What changed in this filing

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Item 2. Management’s Discussion and Analysis

2025-05-01 compared with 2025-01-30 · 355 added, 176 removed, 310 unchanged (63% of the section changed)

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

The Company's efforts in this regard are not

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limited to affiliated projects.

The Company's efforts in this regard are not limited to affiliated projects.

The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas customers in the Appalachian Basin.

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

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

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

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lease, providing access to Mid-Atlantic markets.

Supply Corporation filed a Section 7 (c) application with FERC for the project on August 21, 2024 and on February 13, 2025, the FERC issued the Environmental Assessment for the project.

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

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

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

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

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

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

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

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

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 for the quarter ended December 31, 2024 of $108.3 million ($79.1 million after-tax).

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

From a financing perspective, given the impairments recorded since June 30, 2024, under its existing indenture covenants, the Company is precluded from issuing incremental long-term debt from January 1, 2025 to June 13, 2025, the maturity date of the Company's remaining indebtedness outstanding under its 1974 indenture.

To the extent the Company wishes to relieve its obligations to comply with the 1974 indenture's restrictions, the Company expects to be able to place future principal and interest payments in trust for the benefit of bondholders pursuant to the terms of the 1974 indenture.

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

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

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

In January 2025, the Company and the eleven banks in the syndicate consented to a second one-year extension on the maturity date from February 25, 2028 to February 23, 2029, such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion through February 23, 2029.

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 March 31, 2025, the ceiling exceeded the book value of the exploration and production properties, and thus, did not result in an impairment charge for the quarter ended March 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 the 7.38% notes outstanding under the Company's 1974 indenture, as discussed below.

For further details of these matters, refer to the Capital Resources and Liquidity section below.

Prior to the long-term debt issuances discussed above, the Company placed a total of $53.2 million in trust during the quarter ended March 31, 2025 for the benefit of holders of the 7.38% notes outstanding under the Company’s 1974 indenture.

This included $50.0 million in principal and $3.2 million in interest related to long-term debt issued in June 1995 under the 1974 indenture, with a maturity date of June 13, 2025.

Placing these funds in trust, in an amount equal to the future principal and interest payments due on the 7.38% notes, enabled the Company to cancel and discharge the 1974 indenture, effectively relieving the Company from its obligations to comply with the 1974 indenture’s covenants.

For further discussion of this matter, 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 eleven banks in 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 under the Credit Agreement in the full amount of $1.0 billion through February 23, 2029.

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

The program authorizes the Company to repurchase up to an aggregate amount of $200 million of its outstanding common stock in the open market or through privately negotiated transactions.

During the quarter ended December 31, 2024, the Company executed transactions to repurchase 548,596 shares at an average price of $61.27 per share.

With broker fees and excise taxes, the total cost of these repurchases amounted to $33.9 million.

As of December 31, 2024, the Company has repurchased 1,694,855 shares under the share repurchase program at an average price of $57.93, for a total cost of $99.1 million (including broker fees and excise taxes).

Given the recent macroeconomic uncertainty, as well as increased volatility in the natural gas market, the Company has slowed its pace of repurchases.

During the six months ended March 31, 2025, the Company executed transactions to repurchase 774,768 shares at an average price of $63.74 per share, for a total cost of $49.8 million (including broker fees and excise taxes).

As of March 31, 2025, the Company has repurchased 1,921,027 shares under the share repurchase program at an average price of $59.32, for a total cost of $115.0 million (including broker fees and excise taxes).

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

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

The Company continues to evaluate these financing needs and

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

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

Given the current economic conditions, which include continued inflationary pressures, volatile interest rates and a change in administration at the federal level, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs.

options to meet them.

Given the current economic conditions, which include continued inflationary pressures, volatile interest rates and the ongoing impacts of federal policy changes, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs.

CRITICAL ACCOUNTING ESTIMATES

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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.

The book value of the exploration and production properties exceeded the ceiling at December 31, 2024, resulting in a non-cash impairment charge of $108.3 million ($79.1 million after-tax) for the quarter ended December 31, 2024.

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, 2024, based on the quoted Henry Hub spot price for natural gas, was $2.13 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 December 31, 2024.

Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the additional impairment that the Company would have recorded at December 31, 2024 if natural gas prices were $0.25 per MMBtu lower than the average prices used at December 31, 2024 (all amounts are presented after-tax).

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

Ceiling Testing Sensitivity to Commodity Price Changes

(Millions) $0.25/MMBtu

Natural Gas Prices

Calculated Impairment under Sensitivity Analysis

Actual Impairment Recorded at December 31, 2024 79.1

Additional Impairment

At March 31, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $395.5 million.

The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended March 31, 2025, based on the quoted Henry Hub spot price for natural gas, was $2.44 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 March 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 $16.4 million (after-tax), which would not have resulted in an impairment charge.

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

It is difficult to predict what factors could lead to future non-cash impairments under the SEC's full cost ceiling test.

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For a more complete discussion of the full cost method of accounting, refer to "Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2024 Form 10-K.

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RESULTS OF OPERATIONS

The Company's earnings were $45.0 million for the quarter ended December 31, 2024 compared to earnings of $133.0 million for the quarter ended December 31, 2023.

The decrease in earnings of $88.0 million is primarily the result of a loss recognized in the Exploration and Production segment.

Lower earnings in the Gathering Segment and losses in the Corporate and All Other categories also contributed to the decrease.

Higher earnings in the Pipeline and Storage segment and Utility segment partially offset these decreases.

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 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 $216.4 million for the quarter ended March 31, 2025 compared to earnings of $166.3 million for the quarter ended March 31, 2024.

The increase in earnings of $50.1 million is primarily the result of higher earnings in the Exploration and Production segment and Utility segment, as well as the Pipeline and Storage segment.

