Item 7
Management’s Discussion and Analysis of Financial Condition and Results of Operations
OVERVIEW
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.
In the Company’s 2024 Form 10-K and its Form 10-Qs for the first three quarters of 2025, the Company previously reported financial results for four business segments: Exploration and Production, Pipeline and Storage, Gathering, and Utility. The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services as well as regulatory environment. During the quarter ended September 30, 2025, the president and chief executive officer determined that the Exploration and Production segment and Gathering segment should be treated as one operating segment in order to provide more clarity for management and investors as to the interdependence of both Seneca and Midstream Company in bringing Appalachian natural gas to market. As a result, the Company is now reporting financial results for three business segments: Integrated Upstream and Gathering, Pipeline and Storage, and Utility. Prior year segment information shown below has been recast to reflect this change in presentation. Refer to Item 1, Business, for a more detailed description of each of the segments.
Fiscal 2025 Highlights
This Item 7, MD&A, provides information concerning:
1. The critical accounting estimates of the Company;
2. Changes in revenues and earnings of the Company under the heading, “Results of Operations;”
3. Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity” and;
4. Other Matters, including: (a) 2025 and projected 2026 funding for the Company’s pension and other post-retirement benefits; (b) disclosures and tables concerning market risk sensitive instruments; (c) rate matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions; (d) 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 2025 and fiscal 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 2023 to fiscal 2024 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, 2024, filed with the SEC on November 22, 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 Integrated Upstream and Gathering segment continues to grow, as evidenced by a 5% growth in proved reserves from the prior year to a total of 4,981 Bcfe at September 30, 2025. Production
increased 34 Bcfe, or 9%, during the year ended September 30, 2025 to a total of 427 Bcfe, and is expected to increase again in fiscal 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, 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. On May 5, 2025, FERC issued the Section 7(b)/7(c) certificate for the project. Construction on the 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.
Supply Corporation has also announced that it expects to serve as the transporter for 205,000 Dth/day of natural gas supplies to the Shippingport Power Station, a natural gas power generation facility under development in Beaver County, Pennsylvania. 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 (the “Shippingport Lateral Project”), with the incremental capacity expected to come online as early as Fall 2026 and a preliminary cost estimate of approximately $57 million. 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, 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 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 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 for an aggregate purchase price of $2.62 billion, subject to customary adjustments, as provided in the Purchase Agreement. Closing is expected to occur in the fourth quarter of calendar 2026, pending completion of a notice filing and review with the Public Utilities Commission of Ohio, 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. 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%. The Company intends to execute permanent financing, inclusive of the amount to repay the promissory note, using the issuance of long-term debt and common equity, along with expected future free cash flow. 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.
In connection with its entry into the Purchase Agreement, the Company entered into a senior unsecured bridge loan facility commitment letter supported by The Toronto-Dominion Bank, New York Branch (“TD Bank”) and Wells Fargo Bank, National Association (together with TD Bank, the “Commitment Parties”) and additional banks, 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 the purchase price of $2.62 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. In addition to the 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 $108.3 million ($79.1 million after-tax). At September 30, 2025, June 30, 2025 and March 31, 2025, the ceiling exceeded the book value of the exploration and production properties, and thus, did not result in an impairment charge in any of these quarters. Please refer to the Critical Accounting Estimates section below for more details on this matter and a sensitivity analysis concerning commodity price changes.
From a financing perspective, on February 19, 2025, the Company issued $500.0 million of 5.50% notes due March 15, 2030 and $500.0 million of 5.95% notes due March 15, 2035. The proceeds of these debt issuances were used for general corporate purposes, including the March 2025 redemptions of $450.0 million of the Company’s 5.20% notes that were scheduled to mature in July 2025 and $500.0 million of the Company’s 5.50% notes that were scheduled to mature in January 2026. The Company redeemed those notes for $450.8 million and $503.3 million, respectively, plus accrued interest. The remaining proceeds of the debt issuances were used in conjunction with funding a defeasance trust associated with the June 2025 redemption of $50.0 million of 7.38% notes, the last of the notes under the Company’s 1974 indenture. For details of these matters, refer to the Capital Resources and Liquidity section below.
The Company is a party to a syndicated Credit Agreement that provides a $1.0 billion unsecured committed revolving credit facility. In January 2025, the Company and the syndicate of banks under the Credit Agreement consented to a second one-year extension on 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 number of 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 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 2025, the Company executed transactions to repurchase 828,720 shares at an average price of $64.37 per share, for a total cost of $53.8 million (including broker fees and excise 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 $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 under the program 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 from operations, short-term and/or long-term borrowings, and equity financing as needed to meet its financing needs for fiscal 2026, including the repayment of a $300.0 million delayed draw term loan that matures in February 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
The Company has prepared its consolidated financial statements in conformity with GAAP. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Company’s most critical accounting estimates, which are defined as those estimates whereby judgments or uncertainties could affect the application of accounting policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company’s significant accounting policies, refer to Item 8 at Note A — Summary of Significant Accounting Policies.
Exploration and Development Costs. In the Company’s Integrated Upstream and Gathering segment, upstream property acquisition, exploration and development costs are accounted for under the full cost method of 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.
Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the full cost method of accounting (on a units-of-production basis). Unproved properties are excluded from the depletion calculation until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
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. At September 30, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $1.1 billion (after-tax). The 12-month average of the first day of the month price for natural gas for each month during 2025, based on the quoted Henry Hub spot price for natural gas, was $3.10 per MMBtu. (Note: Because actual pricing of the Company’s producing properties varies 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 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 September 30, 2025 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 (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.
