What changed in this filing

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Item 2. Management’s Discussion and Analysis

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

The Company also develops and produces oil reserves, primarily in California.

The Company reports financial results for four business segments.

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

The Company is closely monitoring and responding to developments related to the novel coronavirus (COVID-19) and is taking steps to limit operational impacts and the potential exposure for our workforce and customers.

Refer to Risk Factors in Part I, Item 1A, Risk Factors, under Operational Risks in the Company's 2021 Form 10-K for a more complete discussion of the risks to the Company associated with the COVID-19 pandemic.

On May 1, 2022, the Company entered into a purchase and sale agreement to sell Seneca’s California oil and gas assets to Sentinel Peak Resources California LLC for total consideration between $280 million and $310 million, depending on oil prices.

This consideration consists of $280 million in cash at closing, plus up to three annual contingent payments between calendar 2023 and 2025 that can total $30 million in aggregate.

The transaction has an effective date of April 1, 2022 and is expected to close on June 30, 2022, subject to customary closing conditions (including waivers of certain transfer restrictions).

On June 30, 2022, the Company completed the sale of Seneca’s California assets to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing.

Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar 2023 and 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel.

The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date.

The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin.

Under the full cost method of accounting for oil and natural gas properties, it is expected that substantially all of the sale proceeds received at closing will be accounted for as a reduction of capitalized costs since the disposition will not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center.

A portion of the sales proceeds will be applied to assets that are not subject to the full cost method of accounting.

Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center.

The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets.

The majority of this gain related to the sale of emission allowances.

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

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The incremental pipeline capacity from this project and associated gathering system development by Midstream Company allows Seneca to increase its production and reach premium Transco Zone 6 (Non-New York) markets.

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

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

On February 28, 2022, the Company entered into 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 an initial maturity date of February 26, 2027.

From a financing perspective, the Company expects to use cash on hand and cash from operations, as well as short-term borrowings, to meet its financing needs for fiscal 2022.

The Company may issue long-term debt during fiscal 2022 to replace all or a portion of its March 2023 debt maturities.

On June 30, 2022, the Company entered into the 364-Day Credit Agreement with a syndicate of five banks, all of which are also lenders under the Credit Agreement.

The 364-Day Credit Agreement provides an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023.

Under the delayed draw mechanism of the 364-Day Credit Agreement, the Company may, through September 28, 2022, make up to three elections to borrow funds under the facility, provided that the Company may extend the period to make such elections to October 28, 2022.

From a financing perspective, the Company expects to use the proceeds from the sale of the Company's California assets, cash on hand and cash from operations, as well as short-term borrowings, to meet its financing needs for fiscal 2022.

The Company is closely monitoring and responding to developments related to COVID-19 and is taking steps to limit operational impacts and the potential exposure for our workforce and customers.

CRITICAL ACCOUNTING ESTIMATES

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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.

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

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 June 30, 2022 sale of the Company's California oil and natural gas properties.

That sale is discussed in more detail in Item 1 at Note 2 - Asset Acquisitions and Divestitures.

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.

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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, 2022, the ceiling exceeded the book value of the oil and gas properties by approximately $1.8 billion.

The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended March 31, 2022, based on posted Midway Sunset prices, was $74.02 per Bbl.

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, 2022, based on the quoted Henry Hub spot price for natural gas, was $4.09 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 Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for the twelve months ended March 31, 2022.

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 amounts the ceiling would have exceeded the book value of the Company's oil and gas properties at March 31, 2022 if natural gas prices were $0.25 per MMBtu lower than the average prices used at March 31, 2022, if crude oil prices were $5 per Bbl lower than the average prices used at March 31, 2022, and if both natural gas prices and crude oil prices were $0.25 per MMBtu and $5 per Bbl lower than the average prices used at March 31, 2022 (all amounts are presented after-tax).

In all such cases, these price decreases would not have resulted in an impairment charge.

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

Ceiling Testing Sensitivity to Commodity Price Changes

(Millions) $0.25/MMBtu

Natural Gas Prices $5.00/Bbl

Crude Oil Prices $0.25/MMBtu

Natural Gas Prices

and $5.00/Bbl

Crude Oil Prices

Excess of Ceiling over Book Value under Sensitivity Analysis $ 1,485.0 $ 1,724.6 $ 1,450.5

At June 30, 2022, the ceiling exceeded the book value of the oil and gas properties by approximately $2.4 billion.

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, 2022, based on the quoted Henry Hub spot price for natural gas, was $5.13 per MMBtu.

Because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for the twelve months ended June 30, 2022.

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 used at June 30, 2022 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's oil and gas properties by approximately $2.1 billion (after-tax), which would not have resulted in an impairment charge.

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

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

Fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time.

Fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in gas prices 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 2021 Form 10-K.

RESULTS OF OPERATIONS

The Company's earnings were $167.3 million for the quarter ended March 31, 2022 compared to earnings of $112.4 million for the quarter ended March 31, 2021.

The increase in earnings of $54.9 million is primarily the result of higher earnings in all reportable segments, partially offset by losses in the Corporate category.

The Company's earnings were $299.7 million for the six months ended March 31, 2022 compared to earnings of $190.2 million for the six months ended March 31, 2021.

The Company's earnings were $108.2 million for the quarter ended June 30, 2022 compared to earnings of $86.5 million for the quarter ended June 30, 2021.

The increase in earnings of $21.7 million is primarily the result of higher earnings in the Exploration and Production segment, Pipeline and Storage segment and Gathering segment.

Lower earnings in the Utility segment and a higher loss in the Corporate category partially offset these increases.

The Company's earnings were $407.9 million for the nine months ended June 30, 2022 compared to earnings of $276.7 million for the nine months ended June 30, 2021.

The increase in earnings of $131.2 million is primarily the result of higher earnings in all reportable segments, partially offset by losses in the Corporate and All Other categories.

The Company's earnings for the quarter and six months ended March 31, 2022 include the reduction of an OPEB regulatory liability that increased earnings by $18.5 million ($14.6 million after-tax) recorded in the Utility segment in accordance with a regulatory proceeding in Distribution Corporation's Pennsylvania service territory.

The Company's earnings for the six months ended March 31, 2021 included a non-cash impairment charge of $76.2 million ($55.2 million after-tax) recorded during the quarter ended December 31, 2020 for the Exploration and Production segment's oil and gas producing properties.

The Company's earnings for the six months ended March 31, 2021 also included a gain recognized on the sale of timber properties of $51.1 million ($37.0 million after-tax) recorded during the quarter ended December 31, 2020 in the Company's All Other category.

The Company's earnings for the quarter and nine months ended June 30, 2022 include the impact of several items in the Company's Exploration and Production segment related to the completion of the sale of Seneca’s California assets, as discussed above.

The Company recorded a gain on the sale of these assets of $12.7 million ($9.5 million after-tax) related to a portion of the sales price that was applied to assets that were not subject to the full cost method of accounting.

The Company also recorded a loss of $44.6 million ($33.3 million after-tax) related to the termination of its remaining crude oil derivative contracts as a result of the sale.

In addition, the Company incurred transaction and severance costs of $9.7 million ($7.2 million after-tax) related to the California asset sale.

The Company's earnings for the nine months ended June 30, 2022 include the reduction of an OPEB regulatory liability that increased earnings by $18.5 million ($14.6 million after-tax) recorded during the quarter ended March 31, 2022 in the Utility segment in accordance with a regulatory proceeding in Distribution Corporation's Pennsylvania service territory.

The Company's earnings for the nine months ended June 30, 2021 included a non-cash impairment charge of $76.2 million ($55.2 million after-tax) recorded during the quarter ended December 31, 2020 for the Exploration and Production segment's oil and gas producing properties.

The Company's earnings for the nine months ended June 30, 2021 also included a gain recognized on the sale of timber properties of $51.1 million ($37.0 million after-tax) recorded during the quarter ended December 31, 2020 in the Company's All Other category.

Additional discussion of earnings in each of the business segments can be found in the business segment information that follows.

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Oil (after Hedging) (1)

40,867 33,065 7,802 112,907 93,256 19,651

Gas Processing Plant 1,016 732 284 3,029 2,056 973

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Weighted Average After Hedging (1)

$ 77.65 $ 59.22 $ 18.43 $ 70.71 $ 55.40 $ 15.31

(1) Oil revenue and weighted average oil price after hedging for the three months and nine months ended June 30, 2022 excludes a loss on discontinuance of crude oil cash flow hedges of $44,632.

