What changed in this filing

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Item 2. Management’s Discussion and Analysis

2024-08-01 compared with 2024-05-02 · 265 added, 228 removed, 372 unchanged (57% of the section changed)

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

Interim settlement rates became effective on February 1, 2024 under a settlement in principle that was filed with FERC on March 27, 2024, and are estimated to increase Supply Corporation's revenues by approximately $56 million on an annual basis.

The settlement remains subject to final FERC approval.

Settlement rates became effective on February 1, 2024 under a settlement in principle that was filed with FERC on March 27, 2024.

The settlement, which is estimated to increase Supply Corporation's revenues by approximately $56 million on an annual basis, was approved on June 11, 2024, with no modifications.

For further discussion of Distribution Corporation and Supply Corporation 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 oil and natural gas properties in the Exploration and Production segment and that book value is subject to a quarterly ceiling test.

The Company did not record an impairment under the ceiling test during the quarter ended March 31, 2024.

Looking ahead, the first day of the month Henry Hub spot price for natural gas in April 2024 was $1.56 per MMBtu.

Given the April price, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation at June 30, 2024 and September 30, 2024, the Company expects to experience a ceiling test impairment in each of these quarters.

From a financing perspective, effective February 7, 2024, certain lenders under the Credit Agreement consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028.

As a result, the Company has aggregate commitments available under the Credit Agreement of $1.0 billion before February 26, 2027, and $940 million in aggregate commitments available on and after February 26, 2027 to February 25, 2028.

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

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

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

The Company recorded an impairment under the ceiling test during the quarter ended June 30, 2024 of $200.7 million ($145.0 million after-tax).

Looking ahead, the first day of the month Henry Hub spot price for natural gas in

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February 14, 2026.

July 2024 was $2.39 per MMBtu.

Given the July price, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation for the next two quarters, the Company could experience a ceiling test impairment for the quarter ending September 30, 2024 as well as the quarter ending December 31, 2024.

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

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

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

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

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

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

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

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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.

Repurchases under this program amounted to 96,133 shares at a total cost of $5.0 million during the quarter ended March 31, 2024.

During the nine months ended June 30, 2024, the Company executed transactions to repurchase 526,652 shares at an average price of $54.28 per share.

With broker fees and excise taxes, the total cost of these repurchases amounted to $28.8 million.

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

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The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K.

Oil and Gas Exploration and Development Costs.

The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its oil and natural gas properties, with natural gas properties in the Appalachian Region being the primary component after the fiscal 2022 sale of the Company's California oil and natural gas properties.

Exploration and Development Costs.

The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its exploration and production properties, with natural gas properties in the Appalachian Region being the primary component after the fiscal 2022 sale of the Company's California exploration and production properties.

In accordance with the full cost methodology, the Company is required to perform a quarterly ceiling test.

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

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

The present value of future revenues is calculated using a 10% discount factor.

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

At March 31, 2024, the ceiling exceeded the book value of the oil and gas properties by approximately $3.1 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, 2024, based on the quoted Henry Hub spot price for natural gas, was $2.45 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 March 31, 2024.

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, 2024 in the ceiling test calculation, the book value of the Company's oil and gas properties would have exceeded the ceiling by approximately $329.9 million (after-tax), which would 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.

Looking ahead, the first day of the month Henry Hub spot price for natural gas in April 2024 was $1.56 per MMBtu.

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

Fluctuations in or subtractions from proved reserves and increases in development costs for undeveloped reserves can have an impact on the amount of the ceiling at any point in time.

For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2023 Form 10-K.

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 June 30, 2024, resulting in a non-cash impairment charge of $200.7 million ($145.0 million after-tax) for the quarter ended June 30, 2024.

The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended June 30, 2024, based on the quoted Henry Hub spot price for natural gas, was $2.32 per MMBtu.

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 June 30, 2024 if natural gas prices were $0.25 per MMBtu lower than the average prices used at June 30, 2024 (all amounts are presented after-tax).

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

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Ceiling Testing Sensitivity to Commodity Price Changes

(Millions) $0.25/MMBtu

Natural Gas Prices

Calculated Impairment under Sensitivity Analysis

Actual Impairment Recorded at June 30, 2024 145.0

Additional Impairment

Looking ahead, the first day of the month Henry Hub spot price for natural gas in July 2024 was $2.39 per MMBtu.

RESULTS OF OPERATIONS

The Company's earnings were $166.3 million for the quarter ended March 31, 2024 compared to earnings of $140.9 million for the quarter ended March 31, 2023.

The increase in earnings of $25.4 million is primarily the result of higher earnings in all reportable segments as well as in the Corporate category, slightly offset by a loss in the All Other category.

The Company's earnings were $299.3 million for the six months ended March 31, 2024 compared to earnings of $310.6 million for the six months ended March 31, 2023.

The decrease in earnings of $11.3 million is primarily the result of lower earnings in the Exploration and Production segment.

Higher earnings in the Utility segment, Gathering segment and Pipeline and Storage segment, as well as higher earnings in the Corporate category and a lower loss in the All Other category partially offset this decrease.

The Company recorded a loss of $54.2 million for the quarter ended June 30, 2024 compared to earnings of $92.6 million for the quarter ended June 30, 2023.

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

Losses in the Corporate and All Other categories also contributed to the decrease.

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

The Company's earnings were $245.1 million for the nine months ended June 30, 2024 compared to earnings of $403.2 million for the nine months ended June 30, 2023.

The decrease in earnings of $158.1 million is primarily the result of lower earnings in the Exploration and Production segment and the Corporate category.

Higher earnings in the Utility segment, Gathering segment and Pipeline and Storage segment, as well as a lower loss in the All Other category, partially offset these decreases.

The Company's earnings for the quarter and nine months ended June 30, 2024 included a non-cash $200.7 million impairment charge ($145.0 million after-tax) recorded during the quarter ended June 30, 2024 for its exploration and production properties, as discussed above.

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

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Three Months Ended

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(Thousands) 2024 2023 Increase

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Total Consolidated $ (54,158) $ 92,620 $ (146,778) $ 245,134 $ 403,189 $ (158,055)

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Exploration and Production

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(Thousands) 2024 2023 Increase

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Gas Production per MMcf 96,504 94,747 1,757 300,144 278,562 21,582

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Average Prices

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2024 2023 Increase

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2024 Compared with 2023

Operating revenues for the Exploration and Production segment increased $20.1 million for the quarter ended March 31, 2024 as compared with the quarter ended March 31, 2023.

Gas production revenue after hedging increased $22.4 million due to the impact of a 9.6 Bcf increase in natural gas production, offset by a $0.02 per Mcf decrease in the weighted average price of natural gas after hedging.

Operating revenues for the Exploration and Production segment increased $4.3 million for the quarter ended June 30, 2024 as compared with the quarter ended June 30, 2023.

