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Item 7. Management’s Discussion and Analysis

2025-11-21 compared with 2024-11-22 · 382 added, 323 removed, 432 unchanged (62% of the section changed)

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The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian Basin.

Current exploration and production development activities are focused primarily in the Marcellus and Utica shales, geological formations that are present in the Appalachian region of the United States.

The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian Basin to markets in the eastern United States and Canada.

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In addition to expansion projects, the Company continues to focus on the ongoing modernization of its regulated Pipeline and Storage and Utility assets.

The Company reports financial results for four business segments:

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

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Other Matters, including:

(a) details regarding the status of Supply Corporation and Empire’s Northern Access project;

(b) 2024 and projected 2025 funding for the Company’s pension and other post-retirement benefits;

(d) rate matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions;

(e) environmental matters;

(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;

(d) environmental matters;

(e) new authoritative accounting and financial reporting guidance;

and (f) effects of inflation.

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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 2022 to fiscal 2023 has been omitted from this Form 10-K, but may be found in Item 7, MD&A, of the Company’s Form 10-K for the fiscal year ended September 30, 2023, filed with the SEC on November 17, 2023.

The Company’s Exploration and Production segment continues to grow, as evidenced by a 5% growth in proved reserves from the prior year to a total of 4,753 Bcfe at September 30, 2024.

Production increased 19.8 Bcfe, or 5%, during the fiscal year ended September 30, 2024 to a total of 392.2 Bcfe, and is expected to increase again in fiscal 2025.

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.

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, which is an expansion and modernization project that would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC (“Transco”) capacity lease, providing access to Mid-Atlantic markets.

Supply Corporation filed a Section 7 (c) application with FERC for the project on August 21, 2024.

The Tioga Pathway Project has a target in-service date in late calendar 2026 and a preliminary cost estimate of approximately $101 million.

The Tioga Pathway Project is discussed in more detail in the Capital Resources and Liquidity section that follows.

From a rate perspective, Distribution Corporation, in its Pennsylvania jurisdiction, reached a settlement with the parties to its rate case proceeding.

On June 15, 2023, the PaPUC issued an order adopting the settlement in full.

The settlement authorized an increase in Distribution Corporation’s annual base rate operating revenues of $23 million that became effective August 1, 2023.

Distribution Corporation also filed a rate case proceeding with the NYPSC in its New York jurisdiction on October 31, 2023 seeking an increase of approximately $88 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024.

After settlement negotiations, a Joint Proposal was filed with the NYPSC on September 9, 2024, that establishes a three-year rate plan allowing for an $86 million increase in annual revenue requirement over three years, with the first-year impact of $57 million in fiscal 2025 and the remainder in fiscal 2026 and fiscal 2027.

It also includes standard make-whole language allowing the recovery of authorized revenues between September 30, 2024 and the start of new rates.

The Joint Proposal remains subject to final NYPSC approval.

In addition, Supply Corporation filed an NGA Section 4 rate case at FERC on July 31, 2023.

Settlement rates became effective on February 1, 2024 under a settlement that was approved by FERC without modification on June 11, 2024, and which is estimated to increase Supply Corporation’s revenues by approximately $56 million on an annual basis.

For further discussion of Distribution Corporation and Supply Corporation rate matters, refer to the Rate Matters section below.

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.

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.

The Company recorded cumulative impairment charges under the ceiling test during fiscal 2024 of $463.7 million ($336.4 million after-tax).

Looking ahead, the first day of the month Henry Hub spot price for natural gas in October 2024 and November 2024 was $2.66 per MMBtu and $1.87 per MMBtu, respectively.

Given these prices, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation for the next quarter, the Company expects to experience a ceiling test impairment for the quarter ending December 31, 2024, and could record additional ceiling test impairments in fiscal 2025.

Please refer to the Critical Accounting Estimates section below for a sensitivity analysis concerning commodity price changes.

The Company also recorded an impairment charge of $46.1 million ($33.8 million after-tax) in its Pipeline and Storage segment at September 30, 2024 to write down the value of certain assets associated with Supply Corporation and Empire’s Northern Access project.

Additional details related to the Northern Access project are discussed further in the Other Matters section below.

From a financing perspective, given the significant impairments recorded during fiscal 2024 discussed above, under its existing indenture covenants, the Company would be precluded from issuing incremental long-term debt beginning in January 2025, for a period likely to extend to June 2025, when the remaining long-term debt outstanding under the Company’s 1974 indenture matures.

However, the 1974 indenture would not prevent the Company from issuing new long-term debt to replace existing long-term debt, including borrowings under the Term Loan Agreement, or from issuing additional short-term debt.

To the extent a need arises to issue incremental long-term debt, the Company expects to be able to place future principal and interest payments in trust for the benefit of bondholders pursuant to the terms of the 1974 indenture.

Depositing the future principal and interest payments in trust would effectively relieve the Company from its obligations to comply with the 1974 indenture’s restrictions, including those on the issuance of incremental long-term debt.