As discussed above, the full cost method of accounting provides a ceiling to the amount of costs that can be capitalized in the full cost pool. In accordance with current authoritative guidance, the future cash outflows associated with plugging and abandoning wells are excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation.
Regulation. The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to the FASB authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting principles for certain types of rate-regulated activities provides that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the Consolidated Statement of Income for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company’s regulatory assets and liabilities, refer to Item 8 at Note F — Regulatory Matters.
RESULTS OF OPERATIONS
EARNINGS
2025 Compared with 2024
The Company’s earnings were $518.5 million in 2025 compared to earnings of $77.5 million in 2024. The increase in earnings of $441.0 million was 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 Pipeline and Storage, and Utility segments. A higher loss in the Corporate category partially offset these 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:
2025 Event
• Non-cash impairment charges of $141.8 million ($103.6 million after-tax) recorded during 2025 in the Integrated Upstream and Gathering segment, consisting mostly of a ceiling test impairment charge of $108.3 million ($79.1 million after-tax). The remaining charges are related to an impairment of certain water disposal assets.
2024 Events
• Non-cash impairment charges of $473.1 million ($343.2 million after-tax) recorded during 2024 in the Integrated Upstream and Gathering 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.
• Non-cash impairment charge of $46.1 million ($33.8 million after-tax) recorded during the quarter ended September 30, 2024 in the Pipeline and Storage segment associated with the Northern Access project.
Earnings (Loss) by Segment
Year Ended September 30
(Thousands)
Integrated Upstream and Gathering
Pipeline and Storage
Utility
Total Reported Segments
All Other
Corporate
Total Consolidated
INTEGRATED UPSTREAM AND GATHERING
Revenues
Integrated Upstream and Gathering Operating Revenues
Year Ended September 30
(Thousands)
Gas Produced in Appalachia (after Hedging)
Gathering
Other
Operating Revenues
Production
Year Ended September 30
Gas Production (MMcf)
Average Prices
Year Ended September 30
Average Gas Price/Mcf
Weighted Average
Weighted Average After Hedging(1)
(1) Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note J — Financial Instruments in Item 8 of this report.
2025 Compared with 2024
Operating revenues for the Integrated Upstream and Gathering segment increased $207.5 million in 2025 as compared with 2024. Gas production revenue after hedging increased $195.5 million due to the impact of a $0.26 per Mcf increase in the weighted average price of natural gas after hedging, combined with a 34.3 Bcf increase in natural gas production. The increase in natural gas production in 2025 as compared with 2024 was largely due to pads recently turned in line. In addition, other revenue increased $15.8 million primarily due to a change in segment reporting combined with a gain recognized on the sale of certain fixed assets. These increases in operating revenues were partially offset by a decrease of $3.7 million in gathering revenue driven primarily by a decrease in gathered volume. The decrease in gathered volume was largely the result of natural production declines by producers connected to the Trout Run gathering system, partially offset by the impact of new wells brought online by producers connected to the Tioga gathering system.
2024 Compared with 2023
Operating revenues for the Integrated Upstream and Gathering segment increased $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.
Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.
Earnings
2025 Compared with 2024
The Integrated Upstream and Gathering segment’s earnings in 2025 were $324.7 million, an increase of $381.7 million when compared with a net loss of $57.0 million in 2024. The $381.7 million increase was primarily attributed to the following factors:
(Millions)
Lower non-cash impairments of assets
Higher natural gas prices after hedging
Higher natural gas production
Higher other revenue
Lower earnings reduction associated with remeasurement of state deferred income taxes
due to ceiling test impairments
Lower depreciation / depletion expense
Lower lease operating expenses
Change in mark to market adjustment on contingent consideration
Higher other operating expenses
Higher income tax expense
Higher other tax expense
Lower other income
Lower gathering revenues
Premiums paid on early redemption of debt
Other items
(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, offset by ceiling test impairments of $336.4 million and a $6.8 million impairment of certain water disposal assets both recorded during the year ended September 30, 2024.
(2) The decrease in depreciation / depletion expense is primarily the result of a $7.5 million decrease in depletion expense due to ceiling test impairments recorded in fiscal 2024 and 2025, which lowered the segment’s full cost pool depletable base. This decrease was partially offset by a $3.6 million increase in depreciation expense largely due to additional plant in-service associated with the Tioga gathering system.
(3) The decrease in lease operating expenses was primarily the result of lower workover and salt water disposal costs.
(4) Includes a decrease in unrealized losses in 2025 as compared to 2024 related to contingent consideration received as part of the sale of this segment’s California oil properties in 2022, net of tax effects. The fair value of the contingent consideration was zero at September 30, 2025.
(5) The increase in other operating expenses is mainly attributed to a change in segment reporting, as well as higher personnel costs, higher abandonment accretion expense, and higher environmental remediation costs in fiscal 2025, partially offset by higher abandonment costs recognized in fiscal 2024.
(6) The increase in income tax expense was primarily driven by an increase in state income tax expense due to higher pre-tax income.
(7) 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 additional wells drilled in the current year.
(8) The decrease in other income is mainly attributable to the non-recurrence of business interruption insurance proceeds received during the quarter ended December 31, 2023 related to a pipeline outage impacting Seneca’s ability to market gas, combined with lower interest income due to the reimbursement of security deposits related to the terminated Northern Access project.