Gas production revenue after hedging increased $4.3 million due to the impact of a 1.8 Bcf increase in natural gas production combined with a $0.01 per Mcf increase in the weighted average price of natural gas after hedging.

The increase in natural gas production was largely due to additional production from new Marcellus and Utica wells in the Appalachian region.

In addition, other revenue decreased $2.3 million due to the non-recurrence of temporary capacity release revenue for a portion of this segment's transportation capacity during the quarter ended March 31, 2023.

Operating revenues for the Exploration and Production segment decreased $2.9 million for the six months ended March 31, 2024 as compared with the six months ended March 31, 2023.

This decrease resulted primarily from the non-recurrence of temporary capacity release revenue for a portion of this segment’s transportation capacity during the six months ended March 31, 2023, which contributed to a $4.5 million decrease in other revenue period over period.

Operating revenues for the Exploration and Production segment increased $1.4 million for the nine months ended June 30, 2024 as compared with the nine months ended June 30, 2023.

Gas production revenue after hedging increased $5.9 million due to the impact of a 21.6 Bcf increase in natural gas production, offset by a $0.17 per Mcf decrease in the weighted average price of natural gas after hedging.

The increase in natural gas production was largely due to additional production from new Marcellus and Utica wells in the Appalachian region during the six months ended March 31, 2024 as compared with the six months ended March 31, 2023.

The Exploration and Production segment's earnings for the quarter ended March 31, 2024 were $62.1 million, an increase of $1.1 million when compared with earnings of $61.0 million for the quarter ended March 31, 2023.

The increase in earnings was attributable to higher natural gas production ($19.7 million) and lower other taxes ($1.3 million).

There was also an unrealized gain recognized in the three-month period ended March 31, 2024 ($0.4 million) on contingent consideration received as part of the California asset sale, compared to an unrealized loss that was recognized in the three-month period ended March 31, 2023 ($1.8 million) on such contingent consideration.

These increases were partially offset by lower natural gas prices after hedging ($2.0 million) and lower other revenue ($1.8 million) as previously discussed.

Higher depletion expense ($11.7 million), higher lease operating and transportation expenses ($3.1 million) and an increase in interest expense ($2.3 million) also reduced earnings.

The decrease in other taxes was primarily attributable to lower Impact Fees in the Appalachian region due to lower NYMEX pricing, which reduces the cost per well due to moving the Company into a lower rate tier.

The increase in natural gas production was largely due to additional production from new Marcellus and Utica wells in the Appalachian region during the nine months ended June 30, 2024 as compared with the nine months ended June 30, 2023.

In addition, other revenue decreased $4.5 million due to the non-recurrence of temporary capacity release revenue for a portion of this segment's transportation capacity during the nine months ended June 30, 2023.

The Exploration and Production segment's loss for the quarter ended June 30, 2024 was $112.0 million, a decrease of $155.3 million when compared with earnings of $43.3 million for the quarter ended June 30, 2023.

This decrease can be primarily attributed to a non-cash impairment of exploration and production properties during the quarter ended June 30, 2024 ($145.0 million), higher depletion expense ($6.5 million), higher lease operating and transportation expenses ($3.8 million), higher other operating expenses ($3.6 million), higher other taxes ($0.6 million) and an increase in interest expense ($0.8 million).

There was also an unrealized loss recognized in the three-month period ended June 30, 2024 ($0.9 million) on contingent consideration received as part of the California asset sale, compared to an unrealized loss that was recognized in the three-month period ended June 30, 2023 ($1.0 million) on such contingent consideration.

These decreases were partially offset by higher natural gas production ($3.2 million), higher natural gas prices after hedging ($0.2 million) and a reduction in income tax expense ($1.4 million).

The increase in depletion expense was primarily due to the net increase in production combined with a $0.07 per Mcf increase in the depletion rate.

The increase in lease operating and transportation expenses was primarily the result of higher gathering and transportation costs and higher workover expenses, offset by lower saltwater disposal expenses.

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

The Exploration and Production segment's earnings for the six months ended March 31, 2024 were $114.5 million, a decrease of $37.7 million when compared with earnings of $152.2 million for the six months ended March 31, 2023.

The decrease in earnings was attributable to lower natural gas prices after hedging ($42.5 million) and lower other revenue ($3.6 million) as previously discussed.

The increase in lease operating and transportation expenses was primarily

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the result of higher gathering and transportation costs.

The increase in other operating expenses was primarily attributable to recognizing an accrual of plugging and abandonment costs related to certain wells that were formerly owned by Seneca, combined with higher general and administrative costs.

The increase in other taxes was primarily attributed to higher Impact Fees in the Appalachian region as a result of additional wells drilled combined with a prior year fee true-up that reduced Impact Fees in the quarter ended June 30, 2023.

The increase in interest expense can largely be attributed to higher average interest rates on intercompany short-term and long-term borrowings, as well as higher intercompany long-term debt balances The reduction in income tax expense was primarily driven by lower state income tax expense as a result of both a decrease in pre-tax income and a decrease in Pennsylvania's state income tax rate from 9.99% to 4.99% over a ten year period.

The Exploration and Production segment's earnings for the nine months ended June 30, 2024 were $2.5 million, a decrease of $193.0 million when compared with earnings of $195.5 million for the nine months ended June 30, 2023.

The decrease in earnings was primarily attributable to a non-cash impairment of exploration and production properties ($145.0 million), lower natural gas prices after hedging ($40.0 million) and lower other revenue ($3.6 million), as previously discussed.

Higher depletion expense ($31.2 million), higher lease operating and transportation expenses ($11.2 million), higher other operating expenses ($7.9 million) and an increase in interest expense ($4.7 million) also reduced earnings.

There was also a higher unrealized loss recognized in the six-month period ended March 31, 2024 ($2.7 million) on contingent consideration received as part of the California asset sale as compared to an unrealized loss that was recognized in the six-month period ended March 31, 2023 ($1.7 million) on such contingent consideration.

These decreases were partially offset by higher natural gas production ($43.8 million), lower other taxes ($3.9 million) and a reduction in income tax expense ($1.5 million).

There was also a higher unrealized loss recognized in the nine months ended June 30, 2024 ($3.5 million) on contingent consideration received as part of the California asset sale as compared to an unrealized loss that was recognized in the nine months ended June 30, 2023 ($2.7 million) on such contingent consideration.

These decreases were partially offset by higher natural gas production ($44.7 million) combined with lower other taxes ($3.3 million) and a reduction in income tax expense ($2.9 million).

The increase in depletion expense was primarily due to the net increase in production combined with a $0.08 per Mcf increase in the depletion rate.

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

The increase in other operating expenses was primarily attributable to recognizing an accrual of plugging and abandonment costs related to certain wells that were formerly

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owned by Seneca, combined with higher general and administrative costs.