This loss is presented in other revenue in the table above.

2022 Compared with 2021

Operating revenues for the Exploration and Production segment increased $41.4 million for the quarter ended March 31, 2022 as compared with the quarter ended March 31, 2021.

Operating revenues for the Exploration and Production segment increased $43.1 million for the quarter ended June 30, 2022 as compared with the quarter ended June 30, 2021.

Gas production revenue after hedging increased $81.0 million due to the impact of a 9.5 Bcf increase in natural gas production, together with a $0.67 per Mcf increase in the weighted average price of natural gas after hedging.

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The decrease in oil production was largely due to natural production declines.

In addition, other revenue increased $4.5 million and gas processing plant revenue increased $0.2 million.

The increase in other revenue is primarily attributed to a temporary capacity release through March 2022 for a small portion of this segment's Leidy South transportation contract combined with operating revenue from Highland Field Services water treatment plants acquired at the end of fiscal 2021.

Operating revenues for the Exploration and Production segment increased $94.2 million for the six months ended March 31, 2022 as compared with the six months ended March 31, 2021.

These amounts were partially offset by a decrease in other revenue of $46.0 million.

The decrease in other revenue is primarily attributed to a loss on discontinuance of crude oil cash flow hedges combined with royalty shut-in payments made in accordance with lease agreements.

Operating revenues for the Exploration and Production segment increased $137.3 million for the nine months ended June 30, 2022 as compared with the nine months ended June 30, 2021.

Gas production revenue after hedging increased $156.3 million due to the impact of a 17.3 Bcf increase in natural gas production combined with a $0.46 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 during the six months ended March 31, 2022 as

compared with the six months ended March 31, 2021.

Oil production revenue after hedging increased $11.8 million due to a $13.80 per Bbl increase in the weighted average price of oil after hedging, offset by the impact of a 54 Mbbl decrease in oil production.

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, 2022 as

compared with the nine months ended June 30, 2021.

Oil production revenue after hedging increased $19.7 million due to a $15.31 per Bbl increase in the weighted average price of oil after hedging, offset by the impact of an 86 Mbbl decrease in oil production.

The decrease in oil production was largely due to natural production declines.

In addition, other revenue increased $6.4 million and gas processing plant revenue increased $0.7 million.

The increase in other revenue is primarily attributed to a temporary capacity release for a small portion of this segment's Leidy South transportation contract combined with operating revenue from Highland Field Services water treatment plants acquired at the end of fiscal 2021.

The Exploration and Production segment's earnings for the quarter ended March 31, 2022 were $71.1 million, an increase of $34.3 million when compared with earnings of $36.8 million for the quarter ended March 31, 2021.

The increase in earnings was due to higher natural gas production ($3.8 million), higher natural gas prices after hedging ($21.5 million), higher oil prices after hedging ($5.5 million), higher other revenue ($3.5 million) and lower interest expense ($2.6 million).

The Exploration and Production segment also recognized a loss in March 2021 ($10.7 million) for its share of the premium paid by the Company to redeem $500 million of the Company’s 4.90% notes that were scheduled to mature in December 2021.

The positive earnings impact of these items was partially offset by lower oil production ($1.8 million), higher lease operating and transportation expenses ($4.4 million), higher depletion expense ($3.5 million), higher other operating expenses ($1.7 million), higher other taxes ($1.9 million) and higher income tax expense ($0.3 million).

The decrease in interest expense can largely be attributed to a lower average amount of intercompany long-term borrowings outstanding combined with a lower average interest rate on such borrowings.

The increase in lease operating and transportation expenses was primarily the result of increased well workover costs and higher steam fuel costs in the West Coast region.

These amounts were partially offset by a decrease in other revenue of $39.6 million.

The decrease in other revenue was primarily attributed to a loss on discontinuance of crude oil cash flow hedges combined with royalty shut-in payments made in accordance with lease agreements.

These were partially offset by a temporary capacity release for a small portion of this segment's Leidy South transportation contract and operating revenue from Highland Field Services water treatment plants acquired at the end of fiscal 2021.

The Exploration and Production segment's earnings for the quarter ended June 30, 2022 were $56.5 million, an increase of $17.5 million when compared with earnings of $39.0 million for the quarter ended June 30, 2021.

The increase in earnings was due to higher natural gas production ($16.6 million), higher natural gas prices after hedging ($47.4 million), higher oil prices after hedging ($7.7 million), lower income tax expense ($3.3 million) and a gain that was recognized on the sale of Seneca's California non-full cost pool assets ($9.5 million), as discussed above.

The positive earnings impact of these items was partially offset by lower oil production ($1.5 million), higher lease operating and transportation expenses ($10.1 million), higher depletion expense ($7.3 million), higher other operating expenses ($4.8 million) and higher interest expense ($2.0 million).

Finally, the Company also had a loss related to discontinuance of its crude oil cash flow hedges ($33.3 million) and had transaction and severance costs ($7.2 million), all of which were driven by the sale of its California assets.

The increase in lease operating and transportation expenses was primarily the result of higher gathering and transportation costs in the Appalachian region due to increased production combined with higher steam fuel costs, utilities and contract labor in the West Coast region.

The increase in depletion expense was primarily due to the net increase in production combined with a $0.04 per Mcf increase in the depletion rate.

The increase in other operating expenses was partially attributed to an increase in operating costs associated with the Highland Field Services water treatment plants acquired at the end of fiscal 2021, as well as higher consulting services and technology-related expenses.

The increase in other taxes was mainly attributed to increased Impact Fees in the Appalachian region as a result of an increase in natural gas prices.

T he Impact Fees are calculated annually based on calendar year NYMEX natural gas prices.

The Exploration and Production segment's earnings for the six months ended March 31, 2022 were $133.5 million, an increase of $126.3 million when compared with earnings of $7.2 million for the six months ended March 31, 2021.

The increase in earnings was primarily attributable to an impairment of oil and gas properties ($55.2 million) recorded during the six months ended March 31, 2021, higher natural gas production ($13.6 million), higher natural gas prices after hedging ($45.9 million), higher oil prices after hedging ($11.7 million), higher other revenue ($5.1 million), higher gas processing plant revenue ($0.5 million), lower interest expense ($5.2 million) and lower income tax expense ($0.6 million).

The increase in other operating expenses was primarily attributed to the accrual of estimated abandonment costs related to certain offshore Gulf of Mexico wells that were formally owned by the Company.

Several years ago, Seneca sold those wells to an operator that has since gone bankrupt, and, as a result of the bankruptcy, the cost of abandoning the wells will likely revert back to Seneca.

The increase in interest expense can largely be attributed to a higher average amount of intercompany short-term borrowings outstanding combined with a higher average interest rate on such borrowings.

The Exploration and Production segment's earnings for the nine months ended June 30, 2022 were $190.0 million, an increase of $143.8 million when compared with earnings of $46.2 million for the nine months ended June 30, 2021.

The increase in earnings was primarily attributable to an impairment of oil and gas properties ($55.2 million) recorded during the nine months ended June 30, 2021, higher natural gas production ($30.2 million), higher natural gas prices after hedging ($93.3 million), higher oil prices after hedging ($19.3 million), higher other revenue ($4.0 million), lower interest expense ($3.2 million), lower income tax expense ($3.8 million) and a gain that was recognized on the sale of Seneca's California non-full cost pool assets ($9.5 million).

These increases in earnings were partially offset by lower oil production ($3.8 million), higher lease operating and transportation expenses ($17.3 million), higher depletion expense ($14.1 million), higher other operating expenses ($7.8 million) and higher other taxes ($3.1 million).

Finally, the Company also had a loss related to discontinuance of its crude oil cash flow hedges ($33.3 million) and also had transaction and severance costs ($7.2 million), all of which were driven by the sale of its California assets.

The decrease in interest expense can largely be attributed to a lower average amount of intercompany long-term borrowings outstanding combined with a lower average interest rate on such borrowings.

The increase in lease operating and transportation expenses was primarily the result of increased well workover costs and higher steam fuel costs in the West Coast region combined with gathering and transportation costs in the Appalachian region due to increased production.

The increase in lease operating and transportation expenses was primarily the result of higher gathering and transportation costs in the Appalachian region due to increased production combined with higher steam fuel costs, well workover costs and contract labor in the West Coast region.