(9) Represents the Integrated Upstream and Gathering segment’s share of the premiums paid by the Company to redeem long-term debt. Refer to Note H — Capitalization and Short-Term Borrowings for further discussion.
2024 Compared with 2023
The Integrated Upstream and Gathering segment experienced a loss of $57.0 million in 2024, a decrease of $389.0 million from earnings of $332.0 million in 2023. The $389.0 million decrease was primarily attributed to the following factors:
(Millions)
Non-cash impairments of assets
Lower natural gas prices after hedging
Higher depreciation / depletion expense
Higher other operating expenses
Earnings reduction associated with remeasurement of state deferred income taxes
due to ceiling test impairments
Change in mark to market adjustment on contingent consideration related to the
sale of California oil properties in 2022
Lower other revenue
Higher interest expense
Higher lease operating expenses
Higher natural gas production
Lower income tax expense
Lower other tax expense
Higher gathering revenue
(1) Includes aggregate ceiling test impairments of $336.4 million recorded during the quarters ended June 30, 2024 and September 30, 2024 and a $6.8 million impairment of certain water disposal assets recorded during the quarter ended September 30, 2024.
(2) The increase in depreciation / depletion expense was primarily due to an increase in depletion expense of $29.1 million largely due to the net increase in production combined with a $0.06 per Mcf increase in the depletion rate. An increase in depreciation expense of $2.4 million, primarily due to additional plant in-service associated with the Tioga and Clermont gathering systems, also contributed to the increase.
(3) The increase in other operating expenses was primarily attributable to recognizing an accrual of plugging and abandonment costs related to certain offshore Gulf of Mexico wells and certain California wells that were sold by Seneca to operators that are now defunct or unable to cover the cost of the abandonment activities. As a result, a portion of the cost of abandoning the wells was expected to revert back to Seneca. Higher personnel and material costs also contributed to the increase in other operating expenses.
(4) The increase in interest expense was largely attributable to higher average interest rates on intercompany short-term and long-term borrowings, partially offset by lower intercompany long-term debt balances.
(5) The increase in lease operating expenses was primarily the result of higher workover and repairs and maintenance expenses, partially offset by lower salt water disposal costs.
(6) The reduction in income tax expense was primarily driven by a decrease in pre-tax income and lower state income tax expense. The lower state income taxes were a result of a decrease in Pennsylvania’s state income tax rate from 9.99% in the prior year to 8.99% in the current year, as well as a change in the mix of revenues between state jurisdictions.
(7) The decrease in other tax expense was primarily attributable to lower Impact Fees in the Appalachian region as the Company moved into a lower rate tier due to lower NYMEX pricing.
PIPELINE AND STORAGE
Revenues
Pipeline and Storage Operating Revenues
Year Ended September 30
(Thousands)
Firm Transportation
Interruptible Transportation
Firm Storage Service
Interruptible Storage Service
Other
Pipeline and Storage Throughput — (MMcf)
Year Ended September 30
Firm Transportation
Interruptible Transportation
2025 Compared with 2024
Operating revenues for the Pipeline and Storage segment increased $15.2 million in 2025 as compared with 2024. For the twelve months ended September 30, 2025, the $12.3 million increase in transportation revenues and $4.4 million increase in storage revenues were primarily attributable to an increase in Supply Corporation’s transportation and storage rates effective February 1, 2024 in accordance with Supply Corporation’s rate case settlement. The settlement was approved by FERC on June 11, 2024. This increase was partially offset by the impact of a final true-up adjustment recorded during the year ended September 30, 2024 to the surcharge for pipeline safety and greenhouse gas costs that ended effective February 1, 2024. The increase in transportation revenues was also partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions. The $1.4 million decrease in other revenues primarily reflects lower cashout revenues, which are completely offset by purchased gas expense, and an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense.
Transportation volume increased by 26.9 Bcf in 2025 as compared with 2024, primarily due to an increase in volume from colder weather. This increase was partially offset by lower capacity utilization with certain contract shippers and certain contract expirations and revisions. 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 majority of Supply Corporation’s and Empire’s transportation and storage contracts allow either party to terminate the contract upon six or twelve months’ notice effective at the end of the primary term and include “evergreen” language that allows for annual term extension(s). The Pipeline and Storage segment’s contracted transportation and storage capacity with both affiliated and unaffiliated shippers is expected to remain relatively constant in fiscal 2026.
Earnings
2025 Compared with 2024
The Pipeline and Storage segment’s earnings in 2025 were $121.0 million, an increase of $41.3 million when compared with earnings of $79.7 million in 2024. The $41.3 million increase can be attributed to the following factors:
(Millions)
Non-cash impairment of assets
Higher operating revenues
Lower interest expense
Higher operating expenses
Lower other income
Other items
(1) An impairment charge recognized during the year ended September 30, 2024 wrote down the carrying value of certain assets associated with Supply Corporation and Empire’s Northern Access project.
(2) The decrease in interest expense was primarily driven by a decrease in intercompany short-term borrowings, partially offset by an increase in interest on additional intercompany long-term borrowings associated with the Company’s February 2025 debt issuance.
(3) The increase in operating expenses was primarily due to an increase in personnel costs, as well as an increase in outside service expenses, largely related to system integrity and maintenance spending, and higher power costs related to Empire’s electric motor drive compressor station. The increase in electric power costs is offset by an equal increase in revenue.