The reduction in income tax expense was primarily driven by lower state income tax expense as a result of both a decrease in pre-tax income and Pennsylvania's tax rate decrease, partially offset by a lower benefit from permanent differences related to stock compensation.

The reduction in income tax expense was primarily driven by lower state income tax expense as a result of both a decrease in pre-tax income and a decrease in Pennsylvania's state income tax rate from 9.99% to 4.99% over a ten year period, partially offset by a lower benefit from permanent differences related to stock compensation.

Pipeline and Storage

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Three Months Ended

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(Thousands) 2024 2023 Increase

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Three Months Ended

March 31, Six Months Ended

June 30, Nine Months Ended

(MMcf) 2024 2023 Increase

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168,628 181,537 (12,909) 592,376 639,169 (46,793)

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2024 Compared with 2023

Operating revenues for the Pipeline and Storage segment increased $12.9 million for the quarter ended March 31, 2024 as compared with the quarter ended March 31, 2023.

Operating revenues for the Pipeline and Storage segment increased $13.0 million for the quarter ended June 30, 2024 as compared with the quarter ended June 30, 2023.

The increase in operating revenues was primarily due to an increase in transportation revenues of $9.2 million, an increase in storage revenues of $3.5 million and an increase in other revenues of $0.3 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 the approved interim rates in connection with Supply Corporation's rate case settlement, which is pending final FERC approval.

In addition, the increase in transportation and storage revenues was the result of a final true-up adjustment to a surcharge mechanism for pipeline safety and greenhouse gas costs that ended effective February 1, 2024.

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

Operating revenues for the Pipeline and Storage segment increased $9.7 million for the six months ended March 31, 2024 as compared with the six months ended March 31, 2023.

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

Operating revenues for the Pipeline and Storage segment increased $22.7 million for the nine months ended June 30, 2024 as compared with the nine months ended June 30, 2023.

The increase in operating revenues was primarily due to an increase in transportation revenues of $12.1 million, an increase in storage revenues of $7.3 million, and an increase in other revenues of $3.2 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 the aforementioned Supply Corporation rate case settlement and final true-up adjustment to a surcharge for pipeline safety and greenhouse gas costs.

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 the aforementioned Supply Corporation rate case settlement and final true-up adjustment to the surcharge for pipeline safety and greenhouse gas costs that ended effective February 1, 2024.

The increase in transportation revenues was partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions.

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

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Transportation volume for the quarter ended March 31, 2024 decreased by 8.2 Bcf from the prior year's quarter ended March 31, 2023.

For the six months ended March 31, 2024, transportation volume decreased by 33.9 Bcf from the prior year's six-month period ended March 31, 2023.

The decrease in transportation volume for both the quarter and six months ended March 31, 2024 is primarily due to a decrease in volume from certain contract expirations combined with a decline in volume from warmer weather.

Transportation volume for the quarter ended June 30, 2024 decreased by 12.9 Bcf from the prior year's quarter ended June 30, 2023.

For the nine months ended June 30, 2024, transportation volume decreased by 46.8 Bcf from the prior year's nine-month period ended June 30, 2023.

The decrease in transportation volume for both the quarter and nine months ended June 30, 2024 is primarily due to a decrease in volume from certain contract expirations combined with a decline in volume from warmer weather.

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

The Pipeline and Storage segment’s earnings for the quarter ended March 31, 2024 were $30.7 million, an increase of $6.8 million when compared with earnings of $23.9 million for the quarter ended March 31, 2023.

The increase in earnings was primarily due to the earnings impact of higher operating revenues ($10.2 million), as discussed above.

This increase was partially offset by increases in operating expenses ($1.4 million), depreciation expense ($1.4 million) and interest expense ($1.0 million).

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.

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

The increase in depreciation expense was primarily due to higher average depreciable plant in service compared to the prior year.

The increase in interest expense is mainly due to an increase in intercompany short-term borrowings.

The Pipeline and Storage segment’s earnings for the six months ended March 31, 2024 were $54.8 million, an increase of $1.5 million when compared with earnings of $53.3 million for the six months ended March 31, 2023.

The Pipeline and Storage segment’s earnings for the quarter ended June 30, 2024 were $30.7 million, an increase of $6.9 million when compared with earnings of $23.8 million for the quarter ended June 30, 2023.

The increase in earnings was primarily due to the earnings impact of higher operating revenues ($10.3 million), as discussed above.

This increase was partially offset by increases in operating expenses ($2.9 million), depreciation expense ($2.0 million) and interest expense ($1.6 million).

This increase was partially offset by increases in operating expenses ($1.5 million), interest expense ($0.8 million), depreciation expense ($0.6 million) and higher income tax expense ($0.5 million).

The increase in operating expenses was primarily due to an increase in personnel costs, partially offset by lower pipeline integrity costs.

The increase in interest expense is mainly due to an increase in intercompany short-term and long-term borrowings.

The increase in depreciation expense was primarily due to higher average depreciable plant in service compared to the prior year, partially offset by an adjustment to depreciation expense related to the final regulatory approval of Supply Corporation's rate case settlement.

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 nine months ended June 30, 2024 were $85.5 million, an increase of $8.4 million when compared with earnings of $77.1 million for the nine months ended June 30, 2023.

The increase in earnings was primarily due to the earnings impact of higher operating revenues ($17.9 million), as discussed above, along with an increase in other income ($1.3 million).

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

These increases were partially offset by increases in operating expenses ($4.5 million), depreciation expense ($2.6 million), interest expense ($2.4 million) and higher income tax expense ($0.8 million).

The increase in operating expenses was primarily due to higher personnel costs, as well as higher power costs related to Empire's electric motor drive compressor station.

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The increase in depreciation expense was primarily due to higher average depreciable plant in service compared to the prior year.

The increase in interest expense is mainly due to an increase in intercompany short-term borrowings.

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

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

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Gathering Operating Revenues

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(Thousands) 2024 2023 Increase

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2024 Compared with 2023

Operating revenues for the Ga thering segme nt increased $7.0 million f or the quarter ended March 31, 2024 as compared with the quarter ended March 31, 2023, which was driven primarily by a 16.2 Bcf increase in gathered volume.

Gathered volume on the Trout Run and Tioga gathering systems increased 17.5 Bcf and 5.3 Bcf, respectively, partially offset by a decrease of 6.6 Bcf on the Clermont gathering system.

The net 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 increased $13.2 million for the six months ended March 31, 2024 as compared with the six months ended March 31, 2023, which was driven primarily by a 32.0 Bcf increase in gathered volume.

Contributors to the increase included the Trout Run and Tioga gathering systems, which recorded increases of 29.2 Bcf and 11.6 Bcf, respectively, partially offset by the Clermont gathering system, which recorded a decrease of 8.8 Bcf.

