned in line. In addition, other revenue increased $2.9 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 $0.7 million as a result of natural production declines by producers connected to the Trout Run gathering system. The Integrated Upstream and Gathering segment's earnings for the quarter ended December 31, 2025 were $124.0 million, an increase of $143.6 million when compared with a loss of $19.6 million for the quarter ended December 31, 2024. The $143.6 million increase can be attributed to the following factors: 29 Table of Content (Millions) Lower non-cash impairments of assets $ 103.6 (1) Higher natural gas prices after hedging 31.3 Higher natural gas production 22.9 Lower interest expense 2.6 (2) Higher other revenue 2.3 Earnings impact associated with remeasurement of state deferred income taxes due to ceiling test impairments 1.0 (3) Higher depletion expense (8.3) (4) Higher lease operating expenses (4.9) (5) Higher other operating expenses (2.6) (6) Higher income tax expense (2.4) (7) Higher other tax expense (1.3) (8) Other items (0.6) $ 143.6 (1) Includes a ceiling test impairment of $79.1 million and a $24.5 million impairment of certain water disposal assets recorded during the quarter ended December 31, 2024. (2) The decrease in interest expense is mainly attributed to lower short-term and long-term intercompany borrowings. (3) The increase was due to a $1.0 million earnings reduction associated with the remeasurement of state deferred income taxes for the quarter ended December 31, 2024. (4) The increase in depletion is mainly attributed to higher production. (5) The increase in lease operating expenses was primarily the result of higher third-party gathering and transportation costs combined with higher workover and repairs and maintenance costs. (6) The increase in other operating expenses is mainly attributed to a change in segment reporting, as well as higher gathering operation and maintenance, higher personnel costs and higher abandonment accretion expense, partially offset by higher abandonment costs recognized in fiscal 2024. (7) The increase in income tax expense was primarily driven by an increase in state tax expense due to higher pre-tax income. (8) The increase in other tax expense was primarily attributable to higher Impact Fees in the Appalachian region as the Company moved into a higher rate tier due to higher NYMEX pricing combined with higher well count. Pipeline and Storage Pipeline and Storage Operating Revenues Three Months Ended December 31, (Thousands) 2025 2024 Increase (Decrease) Firm Transportation $ 80,885 $ 81,086 $ (201) Interruptible Transportation 123 118 5 81,008 81,204 (196) Firm Storage Service 25,137 24,993 144 Interruptible Storage Service — — — Other 756 415 341 $ 106,901 $ 106,612 $ 289 30 Table of Content Pipeline and Storage Throughput Three Months Ended December 31, (MMcf) 2025 2024 Increase (Decrease) Firm Transportation 214,073 202,882 11,191 Interruptible Transportation 25 62 (37) 214,098 202,944 11,154 2025 Compared with 2024 Operating revenues for the Pipeline and Storage segment remained relatively flat for the quarter ended December 31, 2025 as compared with the quarter ended December 31, 2024. Transportation volume for the quarter ended December 31, 2025 increased by 11.2 Bcf, from the quarter ended December 31, 2024. The increase in transportation volume for the quarter ended December 31, 2025 is primarily due to increased utilization resulting from colder weather. 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 December 31, 2025 were $31.2 million, a decrease of $1.3 million when compared with earnings of $32.5 million for the quarter ended December 31, 2024. The $1.3 million decrease can be attributed to the following factors: (Millions) Lower other income $ (1.2) (1) Other items (0.1) $ (1.3) (1) The decrease in other income was primarily due to a lower average amount outstanding on intercompany short-term notes receivables and a lower weighted average interest rate on those receivables. Utility Utility Operating Revenues Three Months Ended December 31, (Thousands) 2025 2024 Increase (Decrease) Retail Sales Revenues: Residential $ 196,627 $ 171,365 $ 25,262 Commercial 26,606 23,212 3,394 Industrial 1,399 1,384 15 224,632 195,961 28,671 Transportation 32,243 30,622 1,621 Other 2,262 1,926 336 $ 259,137 $ 228,509 $ 30,628 31 Table of Content Utility Throughput Three Months Ended December 31, (MMcf) 2025 2024 Increase (Decrease) Retail Sales: Residential 21,841 18,476 3,365 Commercial 3,548 2,919 629 Industrial 190 199 (9) 25,579 21,594 3,985 Transportation 19,670 16,942 2,728 45,249 38,536 6,713 Degree Days Three Months Ended December 31, Percent Colder (Warmer) Than Normal 2025 2024 Normal (1) Prior Year (1) Buffalo, NY (2) 2,126 2,281 1,884 7.3 % 21.1 % Erie, PA 1,894 2,121 1,697 12.0 % 25.0 % (1) Percents compare actual 2025 degree days to normal degree days and actual 2025 degree days to actual 2024 degree days. (2) Normal degree days changed in January 2025 from NOAA 30-year degree days to NOAA 15-year degree days with the implementation of new base rates in New York. 2025 Compared with 2024 Operating revenues for the Utility segment increased $30.6 million for the quarter ended December 31, 2025 as compared with the quarter ended December 31, 2024. This increase resulted from a $28.7 million increase in retail gas sales revenue, a $1.6 million increase in transportation revenue and a $0.3 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. Additional details regarding the base rate regulatory proceeding can be found in the Rate Matters section below. The increase in retail gas sales revenue also reflects higher revenues collected from customers for purchased gas costs