In February 2024, eleven lenders in the syndicate of twelve banks under the Credit Agreement consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028.

In May 2024, three of the lenders in the syndicate assumed the commitments of the sole non-extending lender.

As a result, the Company has aggregate commitments available under the Credit Agreement of $1.0 billion to February 25, 2028.

On February 14, 2024, the Company entered into the Term Loan Agreement with six lenders.

The Term Loan Agreement established a $300 million unsecured committed delayed draw term loan credit facility with a maturity date of February 14, 2026.

In April 2024, the Company elected to draw a total of $300 million under the facility.

The Company used the proceeds for general corporate purposes, including the redemption of

outstanding commercial paper.

For further discussion of the Term Loan Agreement, refer to the Capital Resources and Liquidity section that follows.

The Company began repurchasing outstanding shares of common stock during the quarter ended March 31, 2024 under a share repurchase program authorized by the Company’s Board of Directors.

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 2024, the Company executed transactions to repurchase 1,146,259 shares at an average price of $56.32 per share.

With broker fees and excise taxes, the total cost of these repurchases amounted to $65.2 million.

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 on hand, cash from operations, and short-term and long-term borrowings, as needed, to meet its financing needs for fiscal 2025, including the redemption of two of the Company’s long-term debt maturities totaling $500.0 million that are scheduled to mature in 2025.

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 a change in administration at the federal level, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs.

Corporate Responsibility

The Board of Directors and management recognize that the long-term interests of stockholders are served by considering the interests of customers, employees and the communities in which the Company operates.

The Board retains risk oversight and general oversight of corporate responsibility and sustainability, and any related health and safety issues that might arise from the Company’s operations.

The Board’s Nominating/Corporate Governance Committee oversees and provides guidance on corporate responsibility and sustainability strategies and initiatives that are of significance to the Company and its stakeholders, and may also make recommendations to the Board regarding these strategies and initiatives.

Part of the Board and management’s strategic and capital spending decision process includes identifying and assessing climate-related risks and opportunities.

Management reports quarterly to the Board on critical and potentially emerging risks, including climate-related risks, as part of the Enterprise Risk Management process.

Since the Company operates an integrated business with assets being utilized for, and benefiting from, the production, transportation and consumption of natural gas, the Board and management consider physical and transitional climate risks, including policy and legal risks, technological developments, shifts in market conditions, including future natural gas usage, and reputational risks, and the impact of those risks on the Company’s business.

The Company reviews and considers adjustments to its approach to capital investment in response to these risks and developments, with its long-term, returns-focused approach.

The Company recognizes the important role of ongoing system modernization and efficiency in reducing greenhouse gas emissions and remains focused on reducing the Company’s carbon footprint, with these efforts positioning natural gas, and the Company’s related infrastructure, to remain an important part of the energy complex.

In 2021, the Company set 2030 methane intensity reduction targets at each of its businesses, a 2030 absolute greenhouse gas emissions reduction target for the consolidated Company, and 2030 and 2050 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 also incorporated short-term and long-term executive compensation goals designed to incentivize and reward progress towards the Company’s emissions targets.

The Company’s ability to estimate accurately the time, costs and resources necessary to meet these emissions reduction targets may change as environmental exposures and opportunities change, technology advances, and legislative and regulatory updates are issued.

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

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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.

results could differ from those estimates.

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.

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Exploration and Development Costs.

In the Company’s Exploration and Production segment, property acquisition, exploration and development costs are capitalized under the full cost method of accounting, with natural gas properties in the Appalachian region being the primary component after the fiscal 2022 sale of the Company’s California exploration and production properties.

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.

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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.

The book value of the exploration and production properties exceeded the ceiling at September 30, 2024 as well as June 30, 2024, resulting in a cumulative non-cash impairment charge of $463.7 million ($336.4 million after-tax) for the year ended September 30, 2024.

The 12-month average of the first day of the month price for

natural gas for each month during 2024, based on the quoted Henry Hub spot price for natural gas, was $2.21 per MMBtu.

Because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for 2024.

Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the additional impairment that the Company would have recorded at September 30, 2024 if natural gas prices were $0.25 per MMBtu lower than the average prices used at September 30, 2024 (all amounts are presented after-tax).

These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

Ceiling Testing Sensitivity to Commodity Price Changes

(Millions) $0.25/MMBtu

Natural Gas Prices

Calculated Impairment under Sensitivity Analysis

Actual Impairment Recorded at September 30, 2024 191.4

Additional Impairment

Looking ahead, the first day of the month Henry Hub spot price for natural gas in October 2024 and November 2024 was $2.66 per MMBtu and $1.87 per MMBtu, respectively.

Given the October and November prices, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation for the next quarter, the Company expects to experience a ceiling test impairment for the quarter ending December 31, 2024, and could record additional ceiling test impairments in fiscal 2025.

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.

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.

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The Company’s earnings were $518.5 million in 2025 compared to earnings of $77.5 million in 2024.