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

The Company's earnings were $261.3 million for the six months ended March 31, 2025 compared to earnings of $299.3 million for the six months ended March 31, 2024.

The decrease in earnings of $38.0 million is primarily the result of lower earnings in the Exploration and Production segment and Gathering segment, along with losses in the Corporate and All Other categories.

Higher earnings in the Utility segment and Pipeline and Storage segment partially offset these decreases.

The Company's earnings for the six months ended March 31, 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 remaining charges are related to the impairment of certain water disposal assets.

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

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Earnings (Loss) by Segment

Three Months Ended

March 31, Six Months Ended

(Thousands) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Exploration and Production $ 97,828 $ 62,065 $ 35,763 $ 51,051 $ 114,548 $ (63,497)

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Three Months Ended

March 31, Six Months Ended

(Thousands) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Gas Produced in Appalachia (after Hedging) $ 310,570 $ 263,382 $ 47,188 $ 557,757 $ 515,798 $ 41,959

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Three Months Ended

March 31, Six Months Ended

2025 2024 Increase

(Decrease) 2025 2024 Increase

Gas Production per MMcf 105,514 102,883 2,631 203,232 203,640 (408)

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Average Prices

Three Months Ended

March 31, Six Months Ended

2025 2024 Increase

(Decrease) 2025 2024 Increase

Average Gas Price/Mcf

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2025 Compared with 2024

Operating revenues for the Exploration and Production segment decreased $5.2 million for the quarter ended December 31, 2024 as compared with the quarter ended December 31, 2023.

Gas production revenue after hedging decreased $5.2 million due to the impact of a 3.0 Bcf decrease in natural gas production partially offset by a $0.02 per Mcf increase in the weighted average price of natural gas after hedging.

The decrease in natural gas production was largely due to lower production in the Marcellus and Utica wells in the Appalachian region.

The Exploration and Production segment's loss for the quarter ended December 31, 2024 was $46.8 million, a decrease of $99.3 million when compared with earnings of $52.5 million for the quarter ended December 31, 2023.

This decrease can be primarily attributed to non-cash impairments of assets ($103.6 million), including ceiling test impairments of $79.1 million and a $24.5 million impairment of certain water disposal assets recorded during the quarter ended December 31, 2024, as well as lower natural gas production ($6.0 million).

In conjunction with the ceiling test impairment, there was a $1.0 million earnings reduction associated with the remeasurement of state deferred income taxes.

A decline in other income ($1.7 million) also contributed to the decrease in earnings.

These decreases were partially offset by higher natural gas prices after hedging ($1.9 million), lower depletion expense ($6.8 million) and lower lease operating and transportation expenses ($1.1 million).

There was also an unrealized loss recognized in the three-month period ended December 31, 2024 ($0.3 million) on contingent consideration received as part of the 2022 California asset sale, compared to an unrealized loss that was recognized in the three-month period ended December 31, 2023 ($3.0 million) on such contingent consideration.

The decline in other income was mainly attributed to business interruption insurance proceeds received during the quarter ended December 31, 2023 related to a pipeline outage impacting Seneca’s ability to market gas.

The decrease in depletion expense was primarily due to the net decrease in production combined with a $0.06 per Mcf decrease in the depletion rate largely due to ceiling test impairments recorded in the third and fourth quarters of fiscal 2024 that lowered Seneca’s full cost pool depletable base.

The decrease in lease operating and transportation expenses was primarily the result of lower gathering and transportation costs combined with lower workover and salt water disposal expenses.

Operating revenues for the Exploration and Production segment increased $47.3 million for the quarter ended March 31, 2025 as compared with the quarter ended March 31, 2024.

Gas production revenue after hedging increased $47.2 million due to the impact of a 2.6 Bcf increase in natural gas production combined with a $0.38 per Mcf increase in the weighted average price of natural gas after hedging.

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

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Operating revenues for the Exploration and Production segment increased $42.2 million for the six months ended March 31, 2025 as compared with the six months ended March 31, 2024.

Gas production revenue after hedging increased $42.0 million due to the impact of a $0.21 per Mcf increase in the weighted average price of natural gas after hedging, partially offset by a 0.4 Bcf decrease in natural gas production.

The minor decrease in natural gas production for the six months ended March 31, 2025 as compared with the six months ended March 31, 2024 is due to the timing of turned in line production.

The Exploration and Production segment's earnings for the quarter ended March 31, 2025 were $97.8 million, an increase of $35.7 million when compared with earnings of $62.1 million for the quarter ended March 31, 2024.

The $35.7 million increase can be attributed to the following factors:

Higher natural gas prices after hedging $ 32.0

Higher natural gas production 5.3

Lower depletion expense 7.0 (1)

Higher income tax expense (2.3) (2)

Higher operating expenses (1.9) (3)

Higher lease operating and transportation expenses (1.2) (4)

Premiums paid on early redemption of debt (1.0) (5)

Higher other tax expense (1.0) (6)

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

of the 2022 California asset sale

Other items (0.6)

(1) The decrease in depletion expense was primarily due to ceiling test impairments recorded in the third and fourth quarters of fiscal 2024 as well as the first quarter of fiscal 2025 that lowered Seneca’s full cost pool depletable base.

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

(3) The increase in operating expenses is mainly attributed to higher personnel and technology-related costs.

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

(5) Represents the Exploration and Production segment’s share of the premiums paid by the Company to redeem $450 million of the Company’s 5.20% notes that were scheduled to mature in July 2025 and $500 million of the Company’s 5.50% notes that were scheduled to mature in January 2026.

(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) Unrealized loss of $0.2 million recognized during the quarter ended March 31, 2025 compared to an unrealized gain of $0.4 million recognized during the quarter ended March 31, 2024.