The net increase

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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, 2024 were $28.7 million, an increase of $4.4 million when compared with earnings of $24.3 million for the quarter ended March 31, 2023.

The increase in earnings was primarily due to higher gathering revenues ($5.5 million) driven by the increase in gathered volume, as discussed above.

This increase was partially offset by higher depreciation expense ($0.5 million) and higher income tax expense ($0.5 million).

Operating revenues for the Ga thering segme nt increased $1.2 million f or the quarter ended June 30, 2024 as compared with the quarter ended June 30, 2023.

Although gathered volume decreased 0.3 Bcf over the aforementioned time period, changes in the throughput producer mix drove the increase in revenue.

Gathered volume decreased 6.7 Bcf in the Gathering segment's western development area (Clermont), partially offset by a net 6.4 Bcf increase in gathered volume in the Gathering segment's eastern development areas (Trout Run and Tioga).

Operating revenue s for the Gathering segme nt increased $14.4 million f or the nine months ended June 30, 2024 as compared with the nine months ended June 30, 2023, which was driven primarily by a 31.8 Bcf increase in gathered volume.

Gathered volume increased 47.4 Bcf in the Gathering segment's eastern development areas (Trout Run and Tioga), partially offset by a 15.6 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 June 30, 2024 were $25.0 million, an increase of $0.9 million when compared with earnings of $24.1 million for the quarter ended June 30, 2023.

The increase in earnings was primarily due to higher gathering revenues ($1.0 million) and lower operation and maintenance expense ($0.4 million).

The increase in gathering revenues was driven by changes in the throughput producer mix, as discussed above.

The decrease in operation and maintenance expense was primarily due to lower compressor repairs and services along with lower leased compression costs.

This increase was partially offset by higher depreciation expense ($0.6 million).

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

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

The Gathering segment’s earnings for the six months ended March 31, 2024 were $57.5 million, an increase of $8.4 million when compared with earnings of $49.1 million for the six months ended March 31, 2023 .

The increase in earnings was mainly due to higher gathering revenues ($10.4 million) driven by the increase in gathered volume, as discussed above.

The Gathering segment’s earnings for the nine months ended June 30, 2024 were $82.5 million, an increase of $9.3 million when compared with earnings of $73.2 million for the nine months ended June 30, 2023 .

The increase in earnings was mainly due to higher gathering revenues ($11.4 million) driven by the increase in gathered volume, as discussed above, and lower interest expense ($0.6 million).

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

This increase was partially offset by higher depreciation expense ($1.7 million) and higher income tax expense ($1.0 million).

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

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Utility Operating Revenues

Three Months Ended

March 31, Six Months Ended

June 30, Nine Months Ended

(Thousands) 2024 2023 Increase

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Three Months Ended

March 31, Six Months Ended

June 30, Nine Months Ended

(MMcf) 2024 2023 Increase

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22,312 23,589 (1,277) 114,942 120,521 (5,579)

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

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

Normal 2024 2023 Normal (1)

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776 519 802 (33.1) % (35.3) %

Six Months Ended March 31,

Nine Months Ended June 30,

Buffalo, NY 6,491 5,128 5,656 (21.0) % (9.3) %

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2024 Compared with 2023

Operating revenues for the Utility segment decreased $116.6 million for the quarter ended March 31, 2024 as compared with the quarter ended March 31, 2023.

This decrease resulted from a $120.8 million decrease in retail gas sales revenue, which was partially offset by a $3.2 million increase in transportation revenue and a $1.0 million increase in other revenue.

Operating revenues for the Utility segment decreased $19.7 million for the quarter ended June 30, 2024 as compared with the quarter ended June 30, 2023.

This decrease resulted from a $21.2 million decrease in retail gas sales revenue and a $1.0 million decrease in other revenue, which were partially offset by a $2.5 million increase in transportation revenue.

The decrease in retail gas sales revenue reflects a decrease in the cost of gas sold (per Mcf) combined with a 1.6 Bcf decrease in throughput mainly due to warmer weather.

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.

Purchased gas expense

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

The decrease in retail gas sales revenue was partially offset by the impact of new base rates in Distribution Corporation's Pennsylvania jurisdiction pursuant to a settlement approved by the PaPUC on June 15, 2023.

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

The increase in transportation revenue was also largely attributable to the impact of new base rates in Pennsylvania, as well as an increase in revenues earned under the system modernization and system improvement tracker mechanisms in Distribution Corporation's New York jurisdiction, which allow for the recovery of investments in leak prone pipe replacement.

The increase in other revenue was mainly the result of a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($2.2 million), partially offset by decreases in late payment charges billed to customers ($0.7 million) and capacity release revenues ($0.6 million).

Operating revenues for the Utility segment decreased $226.3 million for the six months ended March 31, 2024 as compared with the six months ended March 31, 2023.

The decrease resulted from a $231.4 million decrease in retail gas sales revenue, primarily due to a decrease in the cost of gas sold (per Mcf) as well as a 3.4 Bcf decrease in throughput largely due to warmer weather.

The decrease in other revenue was mainly the result of a larger estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($0.5 million) and a decrease in late payment charges billed to customers ($0.4 million).

The increase in transportation revenue was largely attributable to the impact of new base rates in Pennsylvania, as well as an increase in revenues earned under the system modernization and system improvement tracker mechanisms in Distribution Corporation's New York jurisdiction, which allow for the recovery of investments in leak prone pipe replacement.

Operating revenues for the Utility segment decreased $246.0 million for the nine months ended June 30, 2024 as compared with the nine months ended June 30, 2023.

The decrease resulted from a $252.6 million decrease in retail gas sales revenue and a $0.3 million decrease in other revenue.

The decrease in retail gas sales revenue was primarily due to a decrease in the cost of gas sold (per Mcf) as well as a 5.0 Bcf decrease in throughput largely due to warmer weather.

These factors were partially offset by an increase in base rates in Distribution Corporation's Pennsylvania jurisdiction, as mentioned above.

The decrease in retail gas sales revenue was partially offset by a $4.5 million increase in transportation revenue and a $0.7 million increase in other revenue.

The increase in transportation revenue was also predominantly due to the impact of the new base rates in Pennsylvania in addition to an increase in the system modernization and system improvement tracker allocation to customers in New York, despite a 1.0 Bcf decrease in throughput due to warmer weather.

The increase in other revenue was largely due to a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($2.6 million), partially offset by decreases in late payment charges billed to customers ($1.1 million) and capacity release revenues ($1.0 million).

The Utility segment’s earnings for the quarter ended March 31, 2024 were $44.7 million, an increase of $13.0 million compared to earnings of $31.7 million for the quarter ended March 31, 2023.

The increase was primarily due to the impact of new base rates in the Utility segment's Pennsylvania jurisdiction ($8.5 million), lower income tax expense ($2.4 million), and the impact of system modernization and system improvement trackers in New York ($1.8 million).