The decrease in earnings of $399.4 million was primarily the result of a loss recognized in the Exploration and Production segment compared to earnings in the prior year combined with lower earnings in the Pipeline and Storage segment.

Higher earnings in the Utility segment and the Gathering segment, along with a lower loss in the Corporate category, partially offset these decreases.

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 2024:

• Non-cash impairment charges of $473.1 million ($343.2 million after-tax) recorded during 2024 in the Exploration and Production segment, consisting mostly of ceiling test impairment charges of $463.7 million ($336.4 million after-tax).

Earnings were impacted by the following events in 2025 and 2024:

• 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.

• 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.

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2025 2024 2023

Exploration and Production $ (163,954) $ 232,275 $ 306,064

Integrated Upstream and Gathering $ 324,698 $ (57,041) $ 331,999

Pipeline and Storage 120,957 79,670 100,501

Gathering 106,913 99,724 101,111

Utility 83,249 57,089 48,395

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Total Consolidated $ 518,504 $ 77,513 $ 476,866

EXPLORATION AND PRODUCTION

Exploration and Production Operating Revenues

INTEGRATED UPSTREAM AND GATHERING

Integrated Upstream and Gathering Operating Revenues

Year Ended September 30

2025 2024 2023

Gas Produced in Appalachia (after Hedging) $ 1,151,240 $ 955,790 $ 948,484

Gathering 11,813 15,537 13,891

Other 21,083 5,288 9,971

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Year Ended September 30

2025 2024 2023

Gas Production (MMcf) 426,357 392,047 372,271

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Year Ended September 30

2025 2024 2023

Average Gas Price/Mcf

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2025 Compared with 2024

Operating revenues for the Exploration and Production segment increased $2.6 million in 2024 as compared with 2023.

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.

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2025 Compared with 2024

The Exploration and Production segment experienced a loss of $164.0 million in 2024, a decrease of $396.3 million from earnings of $232.3 million in 2023.

The decrease was primarily attributable to non-cash impairments of assets ($343.2 million), including an aggregate $336.4 million of ceiling test impairments recorded during the quarters ended June 30, 2024 and September 30, 2024 as well as a $6.8 million impairment of certain water disposal assets recorded during the quarter ended September 30, 2024.

In conjunction with the ceiling test impairment, there was a $5.8 million earnings reduction associated with the remeasurement of state deferred income taxes.

Other factors contributing to the decrease included lower natural gas prices after hedging ($34.0 million) and lower other revenue ($3.7 million), as discussed above.

Higher depletion expense ($29.1 million), higher lease operating and transportation expenses ($13.7 million), higher other operating expenses ($8.9 million) and an increase in interest expense ($4.3 million) also reduced earnings.

There was also a $4.1 million increase in unrealized losses related to contingent consideration received as part of the California asset sale.

These decreases were partially offset by higher natural gas production ($39.8 million) combined with lower other taxes ($3.2 million) and a reduction in income tax expense ($7.3 million).

The increase in depletion expense was primarily due to the net increase in production combined with a $0.06 per Mcf increase in the depletion rate.

The increase in lease operating and transportation expenses was primarily the result of higher gathering and transportation costs combined with higher workover expenses.

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:

Lower non-cash impairments of assets $ 239.6 (1)

Higher natural gas prices after hedging 88.3

Higher natural gas production 66.1

Higher other revenue 12.5

Lower earnings reduction associated with remeasurement of state deferred income taxes

due to ceiling test impairments

Lower depreciation / depletion expense 3.9 (2)

Lower lease operating expenses 1.1 (3)

Change in mark to market adjustment on contingent consideration 0.8 (4)

Higher other operating expenses (13.5) (5)

Higher income tax expense (10.6) (6)

Higher other tax expense (3.3) (7)

Lower other income (3.1) (8)

Lower gathering revenues (2.9)

Premiums paid on early redemption of debt (1.7) (9)

Other items (0.3)

(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:

Non-cash impairments of assets $ (343.2) (1)

Lower natural gas prices after hedging (34.0)

Higher depreciation / depletion expense (31.5) (2)

Higher other operating expenses (10.9) (3)

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 (3.7)

Higher interest expense (3.7) (4)

Higher lease operating expenses (3.3) (5)

Higher natural gas production 39.8

Lower income tax expense 7.2 (6)

Lower other tax expense 2.9 (7)

Higher gathering revenue 1.3

(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 is expected to revert back to Seneca.

Higher personnel costs also contributed to the increase in other operating expenses.

The increase in interest expense can largely be attributed to higher average interest rates on intercompany short-term and long-term borrowings, partially offset by lower intercompany long-term debt balances.

The decrease in other taxes 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.

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

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Operating revenues for the Pipeline and Storage segment increased $15.2 million in 2025 as compared with 2024.

The increase in operating revenues was primarily due to an increase in transportation revenues of $20.7 million, an increase in storage revenues of $11.0 million and an increase in other revenues of $1.5 million.

The increase in transportation and storage revenues was 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.

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.

The increase in other revenues primarily reflects an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense.