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The Exploration and Production segment's earnings for the six months ended March 31, 2025 were $51.1 million, a decrease of $63.4 million when compared with earnings of $114.5 million for the six months ended March 31, 2024.

The $63.4 million decrease can be attributed to the following factors:

Non-cash impairments of assets $ (103.6) (1)

Higher income tax expense (2.3) (2)

Lower other income (1.9) (3)

Earnings reduction associated with remeasurement of state deferred income taxes

due to ceiling test impairment

Higher operating expenses (1.7) (4)

Premiums paid on early redemption of debt (1.0) (5)

Lower natural gas production (0.8)

Higher other tax expense (0.7) (6)

Higher natural gas prices after hedging 34.0

Lower depletion expense 13.8 (7)

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

of the 2022 California asset sale

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.

(2) 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.

(3) 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.

(4) The increase in operating expenses is mainly attributed to higher personnel and technology-related costs.

(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 decrease in depletion expense was primarily due to ceiling test impairments recorded in the third and fourth quarters of fiscal 2024 as well as the first quarter of fiscal 2025 that lowered Seneca’s full cost pool depletable base.

(8) Unrealized loss of $0.5 million recognized during the six months ended March 31, 2025 compared to an unrealized loss of $2.7 million recognized during the six months ended March 31, 2024.

Pipeline and Storage

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Three Months Ended

March 31, Six Months Ended

(Thousands) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Firm Transportation $ 82,224 $ 80,979 $ 1,245 $ 163,310 $ 152,475 $ 10,835

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Three Months Ended

March 31, Six Months Ended

(MMcf) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Firm Transportation 234,730 222,258 12,472 437,612 422,359 15,253

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2025 Compared with 2024

Operating revenues for the Pipeline and Storage segment increased $12.2 million for the quarter ended December 31, 2024 as compared with the quarter ended December 31, 2023.

The increase in operating revenues was primarily due to an increase in transportation revenues of $9.6 million and an increase in storage revenues of $3.7 million, partially offset by a decrease in other revenues of $1.1 million.

The increase in transportation and storage revenues was primarily attributable to an increase in Supply Corporation's transportation and storage rates effective February 1, 2024, in accordance with Supply Corporation's rate case settlement.

Operating revenues for the Pipeline and Storage segment increased $1.6 million for the quarter ended March 31, 2025 as compared with the quarter ended March 31, 2024.

The $1.2 million increase in transportation revenues was primarily attributable to an increase in Supply Corporation's transportation rates effective February 1, 2024, in accordance with Supply Corporation's rate case settlement.

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

The 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 ended December 31, 2024 increased by 2.7 Bcf from the prior year's quarter ended December 31, 2023.

The increase in transportation volume for the quarter ended December 31, 2024 is primarily due to an increase in volume from new long-term contracts combined with an increase in volume from colder weather.

This increase was partially offset by the impact of a final true-up adjustment recorded in the quarter ended March 31, 2024 to the surcharge for pipeline safety and greenhouse gas costs that ended effective February 1, 2024.

The $0.4 million increase in other revenues is primarily due to the recognition of a gain on the sale of base gas during the quarter ended March 31, 2025, combined with an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense.

Operating revenues for the Pipeline and Storage segment increased $13.8 million for the six months ended March 31, 2025 as compared with the six months ended March 31, 2024.

The $10.8 million increase in transportation revenues and $3.6 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 the aforementioned Supply Corporation rate case settlement and partially offset by the impact of a final true-up adjustment recorded in the quarter ended March 31, 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 $0.7 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, partially offset by the recognition of a gain on the sale of base gas during the quarter ended March 31, 2025.

Transportation volume for the quarter and six months ended March 31, 2025 increased by 11.7 Bcf and 14.4 Bcf, respectively, from the prior year's quarter and six month periods.

The increase in transportation volume for both the quarter and six months ended March 31, 2025 is primarily due to an increase in volume from a new long-term contract combined with an increase in volume from colder weather.

These were partially offset by lower capacity utilization with certain contract shippers and certain contract expirations and revisions.

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

The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2024 were $32.5 million, an increase of $8.4 million when compared with earnings of $24.1 million for the quarter ended December 31, 2023.

The increase in earnings was primarily due to the earnings impact of higher operating revenues ($9.6 million), as discussed above.

This increase was partially offset by increases in operating expenses ($0.9 million) and higher income tax expense ($0.5 million).

The increase in operating expenses was primarily due to higher pipeline integrity costs combined with an increase in personnel costs.

The increase in income tax expense is mainly due to higher state income tax expense due to higher pre-tax earnings.

The Pipeline and Storage segment’s earnings for the quarter ended March 31, 2025 were $31.7 million, an increase of $1.0 million when compared with earnings of $30.7 million for the quarter ended March 31, 2024.

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

Higher operating revenues $ 1.2

Lower depreciation expense 0.7 (1)

Lower interest expense 0.3 (2)

Higher operating expenses (1.2) (3)

(1) The decrease in depreciation expense primarily reflects higher depreciation on compressor station turbines recorded in the prior year second quarter.

(2) The decrease in interest expense was primarily driven by a decrease in intercompany short-term borrowings.

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(3) The increase in operating expenses was primarily due to an increase in personnel costs, as well as 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.

The Pipeline and Storage segment’s earnings for the six months ended March 31, 2025 were $64.2 million, an increase of $9.4 million when compared with earnings of $54.8 million for the six months ended March 31, 2024.