The decrease in other revenue was largely due to decreases in late payment charges billed to customers ($1.5 million) and capacity release revenues ($1.0 million), partially offset by a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($2.1 million).

The decreases in retail gas sales revenue and other revenue were partially offset by a $7.0 million increase in transportation revenue, predominantly due to the impact of the new base rates in Pennsylvania in addition to an increase in revenues from the system modernization and system improvement tracker in New York, despite a 0.6 Bcf decrease in throughput due to warmer weather.

The Utility segment’s earnings for the quarter ended June 30, 2024 were $2.6 million, an increase of $2.5 million when compared with earnings of less than $0.1 million for the quarter ended June 30, 2023.

The increase was primarily due to the impact of system modernization and system improvement trackers in New York ($3.5 million), lower income tax expense ($3.3 million), and the impact of new base rates in the Utility segment's Pennsylvania jurisdiction ($2.3 million).

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

The Utility segment's earnings also increased $4.5 million due to the impact of higher usage and weather, with current quarter earnings benefiting from the implementation of a weather normalization adjustment (WNA) in the Utility segment's Pennsylvania jurisdiction.

These increases were partially offset by higher operating expenses ($2.3 million), primarily due to higher personnel costs, and a decrease in earnings from regulatory adjustments ($1.6 million).

These increases were partially offset by higher operating expenses ($2.7 million), primarily due to higher personnel costs, a decrease in earnings from the impact of lower usage and weather ($2.4 million), an increase in depreciation and amortization expense ($1.1 million), and a decrease in other operating revenues ($0.4 million).

The increase in depreciation expense was primarily the result of higher average plant balances and increased depreciation associated with negative net salvage in the Utility segment's Pennsylvania jurisdiction.

The decrease in other operating revenues resulted from decreases in late payment charges billed to customers and capacity release revenues.

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

Prior to October 2023, the impact of weather variations on earnings was mitigated by a WNA solely in the Utility segment’s New York rate jurisdiction.

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However, effective October 2023, the impact of weather variations on earnings is also mitigated by a WNA in the Utility segment’s Pennsylvania rate jurisdiction.

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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 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.

For the quarter ended March 31, 2023, the WNA preserved earnings in the Utility segment’s New York jurisdiction of approximately $3.3 million, as the weather was warmer than normal.

The Utility segment’s earnings for the six months ended March 31, 2024 were $71.3 million, an increase of $15.8 million when compared with earnings of $55.5 million for the six months ended March 31, 2023.

The increase was mainly due to the impact of new base rates in the Utility segment's Pennsylvania jurisdiction ($15.4 million), lower income tax expense ($4.2 million), and the impact of system modernization and system improvement trackers in New York ($2.7 million).

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

For the quarter ended June 30, 2023, the WNA preserved earnings in the Utility segment’s New York jurisdiction of approximately $0.6 million, as the weather was warmer than normal.

The Utility segment’s earnings for the nine months ended June 30, 2024 were $73.8 million, an increase of $18.2 million when compared with earnings of $55.6 million for the nine months ended June 30, 2023.

The increase was mainly due to the impact of new base rates in the Utility segment's Pennsylvania jurisdiction ($17.7 million), lower income tax expense ($7.5 million), the impact of system modernization and system improvement trackers in New York ($6.2 million), and an increase in other income ($1.3 million).

The decrease in income tax expense was largely due to an increase in tax deductions related to certain repairs and maintenance expenditures, as discussed above.

The Utility segment's earnings also increased $1.7 million due to the impact of higher usage and weather, with current year earnings benefiting from the implementation of a WNA in the Utility segment's Pennsylvania rate jurisdiction.

These factors were partially offset by higher operating expenses ($5.0 million), primarily due to higher personnel costs, a decrease in earnings from regulatory adjustments ($2.0 million), and an increase in depreciation and amortization expense ($1.5 million), which was primarily the result of the higher average plant balances and increased depreciation for negative net salvage in Pennsylvania.

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.

For the six months ended March 31, 2023, the WAC preserved earnings in the Utility segment's New York rate jurisdiction of approximately $4.2 million, as the weather was warmer than normal.

The increase in other income was primarily driven by a decrease in non-service pension and post-retirement benefit costs in the Utility segment's Pennsylvania jurisdiction.

These factors were partially offset by higher operating expenses ($7.7 million), primarily due to higher personnel costs, an increase in depreciation and amortization expense ($2.6 million), a decrease in earnings from regulatory adjustments ($2.1 million), a decrease in other operating revenues ($1.9 million), and a decrease in earnings from the impact of lower usage and weather ($0.7 million).

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

For the nine months ended June 30, 2023, the WNA preserved earnings in the Utility segment's New York rate jurisdiction of approximately $4.8 million, as the weather was warmer than normal.

Corporate and All Other

2024 Compared with 2023

Corporate and All Other operations had earnings of less than $0.1 million for the quarter ended March 31, 2024, essentially flat when compared with a net loss of less than $0.1 million for the quarter ended March 31, 2023.

For the six months ended March 31, 2024, Corporate and All Other operations had earnings of $1.1 million, an increase of $0.6 million when compared with earnings of $0.5 million for the six months ended March 31, 2023.

The increase in earnings for the six-month period was primarily attributable to changes in unrealized gains on investments in equity securities.

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

During the six months ended March 31, 2023, the Company recorded unrealized gains of $1.0 million.

Corporate and All Other operations had a net loss of $0.4 million for the quarter ended June 30, 2024, a decrease of $1.7 million when compared with earnings of $1.3 million for the quarter ended June 30, 2023.

The decrease was primarily attributable to lower other income ($0.6 million), higher operating expenses ($0.4 million), and changes in unrealized gains and losses on investments in equity securities.

During the quarter ended June 30, 2023, the Company recorded unrealized gains of $0.3 million.

During the quarter ended June 30, 2024, the Company recorded unrealized losses of less than $0.1 million.

For the nine months ended June 30, 2024, Corporate and All Other operations had earnings of $0.8 million, a decrease of $1.0 million when compared with earnings of $1.8 million for the nine months ended June 30, 2023.

The decrease in earnings for the nine-month period was primarily attributable to higher operating expenses ($1.6 million), primarily due to higher legal costs.

Other Income (Deductions)

Net other income on the Consolidated Statements of Income was $6.1 million for the quarter ended March 31, 2024, compared to net other income of $2.9 million for the quarter ended March 31, 2023, for an increase of $3.2 million.

This increase can be attributed primarily to a $0.5 million gain on the revaluation of the contingent consideration received from the sale of Seneca's California assets in June 2022 (compared to a loss of $2.5 million for the quarter ended March 31, 2023), as well as an increase of $0.9 million in allowance for funds used during construction and an increase in the cash surrender value of life insurance policies of $0.8 million.