The increase in depletion expense was primarily due to the net increase in production combined with a $0.03 per Mcf increase in the depletion rate.

The increase in other taxes was mainly attributed to increased Impact Fees in the Appalachian region, as discussed above.

The increase in other operating expenses was primarily attributed to the accrual of estimated abandonment costs related to certain offshore Gulf of Mexico wells formally owned by the Company, as discussed above.

In addition, the increase in other operating expenses was also attributed to an increase in operating costs associated with the Highland Field Services water treatment plants acquired at the end of fiscal 2021.

The increase in other taxes was mainly attributed to increased Impact Fees in the Appalachian region as a result of an increase in natural gas prices.

The Impact Fees are calculated annually based on calendar year NYMEX natural gas prices.

Pipeline and Storage

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2022 Compared with 2021

Operating revenues for the Pipeline and Storage segment increased $8.7 million for the quarter ended March 31, 2022 as compared with the quarter ended March 31, 2021.

The increase in operating revenues was primarily due to an increase in transportation revenues of $8.0 million and an increase in other revenue of $0.5 million.

The increase in transportation revenues was primarily attributable to new demand charges for transportation service from the expansion portion of Supply Corporation's FM100 Project, which was placed into service in December 2021, partially offset by revenue decreases associated with miscellaneous contract terminations and revisions.

The increase in other revenue primarily reflects higher cashout revenues partially offset by lower electric surcharge true-up revenues.

Cashout revenues are completely offset by purchased gas expense.

Operating revenues for the Pipeline and Storage segment increased $11.5 million for the quarter ended June 30, 2022 as compared with the quarter ended June 30, 2021.

The increase in operating revenues was primarily due to increases in transportation revenues of $11.7 million and storage revenues of $0.4 million, partially offset by a decrease in other revenue of $0.7 million.

This increase from the FM100 Project includes the impact of a negotiated revenue step-up to Period 2 Rates that went into effect April 1, 2022 as specified in Supply Corporation's 2020 rate case settlement.

The increase in storage revenues was mainly due to the Period 2 Rates that went into effect April 1, 2022 related to the FM100 Project, as discussed above, as well as an increase in a surcharge for Pipeline Safety and Greenhouse Gas Regulatory Costs (PS/GHG Regulatory Costs) that went into effect in November 2020 associated with Supply Corporation's 2020 rate case settlement.

The decrease in other revenue primarily reflects lower electric surcharge true-up revenues.

Revenues collected through the electric surcharge mechanism are completely offset by electric power costs recorded in operation and maintenance expense.

Operating revenues for the Pipeline and Storage segment increased $9.3 million for the six months ended March 31, 2022 as compared with the six months ended March 31, 2021.

The increase in operating revenues was primarily due to an increase in transportation revenues of $9.5 million and an increase in storage revenues of $0.5 million, partially offset by a decrease in other revenues of $0.7 million.

The increase in transportation revenues was primarily attributable to new demand charges for transportation service from Supply Corporation's FM100 Project being placed into service as mentioned above, partially offset by revenue decreases associated with miscellaneous contract terminations and revisions.

In addition, a surcharge for Pipeline Safety and Greenhouse Gas Regulatory Costs (PS/GHG Regulatory Costs) that went into effect in November 2020 associated with Supply Corporation’s 2020 rate case settlement also contributed to the increase in transportation revenues and was primarily responsible for the increase in storage revenues.

The decrease in other revenue primarily reflects the non-recurrence of revenue associated with a contract buyout that occurred during the quarter ended December 31, 2020, partially offset by higher cashout revenues.

Transportation volume for the quarter ended March 31, 2022 increased by 22.9 Bcf from the prior year's quarter, primarily due to an increase in volume from the FM100 Project, which was brought online in December 2021, combined with an increase in volume from colder weather and an increase in capacity utilization by certain contract shippers.

For the six months ended March 31, 2022, transportation volume increased by 13.6 Bcf from the prior year's six-month period ended March 31, 2021.

The increase in transportation volume for the six-month period primarily reflects an increase in volume from the FM100 Project.

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, 2022 were $25.5 million, an increase of $0.6 million when compared with earnings of $24.9 million for the quarter ended March 31, 2021.

Operating revenues for the Pipeline and Storage segment increased $20.8 million for the nine months ended June 30, 2022 as compared with the nine months ended June 30, 2021.

The increase in operating revenues was primarily due to increases in transportation revenues of $21.2 million and storage revenues of $1.0 million, partially offset by a decrease in other revenues of $1.4 million.

The increase in transportation revenues was primarily attributable to new demand charges for transportation service from Supply Corporation's FM100 Project being placed into service as mentioned above, which includes the impact of a negotiated revenue step-up to Period 2 Rates that went into effect April 1, 2022, also mentioned above.

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

In addition, the PS/GHG Regulatory Costs surcharge that went into effect in November 2020 associated with Supply Corporation’s 2020 rate case settlement also contributed to the increase in transportation revenues and was primarily responsible for the increase in storage revenues.

The decrease in other revenue primarily reflects the non-recurrence of revenue associated with a contract buyout that occurred during the quarter ended December 31, 2020, combined with lower electric surcharge true-up revenues, partially offset by higher cashout revenues.

Cashout revenues are completely offset by purchased gas expense.

Transportation volume for the quarter ended June 30, 2022 increased by 1.7 Bcf from the prior year's quarter ended June 30, 2021.

For the nine months ended June 30, 2022, transportation volume increased by 15.3 Bcf from the prior year's

nine-month period ended June 30, 2021.

The increase in transportation volume for both the quarter and nine months ended June 30, 2022 primarily reflects an increase in volume from the FM100 Project, which was brought online in December 2021, as well as an increase in short-term contracts.

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

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 June 30, 2022 were $26.6 million, an increase of $4.7 million when compared with earnings of $21.9 million for the quarter ended June 30, 2021.

The increase in earnings was primarily due to the earnings impact of higher operating revenues of $9.1 million, as discussed above.

These earnings increases were partially offset by an increase in operating expenses ($3.7 million) and an increase in depreciation expense ($1.2 million).

The increase in operating expenses was primarily due to a decrease in the reserve for preliminary project costs recorded in the quarter ended March 31, 2021 that did not recur this fiscal year, as well as higher pipeline integrity costs and vehicle fuel costs.

These earnings increases were partially offset by an increases in operating expenses ($1.4 million), depreciation expense ($1.4 million), and income tax expense ($0.7 million).

The increase in operating expenses was primarily due to higher personnel costs, vehicle fuel costs and compressor station maintenance costs.

This was partially offset by lower power costs related to Empire's electric motor drive compressor station.

The Pipeline and Storage segment also experienced higher purchased gas costs ($0.6 million), largely related to Empire's natural gas driven compressor stations.

The electric power costs and purchased gas costs are offset by an equal amount of revenue, as discussed above.

The increase in depreciation expense was primarily due to incremental depreciation from Supply's FM100 Project going into service in December 2021.

The Pipeline and Storage segment’s earnings for the six months ended March 31, 2022 were $50.6 million, an increase of $1.5 million when compared with earnings of $49.1 million for the six months ended March 31, 2021.

The electric power costs are offset by an equal amount of revenue, as discussed above.

The increase in depreciation expense was primarily due to incremental depreciation from Supply Corporation's FM100 Project going into service in December 2021.

The increase in income tax expense was mainly attributable to higher state income taxes due to higher pre-tax earnings.

The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2022 were $77.2 million, an increase of $6.1 million when compared with earnings of $71.1 million for the nine months ended June 30, 2021.

The increase in earnings was primarily due to the earnings impact of higher operating revenues of $16.4 million, as discussed above, combined with an increase in other income ($0.7 million).

The increase in other income was mainly due to higher non-service pension and post-retirement benefit income and an increase in allowance for funds used during construction (equity component) related to the construction of the FM100 Project.

These earnings increases were partially offset by an increase in operating expenses ($4.5 million) and an increase in depreciation expense ($1.5 million).

The increase in operating expenses was primarily due to a decrease in the reserve for preliminary project costs recorded in the six months ended March 31, 2021 that did not recur this fiscal year, as well as an increase in vehicle fuel costs and utilities expenses.