(4) 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, as well as a decline in non-service pension and post-retirement benefit income.
UTILITY
Revenues
Utility Operating Revenues
Year Ended September 30
(Thousands)
Retail Revenues:
Residential
Commercial
Industrial
Transportation
Other
Utility Throughput — million cubic feet (MMcf)
Year Ended September 30
Retail Sales:
Residential
Commercial
Industrial
Transportation
Degree Days
Percent (Warmer)
Colder Than
Year Ended September 30
Normal
Actual
Normal(1)
Prior Year(1)
Buffalo, NY(2)
Erie, PA
Buffalo, NY
Erie, PA
(1) Percents compare actual degree days to normal degree days and actual degree days to actual prior year degree days.
(2) Normal degree days changed from NOAA 30-year degree days to NOAA 15-year degree days with the implementation of new base rates in New York effective October 2024.
2025 Compared with 2024
Operating revenues for the Utility segment increased $120.3 million in 2025 compared with 2024. The increase resulted from a $109.6 million increase in retail gas sales revenue, a $0.7 million increase in transportation revenue and a $10.0 million increase in other revenue. The increases in retail gas sales and transportation revenues reflect the impact of new base delivery rates in Distribution Corporation’s New York jurisdiction pursuant to a settlement approved by the NYPSC on December 19, 2024. 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 9.3 Bcf increase in throughput mainly due to colder weather combined with an increase in the cost of gas sold (per Mcf). The increase in transportation revenue also reflects a 3.9 Bcf increase in throughput due primarily to colder weather, partially offset by the amortization of certain regulatory assets in accordance with the New York rate settlement. The increase in other revenue was largely due to the elimination of the refund provision that required the Utility segment to defer and return the income tax benefits resulting from the 2017 Tax Reform Act to customers ($12.0 million). The refund provision is no longer necessary because Distribution Corporation’s new base delivery rates now reflect the current federal income tax rate of 21%. This increase in other revenue was partially offset by decreases in other gas revenues ($0.8 million), capacity release revenues ($0.8 million), and late payment charges billed to customers ($0.4 million).
Purchased Gas
The cost of purchased gas is one of the Company’s largest operating expenses. Annual variations in purchased gas costs are attributed directly to changes in gas sales volume, the price of gas purchased and the operation of purchased gas adjustment clauses. Distribution Corporation recorded $358.5 million and $283.2 million of Purchased Gas expense during 2025 and 2024, respectively. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation does not profit from fluctuations in gas costs. Purchased Gas expense recorded on the consolidated income statement matches the revenues collected from customers, a component of Operating Revenues on the consolidated income statement. Under
mechanisms approved by the NYPSC in New York and the PaPUC in Pennsylvania, any difference between actual purchased gas costs and what has been collected from the customer is deferred on the consolidated balance sheet as either an asset, Unrecovered Purchased Gas Costs, or a liability, Amounts Payable to Customers. These deferrals are subsequently collected from the customer or passed back to the customer, subject to review by the NYPSC and the PaPUC. Absent disallowance of full recovery of Distribution Corporation’s purchased gas costs, such costs do not impact the profitability of the Company. Purchased gas costs impact cash flow from operations due to the timing of recovery of such costs versus the actual purchased gas costs incurred during a particular period. Distribution Corporation’s purchased gas adjustment clauses seek to mitigate this impact by adjusting revenues on either a quarterly or monthly basis.
Distribution Corporation contracts for firm long-term transportation and storage capacity services with rights-of-first-refusal from ten upstream pipeline companies including Supply Corporation for transportation and storage services and Empire, for transportation services. Distribution Corporation contracts for firm spot and term gas supplies with various producers, marketers and two local distribution companies to meet its gas purchase requirements. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.
Earnings
2025 Compared with 2024
The Utility segment’s earnings in 2025 were $83.2 million, an increase of $26.1 million when compared with earnings of $57.1 million in 2024. The increase can be attributed to the following factors:
(Millions)
Impact of new base rates in New York
Higher other income
Impact of higher customer usage
Higher operating expenses
Higher interest expense
Higher income tax expense
Higher depreciation expense
Other items
(1) The increase in other income was primarily due to the New York rate settlement, which required the recognition of non-service pension and post-retirement benefit income and a corresponding reduction in new base rates.
(2) The increase in operating expenses is largely attributable to higher personnel costs partially offset by a reduction in amortizations of certain regulatory assets and lower uncollectible expenses mainly as a result of a tracker implemented, both of which were associated with the New York rate settlement.
(3) The increase in interest expense is mainly attributed to an increase in both short-term and long-term intercompany debt balances.
(4) The increase in income tax expense was primarily driven by a smaller tax deduction in 2025 as compared to 2024 in the Utility’s Pennsylvania jurisdiction for certain repairs and maintenance expenditures, lower benefit from the amortization of excess deferred income taxes in accordance with the New York rate settlement, and higher state income tax expense due to higher pre-tax income.
(5) 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 earnings for the
Utility segment. In addition, in periods of colder than normal weather, the WNA benefits the Utility segment’s customers. For 2025, the WNA preserved earnings of approximately $3.9 million and $1.7 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. For 2024, the WNA preserved earnings of approximately $8.1 million and $5.5 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
Earnings
2025 Compared with 2024
All Other and Corporate operations had a net loss of $10.4 million in 2025, an increase in loss of $8.2 million when compared with a net loss of $2.2 million in 2024. The increase in loss was attributable to the following factors: (1) the Company recorded unrealized losses on equity securities of $0.9 million in 2025 compared to unrealized gains on equity securities of $2.4 million in 2024; (2) higher interest expense ($2.1 million) due mainly to higher average long-term borrowings; (3) higher operating expense ($2.9 million) due mainly to higher legal, consulting, and outside service costs; and (4) higher income tax expense ($1.0 million) due primarily to the impact of less favorable consolidated tax sharing provisions in fiscal 2025. These changes were partially offset by realized gains from investment securities sold during 2025 ($1.2 million).