These increases were partially offset by a decrease in interest income of $0.9 million that was mainly due to lower interest income from investments as well as changes in unrealized gains and losses on investments in equity securities that decreased other income by $0.5 million.

Net other income on the Consolidated Statement of Income was $9.8 million for the six months ended March 31, 2024, compared to net other income of $9.2 million for the six months ended March 31, 2023, for an increase of $0.6 million.

This increase was primarily due to $2.0 million of business interruption insurance proceeds that Seneca received during the current fiscal year related to a pipeline outage impacting Seneca's ability to market its gas, along with an increase in the cash surrender value of life insurance policies of $1.0 million.

There was also a $0.6 million increase in non-service pension and post-retirement benefit income year over year and an increase of $0.6 million in allowance for funds used during construction.

These increases were partially offset by a decrease in interest income of $2.4 million that was mainly due to lower interest income from investments and a decrease in interest from hedging collateral for derivative financial instruments as well as a $3.7

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million loss on the revaluation of the contingent consideration received from the sale of Seneca's California assets in June 2022 (compared to a loss of $2.3 million for the six months ended March 31, 2023).

Net other income on the Consolidated Statements of Income was $3.2 million for the quarter ended June 30, 2024, compared to net other income of $3.6 million for the quarter ended June 30, 2023, for a decrease of $0.4 million.

This decrease can be attributed primarily to lower income from life insurance policies of $0.6 million partially offset by an increase in interest income of $0.1 million and a decrease of $0.2 million when comparing the quarter over quarter losses associated with revaluing the contingent consideration received from the California asset sale.

Net other income on the Consolidated Statement of Income was $13.0 million for the nine months ended June 30, 2024, compared to net other income of $12.8 million for the nine months ended June 30, 2023, for an increase of $0.2 million.

While the overall variation is not significant, there were a number of items that contributed to the variance.

Items increasing other income included $2.0 million of business interruption insurance proceeds received during the nine months ended June 30, 2024 related to a pipeline outage that impacted Seneca's ability to market its gas, a $0.7 million increase in non-service pension and post-retirement benefit income, a $0.6 million increase in the allowance for funds used during construction, and a $0.4 million increase in income from life insurance policies.

Items decreasing other income included a $2.8 million decrease in interest income and a $1.1 million period over period increase in losses associated with revaluing the contingent consideration received from the California asset sale.

Interest Expense on Long-Term Debt

Interest expense on long-term debt on the Consolidated Statement of Income increased $0.9 million for the quarter ended March 31, 2024 as compared to the quarter ended March 31, 2023.

This was primarily due to a higher weighted average interest rate on long-term debt.

For the six months ended March 31, 2024, interest expense on long-term debt decreased $0.3 million as compared with the six months ended March 31, 2023.

This decrease is primarily due to an increase in capitalized interest (mostly in Midstream Company) as a result of higher capital expenditures.

This was partially offset by a higher weighted average interest rate on long-term debt.

In November 2022 and March 2023, the Company redeemed 3.75% notes, which in the aggregate amounted to $500.0 million, and in March 2023, the Company also redeemed $49.0 million of 7.395% notes.

These redemptions were partially offset by the issuance of $300.0 million of 5.50% notes in May 2023.

Interest expense on long-term debt on the Consolidated Statement of Income increased $6.6 million for the quarter ended June 30, 2024 as compared to the quarter ended June 30, 2023.

For the nine months ended June 30, 2024, interest expense on long-term debt increased $6.3 million as compared with the nine months ended June 30, 2023.

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

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

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

The Company selected an initial six month interest period for these borrowings, locking in a weighted average interest rate of 6.705% through the beginning of October 2024.

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

In addition, there was an increase in capitalized interest (mostly in Midstream Company) as a result of higher capital expenditures.

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CAPITAL RESOURCES AND LIQUIDITY

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’s primary sources of cash during the six-month period ended March 31, 2023 consisted of cash provided by operating activities, proceeds from short-term borrowings and proceeds from the sale of a fixed income mutual fund held in a grantor trust.

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

The Company’s primary sources of cash during the nine-month period ended June 30, 2023 consisted of cash provided by operating activities, net proceeds from short-term and long-term borrowings and proceeds from the sale of a fixed income mutual fund held in a grantor trust.

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 2024, the Company expects to use cash provided by operating activities, as well as net proceeds from short-term borrowings, to fund the Company's capital expenditures.

During the remainder of 2024, 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.

Looking forward to 2025, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures.

The Company also has two long-term debt maturities in 2025, totaling $500.0 million, which the Company anticipates funding with cash on hand as well as short-term and long-term borrowings.

The Company also has two long-term debt maturities in 2025, totaling $500.0 million, which the Company anticipates funding with 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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Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities.

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

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

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

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

The Company uses various

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

Net cash provided by operating activities totaled $868.0 million for the nine months ended June 30, 2024, a decrease of $187.1 million compared with $1,055.1 million provided by operating activities for the nine months ended June 30, 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.

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

Net cash provided by operating activities totaled $586.3 million for the six months ended March 31, 2024, a decrease of $124.9 million compared with $711.2 million provided by operating activities for the six months ended March 31, 2023.

Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $435.7 million during the six months ended March 31, 2024 and $440.6 million during the six months ended March 31, 2023.

The Company’s expenditures for long-lived assets totaled $655.5 million during the nine months ended June 30, 2024 and $804.1 million during the nine months ended June 30, 2023.

The table below presents these expenditures:

Total Expenditures for Long-Lived Assets

Six Months Ended March 31, 2024 2023 Increase (Decrease)

Nine Months Ended June 30, 2024 2023 Increase (Decrease)

Exploration and Production:

Capital Expenditures (1)

$ 399.8 (2) $ 592.8 (3) $ (193.0)

Pipeline and Storage:

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$ 655.5 $ 804.1 $ (148.6)

(1) 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.

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

The acquisition costs for the assets acquired from SWN is reported as a component of Acquisition of Upstream Assets on the Consolidated Statement of Cash Flows.

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

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

(2) At March 31, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $56.1 million, $2.2 million, $2.0 million and $4.2 million, respectively, of non-cash capital expenditures.

(3) At June 30, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $52.8 million, $7.7 million, $2.8 million and $8.5 million, respectively, of non-cash capital expenditures.

At September 30, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $83.0 million, $15.2 million, $10.7 million and $11.4 million, respectively, of non-cash capital expenditures.

Exploration and Production

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.

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

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

The Exploration and Production segment capital expenditures for the six months ended March 31, 2023 were primarily well drilling and completion expenditures in the Appalachian region, and included $143.2 million in the Marcellus Shale area and $172.4 million in the Utica Shale area.

The Exploration and Production segment capital expenditures for the nine months ended June 30, 2023 were primarily well drilling and completion expenditures in the Appalachian region and included $229.6 million in the Marcellus Shale area and $352.2 million in the Utica Shale area.