resulting from a 4.0 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. The increase in transportation revenue also reflects a 2.7 Bcf increase in throughput due primarily to colder weather. The Utility segment’s earnings for the quarter ended December 31, 2025 were $34.1 million, an increase of $1.6 million when compared with earnings of $32.5 million for the quarter ended December 31, 2024. The increase can be attributed to the following factors: (Millions) Impact of new base rates in New York $ 2.9 Impact of higher customer usage 2.8 Impact of regulatory revenue adjustments 1.0 (1) Higher operating expenses (3.7) (2) Higher depreciation expense (1.3) (3) Other items (0.1) $ 1.6 (1) Amount primarily reflects an increase in earnings from a distribution system improvement charge (“DSIC”) modernization tracker in Pennsylvania that became effective in January 2025. For further discussion of the DSIC tracker, refer to the Rate Matters section below. 32 Table of Content (2) The increase in operating expenses is largely attributable to higher personnel costs and higher uncollectible expenses. (3) The increase in depreciation expense is attributable to higher average property, plant and equipment balances. The impact of weather variations on earnings in the Utility segment is mitigated by a WNA. The WNA, which covers the eight-month period from October through May, has had a stabilizing effect on customer bills and earnings for the Utility segment. For the quarter ended December 31, 2025, the WNA reduced earnings by approximately $0.8 million and $1.0 million, respectively, in the Utility segment’s New York and Pennsylvania rate jurisdictions, as the weather was colder than normal on a cycle-bill basis in both jurisdictions. For the quarter ended December 31, 2024, the WNA preserved earnings of approximately $2.0 million and $1.2 million, respectively, in the Utility segment’s New York and Pennsylvania rate jurisdictions, as the weather was warmer than normal on a cycle-bill basis in both jurisdictions. ALL OTHER AND CORPORATE OPERATIONS 2025 Compared with 2024 All Other and Corporate operations reported a net loss of $7.7 million for the quarter ended December 31, 2025, an increase in net loss of $7.4 million when compared with a net loss of $0.3 million for the quarter ended December 31, 2024. The increase in net loss was primarily attributable to costs associated with the Company's planned acquisition of CenterPoint Ohio ($5.9 million). Refer to Part I, Item 1 at Note 2 - Pending Acquisition for further discussion of this acquisition. Additional contributing factors to the increase in net loss were a decrease in the cash surrender value of life insurance policies ($0.9 million) and higher operating expenses ($0.9 million), primarily due to increased legal and consulting fees and outside service costs. Other Income (Deductions) Net other income on the Consolidated Statements of Income was $8.2 million for the quarter ended December 31, 2025, compared to net other income of $7.7 million for the quarter ended December 31, 2024, for an increase of $0.5 million. This increase can be attributed primarily to a $1.1 million increase in interest income. Partially offsetting this increase was a $0.7 million decrease in non-service pension and post-retirement benefit income. Other Interest Expense Other interest expense on the Consolidated Statement of Income increased $5.5 million for the quarter ended December 31, 2025 as compared to the quarter ended December 31, 2024. These increases are primarily due to financing costs incurred associated with the Company's acquisition of CenterPoint Ohio's natural gas utility. CAPITAL RESOURCES AND LIQUIDITY The Company’s primary source of cash during the three-month period ended December 31, 2025 consisted of cash provided by operating activities and net proceeds from the issuance of common stock. The Company’s primary source of cash during the three-month period ended December 31, 2024 consisted of cash provided by operating activities and net proceeds from short-term borrowings. The Company expects to have adequate amounts of cash available to meet both its short-term and long-term cash requirements for at least the next twelve months and for the foreseeable future thereafter. During the remainder of 2026, the Company expects to use cash provided by operating activities and short-term and long-term borrowings to fund the Company's capital expenditures. The Company has repaid the $300.0 million delayed draw term loan that was expected to mature in February 2026. Looking forward to 2027, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures. These cash flow projections include the impact of the CenterPoint Ohio acquisition but do not reflect the impact of other acquisitions or divestitures that may arise in the future. Operating Cash Flow Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of assets, deferred income taxes and stock-based compensation. 33 Table of Content Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs, weather and regulatory lag may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire. The weather impact on cash flow in the Utility segment is mitigated by a WNA in both its New York and Pennsylvania rate jurisdictions. Because of the seasonal nature of the heating business in the Utility segment, revenues in this business are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the receivable balances at September 30. The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the LIFO method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption "Other Accruals and Current Liabilities." Such reserve is reduced as the inventory is replenished. Cash provided by operating activities in the Integrated Upstream and Gathering segment may vary from period to period as a result of changes in the commodity prices of natural gas as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and no cost collars, in an attempt to manage this energy commodity price risk. The pricing protection obtained from derivative financial instruments will fluctuate over time as instruments expire and are replaced with new instruments reflecting current commodity prices of natural gas. Net cash provided by operating activities totaled $274.9 million for the three months ended December 31, 2025, an increase of $54.8 million compared with $220.1 million provided by operating activities for the three months ended December 31, 2024. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Integrated Upstream and Gathering segment, partially offset by lower cash provided by operating activities in the Utility segment. The increase in the Integrated Upstream and Gathering segment is primarily due to higher natural gas prices and production in the Appalachian region combined with the timing of cash receipts and hedge settlements associated with that production. The decrease in the Utility segment is primarily due to higher natural gas prices and throughput combined with the timing of the associated gas cost recovery. Investing Cash Flow Expenditures for Long-Lived Assets The Company’s expenditures for long-lived assets totaled $222.7 million during the three months ended December 31, 2025 and $192.1 million during the three months ended December 31, 2024. The table below presents these expenditures: Total Expenditures for Long-Lived Assets Three Months Ended December 31, 2025 2024 Increase (Decrease) (Millions) Integrated Upstream and Gathering: Capital Expenditures $ 141.8 (1) $ 135.6 (2) $ 6.2 Pipeline and Storage: Capital Expenditures 37.6 (1) 19.8 (2) 17.8 Utility: Capital Expenditures 43.1 (1) 36.5 (2) 6.6 All Other: Capital Expenditures 0.2 0.2 — $ 222.7 $ 192.1 $ 30.6 (1) At December 31, 2025, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $55.5 million, $8.1 million and $6.8 million, respectively, of non-cash capital expenditures. At September 30, 2025, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $87.9 million, $19.4 million and $18.0 million, respectively, of non-cash capital expenditures. 34 Table of Content (2) At December 31, 2024, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $62.3 million, $4.4 million and $4.9 million, respectively, of non-cash capital expenditures. At September 30, 2024, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $85.0 million, $14.4 million and $20.6 million, respectively, of non-cash capital expenditures. Integrated Upstream and Gathering The Integrated Upstream and Gathering segment capital expenditures for the three months ended December 31, 2025 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $90.9 million spent in the Utica Shale area and $33.5 million spent in the Marcellus Shale area. These amounts included approximately $78.1 million spent to develop proved undeveloped reserves. Integrated Upstream and Gathering segment capital expenditures also included expenditures related to the continued expansion of Midstream Company’s Trout Run and Tioga gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower. The Integrated Upstream and Gathering segment capital expenditures for the three months ended December 31, 2024 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $90.9 million spent in the Utica Shale area and $27.5 million spent in the Marcellus Shale area. These amounts included approximately $34.6 million spent to develop proved undeveloped reserves. Integrated Upstream and Gathering segment capital expenditures also included expenditures related to the continued expansion of Midstream Company’s Tioga gathering system. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online and system optimization, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower. Pipeline and Storage The Pipeline and Storage segment capital expenditures for the three months ended December 31, 2025 and December 31, 2024 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions. In addition, the Pipeline and Storage segment capital expenditures for the three months ended December 31, 2025 included expenditures related to Supply's Corporation's Tioga Pathway Project ($5.4 million) and Shippingpoint Lateral Project ($2.4 million). In addition, due to the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, specifically in the Marcellus and Utica Shale producing areas, Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines, on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems, including projects to support regional demand for power generation to support the electric grid and data center development. Expansion and modernization projects where the Company has forecasted a significant amount of investment in preliminary survey and investigation costs and/or capital expenditures, and where a precedent agreement has been executed, are discussed below. Supply Corporation has designed a 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 (“Tioga Pathway Project”). The Tioga Pathway Project involves the construction of approximately 19 miles of new pipeline and the replacement of approximately four miles of existing pipeline on the Supply Corporation system. Supply Corporation has executed a Precedent Agreement with Seneca for 190,000 Dth per day of transportation capacity and filed a Section 7(b)/7(c) application with the FERC on August 21, 2024. FERC issued the Section 7(b)/7(c) certificate on May 5, 2025 and on January 8, 2026, FERC issued the Notice to Proceed with Construction. Construction on the Tioga Pathway Project is expected