The $9.4 million increase can be attributed to the following factors:

Higher operating revenues $ 10.9

Lower depreciation expense 0.5 (1)

Lower interest expense 0.3 (2)

Higher operating expenses (2.1) (3)

Lower other income (0.6) (4)

Other items 0.4

(1) The decrease in depreciation expense primarily reflects higher depreciation on compressor station turbines recorded in the prior year six-month period, combined with a reduction in certain Supply Corporation depreciation rates associated with its rate case settlement.

These decreases were partially offset by depreciation from new plant placed in service over the past year.

(2) The decrease in interest expense was primarily driven by a decrease in intercompany short-term borrowings, partially offset by a decrease in the allowance for funds used during construction (debt component) driven by lower average construction work in process balances.

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

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

(4) The decrease in other income was primarily driven by a decline in non-service pension and post-retirement benefit income.

Gathering Operating Revenues

Three Months Ended

March 31, Six Months Ended

(Thousands) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Gathering Revenues $ 65,030 $ 63,993 $ 1,037 $ 126,161 $ 126,581 $ (420)

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Three Months Ended

March 31, Six Months Ended

2025 2024 Increase

(Decrease) 2025 2024 Increase

Gathered Volume - (MMcf) 129,771 125,565 4,206 250,732 249,388 1,344

2025 Compared with 2024

Operating revenues for the Ga thering segme nt decreased $1.5 million f or the quarter ended December 31, 2024 as compared with the quarter ended December 31, 2023, which was driven primarily by a 3.3 Bcf decrease in gathered volume.

Operating revenues for the Ga thering segme nt increased $1.0 million f or the quarter ended March 31, 2025 as compared with the quarter ended March 31, 2024, which was driven primarily by a 4.

2 Bcf increase in gathered volume.

Gathered volume increased 6.5 Bcf in the Gathering segment's eastern development areas (Tioga and Trout Run), partially offset by a 2.3 Bcf decrease in gathered volume in the Gathering segment's western development area (Clermont).

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Gathered volume decreased 1.9 Bcf and 1.4 Bcf in the Gathering segment's eastern development areas (Trout Run and Tioga) and western development area (Clermont), respectively.

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

The Gathering segment’s earnings for the quarter ended December 31, 2024 were $27.1 million, a decrease of $1.7 million when compared with earnings of $28.8 million for the quarter ended December 31, 2023.

The decrease in earnings was primarily due to lower gathering revenues ($1.2 million) and higher depreciation expense ($0.8 million).

The decrease in gathering revenues was driven by the decrease in gathered volume, as discussed above.

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

Operating revenue s for the Gathering segme nt decreased $0.4 million for the six months ended March 31, 2025 as compared with the six months ended March 31, 2024.

Although gathered volume increased 1.3 Bcf over the aforementioned time period, changes in the throughput producer mix drove the decrease in revenue.

Gathered volume increased 4.9 Bcf in the Gathering segment's eastern development areas (Tioga and Trout Run), partially offset by a 3.6 Bcf decrease in gathered volume in the Gathering segment's western development area (Clermont).

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

The Gathering segment’s earnings for the quarter ended March 31, 2025 were $26.3 million, a decrease of $2.4 million when compared with earnings of $28.7 million for the quarter ended March 31, 2024.

The $2.4 million decrease can be attributed to the following factors:

Higher operation and maintenance expense $ (1.2) (1)

Higher depreciation expense (1.0) (2)

Higher other interest expense (0.9) (3)

Premiums paid on early redemption of debt (0.7) (4)

Higher operating revenues 0.8

Lower income tax expense 0.5 (5)

Other items 0.1

(1) The increase in operation and maintenance expense was primarily due to higher compressor repairs and services and higher labor-related costs.

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

These decreases in earnings were partially offset by a decrease in income tax expense ($0.4 million) due to lower state income taxes driven by lower pre-tax income and a reduction in the Pennsylvania state income tax rate.

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

(4) Represents the Gathering segment’s share of the premiums paid by the Company to redeem $450 million of the Company’s 5.20% notes that were scheduled to mature in July 2025 and $500 million of the Company’s 5.50% notes that were scheduled to mature in January 2026.

(5) The decrease in income tax expense was primarily due to lower state income taxes driven by lower pre-tax income.

The Gathering segment’s earnings for the six months ended March 31, 2025 were $53.5 million, a decrease of $4.0 million when compared with earnings of $57.5 million for the six months ended March 31, 2024.

The $4.0 million decrease can be attributed to the following factors:

Higher depreciation expense $ (1.8) (1)

Higher other interest expense (1.3) (2)

Higher operation and maintenance expense (1.1) (3)

Premiums paid on early redemption of debt (0.7) (4)

Lower operating revenues (0.3)

Lower income tax expense 0.9 (5)

Other items 0.3

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

(2) The increase in other interest expense was primarily driven by additional intercompany borrowings.

(3) The increase in operation and maintenance expense was primarily due to higher labor-related costs and higher compressor repairs and services.

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(5) The decrease in income tax expense was primarily due to lower state income taxes driven by lower pre-tax income.

Utility Operating Revenues

Three Months Ended

March 31, Six Months Ended

(Thousands) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Retail Sales Revenues:

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Three Months Ended

March 31, Six Months Ended

(MMcf) 2025 2024 Increase

(Decrease) 2025 2024 Increase

Retail Sales:

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62,919 54,183 8,736 101,455 92,631 8,824

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

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

Normal 2025 2024 Normal (1)

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Buffalo, NY (2)

3,226 3,116 2,705 (3.4) % 15.2 %

Erie, PA 3,023 3,017 2,576 (0.2) % 17.1 %

Six Months Ended March 31,

Buffalo, NY (2)

5,352 5,000 4,563 (6.6) % 9.6 %

Erie, PA 4,917 4,714 4,240 (4.1) % 11.2 %

(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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2025 Compared with 2024

Operating revenues for the Utility segment increased $26.5 million for the quarter ended December 31, 2024 as compared with the quarter ended December 31, 2023.