This increase was partially offset by proceeds that were received during the quarter ended September 30, 2023 as a result of a contract buyout that did not recur in the current fiscal year.

Transportation volume decreased by 59.5 Bcf in 2024 as compared with 2023, primarily due to a decrease in volume as a result of lower capacity utilization with certain contract shippers and certain contract expirations, combined with a decline in volume from warmer weather.

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.

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2025 Compared with 2024

The Pipeline and Storage segment’s earnings in 2024 were $79.7 million, a decrease of $20.8 million when compared with earnings of $100.5 million in 2023.

The decrease in earnings was primarily due to a non-cash impairment charge ($33.8 million), an increase in operating expenses ($7.6 million), an increase in interest

expense ($3.1 million) and an increase in depreciation expense ($2.9 million).

The impairment charge wrote down the carrying value of certain assets associated with Supply Corporation and Empire’s Northern Access project.

Additional details related to the Northern Access project are discussed in the Other Matters section below.

The increase in operating expenses was primarily due to higher personnel costs, an increase in outside services expenses (including compressor and other pipeline maintenance costs), as well as higher power costs related to Empire’s electric motor drive compressor station.

This increase in electric power costs is offset by an equal increase in revenue.

The increase in interest expense is mainly due to an increase in intercompany short-term borrowings along with a higher weighted average interest rate on intercompany long-term borrowings.

The increase in depreciation expense was primarily due to higher average depreciable plant in service compared to the prior year, partially offset by a reduction in certain Supply Corporation depreciation rates associated with its rate case settlement.

The factors that decreased earnings were partially offset by the impact of higher operating revenues ($26.2 million), as discussed above, combined with an increase in other income ($1.6 million).

The increase in other income is primarily due to an increase in interest income related to a higher weighted average interest rate on intercompany short-term notes receivables and a higher average amount outstanding on those receivables.

Gathering Operating Revenues

Year Ended September 30

Gathering $ 244,225 $ 230,317

Gathering Volume — (MMcf)

Year Ended September 30

Gathered Volume 480,688 453,338

2024 Compared with 2023

Operatin g revenues for the Gathering segment increased $13.9 million in 2024 as compared with 2023, which was driven primarily by a 27.4 Bcf increase in gathered volume.

Gathered volume increased 47.7 Bcf in the Gathering segment’s eastern development areas (Trout Run and Tioga), partially offset by a 20.3 Bcf decrease in gathered volume in the Gathering segment’s western development area (Clermont).

The net increase in gathered volume can be attributed to the increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.

2024 Compared with 2023

The Gathering segment’s earnings in 2024 were $106.9 million, an increase of $7.2 million when compared with earnings of $99.7 million in 2023.

The increase in earnings was mainly due to higher gathering revenues ($11.0 million) driven by the increase in gathered volume, as discussed above, and lower interest expense ($0.6 million).

The decrease in interest expense was primarily due to higher capitalized interest.

This increase was partially offset by higher depreciation expense ($2.4 million) and higher operating expenses ($1.3 million).

The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga and Clermont gathering systems.

The increase in operating expenses was largely attributable to higher material costs driven by new plant in-service and higher throughput, in addition to higher labor-related costs.

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:

Non-cash impairment of assets $ 33.8 (1)

Higher operating revenues 13.2

Lower interest expense 1.5 (2)

Higher operating expenses (4.8) (3)

Lower other income (3.1) (4)

Other items 0.7

(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 Operating Revenues

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(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 the NOAA 30-year degree days to NOAA 15-year degree days with the implementation of new base rates in Pennsylvania in August 2023.

(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 decreased $245.0 million in 2024 compared with 2023.

The decrease resulted from a $251.0 million decrease in retail gas sales revenue and a $1.8 million decrease in other revenues.

The decrease in retail gas sales revenue was primarily due to a decrease in the cost of gas sold (per Mcf) as well as a 5.1 Bcf decrease in throughput largely due to warmer weather.

These factors were partially offset by the impact of new base rates in Distribution Corporation’s Pennsylvania jurisdiction pursuant to a settlement approved by the PaPUC on June 15, 2023.

Additional details regarding the base rate regulatory proceeding can be found in the Regulatory Matters section below.

The decrease in other revenues was mainly due to decreases in late payment charges billed to customers ($1.7 million) and capacity release revenues ($1.2

million), partially offset by a lower estimated refund provision for income tax benefits resulting from the 2017 Tax Reform Act ($0.9 million).

The decreases in retail gas sales and other revenues were partially offset by a $7.7 million increase in transportation revenue, predominantly due to the impact of the new base rates in Pennsylvania in addition to an increase in the system modernization and system improvement tracker allocations to customers in New York.

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

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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.

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.

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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 was mainly due to the impact of new base rates in the Utility segment’s Pennsylvania jurisdiction ($18.1 million), the impact of system modernization and system improvement trackers in New York ($7.9 million), lower income tax expense ($4.4 million), and an increase in other income ($1.7 million).