to commence in February 2026. This project has a projected in-service date of late calendar year 2026 and an estimated capital cost of approximately $101 million. As of December 31, 2025, approximately $10.5 million has been capitalized as Construction Work in Progress for this project. Additionally, Supply Corporation concluded an open season on February 26, 2025, and based on interest in that open season, designed a project that would allow for the transportation of 205,000 Dth per day of natural gas supplies from its existing Line N pipeline system to a new interconnection with the Shippingport Power Station, a natural gas power generation facility under development in Beaver County, Pennsylvania, which is expected to support a co-located data center (the 35 Table of Content “Shippingport Lateral Project”). In order to provide this new natural gas transportation capacity, Supply Corporation expects to construct an approximately 7.5 mile pipeline lateral from its existing Line N pipeline system to a direct interconnection with the facility with the incremental capacity expected to come online in late calendar 2026 and an estimated capital cost of approximately $57 million. Supply Corporation has executed a Precedent Agreement with Shippingport Power Station, LLC, the facility developer, for 100% of the capacity for the Shippingport Lateral Project and filed an application with FERC under the Commission’s prior notice regulations on August 29, 2025. The project obtained FERC authorization on November 7, 2025. As of December 31, 2025, approximately $2.6 million has been spent on this project, including $0.1 million spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet. The remaining $2.5 million spent on the project has been capitalized as Construction Work in Progress. Utility The majority of the Utility segment capital expenditures for the three months ended December 31, 2025 and December 31, 2024 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions. Project Funding During the quarter ended December 31, 2025 and fiscal 2025, the Company has financed capital expenditures with cash from operations and short-term debt. Going forward, the Company expects to use cash from operations, equity proceeds, and short-term or long-term borrowings, as needed, to finance capital expenditures. The level of short-term and/or long-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production and the associated commodity price realizations in the Integrated Upstream and Gathering segment. It will also likely depend on the timing of gas cost and base rate recovery in the Utility segment as well as the timing of base rate recovery in the Pipeline and Storage segment. The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive natural gas properties, accelerated development of existing natural gas properties, natural gas storage and transmission facilities, natural gas generation facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. The amounts are also subject to modification for opportunities involving emission reductions and/or energy transition including investments directly related to low- and no-carbon fuels. While the majority of capital expenditures in the Utility and Pipeline and Storage segments are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s business segments depends, to a large degree, upon market and regulatory conditions as well as legislative actions. Financing Cash Flow Consolidated short-term debt decreased $60.2 million when comparing the balance sheet at December 31, 2025 to the balance sheet at September 30, 2025. The maximum amount of short-term debt outstanding during the three months ended December 31, 2025 was $311.0 million. In addition to cash provided by operating activities, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing items such as capital expenditures, asset purchases, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. As of December 31, 2025, the Company had outstanding commercial paper of $90.0 million and did not have any short-term notes payable to banks. On October 20, 2025, the Company entered into a Securities Purchase Agreement (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 Vectren Energy Delivery of Ohio, LLC (the “Acquired Company” or “CenterPoint Ohio”), the Seller’s Ohio natural gas local distribution company, for an aggregate purchase price of $2.62 billion, subject to customary adjustments (the “Purchase Price”), as provided in the Purchase Agreement (the “Transaction”). The Purchase Price will be paid through a combination of cash and a promissory note to be issued by the Company to the Seller at closing pursuant to a Seller Note Agreement (the “Seller Note Agreement”) between the Company, as borrower, and the Seller, as lender. The Seller Note Agreement, which was part of the Seller’s desired transaction structure and was incorporated into the Company’s business valuation, will provide a $1.2 billion unsecured term loan credit facility (the “Seller Note Facility”) that matures on the last business day that is not more than 364 days from the closing of the Transaction. 