This increase resulted from a $24.2 million increase in retail gas sales revenue and a $2.5 million increase in other revenue, which were partially offset by a $0.2 million decrease in transportation revenue.

The increase in retail gas sales revenue is primarily the result of 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 $53.2 million for the quarter ended March 31, 2025 as compared with the quarter ended March 31, 2024.

This increase resulted from a $46.6 million increase in retail gas sales revenue, a $3.0 million increase in transportation revenue, and a $3.6 million increase in other revenue.

The increases in retail gas sales and transportation revenues reflect the impact of new base delivery rates in Distribution Corporation's New York jurisdiction pursuant to a settlement approved by the NYPSC on December 19, 2024.

Additional details regarding the base rate regulatory proceeding can be found in Note 10 - Regulatory Matters.

This increase also reflects higher purchased gas revenues resulting from a 0.7 Bcf increase in throughput due to cooler temperatures combined with an increase in the cost of gas sold (per Mcf).

The increase in retail gas sales revenue also reflects higher purchased gas revenues resulting from a 6.3 Bcf increase in throughput due to colder temperatures 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.

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

The increase in transportation revenue also reflects a 2.4 Bcf increase in throughput due primarily to colder temperatures.

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 ($4.8 million), partially offset by decreases in capacity release revenues ($0.6 million), other gas revenues ($0.3 million), and late payment charges billed to customers ($0.2 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 Utility segment’s earnings for the quarter ended December 31, 2024 were $32.5 million, an increase of $5.9 million when compared with earnings of $26.6 million for the quarter ended December 31, 2023.

The increase was primarily due to the impact of new base rates in the Utility segment's New York jurisdiction ($7.9 million) and an increase in other income ($3.2 million), which was mainly attributable to the recognition of non-service pension and post-retirement benefit income in accordance with the rate settlement.

These factors were partially offset by higher interest expense ($1.8 million), higher operating expenses ($1.2 million), higher depreciation expense ($0.6 million), an increase in income tax expense ($0.6 million), and a decrease in margin due to lower usage and weather ($0.3 million).

The increase in interest expense was primarily due to an increase in outstanding intercompany debt balances.

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

Operating revenues for the Utility segment increased $79.7 million for the six months ended March 31, 2025 as compared with the six months ended March 31, 2024.

The increase resulted from a $70.7 million increase in retail gas sales revenue, a $2.8 million increase in transportation revenue, and a $6.1 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 7.0 Bcf increase in throughput due to colder temperatures combined with an increase in the cost of gas sold (per Mcf).

The increase in transportation revenue also reflects a 1.9 Bcf increase in throughput due primarily to colder temperatures.

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 ($8.1 million), as discussed above, partially offset by decreases in capacity release revenues ($1.0 million), other gas revenues ($0.6 million), and late payment charges billed to customers ($0.4 million).

The Utility segment’s earnings for the quarter ended March 31, 2025 were $63.5 million, an increase of $18.8 million when compared with earnings of $44.7 million for the quarter ended March 31, 2024.

The increase can be attributed to the following factors:

Impact of new base rates in New York $ 14.6

Impact of higher customer usage 3.0

Higher other income 8.5 (1)

Higher operating expenses (3.3) (2)

Higher interest expense (1.9) (3)

Lower other operating revenues (0.9)

Higher depreciation expense (0.7) (4)

Higher income tax expense (0.5) (5)

(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 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 an increase in state income tax expense due to higher pre-tax income.

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

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

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 in both jurisdictions.

For the quarter ended December 31, 2023, the WNA preserved earnings of approximately $1.4 million in the Utility segment’s New York jurisdiction and $0.5 million in the Utility segment's Pennsylvania jurisdiction, as the weather was warmer than normal.

For the quarter ended March 31, 2025, the WNA preserved earnings of approximately $0.6 million in the Utility segment’s New York rate jurisdiction, as the weather was warmer than normal.

The earnings preserved by the WNA in the Utility segment's Pennsylvania rate jurisdiction were negligible.

For the quarter ended March 31, 2024, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $5.0 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $3.6 million, as the weather was warmer than normal in both jurisdictions.

The Utility segment’s earnings for the six months ended March 31, 2025 were $96.0 million, an increase of $24.7 million when compared with earnings of $71.3 million for the six months ended March 31, 2024.

The increase can be attributed to the following factors:

Impact of new base rates in New York $ 22.4

Impact of higher customer usage 2.7

Higher other income 11.7 (1)

Higher operating expenses (4.6) (2)

Higher interest expense (3.7) (3)

Lower other operating revenues (1.4)

Higher depreciation expense (1.3) (4)

Higher income tax expense (1.1) (5)

(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 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 an increase in state income tax expense due to higher pre-tax income.

For the six months ended March 31, 2025, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $2.6 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $1.2 million, as the weather was warmer than normal in both jurisdictions.

For the six months ended March 31, 2024, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $6.4 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $4.1 million, as the weather was warmer than normal in both jurisdictions.

Corporate and All Other

2025 Compared with 2024

Corporate and All Other operations recorded a net loss of $0.3 million for the quarter ended December 31, 2024, a decrease of $1.4 million when compared with earnings of $1.1 million for the quarter ended December 31, 2023.

The decrease was primarily attributable to changes in unrealized gains and losses on investments in equity securities.

During the quarter ended December 31, 2024, the Company recorded unrealized losses of $2.1 million.

During the quarter ended December 31, 2023, the Company recorded unrealized gains of $0.8 million.

These changes were partially offset by realized gains from investment securities sold in the current quarter ($1.2 million).

There were no realized gains or losses during the quarter ended December 31, 2023.