The decrease in income tax expense was largely due to an increase in tax deductions related to certain repairs and maintenance expenditures recorded in the Utility’s Pennsylvania jurisdiction as a result of updated IRS guidance published in 2023.

The increase in other income was primarily driven by a decrease in non-service costs in the Utility segment’s Pennsylvania jurisdiction.

These factors were partially offset by the earnings impact associated with certain revenue decreases ($8.8 million), including a decrease in regulatory adjustments ($5.3 million), a decrease in other operating revenues ($2.1 million), and a decrease due to lower usage and weather ($1.4 million).

Higher operating expenses ($10.7 million), higher depreciation expense ($3.0 million), and higher interest expense ($0.9 million) were other factors that reduced earnings.

The increase in operating expenses was mainly due to higher personnel costs.

The increase in depreciation expense was mainly due to higher average plant balances in the New York jurisdiction and increased depreciation associated with negative net salvage (i.e., cost of removal in excess of salvage value).

The increase can be attributed to the following factors:

Impact of new base rates in New York $ 31.8

Higher other income 15.3 (1)

Impact of higher customer usage 2.4

Higher operating expenses (9.7) (2)

Higher interest expense (6.5) (3)

Higher income tax expense (3.8) (4)

Higher depreciation expense (3.5) (5)

Other items 0.1

(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.

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 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.

Fiscal 2024 was the first year that a

WNA was in effect for the Utility segment’s Pennsylvania rate jurisdiction.

For 2023, the WNA preserved earnings of approximately $4.8 million in the Utility segment’s New York rate jurisdiction as the weather was warmer than normal.

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

2025 Compared with 2024

All Other and Corporate operations had a net loss of $2.2 million in 2024, an improvement of $1.8 million when compared with a net loss of $4.0 million in 2023 .

The improvement was primarily attributable to changes in unrealized gains on investments in equity securities.

In 2024, the Company recorded unrealized gains of $2.4 million, while in 2023, the Company recorded unrealized gains of $0.7 million.

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 $16.2 million in 2024 compared to net other income of $18.1 million in 2023, for a net decrease of $1.9 million.

This was primarily due to a $5.6 million period-over-period increase in losses associated with revaluing the contingent consideration received from the California asset sale and a $2.8 million decrease in interest income.

Partially offsetting factors included higher net gains on investments in equity securities of $2.5 million, $2.0 million of business interruption insurance proceeds received during 2024 related to a pipeline outage that impacted Seneca’s ability to market its gas, a $0.7 million increase in the allowance for funds used during construction, a $0.7 million increase in income from life insurance policies and a $0.5 million increase in non-service pension and post-retirement benefit income.

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

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Interest on long-term debt increased $18.1 million in 2025 as compared to 2024.

The increase was primarily due to higher average balances and a higher weighted average interest rate on long-term debt.

In May 2023, the Company issued $300.0 million of 5.50% notes.

Additionally, the Company elected to draw a total of $300.0 million under a delayed draw term loan credit facility in April 2024.

The Company selected an initial six-month interest period for these borrowings, locking in a weighted average interest rate of 6.71% through the beginning of October 2024.

Partially offsetting these increases, the Company redeemed 3.75% notes in November 2022 and March 2023, amounting to $500.0 million in the aggregate, and also redeemed $49.0 million of 7.395% notes in March 2023.

In addition, there was an increase in capitalized interest in Midstream Company and Seneca.

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 average short-term debt balances in 2024 compared to 2023, partially offset by higher weighted average interest rates for 2024.

There was also a net decrease in interest costs related to gas storage inventory and deferred gas costs in the Utility segment.

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

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Sale of Fixed Income Mutual Fund Shares in Grantor Trust 7.0 —

Acquisition of Upstream Assets — (124.8)

Other Investing Activities 14.1 (2.7)

Proceeds from Issuance of Short-Term Note Payable to Bank — 250.0

Repayment of Short-Term Note Payable to Bank — (250.0)

Net Change in Other Short-Term Notes Payable to Banks and Commercial Paper 59.5 (196.8)

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Dividends Paid on Common Stock (188.4) (183.8)

Net Decrease in Cash, Cash Equivalents, and Restricted Cash $ (17.2) $ (82.3)

Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash $ 4.9 $ (17.2)

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 also has two long-term debt maturities in 2025, totaling $500.0 million, which the Company anticipates funding with long-term borrowings.

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 do not reflect the impact of acquisitions or divestitures that may arise in the future.

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

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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.

Prior to October 2023, the weather impact on cash flow in the Utility segment was mitigated by a WNA solely in its New York rate jurisdiction.

However, effective October 2023, the weather impact on cash flow in the Utility segment is also mitigated by a WNA in its Pennsylvania rate jurisdiction.

The Pennsylvania rate jurisdiction WNA resulted from the PaPUC’s approved settlement on June 15, 2023, further discussed in the Rate Matters section below.

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 Exploration and Production 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.

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 Exploration and Production 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.

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 Exploration and Production segment and Utility segment.