36 Table of Content The borrowings under the Seller Note Facility will bear interest at a rate of 6.5% per annum. The Seller Note Agreement will contain customary representations and affirmative, negative and financial covenants, consistent with the Company’s February 2024 term loan agreement discussed below. The Seller Note Agreement will also include covenants restricting certain actions with respect to the Acquired Company. The Seller Note Agreement will contain certain specified events of default, and should an event of default occur, the lender is entitled to exercise certain remedies, including acceleration of the loan and related obligations. The Seller Note Agreement will contain a covenant defeasance provision that permits the Company to relieve itself from its obligations to comply with covenants under the Seller Note Agreement upon deposit of an amount with a paying agent sufficient to pay the principal of and interest due on the loan on each applicable interest payment date and the maturity date. In connection with its entry into the Purchase Agreement, the Company entered into a bridge facility commitment letter (the “Bridge Commitment Letter”), pursuant to which The Toronto-Dominion Bank, New York Branch (“TD Bank”) and Wells Fargo Bank, National Association (“Wells Fargo Bank” and, together with TD Bank, the “Commitment Parties”), agreed to provide to the Company loans under a senior unsecured bridge loan facility (the “Bridge Facility”) composed of a $1.42 billion 364-day tranche (the “Acquisition Tranche”), the proceeds of which will be used, if needed, to finance the Transaction, and a $1.2 billion 364-day tranche (the “Seller Note Tranche”), the proceeds of which will be used, if needed, to refinance the Seller Note Facility at its scheduled maturity. On November 6, 2025, the Company entered into a 364-day term loan facility commitment letter (the “Term Loan Commitment Letter”), pursuant to which the Commitment Parties and ten additional banks, all of which are lenders under our primary credit facility, agreed to provide to the Company loans under a 364-day senior unsecured term loan facility (the “Term Loan Facility”) in the amount of $1.42 billion, the proceeds of which will be used, if needed, to finance the Transaction. Entering into the Term Loan Commitment Letter enabled the Company to terminate the commitments under the Bridge Commitment Letter in respect of the Acquisition Tranche. Also on November 6, 2025, the same ten additional banks joined the Commitment Parties as parties to the Bridge Commitment Letter in respect of the Seller Note Tranche. Subject to the conditions in the respective commitment letters, the commitments under the Term Loan Facility and the Bridge Facility (together, the “Commitments”) may be reduced by proceeds of certain additional indebtedness that may be incurred by the Company and certain equity offerings of the Company to finance the Transaction. 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 $338.6 million. The Company is using the net proceeds from the issuance for general corporate purposes, including to finance a portion of the Purchase Price for the Transaction. The net proceeds of the issuance reduced the commitments under the Term Loan Facility to $1.08 billion. The Company expects to further reduce the Commitments through additional financings, possibly to zero, prior to the closing date of the Transaction or the scheduled maturity of the Seller Note Facility, as applicable, but there can be no assurance such financings will occur and any such expectation is subject to market conditions. The Company is subject to certain customary fees with respect to the Term Loan Facility and the Bridge Facility. Interest on borrowings under the Term Loan Facility or the Bridge Facility would accrue at one of two rates, at the option of the Company: Term SOFR plus an applicable margin of 1.125% to 1.750%, or a base rate (at least as great as one-month Term SOFR plus 1.0%) plus an applicable margin of 0.125% to 0.750%. In each case, the applicable margin would depend on the Company’s credit ratings (at current ratings, the applicable margin would be 1.500% for Term SOFR loans and 0.500% for base rate loans). With respect to the Term Loan Facility, the Company will pay a fee on the 270th day after the funding date in an amount equal to 0.025% of the principal amount of any loans outstanding under such facility at the close of business on that date. With respect to the Bridge Facility, the applicable margin would increase by an additional 0.25% on each of the 90th, 180th and 270th day after the funding date for any loans outstanding under the Bridge Facility. Any borrowings under the Term Loan Facility or the Bridge Facility would mature 364 days from the funding date, which, for the Term Loan Facility, would be on or around the closing date of the Transaction and, for the Bridge Facility, would be on or around the scheduled maturity of the Seller Note Facility. The availability of borrowings under the Term Loan Facility and the Bridge Facility is subject to the satisfaction of certain customary conditions for transactions of these types. Any definitive financing documentation for the Term Loan Facility or the Bridge Facility will contain customary representations and warranties, covenants and events of defaults for transactions of these types. The Company expects to execute permanent financing prior to the respective funding dates of the Term Loan 37 Table of Content Facility and the Bridge Facility, such that borrowings under the facilities would not be incurred. There can be no assurance, however, such permanent financing will occur and any such expectation is subject to market conditions. The Company is a party to a syndicated Credit Agreement (as amended from time to time, the “Credit Agreement”) that provides a $1.0 billion unsecured committed revolving credit facility. In January 2025, the Company and the banks in the syndicate consented to a second one-year extension of the maturity date of the Credit Agreement, such that the Company has aggregate commitments available in the full amount of $1.0 billion through February 23, 2029. In May 2025, the total lenders under the Credit Agreement increased to twelve as a new lender joined the syndicate, assuming a portion of an existing lender's