The increase in other income was mainly due to higher non-service pension and post-retirement benefit income partially offset by a decrease in the allowance for funds used during construction (equity component) as a result of the FM100 Project being placed in service in December 2021.

These earnings increases were partially offset by increases in operating expenses ($5.9 million), depreciation expense ($2.9 million) and property taxes ($0.8 million).

The increase in operating expenses was primarily due to a decrease in the reserve for preliminary project costs recorded during the nine months ended June 30, 2021 that did not recur this fiscal year, as well as an increase in personnel costs and vehicle fuel costs.

This was partially offset by lower power costs related to Empire's electric motor driven compressor station.

The Pipeline and Storage segment also experienced higher purchased gas costs ($0.9 million), largely related to Empire's natural gas-driven compressor stations.

Purchased gas costs are offset by an equal amount of revenue, as discussed above.

The increase in depreciation expense was primarily due to incremental depreciation from Supply's FM100 Project going into service in December 2021.

The electric power costs and purchased gas costs are offset by an equal amount of revenue, as discussed above.

The increase in depreciation expense was primarily due to incremental depreciation from the FM100 Project going into service in December 2021.

The increase in property taxes was primarily due to school taxes related to the Empire North project's Farmington compressor station that were assessed since the project went into service.

Gathering Operating Revenues

Three Months Ended

March 31, Six Months Ended

June 30, Nine Months Ended

(Thousands) 2022 2021 Increase

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Three Months Ended

March 31, Six Months Ended

June 30, Nine Months Ended

2022 2021 Increase

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2022 Compared with 2021

Operating revenues for the Ga thering segment increased $2.3 million for the quarter ended March 31, 2022 as compared with the quarter ended March 31, 2021, which was driven primarily by an 8.6 Bcf increase in gathered volume.

The increase in gathered volume can be attributed primarily to an increase in non-affiliated natural gas production on the Trout Run gathering system in the Appalachian region.

Operating revenue s for the Gathering segment increased $7.6 million for the six months ended March 31, 2022 as compared with the six months ended March 31, 2021, which was driven primarily by a 21.4 Bcf increase in gathered volume.

Contributors to the increase included the Trout Run, Clermont and Wellsboro gathering systems, which recorded increases of 13.7 Bcf, 7.3 Bcf and 4.8 Bcf, respectively, partially offset by the Covington gathering system, which recorded a decrease of 4.4 Bcf.

The net increase in gathered volume can be attributed primarily to an increase in non-affiliated natural gas production

on the Trout Run gathering system in the Appalachian region and, to a lesser extent, an increase in Seneca's gross natural gas production in the Appalachian region.

The Gathering segment’s earnings for the quarter ended March 31, 2022 were $22.1 million, an increase of $1.4 million when compared with earnings of $20.7 million for the quarter ended March 31, 2021.

Operating revenues for the Ga thering segment increased $7.3 million for the quarter ended June 30, 2022 as compared with the quarter ended June 30, 2021, which was driven primarily by an 18.0 Bcf increase in gathered volume.

The increase in gathered volume can be attributed primarily to an increase in natural gas production on the Covington, Wellsboro, Trout Run and Clermont gathering systems, which recorded increases of 10.7 Bcf, 3.6 Bcf, 2.3 Bcf and 1.4 Bcf, respectively.

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 segment increased $14.8 million for the nine months ended June 30, 2022 as compared with the nine months ended June 30, 2021, which was driven primarily by a 39.3 Bcf increase in gathered volume.

Contributors to the increase included the Trout Run, Clermont, Wellsboro and Covington gathering systems, which recorded increases of 16.0 Bcf, 8.7 Bcf, 8.3 Bcf and 6.3 Bcf, respectively.

The 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.

The Gathering segment’s earnings for the quarter ended June 30, 2022 were $24.7 million, an increase of $4.3 million when compared with earnings of $20.4 million for the quarter ended June 30, 2021.

The increase in earnings was mainly due to higher gathering revenues ($5.7 million) driven by the increase in gathered volume, as discussed above.

Additionally, the Gathering segment's earnings were positively impacted as a result of the Gathering segment's recognition of a loss during the quarter end March 31, 2021 ($0.7 million) for its share of the premium paid by the Company to redeem $500 million of the Company's 4.90% notes that were scheduled to mature in December 2021.

These earnings increases were partially offset by higher operating expenses ($0.6 million) and higher income tax expense ($0.5 million).

The increase in operating expenses was largely attributable to higher outside services costs associated with preventative maintenance overhauls on the Trout Run and Clermont gathering systems.

The Gathering segment’s earnings for the six months ended March 31, 2022 were $45.2 million, an increase of $3.9 million when compared with earnings of $41.3 million for the six months ended March 31, 2021.

This increase was partially offset by higher operating expenses ($0.8 million) and income tax expense ($ 0.3 million).

The increase in operating expenses was largely attributable to higher labor and costs for materials, as well as higher outside service costs associated with preventative maintenance overhauls on the Clermont gathering system.

The Gathering segment’s earnings for the nine months ended June 30, 2022 were $69.9 million, an increase of $8.2 million when compared with earnings of $61.7 million for the nine months ended June 30, 2021.

The increase in earnings was mainly due to higher gathering revenues ($11.7 million) driven by the increase in gathered volume, as discussed above.

Earnings also decreased due to higher operating expenses ($1.3 million), higher depreciation expense ($0.6 million) and higher income tax expense ($0.7 million).

The increase in operating expenses was largely attributable to higher outside services costs associated with preventative maintenance overhauls on the Trout Run and Clermont gathering systems.

The increases were partially offset by higher operating expenses ($2.2 million), depreciation expense ($1.0 million) and income tax expense ($1.0 million).

The increase in operating expenses was largely attributable to higher labor costs combined with higher outside service costs associated with preventative maintenance overhauls on the Trout Run and Clermont gathering systems.

The increase in depreciation expense was largely due to higher plant balances associated with the Clermont gathering system.

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Three Months Ended

March 31, Six Months Ended

June 30, Nine Months Ended

(Thousands) 2022 2021 Increase

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Three Months Ended

March 31, Six Months Ended

June 30, Nine Months Ended

(MMcf) 2022 2021 Increase

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24,865 24,508 357 125,582 121,703 3,879

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

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

Normal 2022 2021 Normal (1)

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Erie, PA 871 741 741 (14.9) % — %

Six Months Ended March 31,

Nine Months Ended June 30,

Buffalo, NY 6,455 5,662 5,693 (12.3) % (0.5) %

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2022 Compared with 2021

Operating revenues for the Utility segme n t increased $98.3 million for the quarter ended March 31, 2022 as compared with the quarter ended March 31, 2021.

The increase resulted from a $96.2 million increase in retail gas sales revenue, which was primarily due to a significant increase in the cost of gas sold (per Mcf) coupled with higher throughput due to colder weather.

Operating revenues for the Utility segme n t increased $52.9 million for the quarter ended June 30, 2022 as compared with the quarter ended June 30, 2021.

The increase resulted from a $50.9 million increase in retail gas sales revenue, which was primarily due to a significant increase in the cost of gas sold (per Mcf).

Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is not allowed to profit from fluctuations in gas costs.

In addition, there was a $1.3 million increase in transportation revenues and a $0.7 million increase in other revenues.

The increase in transportation revenues was largely the result of a 1.2 Bcf increase in transportation throughput due to colder weather.

The increase in other revenues was mainly the result of higher late payment charges billed to customers and higher capacity release revenues, partially offset by a larger estimated refund provision for the income tax benefits resulting from the 2017 Tax Reform Act.

Operating revenues for the Utility segment increased $146.1 million for the six months ended March 31, 2022 as compared with the six months ended March 31, 2021.

The increase largely resulted from a $145.4 million increase in retail gas sales revenue and a $0.7 million increase in transportation revenues.

The increase in retail gas sales revenue was primarily due to a significant increase in the cost of gas sold (per Mcf).

The increase in transportation revenues was largely due to 0.8 Bcf increase in transportation throughput during the six months ended March 31, 2022.

The Utility segment’s earnings for the quarter ended March 31, 2022 were $53.0 million, an increase of $21.0 million when compared with earnings of $32.0 million for the quarter ended March 31, 2021.

In February 2022, the PaPUC concluded a regulatory proceeding that addressed Distribution Corporation's recovery of other post-employment benefit ("OPEB") expenses.