The decrease in the Exploration and Production segment is primarily due to lower cash receipts from natural gas production in the Appalachian region.

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.

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Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets, including non-cash capital expenditures, totaled $942.0 million and $1.12 billion in 2024 and 2023, respectively.

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

Exploration and Production:

2025 2024 2023

Integrated Upstream and Gathering:

Capital Expenditures (1) $ 605.4 (2) $ 645.6 (3) $ 841.0 (4)

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Capital Expenditures 190.0 (2) 184.6 (3) 139.9 (4)

Capital Expenditures 184.6 (2) 139.9 (3)

All Other and Corporate:

1 unchanged sentence

Total Expenditures $ 918.1 $ 942.0 $ 1,123.6

(1) The year ended September 30, 2023 includes $124.8 million related to the acquisition of upstream assets acquired from SWN.

(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) 2024 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $63.3 million, $14.4 million, $21.7 million and $20.6 million, respectively, of non-cash capital expenditures.

(3) 2023 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $43.2 million, $31.8 million, $20.6 million and $13.6 million, respectively, of non-cash capital expenditures.

Exploration and Production

In 2024, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures in the Appalachian region, and included $76.3 million in the Marcellus Shale area and $439.9 million in the Utica Shale area.

(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.

cost of this acquisition is reported as a component of Capital Expenditures on the Consolidated Statement of Cash Flows.

In 2023, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures in the Appalachian region, and included approximately $292.6 million in the Marcellus Shale area and $430.7 million in the Utica Shale area.

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.

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.

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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.

The majority of the Gathering segment’s capital expenditures for 2024 included expenditures related to the continued expansion of Midstream Company’s Tioga, Clermont and Trout Run gathering systems.

The majority of the Gathering segment’s capital expenditures for 2023 included expenditures related to the continued expansion of Midstream Company’s Clermont, Tioga and Trout Run gathering systems.

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.

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Other Investing Activities

In October 2022, the Company sold $10 million of fixed income mutual fund shares held in a grantor trust that was established for the benefit of Pennsylvania ratepayers.

The proceeds were used in the Utility segment’s Pennsylvania service territory during fiscal 2023 to fund the second year 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 for purposes of funding future installments.

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

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2026 2027 2028

Exploration and Production(1) $ 510 $ 490 $ 470

Integrated Upstream and Gathering(1) $ 585 $ 575 $ 565

Pipeline and Storage 230 145 125

Gathering 105 105 105

Utility(2) 195 200 205

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(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.

Exploration and Production

Capital expenditures for the Exploration and Production segment in 2025 through 2027 are expected to be primarily well drilling and completion expenditures, combined with related infrastructure, in the Appalachian region.

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

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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 and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems.

An expansion and modernization project where the Company has forecasted a significant amount of investment in preliminary survey and investigation costs and/or capital expenditures in 2025 through 2027, and where a precedent agreement has been executed, is discussed below.

Supply Corporation concluded an Open Season on August 25, 2023, and based on post-open season discussions, 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”).

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(c) application with the FERC on August 21, 2024.

The Tioga Pathway Project has a projected in-service date of late calendar year 2026 and an estimated capital cost of approximately $101 million.

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, 2024, approximately $2.6 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at September 30, 2024.

The majority of the Gathering segment capital expenditures in 2025 through 2027, included in the table above, are expected to be for additional pipeline and compression infrastructure.

The Gathering segment primarily invests capital to support Seneca’s drilling and completion activity in its long-term development plan.

Seneca has shifted nearly all of its forward-looking activity from its Western Development Area to Tioga County, Pennsylvania.

As a result, the Gathering segment is expecting to see near-term increases in capital expenditures as it constructs the necessary infrastructure to support Seneca’s activity in the region.

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.

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.

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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 on hand, 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 Exploration and Production segment.

It will also likely depend on the timing of gas cost and base rate recovery in the Utility segment.

In the Exploration and Production 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 Exploration and Production segment shown above.

The Company, in its Pipeline and Storage segment, Gathering segment and Utility segment, has entered into several contractual commitments associated with various pipeline, compressor and gathering system modernization and expansion projects.

Going forward, the Company expects to use cash from operations and short-term or long-term borrowings, as needed, to finance capital expenditures.

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.

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, Gathering segment and Utility segment that are shown above.

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.

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FINANCING CASH FLOW

Consolidated short-term debt decreased $196.8 million, to a total of $90.7 million, when comparing the balance sheet at September 30, 2024 to the balance sheet at September 30, 2023.

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, repurchases of stock, other working capital needs and repayment of long-term debt.

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, 2024, the Company had outstanding commercial paper of $90.7 million and did not have any short-term notes payable to banks as of September 30, 2024.

On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the “Credit Agreement”) with a syndicate of twelve banks.

The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement.

As initially entered, the Credit Agreement provided a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027.

In February 2024, the Company and eleven of the banks in the syndicate consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028.

In May 2024, three of the banks in the syndicate assumed the commitments of the sole non-extending lender, such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion to February 25, 2028.