These amounts included approximately $256.4 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2024 and March 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.

On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN for total consideration of $124.8 million.

As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets.

This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment.

In April 2023, the Company completed the acquisition of certain upstream assets located in Lycoming County in Northeast Pennsylvania for total consideration of $11.5 million.

This acquisition included 1,145 net acres in Lycoming County.

This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment.

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

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Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2024 and June 30, 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.

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.

Supply Corporation expects to file a Section 7(c) application with the FERC in late summer 2024.

Supply Corporation expects to file a Section 7(c) application with the FERC in August 2024.

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

As of March 31, 2024, approximately $1.0 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, 2024.

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.

Midstream Company spent $31.2 million and $7.0 million, respectively, during the six months ended March 31, 2024 on the development of the 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 Gathering segment capital expenditures for the six months ended March 31, 2023 included expenditures related to the continued expansion of Midstream Company's Clermont, Tioga and Trout Run gathering systems.

Midstream Company spent $10.2 million, $16.8 million and $3.8 million, respectively, during the six months ended March 31, 2023 on the development of the Clermont, Tioga and Trout Run gathering systems.

As of June 30, 2024, approximately $1.5 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at June 30, 2024.

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

Midstream Company spent $55.4 million and $10.2 million, respectively, during the nine months ended June 30, 2024 on the development of the 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 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 nine months ended June 30, 2023 included expenditures related to the continued expansion of Midstream Company's Clermont, Tioga and Trout Run gathering systems.

Midstream Company spent $14.7 million, $33.7 million and $6.8 million, respectively, during the nine months ended June 30, 2023 on the development of the Clermont, Tioga and Trout Run gathering systems.

These expenditures were largely attributable to the installation of new in-field gathering pipelines, as well as the continued development of centralized station facilities, including increased compression horsepower, at the Clermont, Trout Run, and Tioga gathering systems.

In the Tioga gathering system, expenditures were also largely attributable to the expansion of on-pad and centralized station facilities related to bringing new development online.

The majority of the Utility segment capital expenditures for the six months ended March 31, 2024 and March 31, 2023 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions.

In the Tioga gathering system, expenditures were also largely attributable to the expansion of on-pad facilities related to bringing new development online.

The majority of the Utility segment capital expenditures for the nine months ended June 30, 2024 and June 30, 2023 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.

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

The proceeds were used in the Utility segment's Pennsylvania service territory during fiscal 2023 to fund the second year installment of a 5-year pass back of previously overcollected OPEB expenses, as well as to diversify a portion of grantor trust investments into lower risk money market mutual fund shares.

The proceeds were used in the Utility segment's Pennsylvania service

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territory during fiscal 2023 to fund the second year installment of a 5-year pass back of previously overcollected OPEB expenses, as well as to diversify a portion of grantor trust investments into lower risk money market mutual fund shares for purposes of funding future installments.

Project Funding

During the six months ended March 31, 2024 and fiscal 2023, the Company has been financing capital expenditures with cash from operations and short-term debt.

During the nine months ended June 30, 2024 and fiscal 2023, 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 and long-term borrowings, as needed, to finance capital expenditures.

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Financing Cash Flow

Consolidated short-term debt decreased $8.6 million, to a total of $278.9 million, when comparing the balance sheet at March 31, 2024 to the balance sheet at September 30, 2023.

The maximum amount of short-term debt outstanding during the six months ended March 31, 2024 was $402.9 million.

Consolidated short-term debt decreased $287.5 million when comparing the balance sheet at June 30, 2024 to the balance sheet at September 30, 2023.

The maximum amount of short-term debt outstanding during the nine months ended June 30, 2024 was $402.9 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 gas 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 March 31, 2024, the Company did not have any short-term notes payable to banks and had outstanding commercial paper of $278.9 million.

As of June 30, 2024, the Company did not have any short-term notes payable to banks or commercial paper outstanding.

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

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

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

Effective February 7, 2024, certain lenders under the Credit Agreement consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028.

As a result, the Company has aggregate commitments available under the Credit Agreement of $1.0 billion before February 26, 2027, and $940.0 million in aggregate commitments available on and after February 26, 2027 to February 25, 2028.

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

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

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

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

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

The Term Loan Agreement provides a $300.0 million unsecured committed term loan with a maturity date of February 14, 2026.

Pursuant to the Term Loan Agreement, there was a delayed draw mechanism and the Company elected to draw a total of $300.0 million under the facility between April 8, 2024 and April 10, 2024.

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

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

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

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

The Company selected an initial six month interest period for these borrowings, locking in a weighted average interest rate of 6.705% through the beginning of October 2024.

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any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million.

Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million.

As a result, at March 31, 2024, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under these agreements.

In addition, for purposes of calculating the debt to capitalization ratio under these agreements, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet.

Under the agreements, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation.

At March 31, 2024, the Company’s debt to capitalization ratio, as calculated under the agreements was 0.44.

The constraints specified in the agreements would have permitted an additional $3.57 billion in short-term and/or long-term debt to be outstanding at March 31, 2024 before the Company’s debt to capitalization ratio exceeded 0.65.

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

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

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

For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million.

Since that date, the Company recorded non-cash, after-tax ceiling test impairments totaling $526.4 million.

As a result, at June 30, 2024, $263.2 million was added back to the Company's total capitalization for purposes of calculating the debt to capitalization ratio under the agreements.

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

all unrealized gains or losses on commodity-related derivative financial instruments, and up to $10 million in unrealized gains or losses on other derivative financial instruments.

As a result of these exclusions, such unrealized gains or losses will not positively or negatively affect the calculation of the debt to capitalization ratio.

At June 30, 2024, the Company’s debt to capitalization ratio, as calculated under the agreements was 0.45.

The constraints specified in the agreements would have permitted an additional $3.46 billion in short-term and/or long-term debt to be outstanding at June 30, 2024 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded 0.65.

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

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

None of the Company's long-term debt as of March 31, 2024 and September 30, 2023 had a maturity date within the following twelve-month period.

The Company’s embedded cost of long-term debt was 4.69% at March 31, 2024 and 4.58% at March 31, 2023.

Under the Company’s existing indenture covenants at March 31, 2024, the Company would have been permitted to issue up to a maximum of approximately $4.02 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by the debt to capitalization ratio constraint under the Credit Agreement and Term Loan Agreement, as discussed above).

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

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

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

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

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

The Current Portion of Long-Term Debt at June 30, 2024 consisted of $50.0 million of 7.375% notes that mature in June 2025.

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

The Company’s embedded cost of long-term debt was 4.91% at June 30, 2024 and 4.70% at June 30, 2023.

Under the Company’s existing indenture covenants at June 30, 2024, the Company would have been permitted to issue up to a maximum of approximately $2.26 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt.

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

It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued.

Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions.