OTHER INCOME (DEDUCTIONS)
Although most of the variances in Other Income (Deductions) are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis (amounts below are pre-tax amounts):
Net other income on the Consolidated Statements of Income was $36.4 million in 2025 compared to net other income of $16.2 million in 2024, for a net increase of $20.2 million. This increase can be attributed primarily to a $22.4 million increase in non-service pension and post-retirement benefit income combined with a $5.8 million change in the year-over-year revaluation of the contingent consideration received as part of the sale of the Company’s California oil properties in 2022. These increases were partially offset by year-over-year changes in the value of investment securities. During the year ended September 30, 2025, there were net gains of $0.5 million on investment securities, compared to net gains of $3.5 million on investment securities during the year ended September 30, 2024. Also offsetting these increases, was a decrease in interest income of $2.7 million, and the non-recurrence of $2.0 million of business interruption insurance proceeds received during the year ended September 30, 2024 related to a pipeline outage that impacted Seneca’s ability to market its gas.
INTEREST CHARGES
Although most of the variances in Interest Charges are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis (amounts below are pre-tax amounts):
Interest on long-term debt increased $18.1 million in 2025 as compared to 2024. These increases are primarily due to higher average balances and a higher weighted average interest rate on long-term debt. On February 19, 2025, the Company issued $500.0 million of 5.50% notes and $500.0 million of 5.95% notes. On March 6, 2025, the Company redeemed $450.0 million of 5.20% notes due July 2025 and $500.0 million of 5.50% notes due January 2026 and paid early redemption premiums totaling $2.4 million that were recorded as interest expense on long-term debt in the Integrated Upstream and Gathering segment. The Company also redeemed $50.0 million of 7.38% notes on June 13, 2025. In addition, in April 2024, the Company elected to draw a total of $300.0 million under a delayed draw term loan credit facility. These borrowings had a locked-in weighted average interest rate of 5.97% for 2025.
Other interest expense decreased $0.9 million in 2025 as compared to 2024. The decrease was primarily due to lower weighted average interest rates on short-term debt for 2025 and lower average short-term debt balances in 2025 compared to 2024.
CAPITAL RESOURCES AND LIQUIDITY
The primary sources and uses of cash during the last two years are summarized in the following condensed statement of cash flows:
Year Ended September 30
(Millions)
Provided by Operating Activities
Capital Expenditures
Sale of Fixed Income Mutual Fund Shares in Grantor Trust
Other Investing Activities
Net Change in Other Short-Term Notes Payable to Banks and Commercial Paper
Net Proceeds from Issuance of Long-Term Debt
Shares Repurchased Under Repurchase Plan
Reduction of Long-Term Debt
Net Repurchases of Common Stock Under Stock and Benefit Plans
Dividends Paid on Common Stock
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash
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 2026, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures. The Company has a delayed draw term loan that matures in February 2026, which the Company anticipates repaying with cash from operations as well as short-term or long-term borrowings. 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.
Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year 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. Refer also to Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) for additional discussion.
Cash provided by operating activities in the Integrated Upstream and Gathering segment may vary from year to year 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.
The Company, in its Utility segment and Integrated Upstream and Gathering segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for additional discussion concerning these
contractual commitments as well as the amounts of future gas purchase, transportation and storage contract commitments expected to be incurred during the next five years and thereafter. Also refer to Item 8 at Note D — Leases for a discussion of the Company’s operating lease arrangements and a schedule of lease payments during the next five years and thereafter.
Net cash provided by operating activities totaled $1,100.0 million in 2025, an increase of $34.0 million compared with the $1,066.0 million provided by operating activities in 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 activities in the Utility segment. The increase in the Integrated Upstream and Gathering segment is primarily due to the timing of cash receipts and hedge settlements from natural gas production. The decrease in the Utility segment is primarily due to the timing of gas cost recovery, partially offset by the impact of higher revenues resulting from the base rate increase in Distribution Corporation’s New York rate jurisdiction.
Net cash provided by operating activities totaled $1,066.0 million in 2024, a decrease of $171.1 million compared with the $1,237.1 million provided by operating activities in 2023. The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Integrated Upstream and Gathering segment and Utility segment. The decrease in the Integrated Upstream and Gathering segment is primarily due to lower cash receipts from natural gas production. The decrease in the Utility segment is primarily due to the timing of gas cost recovery.
INVESTING CASH FLOW
Expenditures for Long-Lived Assets
The Company’s expenditures for long-lived assets, including non-cash capital expenditures, totaled $918.1 million, $942.0 million and $1,123.6 billion in 2025, 2024 and 2023, respectively. The table below presents these expenditures:
Year Ended September 30
(Millions)
Integrated Upstream and Gathering:
Capital Expenditures (1)
Pipeline and Storage:
Capital Expenditures
Utility:
Capital Expenditures
All Other and Corporate:
Capital Expenditures
Total Expenditures
(1) The year ended September 30, 2023 includes $124.8 million related to the acquisition of upstream assets acquired from SWN Production Company, LLC (“SWN”). The acquisition cost is reported as a component of Acquisition of Upstream Assets on the Consolidated Statement of Cash Flows.