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.

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Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future.

On February 14, 2024, the Company entered into a Term Loan Agreement (the “Term Loan Agreement”) with six lenders, all of which are lenders under the Credit Agreement.

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.

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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%.

In April 2024, a weighted average interest rate of 6.71% was locked in until the beginning of October 2024.

The current locked in interest rate is 4.62% for $200.0 million until December 2024 and 4.58% for the remaining $100 million until January 2025.

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.

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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 $3.07 billion in short-term and/or long-term debt to be outstanding at September 30, 2024 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded 0.65.

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.

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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 May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026.

After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $297.3 million.

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%, 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.

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 Current Portion of Long-Term Debt at September 30, 2024 consisted of $50.0 million of 7.38% notes that mature in June 2025 and $450.0 million of 5.20% notes that mature in July 2025.

None of the Company’s long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period.

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:

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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.

The Company’s present liquidity position is believed to be adequate to satisfy known demands.

Under the Company’s 1974 indenture, certain covenants exist that, from time to time, may preclude the Company from issuing incremental long-term debt.

Given the impairments of exploration and production properties the Company recognized during the year ended September 30, 2024, the indenture covenants would preclude the Company from issuing incremental long-term debt beginning January 2025, for a period likely extending to June 2025, when the remaining debt outstanding under the 1974 indenture matures.

The indenture covenants do not, however, prevent the Company from issuing new long-term debt to replace existing long-term debt, including borrowings under the Term Loan Agreement, or from issuing additional short-term debt.

As of September 30, 2024, the Company has $50.0 million in principal and $3.2 million in interest payments remaining related to long-term debt issued under the 1974 indenture.

Currently, the Company does not anticipate a need to issue incremental long-term debt and only has plans for new long-term debt to replace maturing long-term debt.

In addition to the covenants noted above, the Company’s 1974 indenture contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture.

In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

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.

While the program has no fixed expiration date, the Company is targeting completion of this program by the end of fiscal 2025, depending on a number of factors, including but not limited to stock price, market conditions, applicable securities laws, including SEC Rule 10b-18, corporate and regulatory requirements, and capital and liquidity needs.

The Company’s Board of Directors may suspend, discontinue, terminate, modify, cancel or extend the share repurchase program at any time and for any reason.

During the year ended September 30, 2024, the Company executed transactions to repurchase 1,146,259 shares at an average price of $56.32 per share.

With broker fees and excise taxes, the total cost of these repurchases amounted to $65.2 million.

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.

It is expected that future repurchases, if any, under this program will continue to be funded with cash provided by operating activities and/or through the use of short-term borrowings.

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

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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.

Supply Corporation and Empire developed a project which was intended to move significant prospective Marcellus and Utica production from Seneca’s Western Development Area at Clermont to an Empire interconnection with the TC Energy pipeline at Chippawa and an interconnection with TGP’s 200 Line in East Aurora, New York (the “Northern Access project”).

However, after initial FERC approval on February 3, 2017, substantial litigation ensued over the next several years concerning various federal and state authorizations for the project, with the majority of the project development activities suspended pending resolution.

These legal actions included, most recently, an appeal challenging FERC’s June 2022 order granting Supply Corporation and Empire an extension of time to construct the project through December 31, 2024.

In March 2024, the U.S.

Court of Appeals for the D.C.

Circuit issued an order affirming FERC’s extension of time, with such order final as of late June 2024.

Upon resolution of the extensive litigation, Supply Corporation and Empire began to assess

next steps for the project, including a review of the status of necessary federal and state authorizations, as well as potential changes in expected capital expenditures and the related transportation rates that Supply Corporation and Empire needed to support the project.

As a result of this review, and in accordance with the precedent agreements between the respective parties, Supply Corporation and Empire sent notifications to Seneca, the sole shipper for the project, indicating their intent to increase the project’s firm transportation rates to account for the anticipated increase in capital expenditures to complete the project.

Upon receipt, Seneca indicated it was unwilling to accept the revised transportation rates and intended to terminate the precedent agreements for the project.

The precedent agreements were subsequently terminated on October 16, 2024.

Accordingly, the Company will no longer pursue construction of the Northern Access project and has taken an impairment charge of $46.1 million at September 30, 2024.

The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan).

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The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits.

Prior to 2023, the Company had been making contributions to its VEBA trusts and/or 401(h) accounts each year.

However, the Company did not make any contributions to its VEBA trusts or 401(h) accounts in 2023 or 2024, and does not anticipate making contributions to these accounts in 2025.

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.

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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 Exploration and Production 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.

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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, 2024 to terminate the derivatives.

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 related to the swaps and over-the-counter derivatives markets could adversely impact the Company.

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.

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.

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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 Exploration and Production segment.

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.

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Expected Maturity Dates

2025 2026 2027 2028 2029 Thereafter Total

2026 2027 2028 2029 2030 Total

Notional Quantities (Canadian Dollar in millions)

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Weighted Average Interest Rate Paid (1) 5.6% — — — — — 5.6%

(1) Interest rate is a weighted average SOFR interest rate that was locked in from April 2024 until the beginning of October 2024.