As a result of that proceeding, Distribution Corporation recorded an adjustment to an OPEB-related regulatory liability that increased earnings ($14.6 million) and agreed to reduce its base rates in Pennsylvania to eliminate the recovery of OPEB expenses effective October 1, 2021, which reduced earnings for the quarter ($3.1 million).

Additional details related to the regulatory proceeding are discussed in the Rate Matters section and in Item 1 at Note 11 – Regulatory Matters.

With the elimination of OPEB expenses in customer rates, earnings benefited from a decrease in non-service post-retirement benefit costs ($5.2 million) as Distribution Corporation's Pennsylvania service territory recognized OPEB income during the quarter ended March 31, 2022 compared to the prior year period when it recognized OPEB expenses to match against the OPEB amounts collected in base rates.

Higher usage and the impact of weather on customer margins ($3.0 million), as well as the impact of a system modernization tracker in New York ($1.6 million), also contributed to the increase in earnings when comparing the quarter ended March 31, 2022 to the quarter ended March 31, 2021.

These increases were partially offset by higher income tax expense ($1.2 million), which was primarily attributable to state income taxes.

The increase in transportation revenues, despite a 0.4 Bcf decrease in transportation throughput, is mainly due to an increase in the system modernization tracker allocation to transportation customers.

The increase in other revenues was mainly the result of higher late payment charges billed to customers.

Operating revenues for the Utility segment increased $199.0 million for the nine months ended June 30, 2022 as compared with the nine months ended June 30, 2021.

The increase largely resulted from a $196.3 million increase in retail gas sales revenue, which was primarily due to a significant increase in the cost of gas sold (per Mcf).

In addition, there was a $2.1 million increase in transportation revenues and a $0.7 million increase in other revenues.

The increase in transportation revenues was largely due to an increase in the system modernization tracker allocation to transportation customers as well as a 0.5 Bcf increase in transportation throughput due to slightly colder weather during the nine months ended June 30, 2022.

The increase in other revenues was largely due to higher late payment charges billed to customers and higher capacity release revenues.

The Utility segment’s earnings for the quarter ended June 30, 2022 were $4.6 million, a decrease of $0.2 million when compared with earnings of $4.8 million for the quarter ended June 30, 2021.

The decrease in earnings was mainly attributable to higher operating expenses ($2.6 million) due to higher personnel costs, largely offset by the impact of a system modernization tracker in New York ($1.3 million).

In addition, the net effect of changes resulting from the conclusion of a regulatory proceeding by the PaPUC in February 2022, resulted in a decrease to base rates related to the elimination of OPEB expenses in Pennsylvania ($1.1 million), which was more than offset by a decrease in non-service post-retirement benefit costs ($2.6 million) as Distribution Corporation's Pennsylvania service territory recognized OPEB income during the quarter ended June 30, 2022, compared to the prior year when it recognized OPEB expenses to match against the OPEB amounts collected in base rates.

The impact of weather variations on earnings in the Utility segment's New York rate jurisdiction is mitigated by that jurisdiction's weather normalization clause (WNC).

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

For the quarter ended March 31, 2022, the WNC increased earnings by approximately $1.5 million, as the weather was warmer than normal.

For the quarter ended March 31, 2021, the WNC increased earnings by approximately $1.6 million, as the weather was warmer than normal.

The Utility segment’s earnings for the six months ended March 31, 2022 were $75.2 million, an increase of $20.1 million when compared with earnings of $55.1 million for the six months ended March 31, 2021.

The increase is primarily

attributable to conclusion of the regulatory proceeding in Pennsylvania, as discussed above, which resulted in a reduction in a regulatory liability that increased earnings ($14.6 million).

The regulatory proceeding also reduced base rates in Pennsylvania, which reduced earnings for the six-month period ($4.8 million).

With the elimination of OPEB expenses in customer rates, earnings benefited from a decrease in non-service post-retirement benefit costs ($6.9 million) as Distribution Corporation's Pennsylvania service territory recognized OPEB income during the six months ended March 31, 2022 compared to the prior year period when it recognized OPEB expenses to match against the OPEB amounts collected in base rates.

Higher usage and the impact of weather on customer margins ($3.0 million), the impact of a system modernization tracker in New York ($2.4 million), and lower income tax expense ($0.9 million) also contributed to the increase in earnings when comparing the six months ended March 31, 2022 to the six months ended March 31, 2021.

For the quarter ended June 30, 2022, the WNC increased earnings by approximately $0.6 million, as the weather was warmer than normal.

For the quarter ended June 30, 2021, the WNC increased earnings by approximately $1.3 million, as the weather was warmer than normal.

The Utility segment’s earnings for the nine months ended June 30, 2022 were $79.8 million, an increase of $19.9 million when compared with earnings of $59.9 million for the nine months ended June 30, 2021.

The increase is primarily attributable to the conclusion of the regulatory proceeding by the PaPUC in February 2022, which resulted in a reduction in an OPEB-related regulatory liability that increased earnings ($14.6 million).

The regulatory proceeding also reduced base rates in Pennsylvania, which reduced earnings for the nine-month period ($5.9 million).

With the elimination of OPEB expenses in customer rates, earnings benefited from a decrease in non-service post-retirement benefit costs ($10.3 million) as Distribution Corporation's Pennsylvania service territory recognized OPEB income during the nine months ended June 30, 2022 compared to the prior year period when it recognized OPEB expenses to match against the OPEB amounts collected in base rates.

Additional details related to the regulatory proceeding are discussed in the Rate Matters section below and in Item 1 at Note 11 – Regulatory Matters.

The impact of a system modernization tracker in New York ($3.7 million) and higher usage and the impact of weather on customer margins ($3.2 million) also contributed to the increase in earnings when comparing the nine months ended June 30, 2022 to the nine months ended June 30, 2021.

These increases were partially offset by higher operating expenses ($4.5 million), which were primarily the result of higher personnel costs partially offset by a decrease in the allowance for uncollectible accounts, and the impact of regulatory true-up adjustments ($1.0 million).

The decrease in the allowance for uncollectible accounts is related to the COVID-19 pandemic as the Company recorded incremental expense due to the potential for customer non-payment, given the economic environment, during 2021.

For the six months ended March 31, 2022 , the WNC increased earnings by approximately $4.1 million, as the weather was warmer than normal.

For the six months ended March 31, 2021, the WNC increased earnings by approximately $3.2 million, as the weather was warmer than normal.

For the nine months ended June 30, 2022 , the WNC increased earnings by approximately $4.8 million, as the weather was warmer than normal.

For the nine months ended June 30, 2021, the WNC increased earnings by approximately $4.5 million, as the weather was warmer than normal.

Corporate and All Other

2022 Compared with 2021

Corporate and All Other operations had a loss of $4.4 million for the quarter ended March 31, 2022, which was $2.3 million higher than the loss of $2.1 million for the quarter ended March 31, 2021.

The increase in loss for the quarter is primarily attributable to changes in unrealized gains and losses on investments in equity securities.

During the quarter ended March 31, 2021, the Company recorded unrealized gains of $0.7 million.

During the quarter ended March 31, 2022, the Company recorded unrealized losses of $1.7 million.

For the six months ended March 31, 2022 , Corporate and All Other operations had a loss of $4.8 million, a decrease of $42.4 million when compared with earnings of $37.6 million for the six months ended March 31, 2021 .

The decrease in earnings was primarily attributable to the non-recurrence of a $51.1 million gain ($37.0 million gain after-tax) on sale of timber properties recorded by Seneca’s Northeast Division during the six months ended March 31, 2021.

The decrease can also be attributed to changes in unrealized losses on investments in equity securities.

During the six months ended March 31, 2021, the Company recorded unrealized losses of $0.4 million.

During the six months ended March 31, 2022, the Company recorded unrealized losses of $5.3 million .

Corporate and All Other operations had a loss of $4.2 million for the quarter ended June 30, 2022, a decrease of $4.4 million when compared with earnings of $0.2 million for the quarter ended June 30, 2021.

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

During the quarter ended June 30, 2022, the Company recorded unrealized losses of $2.7 million.

During the quarter ended June 30, 2021, the Company recorded unrealized gains of $0.8 million.

For the nine months ended June 30, 2022 , Corporate and All Other operations had a loss of $9.0 million, a decrease of $46.8 million when compared with earnings of $37.8 million for the nine months ended June 30, 2021 .

