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Item 2. Management’s Discussion and Analysis

2026-01-29 compared with 2025-07-31 · 232 added, 381 removed, 282 unchanged (68% of the section changed)

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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.

The Company reports financial results for three business segments.

For a discussion of the Company's earnings, refer to the Results of Operations section below.

The Company has continued to pursue development projects to expand its Pipeline and Storage segment.

One project on Supply Corporation’s system, referred to as the Tioga Pathway Project, is an expansion and modernization project 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

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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.

One project on Supply Corporation’s system, referred to as the Tioga Pathway Project, is an expansion and modernization project in northwest Tioga County, Pennsylvania.

On May 5, 2025, FERC issued the Section 7(b)/7(c) certificate for the project and on January 8, 2026, FERC issued the Notice to Proceed with Construction.

Construction on the Tioga Pathway Project is expected to commence in February 2026.

This project has a target in-service date in late calendar 2026.

Supply Corporation has also announced that it expects to serve as the transporter of natural gas supplies to the Shippingport Power Station, a natural gas power generation facility under development in Beaver County, Pennsylvania.

The project obtained FERC authorization under the Commission’s prior notice regulations on November 7, 2025.

The Tioga Pathway Project and the Shippingport Lateral Project are both discussed in more detail in the Capital Resources and Liquidity section that follows.

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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 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.

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,

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and an additional revenue requirement increase of $12.7 million in fiscal 2027.

The settlement also included standard make-whole language allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024.

In Distribution Corporation's Pennsylvania jurisdiction, Distribution Corporation made a filing with the PaPUC on January 28, 2026 seeking an increase in its annual base rate operating revenues of $19.7 million with a proposed effective date of March 29, 2026.

The Company is proposing, among other things, a new residential energy efficiency pilot program and to make permanent its weather normalization adjustment mechanism.

The Company is also proposing reactivation of the OPEB surcredit to refund $7.2 million for customer bill relief.

In addition, on March 17, 2025, FERC approved an amendment to Empire's 2019 rate case settlement.

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For further discussion of these and other rate matters, refer to the Rate Matters section below.

On October 20, 2025, the Company entered into the Purchase Agreement with CenterPoint Energy Resources Corp.

(the “Seller”), pursuant to which, among other things, the Company agreed to acquire from the Seller all of the issued and outstanding equity interests of CenterPoint Ohio for an aggregate purchase price of $2.62 billion, subject to customary adjustments, as provided in the Purchase Agreement.

This acquisition will add significant regulated scale for the Company, doubling the size of the Company’s gas utility rate base, while expanding its operations beyond New York and Pennsylvania into the neighboring state of Ohio, a state with a constructive regulatory and political environment that is supportive of natural gas.

Closing is expected to occur in the fourth quarter of calendar 2026, pending completion of a notice filing and review with the PUCO, Hart-Scott-Rodino review, and other customary closing conditions.

The purchase price will include a combination of $1.42 billion in cash and a $1.2 billion promissory note to be issued by the Company to the Seller at closing.

The promissory note, which was part of the Seller’s desired transaction structure and was incorporated into the Company’s business valuation, will have a maturity date of 364 days post-closing and will carry an interest rate of 6.5%.

Permanent financing, inclusive of the amount to repay the promissory note, will consist of long-term debt and common equity, along with expected future free cash flow.

In that regard, on December 17, 2025, the Company completed the issuance and sale, in a private placement, of 4,402,513 shares of the Company's common stock, par value $1.00 per share, at a price of $79.50 per share.

After deducting placement fees, the net proceeds to the Company amounted to $338.6 million.

In connection with its entry into the Purchase Agreement, the Company entered into a senior unsecured bridge loan facility commitment letter supported by the Commitment Parties, as well as a 364-day term loan facility commitment letter supported by the Commitment Parties and additional banks, all of which are lenders under the Company’s primary credit facility.

The combination of both facilities fully supports any portion of the purchase price that has not been permanently financed.

As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its exploration and production properties and that book value is subject to a quarterly ceiling test.

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 both 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 either the quarter ended June 30, 2025 or the quarter ended March 31, 2025.

The Company recorded a non-cash impairment charge under the ceiling test during the quarter ended December 31, 2024 of $108.3 million ($79.1 million after-tax).

At December 31, 2025, the ceiling exceeded the book value of the exploration and production properties, and thus, did not result in an impairment charge in the quarter ended December 31, 2025.

Please refer to the Critical Accounting Estimates section below for more details on this matter and a sensitivity analysis concerning commodity price changes.

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 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.

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 total lenders under the Credit Agreement increased to twelve as a new lender joined the syndicate, assuming a portion of an existing lender's commitment.

The 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.

In April 2025, repurchases under the program were temporarily paused.

As a result, the Company expects completion of the program will extend into calendar 2026.

The timing and amount of future repurchases under this program will depend 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.

During the nine months ended June 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).

As of June 30, 2025, the Company has

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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).

The program has no fixed expiration date.

These matters are discussed further in the Capital Resources and Liquidity section that follows.

The Company expects to use cash on hand, cash from operations, and short-term and/or long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2025.

The Company expects to use cash from operations, equity proceeds, and short-term and/or long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2026, including the repayment of a $300.0 million delayed draw term loan scheduled to mature in February 2026 that was repaid in January 2026 and any potential funding for the CenterPoint Ohio acquisition.

The Company continues to evaluate these financing needs and options to meet them.

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Exploration and Development Costs.

The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its exploration and production properties, 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 accordance with the full cost methodology, the Company is required to perform a quarterly ceiling test.

The Company, in its Integrated Upstream and Gathering segment, follows the full cost method of accounting for determining the book value of its exploration and production properties.

In accordance with the full

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cost methodology, the Company is required to perform a quarterly ceiling test.

Under the ceiling test, the present value of future revenues from the Company's exploration and production reserves based on an unweighted arithmetic average of first day of the month commodity prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s exploration and production properties at the balance sheet date.

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If the book value of the exploration and production properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of such properties to the calculated ceiling.

At June 30, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $798.8 million (after-tax).

The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended June 30, 2025, based on the quoted Henry Hub spot price for natural gas, was $2.86 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 the twelve months ended June 30, 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 June 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 $440.1 million (after-tax), which would not have resulted in an impairment charge.

At December 31, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $1.3 billion (after-tax).

The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended December 31, 2025, based on the quoted Henry Hub spot price for natural gas, was $3.39 per MMBtu.

Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices in the twelve-month period used at December 31, 2025 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's exploration and production properties by approximately $953.5 million (after-tax), which would not have resulted in an impairment charge.

This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

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RESULTS OF OPERATIONS

The Company's earnings were $149.8 million for the quarter ended June 30, 2025 compared to a loss of $54.2 million for the quarter ended June 30, 2024.

The increase in earnings of $204.0 million is primarily the result of higher earnings in the Exploration and Production segment, as well as the Gathering and Utility segments.

Lower earnings in the Pipeline and Storage segment and losses in the Corporate and All Other categories partially offset these increases.

The Company's earnings were $411.2 million for the nine months ended June 30, 2025 compared to earnings of $245.1 million for the nine months ended June 30, 2024.

The increase in earnings of $166.1 million is primarily the result of higher earnings in all reportable segments, partially offset by losses in the Corporate and All Other categories.

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The Company's earnings for the nine months ended June 30, 2025 included non-cash impairment charges of $141.8 million ($103.6 million after-tax) in the Exploration and Production segment, consisting mostly of ceiling test impairment charges of $108.3 million ($79.1 million after-tax), as discussed above.