(2) 2025 capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment include $87.9 million, $19.4 million and $18.0 million, respectively, of non-cash capital expenditures.
(3) 2024 capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment include $85.0 million, $14.4 million and $20.6 million, respectively, of non-cash capital expenditures.
(4) 2023 capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment include $63.8 million, $31.8 million and $13.6 million, respectively, of non-cash capital expenditures.
Integrated Upstream and Gathering
In 2025, the Integrated Upstream and Gathering segment capital expenditures were primarily upstream well drilling and completion expenditures in the Appalachian region, including $141.8 million spent in the Marcellus Shale area and $351.2 million spent in the Utica Shale area. These amounts included approximately $246.3 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, Clermont and Trout Run gathering systems. 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.
In 2024, the Integrated Upstream and Gathering segment capital expenditures were primarily upstream well drilling and completion expenditures in the Appalachian region, including $76.3 million spent in the Marcellus Shale area and $439.9 million spent in the Utica Shale area. These amounts included approximately $305.6 million spent to develop proved undeveloped reserves. The Company also completed the acquisition of certain undeveloped acreage in Tioga County, Pennsylvania for $6.2 million in 2024. The acquisition included 2,083 net acres and was accounted for as an asset acquisition with the purchase price allocated to property, plant and equipment. The cost of this acquisition is reported as a component of Capital Expenditures on the Consolidated Statement of Cash Flows. Integrated Upstream and Gathering segment capital expenditures also included expenditures related to the continued expansion of Midstream Company’s Clermont, Tioga and Trout Run 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.
In 2023, the Integrated Upstream and Gathering segment capital expenditures were primarily upstream well drilling and completion expenditures in the Appalachian region, including $292.6 million spent in the Marcellus Shale area and $430.7 million spent in the Utica Shale area. These amounts included approximately $342.0 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 Clermont, Tioga and Trout Run 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.
On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN for total consideration of $124.8 million. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment.
Other 2023 acquisitions included the acquisition of certain upstream assets located in Lycoming County in Northeast Pennsylvania for total consideration of $11.5 million as well as the acquisition of undeveloped acreage in Tioga County, Pennsylvania for $13.6 million. The acquisition in Lycoming County included 1,145 net acres and the acquisition in Tioga County included 4,222 net acres. Both transactions were accounted for as asset acquisitions and, as such, the purchase price for each transaction was allocated to property, plant and equipment. The cost of these acquisitions is reported as a component of Capital Expenditures on the Consolidated Statement of Cash Flows.
Pipeline and Storage
The Pipeline and Storage segment’s capital expenditures for 2025 and 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.
Utility
The majority of the Utility segment’s capital expenditures for 2025 and 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.
Other Investing Activities
In September 2025, the Company sold $7.0 million of fixed income mutual fund shares held in a grantor trust that was established for the benefit of Pennsylvania ratepayers. The proceeds are being used in the Utility segment’s Pennsylvania service territory to fund the final installment of a 5-year pass back of overcollected OPEB expenses, as well as to diversify a portion of grantor trust investments into lower risk money market mutual fund shares.
Estimated Capital Expenditures
The Company’s estimated capital expenditures for the next three years are:
Year Ended September 30
(Millions)
Integrated Upstream and Gathering(1)
Pipeline and Storage
Utility(2)
All Other
(1) Includes estimated expenditures for the years ended September 30, 2026, 2027 and 2028 of approximately $295 million, $245 million and $145 million, respectively, to develop proved undeveloped reserves. The Company is committed to developing its proved undeveloped reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting.
(2) Includes estimated expenditures for the years ended September 30, 2026, 2027, and 2028 of approximately $170 million, $180 million and $185 million, respectively, for system modernization and safety to enhance the reliability and safety of the system and reduce emissions.
Integrated Upstream and Gathering
Capital expenditures for the Integrated Upstream and Gathering segment in 2026 through 2028 are expected to be primarily upstream well drilling and completion expenditures, combined with related infrastructure, in the Appalachian region, as well as additional pipeline and compression infrastructure related to gathering systems.
Pipeline and Storage
Capital expenditures for the Pipeline and Storage segment in 2026 through 2028 are expected to include: the replacement and modernization of transmission and storage facilities, the reconditioning of storage wells, improvements of compressor stations and emissions reduction initiatives, as well as capital expenditures related to system expansion.
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 in 2026 through 2028, 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. Construction on the Tioga Pathway Project is expected to commence in early calendar 2026. This project has a projected in-service date of late calendar 2026 and an estimated capital cost of approximately $101 million. The majority of these expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. As of September 30, 2025, approximately $10.0 million has been spent on this project, including $5.0 million spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet. The remaining $5.0 million spent on the project has been capitalized as Construction Work in Progress.
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 “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 as early as Fall 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 September 30, 2025, approximately $1.8 million has been spent on this project, including $1.7 million spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet. The remaining $0.1 million spent on the project has been capitalized as Construction Work in Progress. The remaining expenditures expected to be spent on the project are included in Pipeline and Storage estimated capital expenditures in the table above.
Utility
Capital expenditures for the Utility segment in 2026 through 2028 are expected to be concentrated in the areas of main and service line improvements and replacements that will enhance the reliability and safety of the system, emission reduction initiatives and, to a lesser extent, the purchase of new equipment.