The decrease can also be attributed to unrealized losses on investments in equity securities of $8.0 million during the nine months ended June 30, 2022 compared to unrealized gains on investments in equity securities of $0.5 million during the nine months ended June 30, 2021.

Other Income (Deductions)

Net other income on the Consolidated Statement of Income was $10.0 million for the quarter ended March 31, 2022, compared to net other deductions of $10.9 million for the quarter ended March 31, 2021.

This change is primarily attributable to non-service pension and post-retirement benefit income of $12.5 million for the quarter ended March 31, 2022 compared to non-service pension and post-retirement benefit costs of $13.4 million for the quarter ended March 31, 2021.

Net other deductions on the Consolidated Statement of Income was $5.6 million for the quarter ended June 30, 2022, compared to net other deductions of $2.0 million for the quarter ended June 30, 2021.

This change is primarily attributable to changes in unrealized gains and losses on investments in equity securities.

During the quarter ended June 30, 2022, the Company recorded pre-tax unrealized losses of $3.9 million.

During the quarter ended June 30, 2021, the Company recorded pre-tax unrealized gains of $1.1 million and pre-tax realized gains of $0.7 million.

Other income (deductions) was also impacted by the change in cash surrender value of life insurance policies, with the change in value for the quarter ended June 30, 2022 decreasing $0.7 million from the change in value for the quarter ended June 30, 2021, as well as a decrease in allowance for funds used during construction (equity component) of $1.2 million.

This was partially offset by a decrease in

non-service pension and post-retirement benefit costs of $3.7 million for the quarter ended June 30, 2022 compared to the quarter ended June 30, 2021.

As discussed above in the Utility, this is largely related to the February 2022 conclusion of the regulatory proceeding in Distribution Corporation's Pennsylvania service territory that addressed Distribution Corporation's recovery of OPEB expenses.

This was partially offset by changes in unrealized gains and losses on investments in equity securities.

During the quarter ended March 31, 2022, the Company recorded pre-tax unrealized losses of $2.8 million.

During the quarter ended March 31, 2021, the Company recorded pre-tax unrealized gains of $0.6 million.

Other income (deductions) was also impacted by the change in cash surrender value of life insurance policies, with the change in value for the quarter ended March 31, 2022 decreasing $1.2 million from the change in value for the quarter ended March 31, 2021.

Net other income on the Consolidated Statement of Income was $8.9 million for the six months ended March 31, 2022, compared to net other deductions of $13.1 million for the six months ended March 31, 2021.

This change is primarily attributable to non-service pension and post-retirement benefit income of $7.7 million for the six months ended March 31, 2022 compared to non-service pension and post-retirement benefit costs of $21.2 million for the six months ended March 31, 2021.

Net other income on the Consolidated Statement of Income was $3.3 million for the nine months ended June 30, 2022, compared to net other deductions of $15.1 million for the nine months ended June 30, 2021.

This change is primarily attributable to non-service pension and post-retirement benefit income of $4.5 million for the nine months ended June 30, 2022 compared to non-service pension and post-retirement benefit costs of $28.1 million for the nine months ended June 30, 2021.

This is largely related to the February 2022 conclusion of a regulatory proceeding, as discussed in the previous paragraph.

This was partially offset by changes in realized and unrealized gains and losses on investments in equity securities.

During the six months ended March 31, 2022, the Company recorded pre-tax realized gains of $4.4 million and pre-tax unrealized losses of

$8.0 million.

During the six months ended March 31, 2021, the Company recorded pre-tax realized gains of $3.3 million and pre-tax unrealized losses of $0.5 million.

Other income (deductions) was also impacted by the change in cash surrender value of life insurance policies, with the change in value for the six months ended March 31, 2022 decreasing $0.8 million from the change in value for the six months ended March 31, 2021.

During the nine months ended June 30, 2022, the Company recorded pre-tax realized gains of $4.4 million and pre-tax unrealized losses of $11.8 million.

During the nine months ended June 30, 2021, the Company recorded pre-tax realized gains of $4.0 million and pre-tax unrealized gains of $0.6 million.

Other income (deductions) was also impacted by the change in cash surrender value of life insurance policies, with the change in value for the nine months ended June 30, 2022 decreasing $1.6 million from the change in value for the nine months ended June 30, 2021, as well as a decrease in allowance for funds used during construction (equity component) of $0.6 million.

Interest Expense on Long-Term Debt

Interest expense on long-term debt on the Consolidated Statement of Income decreased $18.7 million for the quarter ended March 31, 2022 as compared to the quarter ended March 31, 2021.

For the six months ended March 31, 2022, interest expense on long-term debt decreased $20.9 million as compared with the six months ended March 31, 2021.

Interest expense on long-term debt on the Consolidated Statement of Income was relatively flat for the quarter ended June 30, 2022 as compared to the quarter ended June 30, 2021.

For the nine months ended June 30, 2022, interest expense on long-term debt decreased $21.0 million as compared with the nine months ended June 30, 2021.

The Company redeemed $500.0 million of 4.90% notes in March 2021 and paid an early redemption premium of $15.7 million that was recorded as interest expense on long-term debt.

1 unchanged sentence

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary sources of cash during the six-month period ended March 31, 2022 consisted of cash provided by operating activities, net proceeds from short-term borrowings, proceeds from the sale of a fixed income mutual fund in a grantor trust and net proceeds from the sale of oil and gas properties.

The Company’s primary sources of cash during the six-month period ended March 31, 2021 consisted of cash provided by operating activities, net proceeds from the sale of timber properties and net proceeds from the issuance of long-term debt.

The Company expects to have adequate amounts of cash to meet both its short-term and long-term cash requirements.

During the remainder of 2022, cash provided by operating activities is expected to increase over the amount of cash provided by operating activities when compared to the same period in 2021 and will be used to meet the Company's capital expenditures, with any remaining cash being used to meet the Company's dividend requirements and/or reduce short-term borrowings.

The Company’s primary sources of cash during the nine-month period ended June 30, 2022 consisted of cash provided by operating activities, net proceeds from short-term borrowings, proceeds from the sale of a fixed income mutual fund in a grantor trust and net proceeds from the sale of oil and gas producing properties.

The Company’s primary sources of cash during the nine-month period ended June 30, 2021 consisted of cash provided by operating activities, net proceeds from the sale of timber properties and net proceeds from the issuance of long-term debt.

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 2022, cash provided by operating activities is expected to increase over the amount of cash provided by operating activities when compared to the same period in 2021 and, when combined with cash on hand, will be used to fund the Company's capital expenditures.

There are no scheduled repayments of long-term debt in the remainder of 2022.

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In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow.

The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.

The impact of weather on cash flow is tempered in

the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.

Because of the seasonal nature of the heating business in the Utility segment, revenues in this business are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the receivable balances at September 30.

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

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

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 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 $425.6 million for the six months ended March 31, 2022, an increase of $8.5 million compared with $417.1 million provided by operating activities for the six months ended March 31, 2021.

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

The increase in the Exploration and Production segment was primarily due to higher cash receipts from natural gas production.

Net cash provided by operating activities totaled $654.0 million for the nine months ended June 30, 2022, a decrease of $17.8 million compared with $671.8 million provided by operating activities for the nine months ended June 30, 2021.

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

The decrease in the Utility segment is primarily due to lower rates in the Utility segment's Pennsylvania service territory that went into effect October 1, 2021 combined with the timing of gas cost recovery, timing of gas receivables and other regulatory true-ups.

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Please refer to the Rate Matters section that follows for additional discussion of this matter.

The increase in Exploration and Production segment and the Gathering segment was primarily due to higher cash receipts from natural gas production and gathering services in the Appalachian region.

Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $376.2 million during the six months ended March 31, 2022 and $322.4 million during the six months ended March 31, 2021.

The Company’s expenditures for long-lived assets totaled $564.2 million during the nine months ended June 30, 2022 and $509.7 million during the nine months ended June 30, 2021.

The table below presents these expenditures:

Total Expenditures for Long-Lived Assets

Six Months Ended March 31, 2022 2021 Increase (Decrease)

Nine Months Ended June 30, 2022 2021 Increase (Decrease)

Exploration and Production:

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$ 564.2 $ 509.7 $ 54.5

(1) At March 31, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $52.5 million, $3.5 million, $3.4 million and $4.1 million, respectively, of non-cash capital expenditures.