The Company's earnings were $181.6 million for the quarter ended December 31, 2025 compared to earnings of $45.0 million for the quarter ended December 31, 2024.

The increase in earnings of $136.6 million is primarily the result of current year earnings recognized in the Integrated Upstream and Gathering segment compared to a prior year loss combined with higher earnings in the Utility segment.

A higher loss in the Corporate category and lower earnings in the Pipeline and Storage segment partially offset these increases.

The Company's earnings for the quarter ended December 31, 2024 included non-cash impairment charges of $141.8 million ($103.6 million after-tax) in the Integrated Upstream and Gathering segment, consisting mostly of ceiling test impairment charges of $108.3 million ($79.1 million after-tax).

The remaining charges are related to the impairment of certain water disposal assets.

The Company's earnings for the quarter and nine months ended June 30, 2024 included a non-cash ceiling test impairment charge of $200.7 million ($145.0 million after-tax) recorded during the quarter ended June 30, 2024 in the Exploration and Production segment.

Note that all amounts used in earnings discussions are after-tax amounts, unless otherwise noted.

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Three Months Ended

June 30, Nine Months Ended

(Thousands) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Exploration and Production $ 86,671 $ (112,028) $ 198,699 $ 137,722 $ 2,521 $ 135,201

Integrated Upstream and Gathering $ 124,047 $ (19,632) $ 143,679

Pipeline and Storage 31,219 32,454 (1,235)

Gathering 29,996 24,979 5,017 83,483 82,510 973

Utility 34,090 32,499 1,591

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Total Consolidated $ 181,645 $ 44,986 $ 136,659

Exploration and Production

Exploration and Production Operating Revenues

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Integrated Upstream and Gathering

Integrated Upstream and Gathering Operating Revenues

Three Months Ended

June 30, Nine Months Ended

(Thousands) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Gas Produced in Appalachia (after Hedging) $ 315,855 $ 247,187 $ 68,668

Gathering 2,767 3,448 (681)

Other 4,601 1,673 2,928

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Three Months Ended

June 30, Nine Months Ended

2025 2024 Increase

(Decrease) 2025 2024 Increase

Gas Production per MMcf 111,588 96,504 15,084 314,819 300,144 14,675

Gas Production (MMcf) 109,181 97,717 11,464

Average Prices

Three Months Ended

June 30, Nine Months Ended

2025 2024 Increase

(Decrease) 2025 2024 Increase

Average Gas Price/Mcf

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Weighted Average After Hedging $ 2.89 $ 2.53 $ 0.36

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2025 Compared with 2024

Operating revenues for the Exploration and Production segment increased $83.0 million for the quarter ended June 30, 2025 as compared with the quarter ended June 30, 2024.

Operating revenues for the Integrated Upstream and Gathering segment increased $70.9 million for the quarter ended December 31, 2025 as compared with the quarter ended December 31, 2024.

Gas production revenue after hedging increased $68.7 million due to the impact of a $0.36 per Mcf increase in the weighted average price of natural gas after hedging, combined with a 11.5 Bcf increase in natural gas production.

The increase in natural gas production was largely due to pads recently turned in line.

Operating revenues for the Exploration and Production segment increased $125.2 million for the nine months ended June 30, 2025 as compared with the nine months ended June 30, 2024.

Gas production revenue after hedging increased $124.8 million due to the impact of a $0.28 per Mcf increase in the weighted average price of natural gas after hedging, combined with a 14.7 Bcf increase in natural gas production.

The increase in natural gas production for the nine months ended June 30, 2025 as compared with the nine months ended June 30, 2024 was largely due to pads recently turned in line.

The Exploration and Production segment's earnings for the quarter ended June 30, 2025 were $86.7 million, an increase of $198.7 million when compared with a loss of $112.0 million for the quarter ended June 30, 2024.

In addition, other revenue increased $2.9 million primarily due to changes in segment reporting.

The change in segment reporting is fully offset in other operating expenses.

Slightly offsetting these increases, Gathering revenue decreased $0.7 million as a result of natural production declines by producers connected to the Trout Run gathering system.

The Integrated Upstream and Gathering segment's earnings for the quarter ended December 31, 2025 were $124.0 million, an increase of $143.6 million when compared with a loss of $19.6 million for the quarter ended December 31, 2024.

The $143.6 million increase can be attributed to the following factors:

Non-cash ceiling test impairment $ 145.0

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Lower non-cash impairments of assets $ 103.6 (1)

Higher natural gas prices after hedging 31.3

Higher natural gas production 22.9

Change in mark to market adjustment on contingent consideration received as part

of the 2022 California asset sale

Lower interest expense 2.6 (2)

Higher lease operating and transportation expenses (5.7) (2)

Higher other revenue 2.3

Earnings impact associated with remeasurement of state deferred income taxes due to ceiling test impairments 1.0 (3)

Higher depletion expense (8.3) (4)

Higher lease operating expenses (4.9) (5)

Higher other operating expenses (2.6) (6)

Higher income tax expense (2.4) (7)

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Other items (0.6)

(1) Lower interest expense mainly attributed to lower short-term and long-term intercompany borrowings.

(2) The increase in lease operating and transportation expenses was primarily the result of higher production combined with higher gathering and transportation costs.

(1) Includes a ceiling test impairment of $79.1 million and a $24.5 million impairment of certain water disposal assets recorded during the quarter ended December 31, 2024.

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

(3) The increase was due to a $1.0 million earnings reduction associated with the remeasurement of state deferred income taxes for the quarter ended December 31, 2024.

(4) The increase in depletion is mainly attributed to higher production.

(5) The increase in lease operating expenses was primarily the result of higher third-party gathering and transportation costs combined with higher workover and repairs and maintenance costs.

(6) The increase in other operating expenses is mainly attributed to a change in segment reporting, as well as higher gathering operation and maintenance, higher personnel costs and higher abandonment accretion expense, partially offset by higher abandonment costs recognized in fiscal 2024.

(7) The increase in income tax expense was primarily driven by an increase in state tax expense due to higher pre-tax income.

(4) 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.

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The Exploration and Production segment's earnings for the nine months ended June 30, 2025 were $137.7 million, an increase of $135.2 million when compared with earnings of $2.5 million for the nine months ended June 30, 2024.

The $135.2 million increase can be attributed to the following factors:

Higher natural gas prices after hedging $ 70.2

Lower non-cash impairments of assets 41.4 (1)

Higher natural gas production 28.4

Lower depletion expense 13.8 (2)

Change in mark to market adjustment on contingent consideration received as part

of the 2022 California asset sale

Higher income tax expense (7.9) (3)

Higher lease operating and transportation expenses (5.8) (4)

Lower other income (2.4) (5)

Higher other tax expense (2.4) (6)

Higher operating expenses (1.5) (7)

Premiums paid on early redemption of debt (1.0) (8)

Earnings reduction associated with remeasurement of state deferred income taxes

due to ceiling test impairment

Other items 0.4

(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 a ceiling test impairment of $145.0 million in the nine months ending June 30, 2024.

(2) The decrease in depletion expense was primarily due to ceiling test impairments recorded in fiscal 2024 and 2025 that lowered Seneca’s full cost pool depletable base.

(3) The increase in income tax expense was primarily driven by an increase in state income tax expense due to higher pre-tax income before impairments.

(4) The increase in lease operating and transportation expenses was primarily the result of higher production combined with higher gathering and transportation costs.

(5) The decrease in other income is mainly attributable to 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.

(6) 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.

(7) The increase in operating expenses is mainly attributed to higher personnel costs, higher abandonment accretion expense and higher environmental remediation costs in the nine months ended June 30, 2025, partially offset by higher abandonment costs recognized in the nine months ended June 30, 2024.