Other Income (Deductions)

Net other income on the Consolidated Statements of Income was $7.7 million for the quarter ended December 31, 2024, compared to net other income of $3.7 million for the quarter ended December 31, 2023, for an increase of $4.0 million.

This increase can be attributed primarily to a $5.2 million increase in non-service pension and post-retirement benefit income along with a $3.8 million benefit from the quarter-over-quarter revaluation of the contingent consideration received from the 2022 California asset sale.

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

During the quarter ended December 31, 2024, there were net losses of $1.2 million on investment securities.

However, during the quarter ended December 31, 2023, there were net gains of $1.3 million on investment securities.

Another offsetting factor

Corporate and All Other operations recorded a net loss of $3.1 million for the quarter ended March 31, 2025, a decrease of $3.1 million when compared with earnings of less than $0.1 million for the quarter ended March 31, 2024.

The decrease was primarily attributable to higher interest expense ($2.9 million) mainly due to a higher average amount of long-term borrowings.

Other contributing factors include a decrease in investment income from the cash surrender value of life insurance policies ($1.0 million) and changes in unrealized gains on investments in equity securities.

During the quarter ended March 31, 2025, the Company recorded unrealized gains of less than $0.1 million, as compared to unrealized gains of $0.6 million recognized during the quarter ended March 31, 2024.

These changes were partially offset by an increase in interest income on temporary cash investments ($1.1 million).

For the six months ended March 31, 2025, Corporate and All Other operations recorded a net loss of $3.4 million, a decrease of $4.5 million when compared with earnings of $1.1 million for the six months ended March 31, 2024.

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was the non-recurrence of $2.0 million of business interruption insurance proceeds received during the quarter ended December 31, 2023 related to a pipeline outage that impacted Seneca's ability to market its gas.

was primarily attributable to higher interest expense ($3.2 million) mainly due to a higher average amount of long-term borrowings, combined with changes in unrealized gains and losses on investments in equity securities.

During the six months ended March 31, 2025, the Company recorded unrealized losses of $2.1 million.

During the six months ended March 31, 2024, the Company recorded unrealized gains of $1.4 million.

These changes were partially offset by realized gains from investment securities sold during the current six-month period ($1.2 million) and an increase in interest income on temporary cash investments ($1.2 million).

Other Income (Deductions)

Net other income on the Consolidated Statements of Income was $15.2 million for the quarter ended March 31, 2025, compared to net other income of $6.1 million for the quarter ended March 31, 2024, for an increase of $9.1 million.

This increase can be attributed primarily to a $11.2 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 $0.6 million increase in interest income.

These increases were partially offset by a $1.0 million decrease in income recognized from the remeasurement of the cash surrender value of life insurance policies and a $0.9 million change in the quarter-over-quarter revaluation of the contingent consideration received from the 2022 California asset sale.

Also offsetting was a decrease in the quarter-over-quarter unrealized gains on investment securities of $0.6 million.

Net other income on the Consolidated Statements of Income was $23.0 million for the six months ended March 31, 2025, compared to net other income of $9.8 million for the six months ended March 31, 2024, for an increase of $13.2 million.

This increase can be attributed primarily to a $16.4 million increase in non-service pension and post-retirement benefit income, as discussed above, along with a $3.0 million benefit from the year-over-year revaluation of the contingent consideration received from the 2022 California asset sale.

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

During the six months ended March 31, 2025, there were net losses of $1.1 million on investment securities.

However, during the six months ended March 31, 2024, there were net gains of $2.0 million on investment securities.

Another offsetting factor was the non-recurrence of $2.0 million of business interruption insurance proceeds received during the six months ended March 31, 2024 related to a pipeline outage that impacted Seneca's ability to market its gas, along with a $0.5 million decrease in interest income and a $0.4 million decrease in income related to life insurance policies.

Interest Expense on Long-Term Debt

Interest expense on long-term debt on the Consolidated Statement of Income increased $4.9 million for the quarter ended December 31, 2024 as compared to the quarter ended December 31, 2023.

In April 2024, the Company elected to draw a total of $300.0 million under a delayed draw term loan credit facility, which was the primary driver of the increase.

These borrowings had a locked-in weighted average interest rate of 6.30% for the quarter ended December 31, 2024.

Interest expense on long-term debt on the Consolidated Statement of Income increased $11.2 million for the quarter ended March 31, 2025 as compared to the quarter ended March 31, 2024.

For the six months ended March 31, 2025, interest expense on long-term debt increased $16.1 million as compared with the six months ended March 31, 2024.

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 5.81% and 6.05% for the quarter and six months ended March 31, 2025, respectively.

Additionally, 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.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary source of cash during the three-month periods ended December 31, 2024 and December 31, 2023 consisted of cash provided by operating activities and net proceeds from short-term borrowings.

The Company’s primary source of cash during the six-month period ended March 31, 2025 consisted of cash provided by operating activities and net proceeds from short-term and long-term borrowings.

The Company’s primary source of cash during the six-month period ended March 31, 2024 consisted of cash provided by operating activities.

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, as well as net proceeds from short-term and long-term borrowings, to fund the Company's capital expenditures.

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

Looking forward to 2026, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures.

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

The Company 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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Operating Cash Flow

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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 $220.1 million for the three months ended December 31, 2024, a decrease of $50.8 million compared with $270.9 million provided by operating activities for the three months ended December 31, 2023.

The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Exploration and Production segment due to lower cash receipts from natural gas production in the Appalachian region.

Net cash provided by operating activities totaled $473.9 million for the six months ended March 31, 2025, a decrease of $112.4 million compared with $586.3 million provided by operating activities for the six months ended March 31, 2024.

The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Utility segment and 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 decrease 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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Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $192.1 million during the three months ended December 31, 2024 and $235.7 million during the three months ended December 31, 2023.