The current locked in interest rate is 4.62% for $200.0 million until December 2024 and 4.58% for the remaining $100 million until January 2025.

(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.

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.” As noted below, the New York division currently has a rate case on file.

In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs.

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 April 20, 2017 with rates becoming effective May 1, 2017 (“2017 Rate Order”).

The 2017 Rate Order provided for a return on equity of 8.7% and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018.

On October 31, 2023, Distribution Corporation made a filing with the NYPSC seeking an increase of approximately $88 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024.

A Notice of Impending Settlement Negotiations was filed with the NYPSC on March 26, 2024.

Thereafter, settlement discussions with parties commenced and to facilitate these discussions, the Company requested postponements of the evidentiary hearing and agreed to extensions of the suspension period for the effective date of new base delivery rates subject to a “make-whole” provision that would permit the Company to recover or refund any revenue under-collections or over-collections, respectively, resulting from the extension period.

The settlement negotiations were successful and resulted in a Joint Proposal (“JP”) that establishes a three-year rate plan allowing for an $86 million increase in annual revenue requirement over three years, with the first-year impact of $57 million in fiscal 2025 and the remainder in fiscal 2026 and fiscal 2027.

The JP settles all contested issues among the signatory parties and includes, among other things, a return on equity of 9.7%, a common equity ratio of 48% for rate setting purposes, an earnings sharing mechanism, an uncollectible expense tracker, and continuation of the Company’s leak prone pipe replacement program.

The revenue requirement in the JP also includes the impact of negative pension/OPEB expense.

The JP was filed with the NYPSC on September 9, 2024.

On November 14, 2024, the NYPSC issued an order extending the suspension period through December 31, 2024.

That order also includes a “make-whole” provision from September 30, 2024 until the date new rates take effect under the final decision on the JP.

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

On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $28.1 million.

A settlement involving all active parties to the proceeding was reached and filed with the PaPUC on April 13, 2023.

The settlement provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million.

The PaPUC approved the settlement in full, without modification or correction, on June 15, 2023 and new rates went into effect on August 1, 2023.

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.

If approved as filed, the Company will be able to recover costs associated with plant placed in service on and after August 1, 2024 if its total plant in service exceeds approximately $781.3 million and its quarterly rate of return does not exceed the authorized PaPUC rate of return.

As of September 30, 2024, plant placed in service for Distribution Corporation’s Pennsylvania division was $785.2 million.

The DSIC petition is currently pending before the PaPUC.

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, approved June 11, 2024, provides that Supply Corporation may make a rate filing for new rates to be effective at any time.

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.

Empire’s 2019 rate settlement requires a Section 4 rate case filing no later than May 1, 2025.

Empire has no rate case currently on file.

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.

The Company has established procedures for the ongoing evaluation of its operations to

identify potential environmental exposures and comply with regulatory requirements.

In 2022, the Company began measuring progress against these reduction targets.

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Environmental Regulation

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in the United States.

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.

For example, the federal Inflation Reduction Act of 2022 (IRA) legislation was signed into law on August 16, 2022, and includes a directive for the EPA, the lead federal agency that regulates greenhouse gas emissions pursuant to the Clean Air Act, to develop a waste emissions charge (WEC) applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds.

The WEC remains in the proposed rulemaking stage, and is expected to begin in calendar year 2025, covering emissions from applicable facilities reported for calendar year 2024.

The regulations implemented by the EPA also impose stringent leak detection and repair requirements and address reporting and control of methane and volatile organic compound emissions, which were further expanded with EPA’s March 2024 publication and finalization of the Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources and its May 2024 finalization of the Greenhouse Gas Reporting Program, Part 98 - Subpart W Final Rule.

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.

Federal, state or local governments may 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.

The New York State legislature passed the CLCPA that 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.

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.

These climate change and greenhouse gas initiatives could impact the Company’s customer base and assets depending on the promulgation of final regulations and on regulatory treatment afforded in the process.

The NYDEC, in conjunction with the New York State Energy Research and Development Authority, is developing a cap-and-invest program in the state, which is anticipated to be effective in calendar year 2025.

The above-enumerated initiatives 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.

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 administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.

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

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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:

Impairments under the SEC’s full cost ceiling test for natural gas reserves;

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;

Changes in the price of natural gas;

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;

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;

The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets;

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;

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;

Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas;

Changes in economic conditions, including 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;

The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets;

Changes in the price of natural gas;

Impairments under the SEC’s full cost ceiling test for natural gas reserves;

The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;

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 and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;

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;

Negotiations with the collective bargaining units representing the Company’s workforce, including potential work stoppages during negotiations;

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;

The impact of information technology disruptions, cybersecurity or data security breaches;

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;

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;

The Company’s ability to complete strategic transactions;

Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits;

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 7. Management’s Discussion and Analysis