(8) Represents the Exploration and Production segment’s share of the premiums paid by the Company to redeem long-term debt.

Refer to Note 6 – Capitalization for further discussion.

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(8) The increase in other tax expense was primarily attributable to higher Impact Fees in the Appalachian region as the Company moved into a higher rate tier due to higher NYMEX pricing combined with higher well count.

Pipeline and Storage

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Three Months Ended

June 30, Nine Months Ended

(Thousands) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Firm Transportation $ 80,885 $ 81,086 $ (201)

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$ 106,901 $ 106,612 $ 289

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Pipeline and Storage Throughput

Three Months Ended

June 30, Nine Months Ended

(MMcf) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Firm Transportation 214,073 202,882 11,191

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2025 Compared with 2024

Operating revenues for the Pipeline and Storage segment were relatively consistent for the quarter ended June 30, 2025 as compared with the quarter ended June 30, 2024.

Operating revenues for the Pipeline and Storage segment increased $13.9 million for the nine months ended June 30, 2025 as compared with the nine months ended June 30, 2024.

For the nine months ended June 30, 2025, the $11.4 million increase in transportation revenues and $4.1 million increase in 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.

The settlement was approved by FERC on June 11, 2024.

This increase was partially offset by the impact of a final true-up adjustment recorded in the nine months ended June 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 $1.5 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 for the quarter and nine months ended June 30, 2025 increased by 10.6 Bcf and 24.9 Bcf, respectively, from the prior year's quarter and nine month periods.

The increase in transportation volume for both the quarter and nine months ended June 30, 2025 is primarily due to an increase in volume from colder weather.

This increase for the nine month period was partially offset by lower capacity utilization with certain contract shippers and certain contract expirations and revisions.

Operating revenues for the Pipeline and Storage segment remained relatively flat for the quarter ended December 31, 2025 as compared with the quarter ended December 31, 2024.

Transportation volume for the quarter ended December 31, 2025 increased by 11.2 Bcf, from the quarter ended December 31, 2024.

The increase in transportation volume for the quarter ended December 31, 2025 is primarily due to increased utilization resulting from colder weather.

Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

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The Pipeline and Storage segment’s earnings for the quarter ended June 30, 2025 were $28.9 million, a decrease of $1.8 million when compared with earnings of $30.7 million for the quarter ended June 30, 2024.

The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2025 were $31.2 million, a decrease of $1.3 million when compared with earnings of $32.5 million for the quarter ended December 31, 2024.

The $1.3 million decrease can be attributed to the following factors:

Higher operating expenses $ (1.7) (1)

Lower other income $ (1.2) (1)

Lower interest expense 0.5 (3)

Other items (0.1)

(1) 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.

(1) The decrease in other income was primarily due to a lower average amount outstanding on intercompany short-term notes receivables and a lower weighted average interest rate on those receivables.

(3) 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.

The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2025 were $93.0 million, an increase of $7.5 million when compared with earnings of $85.5 million for the nine months ended June 30, 2024.

The $7.5 million increase can be attributed to the following factors:

Higher operating revenues $ 12.2

Lower interest expense 0.8 (1)

Higher operating expenses (3.8) (2)

Lower other income (1.8) (3)

Other items 0.1

(1) 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.

(2) 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.

(3) 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.

Gathering Operating Revenues

Three Months Ended

June 30, Nine Months Ended

(Thousands) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Gathering Revenues $ 67,873 $ 60,120 $ 7,753 $ 194,034 $ 186,701 $ 7,333

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Gathering Volume

Three Months Ended

June 30, Nine Months Ended

2025 2024 Increase

(Decrease) 2025 2024 Increase

Gathered Volume - (MMcf) 133,271 118,445 14,826 384,003 367,832 16,171

2025 Compared with 2024

Operating revenues for the Ga thering segm ent increased $7.8 million for the quarter ended June 30, 2025 as compared with the quarter ended June 30, 2024 , which was driven primarily by a 14.8 Bcf increase in gathered volume.

Gathered volume increased 11.0 Bcf in the Gathering segment's Eastern Development Area (Tioga and Trout Run), consisting of an increase of 14.0 Bcf in the Tioga gathering system and a decrease of 3.0 Bcf in the Trout Run gathering system.

The Gathering segment's Western Development Area (Clermont) also contributed an increase of 3.8 Bcf in gathered volume.

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

Operating revenue s for the Gathering segm ent increased $7.3 million for the nine months ended June 30, 2025 as compared with the nine months ended June 30, 2024, which was primarily driven by a 16.2 Bcf increase in gathered volume.

Gathered volume increased 16.0 Bcf in the Gathering segment's Eastern Development Area (Tioga and Trout Run), consisting of an increase of 33.4 Bcf in the Tioga gathering system and a decrease of 17.4 Bcf in the Trout Run gathering system.

Additionally, the Gathering segment's Western Development Area (Clermont) contributed an increase of 0.2 Bcf.

The net increase can be attributed to an increase in gross natural gas production in the Appalachian region, largely by Seneca, connected to the aforementioned gathering systems.

The Gathering segment’s earnings for the quarter ended June 30, 2025 were $30.0 million, an increase of $5.0 million when compared with earnings of $25.0 million for the quarter ended June 30, 2024.

The $5.0 million increase can be attributed to the following factors:

Higher operating revenues $ 6.1

Higher depreciation expense (0.9) (1)

Higher income tax expense (0.2) (2)

(1) The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga gathering system.

(2) The increase in income tax expense was largely due to higher state income taxes driven by higher pre-tax income.

Th e Gathering segment’s earnings for the nine months ended June 30, 2025 were $83.5 million, an increase of $1.0 million when compared with earnings of $82.5 million for the nine months ended June 30, 2024.

The $1.0 million increase can be attributed to the following factors:

Higher operating revenues $ 5.8

Lower income tax expense 0.7 (1)

Higher depreciation expense (2.7) (2)

Higher interest expense (1.6) (3)

Higher operating expenses (0.8) (4)

Premiums paid on early redemption of debt (0.7) (5)

Other items 0.3

(1) The decrease in income tax expense was largely due to lower state income taxes resulting from the application of different state apportionment factors in 2025 vs.

2024, as well as a lower tax rate in Pennsylvania.

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(2) The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga gathering system.

(3) The increase in interest expense was primarily driven by additional short-term intercompany borrowings.

(4) The increase in operating expenses was primarily due to higher personnel costs.

(5) Represents the Gathering segment’s share of the premiums paid by the Company to redeem long-term debt.

Refer to Note 6 – Capitalization for further discussion.

Utility Operating Revenues

Three Months Ended

June 30, Nine Months Ended

(Thousands) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Retail Sales Revenues:

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$ 259,137 $ 228,509 $ 30,628

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Utility Throughput

Three Months Ended

June 30, Nine Months Ended

(MMcf) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Retail Sales:

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45,249 38,536 6,713

Three Months Ended June 30, Percent Colder (Warmer) Than

Three Months Ended December 31, Percent Colder (Warmer) Than

Normal 2025 2024 Normal (1)

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Erie, PA 1,894 2,121 1,697 12.0 % 25.0 %

Nine Months Ended June 30,

Buffalo, NY (2)

6,195 5,825 5,128 (6.0) % 13.6 %

Erie, PA 5,693 5,527 4,759 (2.9) % 16.1 %

(1) Percents compare actual 2025 degree days to normal degree days and actual 2025 degree days to actual 2024 degree days.

(2) Normal degree days changed 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.