The Company’s expenditures for long-lived assets totaled $373.1 million during the six months ended March 31, 2025 and $435.7 million during the six months ended March 31, 2024.

The table below presents these expenditures:

Total Expenditures for Long-Lived Assets

Three Months Ended December 31, 2024 2023 Increase (Decrease)

Six Months Ended March 31, 2025 2024 Increase (Decrease)

Exploration and Production:

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Capital Expenditures 0.4 0.2 0.2

Eliminations (3.5) — (3.5)

$ 373.1 $ 435.7 $ (62.6)

(1) At December 31, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $56.3 million, $4.4 million, $6.0 million and $4.9 million, respectively, of non-cash capital expenditures.

(1) At March 31, 2025, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $44.8 million, $2.4 million, $6.8 million and $4.8 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 December 31, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $74.9 million, $5.5 million, $11.1 million and $6.4 million, respectively, of non-cash capital expenditures.

(2) At March 31, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $44.4 million, $5.0 million, $5.5 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 three months ended December 31, 2024 were primarily well drilling and completion expenditures in the Appalachian region, and included $27.5 million in the Marcellus Shale area and $90.9 million in the Utica Shale area.

The Exploration and Production segment capital expenditures for the six months ended March 31, 2025 were primarily well drilling and completion expenditures in the Appalachian region, and included $84.3 million in the Marcellus Shale area and $137.8 million in the Utica Shale area.

These amounts included approximately $105.4 million spent to develop proved undeveloped reserves.

The Exploration and Production segment capital expenditures for the three months ended December 31, 2023 were primarily well drilling and completion expenditures in the Appalachian region, and included $37.5 million in the Marcellus Shale area and $120.2 million in the Utica Shale area.

The Exploration and Production segment capital expenditures for the six months ended March 31, 2024 were primarily well drilling and completion expenditures in the Appalachian region, and included $52.0 million in the Marcellus Shale area and $224.9 million in the Utica Shale area.

These amounts included approximately $185.8 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the three months ended December 31, 2024 and December 31, 2023 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions.

The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2025 and March 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, due to the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, specifically in the Marcellus and Utica Shale producing areas, Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems.

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

On February 13, 2025, the FERC issued the Environmental Assessment for the project.

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

As of December 31, 2024, approximately $3.2 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at December 31, 2024.

The majority of the Gathering segment capital expenditures for the three months ended December 31, 2024 included expenditures related to the continued expansion of Midstream Company's Tioga gathering system.

As of March 31, 2025, approximately $4.0 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at March 31, 2025.

The majority of the Gathering segment capital expenditures for the six months ended March 31, 2025 included expenditures related to the continued expansion of Midstream Company's Tioga and Trout Run gathering systems.

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

The majority of the Gathering segment capital expenditures for the three months ended December 31, 2023 included expenditures related to the continued expansion of Midstream Company's Tioga and Clermont gathering systems.

The majority of the Gathering segment capital expenditures for the six months ended March 31, 2024 included expenditures related to the continued expansion of Midstream Company's Tioga and Clermont 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 majority of the Utility segment capital expenditures for the three months ended December 31, 2024 and December 31, 2023 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions.

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

Expenditures were also made for main extensions.

Project Funding

During the quarter ended December 31, 2024 and fiscal 2024, the Company has been financing capital expenditures with cash from operations and short-term debt.

During the six months ended March 31, 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.

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Financing Cash Flow

Consolidated short-term debt increased $109.3 million when comparing the balance sheet at December 31, 2024 to the balance sheet at September 30, 2024.

The maximum amount of short-term debt outstanding during the three months ended December 31, 2024 was $253.9 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

Consolidated short-term debt increased $117.7 million when comparing the balance sheet at March 31, 2025 to the balance sheet at September 30, 2024.

The maximum amount of short-term debt outstanding during the six months ended March 31, 2025 was $327.8 million.

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gas costs, margin calls on derivative financial instruments, repurchases of stock, other working capital needs and repayment of long-term debt.

costs, margin calls on derivative financial instruments, repurchases of stock, other working capital needs and repayment of long-term debt.

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

As of December 31, 2024, the Company had outstanding commercial paper of $200.0 million and did not have any short-term notes payable to banks as of December 31, 2024.

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

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

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

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

In January 2025, the Company and the eleven banks in the syndicate consented to a second one-year extension of the maturity date, from February 25, 2028 to February 23, 2029, such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion through February 23, 2029.

As of March 31, 2025, the Company had outstanding commercial paper of $208.4 million and did not have any short-term notes payable to banks.

The Company is a party to a syndicated Credit Agreement (as amended from time to time, the “Credit Agreement”) that provides a $1.0 billion unsecured committed revolving credit facility.

In January 2025, the Company and the eleven banks in the syndicate consented to a second one-year extension of the maturity date of the Credit Agreement, such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion through February 23, 2029.

The total amount available to be issued under the Company’s commercial paper program is $500.0 million.

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

The current locked-in interest rate is 5.78% until February 2025.

The current weighted average locked-in interest rate is 5.79% until mid-May 2025.

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

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

As a result, at December 31, 2024, $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 March 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 December 31, 2024, the Company’s debt to capitalization ratio, as calculated under the agreements, was 0.48.

The constraints specified in the Credit Agreement and the Term Loan Agreement would have permitted an additional $2.97 billion in short-term and/or long-term debt to be outstanding at December 31, 2024 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded 0.65.

At March 31, 2025, the Company’s debt to capitalization ratio, as calculated under the agreements, was 0.47.

The constraints specified in the Credit Agreement and the Term Loan Agreement would have permitted an additional $3.21 billion in short-term and/or long-term debt to be outstanding at March 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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The Credit Agreement and the Term Loan Agreement each contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement or Term Loan Agreement, as applicable.