commitment. The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement. The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future. The Company entered into a term loan agreement (the “Term Loan Agreement”) on February 14, 2024, with six of the 12 banks that are lenders under the Credit Agreement. As of January 22, 2026, the Company repaid the $300.0 million drawn under the Term Loan Agreement, and the agreement was therefore terminated. The Term Loan Agreement provided a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company had the ability to select interest periods of one, three or six months for borrowings. In April 2024, pursuant to the delayed draw mechanism, the Company elected to draw a total of $300.0 million under the facility. After deducting debt issuance costs, the net proceeds to the Company amounted to $299.4 million. Borrowings under the Term Loan Agreement bear interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10%, plus a spread of 1.375%. Both the Credit Agreement and the Term Loan Agreement provide that the Company’s debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company’s total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since that date, the Company recorded non-cash, after-tax ceiling test impairments totaling $797.0 million. As a result, at December 31, 2025, $398.5 million was added back to the Company’s total capitalization for purposes of calculating the debt to capitalization ratio under the Credit Agreement and the Term Loan Agreement. In addition, for purposes of calculating the debt to capitalization ratio, the following amounts included in Accumulated Other Comprehensive Income (Loss) on the Company’s consolidated balance sheet will be excluded from the determination of comprehensive shareholders’ equity: all unrealized gains or losses on commodity-related derivative financial instruments, and up to $10 million in unrealized gains or losses on other derivative financial instruments. As a result of these exclusions, such unrealized gains or losses will not positively or negatively affect the calculation of the debt to capitalization ratio. Finally, pursuant to amendments to the Credit Agreement and Term Loan Agreement entered into as of November 6, 2025, for purposes of calculating the debt to capitalization ratio, the Company’s $1.2 billion obligation under the Seller Note Facility, which is to be incurred at the closing of the Transaction, will be excluded from the definition of consolidated indebtedness upon such time and to the extent that the Company, in accordance with the Seller Note Agreement, deposits with a paying agent funds for defeasance of the Seller Note Facility. At December 31, 2025, the Company’s debt to capitalization ratio, as calculated under the agreements, was 0.41. The constraints specified in the Credit Agreement and the Term Loan Agreement would have permitted an additional $4.54 billion in short-term and/or long-term debt to be outstanding at December 31, 2025 before the Company’s debt to capitalization ratio exceeded 0.65. A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company’s subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources. The Credit Agreement and the Term Loan Agreement each contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the 38 Table of Content Credit Agreement or Term Loan Agreement, as applicable. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. The Current Portion of Long-Term Debt at December 31, 2025 consisted of a $300.0 million long-term delayed draw term loan scheduled to mature in February 2026 that was repaid in January 2026 and $300.0 million of 5.50% notes with a maturity date in October 2026. The Current Portion of Long-Term Debt at September 30, 2025 consisted of the aforementioned $300.0 million long-term delayed draw term loan with a maturity date in February 2026. The Company's present liquidity position is believed to be adequate to satisfy known demands. The Company’s embedded cost of long-term debt was 4.85% at December 31, 2025 and 4.83% at December 31, 2024. OTHER MATTERS In addition to the legal proceedings disclosed in Part II, Item 1 of this report, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company. The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the three months ended December 31, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2026. The Company also did not make any contributions to its VEBA trusts for its other post-retirement benefits during the three months ended December 31, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2026. Market Risk Sensitive Instruments Rules adopted by the CFTC and other regulators could adversely impact the Company. While many of those rules place specific conditions on the operations of swap dealers rather than directly on the Company, concern remains that swap dealers with whom the Company may transact will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs. Some of those rules also may apply directly to the Company and adversely impact its ability to trade swaps and over-the-counter derivatives, whether due to increased costs, limitations on trading capacity or for other reasons. Additionally, given the enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and anti-disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business. Should the Company violate any laws or regulations applicable to our hedging activities, it could be subject to CFTC enforcement action and material penalties and sanctions. The authoritative guidance for fair value measurements and disclosures requires consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At December 31, 2025, the Company determined that nonperformance risk associated with its natural gas price swap agreements, natural