At September 30, 2021, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $47.9 million, $39.4 million, $4.8 million and $10.6 million, respectively, of non-cash capital expenditures.

(2) At March 31, 2021, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $44.5 million, $16.0 million, $2.9 million and $4.7 million, respectively, of non-cash capital expenditures.

(1) At June 30, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $62.0 million, $5.2 million, $2.5 million and $4.7 million, respectively, of non-cash capital expenditures.

At September 30, 2021,

capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $47.9 million, $39.4 million, $4.8 million and $10.6 million, respectively, of non-cash capital expenditures.

(2) At June 30, 2021, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $49.7 million, $25.8 million, $0.9 million and $5.1 million, respectively, of non-cash capital expenditures.

At September 30, 2020, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $45.8 million, $17.3 million, $13.5 million and $10.7 million, respectively, of non-cash capital expenditures.

Exploration and Production

The Exploration and Production segment capital expenditures for the six months ended March 31, 2022 were primarily well drilling and completion expenditures and included approximately $258.8 million for the Appalachian region (including $84.8 million in the Marcellus Shale area and $166.8 million in the Utica Shale area) and $15.2 million for the West Coast region.

The Exploration and Production segment capital expenditures for the nine months ended June 30, 2022 were primarily well drilling and completion expenditures and included approximately $387.0 million for the Appalachian region (including $123.0 million in the Marcellus Shale area and $253.4 million in the Utica Shale area) and $18.7 million for the West Coast region.

These amounts included approximately $130.8 million spent to develop proved undeveloped reserves.

The Exploration and Production segment's capital expenditures for fiscal 2022 are expected to be in the range of $525 million to $550 million.

The Exploration and Production segment capital expenditures for the six months ended March 31, 2021 were primarily well drilling and completion expenditures and included approximately $167.1 million for the Appalachian region (including $58.2 million in the Marcellus Shale area and $97.7 million in the Utica Shale area) and $2.5 million for the West Coast region.

The Exploration and Production segment capital expenditures for the nine months ended June 30, 2021 were primarily well drilling and completion expenditures and included approximately $255.8 million for the Appalachian region (including $79.8 million in the Marcellus Shale area and $155.6 million in the Utica Shale area) and $8.0 million for the West Coast region.

These amounts included approximately $68.5 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2022 were primarily for expenditures related to Supply Corporation's FM100 Project ($21.0 million), which is discussed below.

In addition, the Pipeline and Storage segment capital expenditures for the six months ended March 31, 2022 included additions, improvements and replacements to this segment’s transmission and gas storage systems.

The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2021 were primarily for expenditures related to Supply Corporation's FM100 Project ($60.8 million).

In addition, the Pipeline and Storage segment capital expenditures for the six months ended March 31, 2021 included additions, improvements and replacements to this segment’s transmission and gas storage systems.

The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2022 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems.

In addition, the Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2022 included expenditures related to Supply Corporation's FM100 Project ($23.0 million), which is discussed below.

The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2021 were primarily for expenditures related to Supply Corporation's FM100 Project ($115.4 million).

In addition, the Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2021 included additions, improvements and replacements to this segment’s transmission and gas storage systems.

In light of 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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Abandonment activities on the project will continue in calendar year 2022.

As of March 31, 2022, approximately $207.1 million has been spent on the FM100 project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2022.

As of June 30, 2022, approximately $209.2 million has been spent on the FM100 project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at June 30, 2022.

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

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Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017).

Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification.

Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean

Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification.

FERC denied rehearing requests associated with its Order, and FERC's decisions were appealed.

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In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted.

The Company remains committed to the project and, on January 28, 2022, filed with FERC a request for an extension of time to construct the project.

The Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project.

The Company will update the $500 million preliminary cost estimate and expected in-service date for the project when there is further clarity on the timing of receipt of necessary regulatory approvals.

As of March 31, 2022, approximately $55.8 million has been spent on the Northern Access project, including $24.2 million that has been spent to study the project.

The remaining $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2022.

The majority of the Gathering segment capital expenditures for the six months ended March 31, 2022 included expenditures related to the continued expansion of Midstream Company's Clermont and Covington gathering systems, as discussed below.

Midstream Company spent $8.7 million and $10.6 million, respectively, during the six months ended March 31, 2022 on the development of the Clermont and Covington gathering systems.

As of June 30, 2022, approximately $55.8 million has been spent on the Northern Access project, including $24.2 million that has been spent to study the project.

The remaining $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at June 30, 2022.

The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2022 included expenditures related to the continued expansion of Midstream Company's Clermont and Covington gathering systems, as discussed below.

Midstream Company spent $13.4 million and $12.9 million, respectively, during the nine months ended June 30, 2022 on the development of the Clermont and Covington gathering systems.

These expenditures were largely attributable to the installation of new in-field gathering pipelines in the Clermont gathering system, as well as the development of new gathering facilities, including new in-field gathering pipelines and station upgrades, in the Tioga gathering system, which is part of Midstream Covington.

The majority of the Gathering segment capital expenditures for the six months ended March 31, 2021 were for the continued expansion of Midstream Company's Clermont and Wellsboro gathering systems.

Midstream Company spent $11.6 million and $3.7 million, respectively, during the six months ended March 31, 2021 on the development of the Clermont and Wellsboro gathering systems.

The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2021 were for the continued expansion of Midstream Company's Clermont and Wellsboro gathering systems.

Midstream Company spent $15.1 million and $3.7 million, respectively, during the nine months ended June 30, 2021 on the development of the Clermont and Wellsboro gathering systems.

These expenditures were largely attributable to new Clermont gathering pipelines, as well as the continued development of centralized station facilities, including increased compression horsepower at the Clermont and Wellsboro gathering systems and additional dehydration on the Clermont gathering system.

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The current system consists of one compressor station and backbone and in-field gathering pipelines.

The majority of the Utility segment capital expenditures for the six months ended March 31, 2022 and March 31, 2021 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions.

The majority of the Utility segment capital expenditures for the nine months ended June 30, 2022 and June 30, 2021 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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Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.

The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date.

The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin.

The majority of this gain related to the sale of emission allowances.

Project Funding

Over the past two years, the Company has been financing capital expenditures with cash from operations, short-term and long-term debt, common stock, and proceeds from the sale of timber properties.

During the six months ended March 31, 2022 and March 31, 2021, capital expenditures were funded with cash from operations.

During the nine months ended June 30, 2022 and June 30, 2021, capital expenditures were funded with cash from operations and short-term debt.

The Company issued long-term debt and common stock in June 2020 to help finance the acquisition of upstream assets and midstream gathering assets from Shell.

The financing of the asset acquisition from Shell was completed in December 2020 when the Company completed the sale of substantially all of its timber properties, through the completion of the Reverse 1031 Exchange discussed above.

Going forward, the Company expects to use cash on hand, cash from operations and short-term borrowings to finance capital expenditures.

Going forward, the Company expects to use cash on hand, cash from operations, short-term borrowings and proceeds from the sale of the Company's California assets to finance capital expenditures.

The level of short-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by the timing of gas cost recovery in the Utility segment.

It will also depend on natural gas and crude oil production, and the associated commodity price realizations, as well as the level of hedging collateral deposits in the Exploration and Production segment.

It will also depend on natural gas production, and the associated commodity price realizations, as well as the level of hedging collateral deposits in the Exploration and Production segment.

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

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Financing Cash Flow

Consolidated short-term debt increased $59.5 million when comparing the balance sheet at March 31, 2022 to the balance sheet at September 30, 2021.

The maximum amount of short-term debt outstanding during the six months ended March 31, 2022 was $304.7 million.

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 capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, other working capital needs and repayment of long-term debt.

Consolidated short-term debt increased $241.5 million, to a total of $400.0 million, when comparing the balance sheet at June 30, 2022 to the balance sheet at September 30, 2021.

The maximum amount of short-term debt outstanding during the nine months ended June 30, 2022 was $675.4 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 capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, other working capital needs and repayment of long-term debt.

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

For example, elevated commodity prices relative to its existing portfolio of derivative financial instruments led to the Company posting margin of $102.4 million with a number of its derivative counterparties as of March 31, 2022.

For example, elevated commodity prices relative to its existing portfolio of derivative financial instruments led to the Company posting margin of $154.5 million with a number of its derivative counterparties as of June 30, 2022.