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(2) Normal degree days changed in January 2025 from NOAA 30-year degree days to NOAA 15-year degree days with the implementation of new base rates in New York.

2025 Compared with 2024

Operating revenues for the Utility segment increased $32.6 million for the quarter ended June 30, 2025 as compared with the quarter ended June 30, 2024.

This increase resulted from a $31.5 million increase in retail gas sales revenue and a $2.7 million increase in other revenue.

The increase in retail gas sales revenue reflects 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.

Operating revenues for the Utility segment increased $30.6 million for the quarter ended December 31, 2025 as compared with the quarter ended December 31, 2024.

This increase resulted from a $28.7 million increase in retail gas sales revenue, a $1.6 million increase in transportation revenue and a $0.3 million increase in other revenue.

The increase in retail gas sales revenue and transportation revenue reflects higher base delivery rates effective October 1, 2025 from the impact of the implementation of year two of Distribution Corporation's three-year rate settlement in its New York jurisdiction.

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

The increase in retail gas sales revenue also reflects higher purchased gas revenues resulting from a 2.4 Bcf increase in throughput mainly due to colder weather combined with an increase in the cost of gas sold (per Mcf).

It should be noted that under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation's earnings are not impacted by fluctuations in gas costs.

The increase in retail gas sales revenue also reflects higher revenues collected from customers for purchased gas costs resulting from a 4.0 Bcf increase in throughput mainly due to colder weather.

Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation's earnings are not impacted by fluctuations in gas costs.

Purchased gas expense recorded on the consolidated income statement matches the revenues collected from customers.

The increase in other revenue was mainly due to the elimination of the refund provision that was required to defer and return the income tax benefits resulting from the 2017 Tax Reform Act to customers ($2.8 million).

The refund provision is no longer necessary because Distribution Corporation's new base delivery rates now reflect a revenue requirement determined with the current federal income tax rate of 21% and the refund of excess accumulated deferred income taxes.

The increases in retail gas sales revenue and other revenue were partially offset by a $1.6 million decrease in transportation revenue, primarily due to the the amortization of certain regulatory assets in accordance with the New York rate settlement, despite a 1.0 Bcf increase in throughput and the impact of new base rates in New York discussed above.

Operating revenues for the Utility segment increased $112.3 million for the nine months ended June 30, 2025 as compared with the nine months ended June 30, 2024.

The increase resulted from a $102.2 million increase in retail gas sales revenue, a $1.2 million increase in transportation revenue, and an $8.8 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, as mentioned above.

The increase in retail gas sales revenue also reflects higher purchased gas revenues resulting from a 9.4 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 2.9 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 was required to defer and return the income tax benefits resulting from the 2017 Tax Reform Act to customers ($10.8 million), as discussed above, partially offset by decreases in capacity release revenues ($0.9 million), other gas revenues ($0.7 million), and late payment charges billed to customers ($0.4 million).

The Utility segment’s earnings for the quarter ended June 30, 2025 were $5.0 million, an increase of $2.4 million when compared with earnings of $2.6 million for the quarter ended June 30, 2024.

The increase in transportation revenue also reflects a 2.7 Bcf increase in throughput due primarily to colder weather.

The Utility segment’s earnings for the quarter ended December 31, 2025 were $34.1 million, an increase of $1.6 million when compared with earnings of $32.5 million for the quarter ended December 31, 2024.

The increase can be attributed to the following factors:

Higher other income $ 3.2 (1)

Impact of new base rates in New York $ 2.9

Impact of higher customer usage 2.8

Impact of regulatory revenue adjustments 1.0 (1)

Higher operating expenses (3.7) (2)

Higher interest expense (2.0) (3)

Higher depreciation expense (1.3) (3)

Higher income tax expense (1.2) (5)

Other items (0.1)

(1) The increase in other income reflects the recognition of non-service pension and post-retirement benefit income in accordance with the New York rate settlement.

(2) The increase in operating expenses is attributable to higher personnel costs, partially offset by amortizations of certain regulatory assets and a reduction in uncollectible expenses 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 long-term intercompany debt balances.

(4) The increase in depreciation expense is attributable to higher average property, plant and equipment balances.

(5) The increase in income tax expense was primarily driven by updates to the amortization of excess deferred income taxes in accordance with the New York rate settlement.

(1) Amount primarily reflects an increase in earnings from a distribution system improvement charge (“DSIC”) modernization tracker in Pennsylvania that became effective in January 2025.

For further discussion of the DSIC tracker, refer to the Rate Matters section below.

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The impact of weather variations on cash flows and customer bills in the Utility segment is mitigated by a WNA.

The WNA, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the Utility segment.

In addition, in periods of colder than normal weather, the WNA benefits the Utility segment's customers.

For the quarter ended June 30, 2025, the WNA preserved earnings of approximately $1.3 million in the Utility segment’s New York rate jurisdiction and preserved earnings of approximately $0.5 million in the Utility segment's Pennsylvania rate jurisdiction, as the weather was warmer than normal on a cycle-bill basis in both jurisdictions.

For the quarter ended June 30, 2024, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $1.7 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $1.4 million, as the weather was warmer than normal in both jurisdictions.

The Utility segment’s earnings for the nine months ended June 30, 2025 were $101.0 million, an increase of $27.2 million when compared with earnings of $73.8 million for the nine months ended June 30, 2024.

The increase can be attributed to the following factors:

Impact of new base rates in New York $ 25.2

Higher other income 14.9 (1)

Impact of higher customer usage 5.4

Higher operating expenses (6.7) (2)

Higher interest expense (5.7) (3)

Higher depreciation expense (2.6) (4)

Higher income tax expense (2.3) (5)

Lower other operating revenues (1.4)

Other items 0.4

(1) The increase in other income reflects the recognition of non-service pension and post-retirement benefit income in accordance with the New York rate settlement.

(2) The increase in operating expenses is attributable to higher personnel costs partially offset by amortizations of certain regulatory assets 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.

(2) The increase in operating expenses is largely attributable to higher personnel costs and higher uncollectible expenses.

(3) The increase in depreciation expense is attributable to higher average property, plant and equipment balances.

(5) The increase in income tax expense was primarily driven by updates to 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.

For the nine months ended June 30, 2025, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $3.9 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $1.7 million, as the weather was warmer than normal on a cycle-bill basis in both jurisdictions.

For the nine months ended June 30, 2024, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $8.1 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $5.5 million, as the weather was warmer than normal in both jurisdictions.

Corporate and All Other

The impact of weather variations on earnings in the Utility segment is mitigated by a WNA.

The WNA, which covers the eight-month period from October through May, has had a stabilizing effect on customer bills and earnings for the Utility segment.

For the quarter ended December 31, 2025, the WNA reduced earnings by approximately $0.8 million and $1.0 million, respectively, in the Utility segment’s New York and Pennsylvania rate jurisdictions, as the weather was colder than normal on a cycle-bill basis in both jurisdictions.

For the quarter ended December 31, 2024, the WNA preserved earnings of approximately $2.0 million and $1.2 million, respectively, in the Utility segment’s New York and Pennsylvania rate jurisdictions, as the weather was warmer than normal on a cycle-bill basis in both jurisdictions.

ALL OTHER AND CORPORATE OPERATIONS

2025 Compared with 2024

Corporate and All Other operations recorded a net loss of $0.7 million for the quarter ended June 30, 2025, which was relatively consistent with the net loss of $0.4 million for the quarter ended June 30, 2024.

For the nine months ended June 30, 2025, Corporate and All Other operations recorded a net loss of $4.1 million, a decrease of $4.9 million when compared with earnings of $0.8 million for the nine months ended June 30, 2024.