gas no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates. For a complete discussion of all other market risk sensitive instruments used by the Company, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2025 Form 10-K. Rate Matters Utility Operation Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” In both jurisdictions, 39 Table of Content delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill. New York Jurisdiction Distribution Corporation’s current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on December 19, 2024 with rates effective January 1, 2025 (“2024 Rate Order”). The 2024 Rate Order authorizes a three-year rate plan effective October 1, 2024, with a make-whole provision allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024. It also 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. These revenue requirement increases are being reflected in customer bills on a levelized basis over the three-year rate plan. The revenue requirement for each year of the three-year plan has been reduced by $14 million for actuarial projections of income that is expected to be recognized for qualified pension and other post-retirement benefits. Qualified pension and other post-retirement benefit income or costs are matched with amounts included in revenue resulting in zero impact to earnings. The 2024 Rate Order approves the continuation of several ratemaking mechanisms, including revenue decoupling and WNA, and establishes a number of new cost trackers and regulatory deferrals. It also includes an earnings sharing mechanism, gas safety and customer service performance metrics (including maintaining the Company’s leak prone pipe replacement program), and provisions that will facilitate achievement of the emissions reduction goals of the CLCPA. Pennsylvania Jurisdiction Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC in an order issued on June 15, 2023 with rates effective August 1, 2023 (“2023 Rate Order”). The 2023 Rate Order provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million and authorized a new weather normalization adjustment mechanism. On January 28, 2026, Distribution Corporation made a filing with the PaPUC 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 (Rider I) to refund $7.2 million for customer bill relief. The filing will be suspended for seven months by operation of law unless directed otherwise by the PaPUC. On April 10, 2024, Distribution Corporation filed with the PaPUC a petition for approval of a distribution system improvement charge ("DSIC") to recover, between base rate cases, capital expenses related to eligible property constructed or installed to rehabilitate, improve and replace portions of the Company’s natural gas distribution system. The DSIC petition was approved by the PaPUC on December 5, 2024, and on January 1, 2025, the Company initiated recovery of eligible costs on incremental rate base added after September 30, 2024. During the quarter ended December 31, 2025, Distribution Corporation recovered $1.1 million from customers. The DSIC will be reset to zero when new base rates become effective as a result of the Company's recent rate filing. Pipeline and Storage Supply Corporation’s rate settlement was approved June 11, 2024 with rates effective February 1, 2024, and provides that Supply Corporation may make a rate filing for new rates to be effective at any time. As well, any party can make a filing under NGA Section 5. Supply Corporation has no rate case currently on file. On March 17, 2025, FERC approved an amendment to Empire’s 2019 rate case settlement, which provides for a modest reduction in Empire’s transportation unit rates, effective November 1, 2025. This settlement amendment is estimated to decrease Empire’s revenues on a yearly basis by approximately $0.5 million. Empire will not be able to file a new Section 4 rate case before April 30, 2027 and is required to file a Section 4 rate case by May 31, 2031. Environmental Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory requirements. In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and greenhouse gas reduction targets associated with the Company’s utility delivery system. In 2022, the Company began 40 Table of Content measuring progress against these reduction targets. The Company's ability to estimate accurately the time, costs and resources necessary to meet emissions targets may be impacted as environmental exposures, technology and opportunities change and regulatory and policy updates are issued. For further discussion of the Company's environmental exposures, refer to Item 1 at Note 8 – Commitments and Contingencies under the heading “Environmental Matters.” While the current federal administration has initiated efforts to roll-back and/or limit certain environmental initiatives, legislative and regulatory measures concerning climate change and greenhouse gas emissions are in various phases of discussion or implementation in the United States. These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, cap-and-invest and cap-and-trade programs, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. Additionally, a number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. In New York, the CLCPA, which was passed in 2019, mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. Statements from New York's Governor and the state's 2025 New York State Energy Plan acknowledge that the near term targets of the statute may not be achievable in the required timeframes. The NYPSC has initiated and/or modified various proceedings in an effort to help the State meet these emissions reduction targets. 