Project Funding
During fiscal 2025 and 2024, capital expenditures were funded with cash from operations and short-term debt. Going forward, the Company expects to use cash from operations 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.
In the Integrated Upstream and Gathering segment, the Company has entered into contractual obligations to support its development activities and operations in Pennsylvania, including hydraulic fracturing and other well completion services, well tending services, well workover activities, tubing and casing purchases, production equipment purchases, water hauling services and contracts for drilling rig services. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for the amounts of contractual obligations expected to be incurred during the next five years and thereafter to support the Company’s
exploration and development activities. These amounts are largely a subset of the estimated capital expenditures for the Integrated Upstream and Gathering segment shown above.
The Company, in its Pipeline and Storage segment, Integrated Upstream and Gathering segment and Utility segment, has entered into several contractual commitments associated with various pipeline, compressor and gathering system modernization and expansion projects. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for the amounts of contractual commitments expected to be incurred during the next five years and thereafter associated with the Company’s pipeline, compressor and gathering system modernization and expansion projects. These amounts are a subset of the estimated capital expenditures for the Pipeline and Storage segment, Integrated Upstream and Gathering segment and Utility segment that are shown above.
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 segment 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 increased $59.5 million, to a total of $150.2 million, when comparing the balance sheet at September 30, 2025 to the balance sheet at September 30, 2024. The maximum amount of short-term debt outstanding during the year ended September 30, 2025 was $330.0 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 September 30, 2025, the Company had outstanding commercial paper of $150.2 million and did not have any outstanding 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”), 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 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.
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 existing term loan agreement. 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. The Company expects to reduce the Commitments through such financings or offerings, 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 or offerings 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 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 number of 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 its existing term loan agreement (the “Term Loan Agreement”) on February 14, 2024, with six of the 12 banks that are lenders under the Credit Agreement. The Term Loan Agreement provides a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company has 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. The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper. Borrowings under the Term Loan Agreement currently 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%. The current weighted average locked-in interest rate is 5.43% until mid-December 2025.
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 September 30, 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 September 30, 2025, the Company’s debt to capitalization ratio, as calculated under the agreements, was 0.45. The constraints specified in the Credit Agreement and the Term Loan Agreement would have permitted an additional $3.61 billion in short-term and/or long-term debt to be outstanding at September 30, 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 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.
On February 19, 2025, the Company issued $500.0 million of 5.50% notes due March 15, 2030 and $500.0 million of 5.95% notes due March 15, 2035. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.2 million and $493.5 million, respectively. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50% on the 5.50% notes and 7.95% on the 5.95% notes, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company’s credit rating is subsequently upgraded.
The proceeds of the February 19, 2025 debt issuances were used for general corporate purposes, including the March 6, 2025 redemptions of $450.0 million of the Company’s 5.20% notes that were scheduled to mature in July 2025 and $500.0 million of the Company’s 5.50% notes that were scheduled to mature in January 2026. The Company redeemed those notes for $450.8 million and $503.3 million, respectively, plus accrued interest. The remaining proceeds of the debt issuances were used to repay a portion of short-term borrowings the Company incurred to fund a trust for the benefit of holders of $50.0 million of 7.38% notes under the Company’s 1974 indenture prior to the June 13, 2025 maturity date of these notes. Placing these funds in trust enabled the Company to cancel and discharge the 1974 indenture. This relieved the Company from its obligations to comply with the 1974 indenture’s covenants. The funds were paid out of the trust on June 13, 2025 for the redemption of the $50.0 million of 7.38% notes, leaving no notes outstanding under the 1974 indenture.
The Current Portion of Long-Term Debt at September 30, 2025 consisted of a $300.0 million long-term delayed draw term loan that matures in February 2026. The Current Portion of Long-Term Debt at September 30, 2024 consisted of the $50.0 million of 7.38% notes and $450.0 million of 5.20% notes discussed above, with maturity dates in June 2025 and July 2025, respectively. As of September 30, 2025, the future contractual obligations related to aggregate principal amounts of long-term debt, including interest expense, maturing during the next five years and thereafter are as follows: $420.9 million in 2026, $697.7 million in 2027, $385.1 million in 2028, $72.0 million in 2029, $557.0 million in 2030, and $1,138.7 million thereafter. Refer to Item 8 at Note H — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense. Principal payments of long-term debt are a component of cash used in financing activities while interest payments on long-term debt are a component of cash used in operating activities. 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 4.90% at September 30, 2025 and 4.91% at September 30, 2024. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.
On March 8, 2024, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of $200 million in the open market or through privately negotiated transactions, including through the use of trading plans intended to qualify under SEC Rule 10b5-1, in accordance with applicable securities laws and other restrictions.
During the year ended September 30, 2025, the Company executed transactions to repurchase 828,720 shares at an average price of $64.37 per share, for a total cost of $53.8 million (including broker fees and excise taxes). Share repurchases that settled during the year ended September 30, 2025 were funded with cash provided by operating activities and/or short-term borrowings. 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 $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 under the program have been suspended. The program has no fixed expiration date.
OTHER MATTERS
In addition to the environmental and other matters discussed in this Item 7 and in Item 8 at Note L — Commitments and Contingencies, 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 has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan). During 2025, the Company did not make any contributions to the Retirement Plan. The Company does not expect to make any contributions to the Retirement Plan in 2026. For further discussion of the Company’s Retirement Plan, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the Retirement Plan has been closed to new participants since 2003. In that regard, the average remaining service life of active participants in the Retirement Plan is approximately 5 years.