The decrease for the nine-month period was primarily attributable to changes in unrealized gains and losses on investments in equity securities.

During nine months ended June 30, 2025, the Company recorded unrealized losses of $1.4 million.

During the nine months ended June 30, 2024, the Company recorded unrealized gains of $1.4 million.

Also contributing to the decrease included higher interest expense ($2.7 million)

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mainly due to a higher average amount of long-term borrowings and higher operating expense ($1.7 million) mainly due to higher legal and consulting fees and outside service expenses.

These changes were partially offset by realized gains from investment securities sold during the current nine-month period ($1.2 million), an increase in interest income on temporary cash investments ($0.8 million), and a decrease in non-service pension and post-retirement benefit costs ($0.4 million).

All Other and Corporate operations reported a net loss of $7.7 million for the quarter ended December 31, 2025, an increase in net loss of $7.4 million when compared with a net loss of $0.3 million for the quarter ended December 31, 2024.

The increase in net loss was primarily attributable to costs associated with the Company's planned acquisition of CenterPoint Ohio ($5.9 million).

Refer to Part I, Item 1 at Note 2 - Pending Acquisition for further discussion of this acquisition.

Additional contributing factors to the increase in net loss were a decrease in the cash surrender value of life insurance policies ($0.9 million) and higher operating expenses ($0.9 million), primarily due to increased legal and consulting fees and outside service costs.

Other Income (Deductions)

Net other income on the Consolidated Statements of Income was $8.5 million for the quarter ended June 30, 2025, compared to net other income of $3.2 million for the quarter ended June 30, 2024, for an increase of $5.3 million.

This increase can be attributed primarily to a $4.7 million increase in non-service pension and post-retirement benefit income, primarily due to the recognition of non-service pension and post-retirement benefit income in accordance with Distribution Corporation's New York rate settlement, along with a $1.2 million change in the quarter-over-quarter revaluation of the contingent consideration received as part of the 2022 California asset sale.

Also contributing to the increase was an increase in the quarter-over-quarter unrealized gains on investment securities of $0.9 million.

Partially offsetting these increases, was a decrease in interest income of $1.4 million.

Net other income on the Consolidated Statements of Income was $31.5 million for the nine months ended June 30, 2025, compared to net other income of $13.0 million for the nine months ended June 30, 2024, for an increase of $18.5 million.

This increase can be attributed primarily to a $21.1 million increase in non-service pension and post-retirement benefit income, as discussed above, along with a $4.1 million change in the year-over-year revaluation of the contingent consideration received as part of the 2022 California asset sale.

These increases were offset by year-over-year changes in the value of investment securities.

During the nine months ended June 30, 2025, there were net losses of $0.3 million on investment securities, compared to net gains of $2.0 million on investment securities during the nine months ended June 30, 2024.

Other offsetting factors were the non-recurrence of $2.0 million of business interruption insurance proceeds received during the nine months ended June 30, 2024 related to a pipeline outage that impacted Seneca's ability to market its gas, along with a $1.9 million decrease in interest income.

Interest Expense on Long-Term Debt

Interest expense on long-term debt on the Consolidated Statement of Income increased $1.5 million for the quarter ended June 30, 2025 as compared to the quarter ended June 30, 2024.

For the nine months ended June 30, 2025, interest expense on long-term debt increased $17.6 million as compared with the nine months ended June 30, 2024.

These increases are primarily due to higher average balances and a higher weighted average interest rate on long-term debt.

On February 19, 2025, the Company issued $500 million of 5.50% notes and $500 million of 5.95% notes.

On March 6, 2025, the Company redeemed $450 million of 5.20% notes and $500 million of 5.50% notes and paid early redemption premiums totaling $2.4 million that were recorded as interest expense on long-term debt in the Exploration and Production and Gathering segments.

The Company also redeemed $50 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 5.86% and 5.99% for the quarter and nine months ended June 30, 2025, respectively.

Net other income on the Consolidated Statements of Income was $8.2 million for the quarter ended December 31, 2025, compared to net other income of $7.7 million for the quarter ended December 31, 2024, for an increase of $0.5 million.

This increase can be attributed primarily to a $1.1 million increase in interest income.

Partially offsetting this increase was a $0.7 million decrease in non-service pension and post-retirement benefit income.

Other Interest Expense

Other interest expense on the Consolidated Statement of Income increased $5.5 million for the quarter ended December 31, 2025 as compared to the quarter ended December 31, 2024.

These increases are primarily due to financing costs incurred associated with the Company's acquisition of CenterPoint Ohio's natural gas utility.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary source of cash during the nine-month period ended June 30, 2025 consisted of cash provided by operating activities and net proceeds from long-term borrowings.

The Company’s primary source of cash during the nine-month period ended June 30, 2024 consisted of cash provided by operating activities and net proceeds from long-term borrowings.

The Company’s primary source of cash during the three-month period ended December 31, 2025 consisted of cash provided by operating activities and net proceeds from the issuance of common stock.

The Company’s primary source of cash during the three-month period ended December 31, 2024 consisted of cash provided by operating activities and net proceeds from short-term borrowings.

The Company expects to have adequate amounts of cash available to meet both its short-term and long-term cash requirements for at least the next twelve months and for the foreseeable future thereafter.

During the remainder of 2025, the Company expects to use cash provided by operating activities and short-term borrowings to fund the Company's capital expenditures.

During the remainder of 2026, the Company expects to use cash provided by operating activities and short-term and long-term borrowings to fund the Company's capital expenditures.

The Company has repaid the $300.0 million delayed draw term loan that was expected to mature in February 2026.

Looking forward to 2027, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures.

The Company also has a delayed draw term loan that matures in February 2026, which the Company anticipates funding with cash on hand as well as short-term or long-term borrowings.

These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.

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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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Non-cash items include depreciation, depletion and amortization, impairment of assets, deferred income taxes and stock-based compensation.

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Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases.

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For storage gas inventory accounted for under the LIFO method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption "Other Accruals and Current Liabilities." Such reserve is reduced as the inventory is replenished.

Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas as well as changes in production.

Cash provided by operating activities in the Integrated Upstream and Gathering segment may vary from period to period as a result of changes in the commodity prices of natural gas as well as changes in production.

The Company uses various derivative financial instruments, including price swap agreements and no cost collars, in an attempt to manage this energy commodity price risk.

The pricing protection obtained from derivative financial instruments will fluctuate over time as instruments expire and are replaced with new instruments reflecting current commodity prices of natural gas.

Net cash provided by operating activities totaled $862.3 million for the nine months ended June 30, 2025, a decrease of $5.7 million compared with $868.0 million provided by operating activities for the nine months ended June 30, 2024.

The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Utility segment, partially offset by higher cash provided by operating activities in the Exploration and Production segment.

The decrease in the Utility segment is driven by 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.

The increase in the Exploration and Production segment is due to the timing of cash receipts and hedge settlements from natural gas production in the Appalachian region.

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Net cash provided by operating activities totaled $274.9 million for the three months ended December 31, 2025, an increase of $54.8 million compared with $220.1 million provided by operating activities for the three months ended December 31, 2024.

The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Integrated Upstream and Gathering segment, partially offset by lower cash provided by operating activities in the Utility segment.

The increase in the Integrated Upstream and Gathering segment is primarily due to higher natural gas prices and production in the Appalachian region combined with the timing of cash receipts and hedge settlements associated with that production.

The decrease in the Utility segment is primarily due to higher natural gas prices and throughput combined with the timing of the associated gas cost recovery.

Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $596.0 million during the nine months ended June 30, 2025 and $655.5 million during the nine months ended June 30, 2024.