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 certain exemptions, and in December 2025 the Governor approved legislation that will require residential natural gas service applicants to pay the installation costs for the first 100 feet of facilities necessary to provide service commencing December 19, 2026. The May 2023 legislation is subject to ongoing litigation, with the parties agreeing, in November 2025, to suspend the requirements of the legislation pending resolution of appellate proceedings. In addition, the NYDEC, in conjunction with the New York State Energy Research and Development Authority, is developing a cap-and-invest program in the state, although issuance of certain key regulations necessary to implement the program has been delayed. In October 2025, a New York State Supreme Court judge issued an order requiring the NYDEC to promulgate regulations in accordance with the CLCPA by February 6, 2026. An appeal of that order filed by NYDEC on November 25, 2025 stayed all proceedings to enforce the order pending resolution of the appeal. The above-enumerated initiatives could impact the Company's customer base and assets, and could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also reduce demand for natural gas and delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by federal and state administrative agencies, make it difficult to predict a long-term business impact across twenty or more years. Federal, state or local governments may also provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. Effects of Inflation The Company’s operations are sensitive to increases in the rate of inflation because of its operational and capital spending requirements in both its regulated and non-regulated businesses. For the regulated businesses, recovery of increasing costs from customers can be delayed by the regulatory process of a rate case filing. For the non-regulated businesses, prices received for services performed or products produced are determined by market factors that are not necessarily correlated to the underlying costs required to provide the service or product. Safe Harbor for Forward-Looking Statements The Company is including the following cautionary statement in this Quarterly Report on Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained 41 Table of Content in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements: 1. Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; 2. Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design, retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; 3. Changes in economic conditions, including the imposition of additional tariffs on U.S. imports and related retaliatory tariffs, inflationary pressures, supply chain issues, liquidity challenges, and global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; 4. The Company's ability to complete strategic transactions, such as the pending transaction with CenterPoint Energy Resources Corp., including receipt of required regulatory clearances and satisfaction of other conditions to closing, and to recognize the anticipated benefits of such transactions; 5. Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas; 6. The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets; 7. Changes in the price of natural gas; 8. Impairments under the SEC's full cost ceiling test for natural gas reserves; 9. The creditworthiness or performance of the Company’s key suppliers, customers and counterparties; 10. Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures, other investments, and acquisitions, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; 11. Negotiations with the collective bargaining units representing the Company's workforce, including potential work stoppages during negotiations; 12. Changes in price differentials between similar quantities of natural gas sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; 13. The impact of information technology disruptions, cybersecurity or data security breaches, including the impact of issues that may arise from the use of artificial intelligence technologies; 14. Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability and costs, title disputes, weather conditions, water availability and disposal or recycling opportunities of used water, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; 15. Increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; 42 Table of Content 16. Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; 17. Other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date; 18. The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; 19. Uncertainty of natural gas reserve estimates; 20. Significant differences between the Company’s projected and actual production levels for natural gas; 21. Changes in demographic patterns and weather conditions (including those related to climate change); 22. Changes in the availability, price or accounting treatment of derivative financial instruments; 23. Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities; 24. Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to third-party outages; 25. Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or 26. Increasing costs of insurance, changes in coverage and the ability to obtain insurance. The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof. Forward-looking and other statements in this Quarterly Report on Form 10-Q regarding methane and greenhouse gas reduction plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current and forward-looking statements regarding methane and greenhouse gas emissions may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve and assumptions that are subject to change in the future. Item 3. Quantitative and Qualitative Disclosures About Market Risk Refer to the "Market Risk Sensitive Instruments" section in Item 2 – MD&A.