Losses incurred as a result of significant impairments of exploration and production properties have in the past resulted in such temporary restrictions.

The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt.

At the current outlook for natural gas prices, and taking into account the Company’s present plans for capital expenditures, the Company does not expect the indenture covenants to restrict

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incremental long-term financing activities.

Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

The Company’s 1974 indenture pursuant to which $50.0 million (or 2.1%) of the Company’s long-term debt (as of March 31, 2024) was issued, 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.

The Company’s 1974 indenture, pursuant to which $50.0 million (or 1.9%) of the Company’s long-term debt (as of June 30, 2024) was issued, 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.

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

The Company’s Board of Directors may suspend,

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discontinue, terminate, modify, cancel or extend the share repurchase program at any time and for any reason.

During the quarter ended March 31, 2024, the Company executed transactions to repurchase 96,133 shares for $5.0 million.

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

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

The 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 nine months ended June 30, 2024, the Company executed transactions to repurchase 526,652 shares at an average price of $54.28 per share.

With broker fees and excise taxes, the total cost of these repurchases amounted to $28.8 million.

Share repurchases that settled during the nine months ended June 30, 2024 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.

OTHER MATTERS

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Circuit decision, the Company is evaluating next steps for the project, including the status of various regulatory approvals, the $500 million preliminary cost estimate, and the potential in-service date.

As of March 31, 2024, approximately $55.0 million has been spent on the Northern Access project, including $24.4 million that has been spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet.

The remaining $30.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2024.

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, 2024.

In the remainder of fiscal 2024, the Company expects its contributions to the Retirement Plan to be in the range of zero to $5.0 million.

The Company did not make any contributions to its VEBA trusts for its other post-retirement benefits during the six months ended March 31, 2024, and does not anticipate making any such contributions during the remainder of fiscal 2024.

As of June 30, 2024, approximately $55.0 million has been spent on the Northern Access project, including $24.4 million that has been spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet.

The remaining $30.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at June 30, 2024.

The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the nine months ended June 30, 2024, and does not anticipate making any such contributions during the remainder of fiscal 2024.

The Company also did not make any contributions to its VEBA trusts for its other post-retirement benefits during the nine months ended June 30, 2024, and does not anticipate making any such contributions during the remainder of fiscal 2024.

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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 March 31, 2024, the Company determined that nonperformance risk associated with its natural gas price

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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 June 30, 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.

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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The Company is also proposing, among other things, to continue its leak prone pipe replacement program and to implement a number of initiatives that will facilitate achievement of the emissions reduction goals of the CLCPA.

A Notice of Impending Settlement Negotiations was filed with the NYPSC on March 26, 2024 and settlement discussions with parties are ongoing.

To facilitate settlement negotiations, the Company has indicated that it is willing to accept an extension of the suspension period for the effective date of new base delivery rates through and including January 31, 2025.

Consistent with normal regulatory practice, the Company’s acceptance is subject to a “make-whole” provision that would permit the Company to recover or refund any revenue under-collections or over-collections, respectively, resulting from the extension period.

On August 13, 2021, the NYPSC issued an order extending the date through which qualified pipeline replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (until March 31, 2023).

On December 9, 2022, the Company filed a petition with the NYPSC to effectuate a system improvement tracker through which qualified pipeline replacement costs through September 30, 2024 would be tracked and recovered, and to recover certain deferred costs associated with the existing system modernization tracker, effective April 1, 2023.

On December 9, 2022, the Company filed a petition with the NYPSC to effectuate a system improvement tracker

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through which qualified pipeline replacement costs through September 30, 2024 would be tracked and recovered, and to recover certain deferred costs associated with the existing system modernization tracker, effective April 1, 2023.

The NYPSC approved the petition by order dated March 17, 2023 contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to October 1, 2024.

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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.

If approved as filed, beginning October 1, 2024, the Company will be able to recover costs associated with plant placed in service on and after August 1, 2024 if it exceeds approximately $781.3 million of net plant as of July 31, 2024 and its quarterly rate of return does not exceed the authorized PaPUC rate of return.

If approved as filed, beginning October 1, 2024, the Company will be able to recover costs associated with plant placed in service on and after August 1, 2024 if it exceeds approximately $781.3 million of plant as of July 31, 2024 and its quarterly rate of return does not exceed the authorized PaPUC rate of return.

As of June 30, 2024, plant placed in service for Distribution Corporation’s Pennsylvania division is $763.7 million.

The DSIC petition is currently pending before the PaPUC.

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Pipeline and Storage

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On March 8, 2024, Supply Corporation and the parties in the case reached a settlement in principle (the Settlement) to resolve the rate case.

Supply Corporation’s March 11, 2024 motion to put in place Interim Settlement Rates effective February 1, 2024, was approved by FERC’s Chief Administrative Law Judge on March 12, 2024.

The Settlement was filed with FERC on March 27, 2024 and remains pending.

Supply Corporation’s March 11, 2024 motion to put in place Settlement Rates effective February 1, 2024, was approved by FERC’s Chief Administrative Law Judge on March 12, 2024.

The Settlement was filed with FERC on March 27, 2024.

A letter order approving the Settlement as filed was issued on June 11, 2024.

The “black box” settlement provides for new rates and resolves all issues in the proceeding.

The Interim Settlement Rates are estimated to increase Supply Corporation’s revenues on a yearly basis by approximately $56 million, assuming current contract levels.

The Settlement Rates are estimated to increase Supply Corporation’s revenues on a yearly basis by approximately $56 million, assuming current contract levels.

The Settlement generally provides for the continuation of current depreciation rates with minimal changes.

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These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions.

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

Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, restrictive

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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.

The IRA includes a methane charge that is expected to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, starting in calendar year 2024.

This portion of the IRA is to be administered by the EPA and potential fees will begin with emissions reported for calendar year 2024.

The EPA is the lead federal agency that regulates greenhouse gas emissions pursuant to the Clean Air Act.

The regulations implemented by the EPA impose stringent leak detection and repair requirements and address reporting and control of methane and volatile organic compound emissions, and these regulations continue to be further expanded upon with the recent publication (March 2024) and finalization of the Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources.

The IRA includes a directive for the EPA, the lead federal agency that regulates greenhouse gas emissions pursuant to the Clean Air Act, to develop a methane charge to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, with potential fees expected to begin in calendar 2025, covering emissions reported for calendar year 2024.

The regulations implemented by the EPA also impose stringent leak detection and repair requirements and address reporting and control of methane and volatile organic compound emissions, and these regulations continue to be further expanded upon with the recent publication (March 2024) and finalization of the Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources.

The Company must continue to comply with all applicable regulations.

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

The above-enumerated initiatives could also increase the Company’s cost of environmental compliance

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by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances.

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 delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals.

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

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

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achieved or accomplished.

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

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

Increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators;

Changes in 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;

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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;

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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;

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

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

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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