The Company’s expenditures for long-lived assets totaled $222.7 million during the three months ended December 31, 2025 and $192.1 million during the three months ended December 31, 2024.

The table below presents these expenditures:

Total Expenditures for Long-Lived Assets

Nine Months Ended June 30, 2025 2024 Increase (Decrease)

Exploration and Production:

Three Months Ended December 31, 2025 2024 Increase (Decrease)

Integrated Upstream and Gathering:

Capital Expenditures $ 141.8 (1) $ 135.6 (2) $ 6.2

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Capital Expenditures 0.2 0.2 —

Capital Expenditures 0.5 0.3 0.2

Eliminations (3.5) — (3.5)

$ 222.7 $ 192.1 $ 30.6

(1) At June 30, 2025, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $61.5 million, $5.7 million, $11.6 million and $9.8 million, respectively, of non-cash capital expenditures.

At September 30, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $63.3 million, $14.4 million, $21.7 million and $20.6 million, respectively, of non-cash capital expenditures.

(2) At June 30, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $50.9 million, $7.0 million, $14.6 million and $8.0 million, respectively, of non-cash capital expenditures.

At September 30, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $43.2 million, $31.8 million, $20.6 million and $13.6 million, respectively, of non-cash capital expenditures.

Exploration and Production

The Exploration and Production segment capital expenditures for the nine months ended June 30, 2025 were primarily well drilling and completion expenditures in the Appalachian region, and included $104.3 million in the Marcellus Shale area and $239.2 million in the Utica Shale area.

These amounts included $182.6 million spent to develop proved undeveloped reserves.

The Exploration and Production segment capital expenditures for the nine months ended June 30, 2024 were primarily well drilling and completion expenditures in the Appalachian region, and included $60.2 million in the Marcellus Shale area and $325.7 million in the Utica Shale area.

These amounts included $248.9 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2025 and June 30, 2024 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions.

In addition, 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.

Expansion and modernization projects where the Company has forecasted a significant amount of investment in preliminary survey and investigation costs and/or capital expenditures, and where a precedent agreement has been executed, is discussed below.

(1) At December 31, 2025, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $55.5 million, $8.1 million and $6.8 million, respectively, of non-cash capital expenditures.

At September 30, 2025, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $87.9 million, $19.4 million and $18.0 million, respectively, of non-cash capital expenditures.

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(2) At December 31, 2024, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $62.3 million, $4.4 million and $4.9 million, respectively, of non-cash capital expenditures.

At September 30, 2024, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $85.0 million, $14.4 million and $20.6 million, respectively, of non-cash capital expenditures.

Integrated Upstream and Gathering

The Integrated Upstream and Gathering segment capital expenditures for the three months ended December 31, 2025 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $90.9 million spent in the Utica Shale area and $33.5 million spent in the Marcellus Shale area.

These amounts included approximately $78.1 million spent to develop proved undeveloped reserves.

Integrated Upstream and Gathering segment capital expenditures also included expenditures related to the continued expansion of Midstream Company’s Trout Run and Tioga gathering systems.

These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

The Integrated Upstream and Gathering segment capital expenditures for the three months ended December 31, 2024 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $90.9 million spent in the Utica Shale area and $27.5 million spent in the Marcellus Shale area.

These amounts included approximately $34.6 million spent to develop proved undeveloped reserves.

Integrated Upstream and Gathering segment capital expenditures also included expenditures related to the continued expansion of Midstream Company’s Tioga gathering system.

These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online and system optimization, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the three months ended December 31, 2025 and December 31, 2024 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions.

In addition, the Pipeline and Storage segment capital expenditures for the three months ended December 31, 2025 included expenditures related to Supply's Corporation's Tioga Pathway Project ($5.4 million) and Shippingpoint Lateral Project ($2.4 million).

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”).

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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.

FERC issued the Section 7(b)/7(c) certificate on May 5, 2025 and on January 8, 2026, FERC issued the Notice to Proceed with Construction.

Construction on the Tioga Pathway Project is expected to commence in February 2026.

This project has a projected in-service date of late calendar year 2026 and an estimated capital cost of approximately $101 million.

As of June 30, 2025, approximately $4.3 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at June 30, 2025.

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 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.

As of June 30, 2025, approximately $0.4 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at June 30, 2025.

The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2025 included expenditures related to the continued expansion of Midstream Company's Tioga and Trout Run gathering systems.

The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2024 included expenditures related to the continued expansion of Midstream Company's Tioga and Clermont gathering systems.

The majority of the Utility segment capital expenditures for the nine months ended June 30, 2025 and June 30, 2024 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions.

As of December 31, 2025, approximately $10.5 million has been capitalized as Construction Work in Progress for this project.

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“Shippingport Lateral Project”).

In order to provide this new natural gas transportation capacity, Supply Corporation expects to construct an approximately 7.5 mile pipeline lateral from its existing Line N pipeline system to a direct interconnection with the facility with the incremental capacity expected to come online in late calendar 2026 and an estimated capital cost of approximately $57 million.

Supply Corporation has executed a Precedent Agreement with Shippingport Power Station, LLC, the facility developer, for 100% of the capacity for the Shippingport Lateral Project and filed an application with FERC under the Commission’s prior notice regulations on August 29, 2025.

The project obtained FERC authorization on November 7, 2025.

As of December 31, 2025, approximately $2.6 million has been spent on this project, including $0.1 million spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet.

The remaining $2.5 million spent on the project has been capitalized as Construction Work in Progress.

The majority of the Utility segment capital expenditures for the three months ended December 31, 2025 and December 31, 2024 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions.

Expenditures were also made for main extensions.

Project Funding

During the nine months ended June 30, 2025 and fiscal 2024, the Company has been financing capital expenditures 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.

During the quarter ended December 31, 2025 and fiscal 2025, the Company has financed capital expenditures with cash from operations and short-term debt.

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

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

The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities.

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generation facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise.

The amounts are subject to modification for opportunities such as the acquisition of attractive natural gas properties, accelerated development of existing natural gas properties, natural gas storage and transmission facilities, natural gas generation facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise.

The amounts are also subject to modification for opportunities involving emission reductions and/or energy transition including investments directly related to low- and no-carbon fuels.

While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s business segments depends, to a large degree, upon market and regulatory conditions as well as legislative actions.

While the majority of capital expenditures in the Utility and Pipeline and Storage segments are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s business segments depends, to a large degree, upon market and regulatory conditions as well as legislative actions.

Financing Cash Flow

Consolidated short-term debt decreased $29.2 million when comparing the balance sheet at June 30, 2025 to the balance sheet at September 30, 2024.

The maximum amount of short-term debt outstanding during the nine months ended June 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.

Consolidated short-term debt decreased $60.2 million when comparing the balance sheet at December 31, 2025 to the balance sheet at September 30, 2025.

The maximum amount of short-term debt outstanding during the three months ended December 31, 2025 was $311.0 million.

In addition to cash provided by operating activities, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing items such as capital expenditures, asset purchases, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, other working capital needs and repayment of long-term debt.

Fluctuations in these items can have a significant impact on the amount and timing of short-term debt.

As of June 30, 2025, the Company had outstanding commercial paper of $61.5 million and did not have any short-term notes payable to banks.

As of December 31, 2025, the Company had outstanding commercial paper of $90.0 million and did not have any short-term notes payable to banks.

On October 20, 2025, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with CenterPoint Energy Resources Corp.