The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits. The Company did not make any contributions to its VEBA trusts or 401(h) accounts in 2025, and does not anticipate making contributions to these accounts in 2026. The Company made direct payments of $0.6 million to retirees not covered by the VEBA trusts and 401(h) accounts during 2025. For further discussion of the Company’s other post-retirement benefits, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the other post-retirement benefits provided by the Company have been closed to new participants since 2003. In that regard, the average remaining service life of active participants is approximately 4 years for those eligible for other post-retirement benefits.
The Company has made certain guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the Consolidated Balance Sheets in accordance with the authoritative guidance (see Item 8 at Note J — Financial Instruments); and (ii) other obligations which are reflected on the Consolidated Balance Sheets. The Company believes that the likelihood it would be required to make payments under the guarantees is remote.
MARKET RISK SENSITIVE INSTRUMENTS
Energy Commodity Price Risk
The Company uses various derivative financial instruments (derivatives), including price swap agreements and no cost collars, as part of the Company’s overall energy commodity price risk management strategy in its Integrated Upstream and Gathering segment. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the
amount that the Company would receive from, or pay to, the respective counterparties at September 30, 2025 to terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas transactions that are related to the financial 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 September 30, 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.
The following tables disclose natural gas price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2025. At September 30, 2025, the Company had not entered into any natural gas price swap agreements extending beyond 2029.
Natural Gas Price Swap Agreements
Expected Maturity Dates
Total
Notional Quantities (Equivalent Bcf)
Weighted Average Fixed Rate (per Mcf)
Weighted Average Variable Rate (per Mcf)
At September 30, 2025, the Company would have received an aggregate of approximately $28.0 million to terminate the natural gas price swap agreements outstanding at that date.
At September 30, 2024, the Company had natural gas price swap agreements covering 220.7 Bcf at a weighted average fixed rate of $3.74 per Mcf.
No Cost Collars
The following table discloses the notional quantities, the weighted average ceiling price and the weighted average floor price for the no cost collars used by the Company to manage natural gas price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). At September 30, 2025, the Company had not entered into any natural gas no cost collars extending beyond 2028.
Expected Maturity Dates
Total
Natural Gas
Notional Quantities (Equivalent Bcf)
Weighted Average Ceiling Price (per Mcf)
Weighted Average Floor Price (per Mcf)
At September 30, 2025, the Company would have received an aggregate of approximately $6.1 million to terminate the natural gas no cost collars outstanding at that date.
At September 30, 2024, the Company had no cost collars agreements covering 128.7 Bcf at a weighted average ceiling price of $4.65 per Mcf and a weighted average floor price of $3.52 per Mcf.
Foreign Exchange Risk
The Company uses foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Integrated Upstream and Gathering segment. All of these transactions are forecasted.
The following table discloses foreign exchange contract information by expected maturity dates. The Company receives a fixed price in exchange for paying a variable price as noted in the Canadian to U.S. dollar forward exchange rates. Notional amounts (Canadian dollars) are used to calculate the contractual payments to be exchanged under contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2025. At September 30, 2025, the Company had not entered into any foreign currency exchange contracts extending beyond 2030.
Expected Maturity Dates
Total
Notional Quantities (Canadian Dollar in millions)
Weighted Average Fixed Rate ($Cdn/$US)
Weighted Average Variable Rate ($Cdn/$US)
At September 30, 2025, absent other positions with the same counterparties, the Company would have paid to its respective counterparties an aggregate of $0.7 million to terminate these foreign exchange contracts.
Refer to Item 8 at Note J — Financial Instruments for a discussion of the Company’s exposure to credit risk related to its derivative financial instruments.
Interest Rate Risk
The fair value of long-term debt is $2.7 billion at September 30, 2025. This fair value amount is not intended to reflect principal amounts that the Company will ultimately be required to pay. The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt:
Principal Amounts by Expected Maturity Dates
Thereafter
Total
(Dollars in millions)
Long-Term Fixed Rate Debt
Weighted Average Interest Rate Paid
Long-Term Variable Rate Debt
Weighted Average Interest Rate Paid (1)
(1) Interest rate is based on a weighted average SOFR interest rate and was 5.62% as of September 30, 2025. The current weighted average locked-in interest rate is 5.43% until mid-December 2025.
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, 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 authorizes 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 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 year ended September 30, 2025, Distribution Corporation recovered $0.9 million from customers.
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 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 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 8 at Note L — Commitments and Contingencies under the heading “Environmental Matters.”
The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.
Environmental Regulation
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 other state authorities have acknowledged 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. This 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. 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.
NEW AUTHORITATIVE ACCOUNTING AND FINANCIAL REPORTING GUIDANCE
For discussion of the recently issued authoritative accounting and financial reporting guidance, refer to Item 8 at Note A — Summary of Significant Accounting Policies under the heading “New Authoritative Accounting and Financial Reporting Guidance.”
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 Annual Report on Form 10-K 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 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;
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 Annual Report on Form 10-K 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.
INDUSTRY AND MARKET DATA DISCLOSURE
The market data and certain other statistical information used throughout this Form 10-K are based on independent industry publications, government publications or other published independent sources. Some data is also based on the Company’s good faith estimates. Although the Company believes these third-party sources are reliable and that the information is accurate and complete, it has not independently verified the information.