In particular, a repayment obligation could be triggered if (i) the

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.

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

The Current Portion of Long-Term Debt at December 31, 2024 and September 30, 2024 consisted of $50.0 million of 7.38% notes that mature in June 2025 and $450.0 million of 5.20% notes that mature in July 2025.

The Company’s embedded cost of long-term debt was 4.83% at December 31, 2024 and 4.69% at December 31, 2023.

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 $495.4 million and $493.6 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.

This included $50.0 million in principal and $3.2 million in interest (of which $1.8 million of interest was subsequently paid out of the trust in February 2025) related to long-term debt issued in June 1995 under the 1974 indenture, with a maturity date of June 13, 2025.

The funds held in trust are recorded on the consolidated balance sheet as “Cash Held in Trust for Bondholders” as of March 31, 2025.

The Current Portion of Long-Term Debt at March 31, 2025 consisted of $50.0 million of 7.38% notes that mature in June 2025 and $300.0 million of long-term delayed draw term loans that mature in February 2026.

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

As discussed above, the Company placed $50.0 million (plus interest) in trust for the benefit of holders of the 7.38% notes that mature in June 2025 and redeemed the $450.0 million of 5.20% notes on March 6, 2025.

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

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

Given the impairments of exploration and production properties the Company recognized since June 30, 2024, the indenture covenants preclude the Company from issuing incremental long-term debt from January 1, 2025 to June 13, 2025, the maturity date of the Company's remaining indebtedness outstanding under the 1974 indenture.

As of December 31 2024, the Company had $50.0 million in principal and $3.2 million in interest payments remaining related to long-term debt issued under the 1974 indenture.

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

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

The Company’s embedded cost of long-term debt was 4.97% at March 31, 2025 and 4.69% at March 31, 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.

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

Given the recent macroeconomic uncertainty, as well as increased volatility in the natural gas market, the Company has slowed its pace of repurchases.

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

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

During the three months ended December 31, 2024, the Company executed transactions to repurchase 548,596 shares at an average price of $61.27 per share.

With broker fees and excise taxes, the total cost of these repurchases amounted to $33.9 million.

Share repurchases that settled during the three months ended December 31, 2024 were funded with cash provided by operating activities and/or short-term borrowings.

Share repurchases that settled during the six months ended March 31, 2025 were funded with cash provided by operating activities and/or short-term borrowings.

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

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These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things.

While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the three months ended December 31, 2024, 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-

While these normal-course matters could have a material effect on earnings and cash flows in

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retirement benefits during the three months ended December 31, 2024, and does not anticipate making any such contributions during the remainder of fiscal 2025.

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 six months ended March 31, 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 six months ended March 31, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2025.

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 December 31, 2024, 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 March 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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It also includes an earnings sharing mechanism, gas safety and customer service performance metrics (including maintaining the Company’s leak prone pipe replacement program), and provisions that will facilitate achievement of the emissions reduction goals of the CLCPA.

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Pennsylvania Jurisdiction

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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.

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

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

During the quarter ended March 31, 2025, Distribution Corporation recovered $0.2 million from customers.

Pipeline and Storage

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Supply Corporation has no rate case currently on file.

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

Empire is not barred from filing a Section 4 rate case before the May 1, 2025 date.

Empire has no rate case currently on file.

On March 17, 2025, FERC approved an amendment to Empire's 2019 rate case settlement, which provides for a modest reduction in Empire’s transportation unit rates, effective November 1, 2025.

Based on current contracts, 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.

Environmental Matters

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For further discussion of the Company's environmental exposures, refer to Item 1 at Note 7 – Commitments and Contingencies under the heading “Environmental Matters.”

Legislative and regulatory measures to address 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 executive orders at the state and federal level, and private party litigation related to greenhouse gas emissions.

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.

Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, cap and invest and cap and trade programs, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources.

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

EPA published its final WEC regulations in November 2024.

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

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 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.

The current federal administration has initiated efforts to roll-back and/or limit certain environmental initiatives.

Additionally, a number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions.

Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines.

Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources.

The New York State legislature passed the CLCPA that mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets.

In New York, the CLCPA, which was passed in 2019, mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the

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remaining emission reduction achieved by controlled offsets.

The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040.

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

The NYDEC, in conjunction with the New York State Energy Research and Development Authority, is developing a cap-and-invest program in the state.

The above-enumerated

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initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances.

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 key regulations necessary to implement the program has been delayed.

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

They could also reduce demand for natural gas and delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals.

Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.

Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by federal and state administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.

Federal, state or local governments may also provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources.

Effects of Inflation

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

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

Changes in the price of natural gas;

Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing;

Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design, retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal;

Changes in economic conditions, including the imposition of additional tariffs on U.S.

imports and related retaliatory tariffs, inflationary pressures, supply chain issues, liquidity challenges, and global, national or regional

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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;

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

Changes in economic conditions, including inflationary pressures, supply chain issues, liquidity challenges, and global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services;

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

Changes in the price of natural gas;

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

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

Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;

Changes in price differentials between similar quantities of natural gas sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations;

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

The impact of information technology disruptions, cybersecurity or data security breaches, including the impact of issues that may arise from the use of artificial intelligence technologies;

Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability and costs, title disputes, weather conditions, water availability and disposal or recycling opportunities of used water, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations;

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The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.

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Forward-looking and other statements in this Quarterly Report on Form 10-Q regarding methane and greenhouse gas reduction plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC.

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Refer to the "Market Risk Sensitive Instruments" section in Item 2 – MD&A.

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

What changed 10-Q

Item 2. Management’s Discussion and Analysis