(the “Seller”), pursuant to which, among other things, the Company agreed to acquire from the Seller all of the issued and outstanding equity interests of Vectren Energy Delivery of Ohio, LLC (the “Acquired Company” or “CenterPoint Ohio”), the Seller’s Ohio natural gas local distribution company, for an aggregate purchase price of $2.62 billion, subject to customary adjustments (the “Purchase Price”), as provided in the Purchase Agreement (the “Transaction”).

The Purchase Price will be paid through a combination of cash and a promissory note to be issued by the Company to the Seller at closing pursuant to a Seller Note Agreement (the “Seller Note Agreement”) between the Company, as borrower, and the Seller, as lender.

The Seller Note Agreement, which was part of the Seller’s desired transaction structure and was incorporated into the Company’s business valuation, will provide a $1.2 billion unsecured term loan credit facility (the “Seller Note Facility”) that matures on the last business day that is not more than 364 days from the closing of the Transaction.

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The borrowings under the Seller Note Facility will bear interest at a rate of 6.5% per annum.

The Seller Note Agreement will contain customary representations and affirmative, negative and financial covenants, consistent with the Company’s February 2024 term loan agreement discussed below.

The Seller Note Agreement will also include covenants restricting certain actions with respect to the Acquired Company.

The Seller Note Agreement will contain certain specified events of default, and should an event of default occur, the lender is entitled to exercise certain remedies, including acceleration of the loan and related obligations.

The Seller Note Agreement will contain a covenant defeasance provision that permits the Company to relieve itself from its obligations to comply with covenants under the Seller Note Agreement upon deposit of an amount with a paying agent sufficient to pay the principal of and interest due on the loan on each applicable interest payment date and the maturity date.

In connection with its entry into the Purchase Agreement, the Company entered into a bridge facility commitment letter (the “Bridge Commitment Letter”), pursuant to which The Toronto-Dominion Bank, New York Branch (“TD Bank”) and Wells Fargo Bank, National Association (“Wells Fargo Bank” and, together with TD Bank, the “Commitment Parties”), agreed to provide to the Company loans under a senior unsecured bridge loan facility (the “Bridge Facility”) composed of a $1.42 billion 364-day tranche (the “Acquisition Tranche”), the proceeds of which will be used, if needed, to finance the Transaction, and a $1.2 billion 364-day tranche (the “Seller Note Tranche”), the proceeds of which will be used, if needed, to refinance the Seller Note Facility at its scheduled maturity.

On November 6, 2025, the Company entered into a 364-day term loan facility commitment letter (the “Term Loan Commitment Letter”), pursuant to which the Commitment Parties and ten additional banks, all of which are lenders under our primary credit facility, agreed to provide to the Company loans under a 364-day senior unsecured term loan facility (the “Term Loan Facility”) in the amount of $1.42 billion, the proceeds of which will be used, if needed, to finance the Transaction.

Entering into the Term Loan Commitment Letter enabled the Company to terminate the commitments under the Bridge Commitment Letter in respect of the Acquisition Tranche.

Also on November 6, 2025, the same ten additional banks joined the Commitment Parties as parties to the Bridge Commitment Letter in respect of the Seller Note Tranche.

Subject to the conditions in the respective commitment letters, the commitments under the Term Loan Facility and the Bridge Facility (together, the “Commitments”) may be reduced by proceeds of certain additional indebtedness that may be incurred by the Company and certain equity offerings of the Company to finance the Transaction.

On December 17, 2025, the Company completed the issuance and sale, in a private placement, of 4,402,513 shares of the Company's common stock, par value $1.00 per share, at a price of $79.50 per share.

After deducting placement fees, the net proceeds to the Company amounted to $338.6 million.

The Company is using the net proceeds from the issuance for general corporate purposes, including to finance a portion of the Purchase Price for the Transaction.

The net proceeds of the issuance reduced the commitments under the Term Loan Facility to $1.08 billion.

The Company expects to further reduce the Commitments through additional financings, possibly to zero, prior to the closing date of the Transaction or the scheduled maturity of the Seller Note Facility, as applicable, but there can be no assurance such financings will occur and any such expectation is subject to market conditions.

The Company is subject to certain customary fees with respect to the Term Loan Facility and the Bridge Facility.

Interest on borrowings under the Term Loan Facility or the Bridge Facility would accrue at one of two rates, at the option of the Company:

Term SOFR plus an applicable margin of 1.125% to 1.750%, or a base rate (at least as great as one-month Term SOFR plus 1.0%) plus an applicable margin of 0.125% to 0.750%.

In each case, the applicable margin would depend on the Company’s credit ratings (at current ratings, the applicable margin would be 1.500% for Term SOFR loans and 0.500% for base rate loans).

With respect to the Term Loan Facility, the Company will pay a fee on the 270th day after the funding date in an amount equal to 0.025% of the principal amount of any loans outstanding under such facility at the close of business on that date.

With respect to the Bridge Facility, the applicable margin would increase by an additional 0.25% on each of the 90th, 180th and 270th day after the funding date for any loans outstanding under the Bridge Facility.

Any borrowings under the Term Loan Facility or the Bridge Facility would mature 364 days from the funding date, which, for the Term Loan Facility, would be on or around the closing date of the Transaction and, for the Bridge Facility, would be on or around the scheduled maturity of the Seller Note Facility.

The availability of borrowings under the Term Loan Facility and the Bridge Facility is subject to the satisfaction of certain customary conditions for transactions of these types.

Any definitive financing documentation for the Term Loan Facility or the Bridge Facility will contain customary representations and warranties, covenants and events of defaults for transactions of these types.

The Company expects to execute permanent financing prior to the respective funding dates of the Term Loan

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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.

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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 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.

The Company entered into a term loan agreement (the “Term Loan Agreement”) on February 14, 2024, with six of the 12 banks that are lenders under the Credit Agreement.

As of January 22, 2026, the Company repaid the $300.0 million drawn under the Term Loan Agreement, and the agreement was therefore terminated.

The Term Loan Agreement provided a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company had the ability to select interest periods of one, three or six months for borrowings.

In April 2024, pursuant to the delayed draw mechanism, the Company elected to draw a total of $300.0 million under the facility.

After deducting debt issuance costs, the net proceeds to the Company amounted to $299.4 million.

The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper.

Borrowings under the Term Loan Agreement currently bear interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10%, plus a spread of 1.375%.

The current weighted average locked-in interest rate is 5.82% until mid-August 2025.

Borrowings under the Term Loan Agreement bear interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10%, plus a spread of 1.375%.

Both the Credit Agreement and the Term Loan Agreement provide that the Company’s debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter.

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Since that date, the Company recorded non-cash, after-tax ceiling test impairments totaling $797.0 million.

As a result, at June 30, 2025, $398.5 million was added back to the Company's total capitalization for purposes of calculating the debt to capitalization ratio under the Credit Agreement and the Term Loan Agreement.

As a result, at December 31, 2025, $398.5 million was added back to the Company’s total capitalization for purposes of calculating the debt to capitalization ratio under the Credit Agreement and the Term Loan Agreement.

In addition, for purposes of calculating the debt to capitalization ratio, the following amounts included in Accumulated Other Comprehensive Income (Loss) on the Company’s consolidated balance sheet will be excluded from the determination of comprehensive shareholders’ equity:

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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.

At June 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

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permitted an additional $3.60 billion in short-term and/or long-term debt to be outstanding at June 30, 2025 before the Company’s debt to capitalization ratio exceeded 0.65.