The maximum amount of margin posted during the nine months ended June 30, 2022 was $464.2 million.

The Company's margin deposits are reflected on the balance sheet as a current asset titled Hedging Collateral Deposits.

To meet these margin requirements and other near-term cash flow needs, the Company utilized short-term debt in the form of commercial paper and borrowings under its revolving credit facility.

As of March 31, 2022, the Company had outstanding commercial paper of $68.0 million and short-term notes payable to banks of 150.0 million.

On February 28, 2022, the Company entered into a Credit Agreement (the "Credit Agreement") with a syndicate of 12 banks.

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

As of June 30, 2022, the Company had short-term notes payable to banks of $400.0 million.

The Company did not have any commercial paper outstanding at June 30, 2022.

On June 30, 2022, the Company received $240.9 million in proceeds, after customary closing adjustments, related to the sale of the Company's California assets.

Subsequent to June 30, 2022, these proceeds were used to reduce the amount of short-term notes payable to banks.

On February 28, 2022, the Company entered into 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 an initial maturity date of February 26, 2027.

On June 30, 2022, the Company entered into the 364-Day Credit Agreement with a syndicate of five banks, all of which are also lenders under the Credit Agreement.

The 364-Day Credit Agreement provides an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023.

The Company also has uncommitted lines of credit with financial institutions for general corporate purposes.

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

As a result, at March 31,

2022, $190.7 million was added back to the Company's total capitalization for purposes of the facility, and the Company’s debt to capitalization ratio, as calculated under the facility, was .58.

The constraints specified in the Credit Agreement would have permitted an additional $966.7 million in short-term and/or long-term debt to be outstanding at March 31, 2022 before the Company’s debt to capitalization ratio exceeded .65.

As a result, at June 30, 2022, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement.

On May 3, 2022, the Company entered into Amendment No.

1 to the Credit Agreement with the same 12 banks under the initial Credit Agreement.

The amendment modifies the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ending June 30, 2022, 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 balance sheet.

Under the Credit Agreement as amended, 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.

1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement.

The amendment further modifies the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ended June 30, 2022, 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 balance sheet.

Under the Credit Agreement, 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 June 30, 2022, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement, was .53.

The constraints specified in the Credit Agreement would have permitted an additional $1.99 billion in short-term and/or long-term debt to be outstanding at June 30, 2022 before the Company’s debt to capitalization ratio exceeded .65.

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

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

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

borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement.

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

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The Company redeemed those notes for $515.7 million, plus accrued interest.

The Current Portion of Long-Term Debt at March 31, 2022 consists of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes that mature in March 2023.

The Current Portion of Long-Term Debt at June 30, 2022 consists of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes that mature in March 2023.

None of the Company's long-term debt as of September 30, 2021 had a maturity date within the following twelve-month period.

The Company’s embedded cost of long-term debt was 4.48% at both March 31, 2022 and March 31, 2021.

Under the Company’s existing indenture covenants at March 31, 2022, the Company would have been permitted to issue up to a maximum of approximately $1.75 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 debt to capitalization ratio constraints under the Company’s Credit Agreement, as discussed above).

The Company’s embedded cost of long-term debt was 4.48% at both June 30, 2022 and June 30, 2021.

Under the Company’s existing indenture covenants at June 30, 2022, the Company would have been permitted to issue up to a maximum of approximately $1.89 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 debt to capitalization ratio constraints under the Company’s Credit Agreement, as discussed above).

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

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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 $99.0 million (or 3.7%) of the Company’s long-term debt (as of March 31, 2022) 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 $99.0 million (or 3.7%) of the Company’s long-term debt (as of June 30, 2022) 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 these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

During the six months ended March 31, 2022, the Company contributed $15.0 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $1.6 million to its VEBA trusts for its other post-retirement benefits.

In the remainder of 2022, the Company expects its contributions to the Retirement Plan to be in the range of $5.0 million to $10.0 million.

In the remainder of 2022, the Company expects its contributions to its VEBA trusts to be in the range of $1.0 million to $1.5 million.

The Company, in its Exploration and Production segment, entered into contractual obligations during the quarter ended March 31, 2022 to spend $43.1 million for hydraulic fracturing services and piping and casing work for fiscal 2022.

During the nine months ended June 30, 2022, the Company contributed $19.3 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $2.7 million to its VEBA trusts for its other post-retirement benefits.

In the remainder of 2022, the Company expects to contribute approximately $1.1 million to its Retirement Plan.

In the remainder of 2022, the Company expects to contribute approximately $0.2 million to its VEBA trusts.

The Company, in its Exploration and Production segment, entered into contractual obligations for the nine months ended June 30, 2022 to spend $67.3 million for hydraulic fracturing services work through June 1, 2024.

Market Risk Sensitive Instruments

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The authoritative guidance for fair value measurements and disclosures require 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, 2022, the Company determined that nonperformance risk would have no material impact on its financial position or results of operation.

At June 30, 2022, 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 extension is contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to April 1, 2023.

In response to the COVID-19 pandemic, various legislative actions and NYPSC Staff requests resulted in the Company suspending service terminations and disconnections for a period of time.

In response to the COVID-19 pandemic, various legislative actions and NYPSC Staff requests resulted in the Company suspending service terminations and disconnections.

All legislative prohibitions have expired and the Company has agreed to refrain from terminating residential customers (1) with a pending application for arrears payments through the Emergency Rental Assistance Program administered by the Office of Temporary Disability and (2) participating in the Company’s Statewide Low Income Program (EAP) through September 1, 2022.

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Accordingly, the Company suspended regulatory accounting for OPEB expenses at that time and recorded an $18.5 million adjustment during the quarter ended March 31, 2022 to reduce its regulatory liability for previously deferred OPEB income amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount.

The refunds specified in the tariff supplement will be funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company’s Consolidated Balance Sheet.

With the elimination of OPEB expenses in base rates, Distribution Corporation will no longer fund the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.

The refunds specified in the tariff supplement are being funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company’s Consolidated Balance Sheet.

With the elimination of OPEB expenses in base rates, Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.

Pipeline and Storage

Supply Corporation’s 2020 rate settlement provides that no party may make a rate filing for new rates to be effective before February 1, 2024, except that Supply Corporation may file an NGA general Section 4 rate case to change rates if the

corporate federal income tax rate is increased.

If no case has been filed, Supply Corporation must file for rates to be effective February 1, 2025.

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The Company must continue to comply with all applicable regulations.

Additionally, other federal regulatory agencies are beginning to address greenhouse gas emissions through changes in their regulatory oversight approach and policies.

Additionally, other federal regulatory agencies are beginning to address greenhouse gas emissions through changes

in their regulatory oversight approach and policies.

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

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Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines and is in the process of evaluating cap-and-trade programs (e.g., Regional Greenhouse Gas Initiative).

In California, the Company currently complies with California cap-and-trade rules, which increases the Company's cost of environmental compliance in its Exploration and Production segment.

On April 23, 2021, California's Governor issued an executive order directing California Geologic Energy Management Division to stop issuing hydraulic fracturing permits by 2024, which does not have a direct impact on the plans of the Exploration and Production segment as those plans do not involve fracking.

The executive order also directed the California Air Resources Board to investigate phasing out oil extraction by 2045, which may result in permitting delays and new legislative action in support of the directive.

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.

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

Federal, state or local governments may provide tax advantages and other subsidies to support

alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources.

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

Effects of Inflation

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

The length and severity of the ongoing COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity;

Changes in economic conditions, including inflationary pressures 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;

Changes in the price of natural gas or oil;

Changes in the price of natural gas;

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

The length and severity of the ongoing COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity;

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;

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

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

Increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, including disruptions due to the COVID-19 pandemic, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators;

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The Company's ability to successfully integrate acquired assets and achieve expected cost synergies;

Changes in price differentials between similar quantities of natural gas or oil 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;

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

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

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

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

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

Other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date;

Other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date;

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

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

Uncertainty of oil and gas reserve estimates;

Significant differences between the Company’s projected and actual production levels for natural gas or oil;

Changes in demographic patterns and weather conditions;

Uncertainty of gas reserve estimates;

Significant differences between the Company’s projected and actual production levels for natural gas;

Changes in demographic patterns and weather conditions (including those related to climate change);

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

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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