Finally, pursuant to amendments to the Credit Agreement and Term Loan Agreement entered into as of November 6, 2025, for purposes of calculating the debt to capitalization ratio, the Company’s $1.2 billion obligation under the Seller Note Facility, which is to be incurred at the closing of the Transaction, will be excluded from the definition of consolidated indebtedness upon such time and to the extent that the Company, in accordance with the Seller Note Agreement, deposits with a paying agent funds for defeasance of the Seller Note Facility.

At December 31, 2025, the Company’s debt to capitalization ratio, as calculated under the agreements, was 0.41.

The constraints specified in the Credit Agreement and the Term Loan Agreement would have permitted an additional $4.54 billion in short-term and/or long-term debt to be outstanding at December 31, 2025 before the Company’s debt to capitalization ratio exceeded 0.65.

A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company’s subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties.

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However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources.

The Credit Agreement and the Term Loan Agreement each contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement or Term Loan Agreement, as applicable.

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Credit Agreement or Term Loan Agreement, as applicable.

In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.

On February 19, 2025, the Company issued $500.0 million of 5.50% notes due March 15, 2030 and $500.0 million of 5.95% notes due March 15, 2035.

After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.2 million and $493.5 million, respectively.

The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.

Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50% on the 5.50% notes and 7.95% on the 5.95% notes, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade.

A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded.

The proceeds of these 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.

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 June 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 $50.0 million of 7.38% notes that matured in June 2025 and $450.0 million of 5.20% notes with a maturity date in July 2025.

As discussed above, the Company redeemed the $450.0 million of 5.20% notes on March 6, 2025.

The Current Portion of Long-Term Debt at December 31, 2025 consisted of a $300.0 million long-term delayed draw term loan scheduled to mature in February 2026 that was repaid in January 2026 and $300.0 million of 5.50% notes with a maturity date in October 2026.

The Current Portion of Long-Term Debt at September 30, 2025 consisted of the aforementioned $300.0 million long-term delayed draw term loan with a maturity date in February 2026.

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

The Company’s embedded cost of long-term debt was 4.92% at June 30, 2025 and 4.91% at June 30, 2024.

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.

In April 2025, repurchases under the program were temporarily paused.

As a result, the Company expects completion of the program will extend into calendar 2026.

Share repurchases that settled during the nine months ended June 30, 2025 were funded with cash provided by operating activities and/or short-term borrowings.

As of June 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).

It is expected that future

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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.

The program has no fixed expiration date.

The Company’s embedded cost of long-term debt was 4.85% at December 31, 2025 and 4.83% at December 31, 2024.

OTHER MATTERS

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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.

The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the nine months ended June 30, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2025.

The Company also did not make any contributions to its VEBA trusts for its other post-retirement benefits during the nine months ended June 30, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2025.

The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the three months ended December 31, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2026.

The Company also did not make any contributions to its VEBA trusts for its other post-retirement benefits during the three months ended December 31, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2026.

Market Risk Sensitive Instruments

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The authoritative guidance for fair value measurements and disclosures requires consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities.

At June 30, 2025, the Company determined that nonperformance risk associated with its natural gas price swap agreements, natural gas no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation.

At December 31, 2025, the Company determined that nonperformance risk associated with its natural gas price swap agreements, natural gas no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation.

To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

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Utility Operation

Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs.

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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.

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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

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$15.8 million in fiscal 2026, and an additional revenue requirement increase of $12.7 million in fiscal 2027.

It also reflects a return on equity of 9.7% and authorized a revenue requirement increase of $57.3 million in fiscal 2025, an additional revenue requirement increase of $15.8 million in fiscal 2026, and an additional revenue requirement increase of $12.7 million in fiscal 2027.

These revenue requirement increases are being reflected in customer bills on a levelized basis over the three-year rate plan.

The revenue requirement for each year of the three-year plan has been reduced by $14 million for actuarial projections of income that is expected to be recognized for qualified pension and other post-retirement benefits.

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The 2023 Rate Order provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million and authorized a new weather normalization adjustment mechanism.

On January 28, 2026, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $19.7 million with a proposed effective date of March 29, 2026.

The Company is proposing, among other things, a new residential energy efficiency pilot program and to make permanent its weather normalization adjustment mechanism.

The Company is also proposing reactivation of the OPEB surcredit (Rider I) to refund $7.2 million for customer bill relief.

The filing will be suspended for seven months by operation of law unless directed otherwise by the PaPUC.

On April 10, 2024, Distribution Corporation filed with the PaPUC a petition for approval of a distribution system improvement charge ("DSIC") to recover, between base rate cases, capital expenses related to eligible property constructed or installed to rehabilitate, improve and replace portions of the Company’s natural gas distribution system.

The DSIC petition was approved by the PaPUC on December 5, 2024, and on January 1, 2025, the Company initiated recovery of eligible costs on incremental rate base added after September 30, 2024.

During the quarters ended March 31, 2025 and June 30, 2025, Distribution Corporation recovered $0.2 million and $0.3 million, respectively, from customers.

During the quarter ended December 31, 2025, Distribution Corporation recovered $1.1 million from customers.

The DSIC will be reset to zero when new base rates become effective as a result of the Company's recent rate filing.

Pipeline and Storage

Supply Corporation's rate settlement, 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.

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This settlement amendment is estimated to decrease Empire’s revenues on a yearly basis by approximately $0.5 million.

As well, the revenue sharing mechanism under the 2019 rate case settlement was adjusted and Empire committed to undertake greenhouse gas and reliability reporting.

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.

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The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment.

The Company has established processes for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory requirements.

The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory requirements.

In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and greenhouse gas reduction targets associated with the Company’s utility delivery system.

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

In 2022, the Company began

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measuring progress against these reduction targets.

The Company's ability to estimate accurately the time, costs and resources necessary to meet emissions targets may be impacted as environmental exposures, technology and opportunities change and regulatory and policy updates are issued.

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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, and private party litigation related to greenhouse gas emissions.

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 EPA's regulations, which impose stringent leak detection and repair requirements and address reporting and control of methane and volatile organic compound emissions, were further expanded with the

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agency'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.

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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.

Statements from New York's Governor and the state's 2025 New York State Energy Plan acknowledge that the near term targets of the statute may not be achievable in the required timeframes.

The NYPSC has initiated and/or modified various proceedings in an effort to help the State meet these emissions reduction targets.

In May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to certain exemptions, and in December 2025 the Governor approved legislation that will require residential natural gas service applicants to pay the installation costs for the first 100 feet of facilities necessary to provide service commencing December 19, 2026.

The May 2023 legislation is subject to ongoing litigation, with the parties agreeing, in November 2025, to suspend the requirements of the legislation pending resolution of appellate proceedings.

In addition, the NYDEC, in conjunction with the New York State Energy Research and Development Authority, is developing a cap-and-invest program in the state, although issuance of certain key regulations necessary to implement the program has been delayed.

In October 2025, a New York State Supreme Court judge issued an order requiring the NYDEC to promulgate regulations in accordance with the CLCPA by February 6, 2026.

An appeal of that order filed by NYDEC on November 25, 2025 stayed all proceedings to enforce the order pending resolution of the appeal.

The above-enumerated initiatives could impact the Company's customer base and assets, and could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances.

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All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements.

Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.

Certain statements contained

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in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements.

The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished.

In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:

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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;

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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 estimate accurately the time and resources necessary to meet emissions targets;

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;

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

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;

The Company's ability to complete strategic transactions;

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;

2 unchanged sentences

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;

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

1 unchanged sentence

The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;

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

Uncertainty of natural gas reserve estimates;

2 unchanged sentences

Changes in the availability, price or accounting treatment of derivative financial instruments;

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Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;

8 unchanged sentences

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-Q

Item 2. Management’s Discussion and Analysis