NATIONAL FUEL GAS CO

Previous wording

The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation’s system, referred to as the Tioga Pathway Project, is an expansion and modernization project that would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC (“Transco”) capacity lease, providing access to Mid-Atlantic markets. Supply Corporation filed a Section 7 (c) application with FERC for the project on August 21, 2024. The Tioga Pathway Project has a target in-service date in late calendar 2026 and a preliminary cost estimate of approximately $101 million. The Tioga Pathway Project is discussed in more detail in the Capital Resources and Liquidity section that follows.

Current wording

The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation’s system, referred to as the Tioga Pathway Project, is an expansion and modernization project that would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC (“Transco”) capacity lease, providing access to Mid-Atlantic markets. Supply Corporation filed a Section 7 (c) application with FERC for the project on August 21, 2024 and on February 13, 2025, the FERC issued the Environmental Assessment for the project. The Tioga Pathway Project has a target in-service date in late calendar 2026 and a preliminary cost estimate of approximately $101 million. The Tioga Pathway Project is discussed in more detail in the Capital Resources and Liquidity section that follows.

Previous wording

From a rate perspective, Distribution Corporation, in its New York jurisdiction, reached a settlement with the parties to its rate case proceeding. On December 19, 2024, the NYPSC issued an order approving the settlement. The settlement, effective January 1, 2025, establishes a three-year rate plan that reflects a return on equity of 9.7% and authorizes a revenue requirement increase of $57.3 million in fiscal 2025, an additional revenue requirement increase of $15.8 million in fiscal 2026, and an additional revenue requirement increase of $12.7 million in fiscal 2027. The settlement also includes standard make-whole language allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024. In addition, Supply Corporation filed an NGA Section 4 rate case at FERC on July 31, 2023. Settlement rates became effective on February 1, 2024 under a settlement that was approved by FERC without modification on June 11, 2024, and which is estimated to increase Supply Corporation’s revenues by approximately $56 million on an annual basis. For further discussion of Distribution Corporation and Supply Corporation rate matters, refer to the Rate Matters section below.

Current wording

From a rate perspective, Distribution Corporation, in its New York jurisdiction, reached a settlement with the parties to its rate case proceeding. On December 19, 2024, the NYPSC issued an order approving the settlement. The settlement, effective January 1, 2025, establishes a three-year rate plan that reflects a return on equity of 9.7% and authorizes a revenue requirement increase of $57.3 million in fiscal 2025, an additional revenue requirement increase of $15.8 million in fiscal 2026, and an additional revenue requirement increase of $12.7 million in fiscal 2027. The settlement also includes standard make-whole language allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024. In addition, on March 17, 2025, FERC approved an amendment to Empire's 2019 rate case settlement. This settlement amendment is estimated to decrease Empire's revenues on a yearly basis by approximately $0.5 million. For further discussion of Distribution Corporation and Empire rate matters, refer to the Rate Matters section below.

Previous wording

As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its exploration and production properties and that book value is subject to a quarterly ceiling test. In addition to the non-cash impairment charges under the ceiling test that the Company recorded during fiscal 2024, the Company recorded a non-cash impairment charge under the ceiling test for the quarter ended December 31, 2024 of $108.3 million ($79.1 million after-tax). Please refer to the Critical Accounting Estimates section below for a sensitivity analysis concerning commodity price changes.

Current wording

As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its exploration and production properties and that book value is subject to a quarterly ceiling test. In addition to the non-cash impairment charges under the ceiling test that the Company recorded during fiscal 2024, the Company recorded a non-cash impairment charge under the ceiling test during the quarter ended December 31, 2024 of $108.3 million ($79.1 million after-tax). At March 31, 2025, the ceiling exceeded the book value of the exploration and production properties, and thus, did not result in an impairment charge for the quarter ended March 31, 2025. Please refer to the Critical Accounting Estimates section below for more details on this matter and a sensitivity analysis concerning commodity price changes.

Previous wording

As of December 31 2024, the Company had $50.0 million in principal and $3.2 million in interest payments remaining related to long-term debt issued under the 1974 indenture. To the extent the Company wishes to relieve its obligations to comply with the 1974 indenture's restrictions, the Company expects to be able to place future principal and interest payments in trust for the benefit of bondholders pursuant to the terms of the 1974 indenture. Depositing such future principal and interest payments in trust would effectively relieve the Company from its obligations to comply with the 1974 indenture’s restrictions, including those on the issuance of incremental long-term debt.

Current wording

Prior to the long-term debt issuances discussed above, the Company placed a total of $53.2 million in trust during the quarter ended March 31, 2025 for the benefit of holders of the 7.38% notes outstanding under the Company’s 1974 indenture. This included $50.0 million in principal and $3.2 million in interest related to long-term debt issued in June 1995 under the 1974 indenture, with a maturity date of June 13, 2025. Placing these funds in trust, in an amount equal to the future principal and interest payments due on the 7.38% notes, enabled the Company to cancel and discharge the 1974 indenture, effectively relieving the Company from its obligations to comply with the 1974 indenture’s covenants. For further discussion of this matter, refer to the Capital Resources and Liquidity section below.

Previous wording

In February 2024, eleven lenders in the syndicate of twelve banks under the Credit Agreement consented to a one-year extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. In May 2024, three of the lenders in the syndicate assumed the commitments of the sole non-extending lender. In January 2025, the Company and the eleven banks in the syndicate consented to a second one-year extension on the maturity date from February 25, 2028 to February 23, 2029, such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion through February 23, 2029.

Current wording

The Company is a party to a syndicated Credit Agreement that provides a $1.0 billion unsecured committed revolving credit facility. In January 2025, the Company and the eleven banks in the syndicate of banks under the Credit Agreement consented to a second one-year extension on the maturity date of the Credit Agreement, such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion through February 23, 2029.

Previous wording

The Company began repurchasing outstanding shares of its common stock during the quarter ended March 31, 2024 under a share repurchase program authorized by the Company’s Board of Directors. The program authorizes the Company to repurchase up to an aggregate amount of $200 million of its outstanding common stock in the open market or through privately negotiated transactions. During the quarter ended December 31, 2024, the Company executed transactions to repurchase 548,596 shares at an average price of $61.27 per share. With broker fees and excise taxes, the total cost of these repurchases amounted to $33.9 million. As of December 31, 2024, the Company has repurchased 1,694,855 shares under the share repurchase program at an average price of $57.93, for a total cost of $99.1 million (including broker fees and excise taxes). These matters are discussed further in the Capital Resources and Liquidity section that follows.

Current wording

The Company began repurchasing outstanding shares of its common stock during the quarter ended March 31, 2024 under a share repurchase program authorized by the Company’s Board of Directors. The program authorizes the Company to repurchase up to an aggregate amount of $200 million of its outstanding common stock in the open market or through privately negotiated transactions. Given the recent macroeconomic uncertainty, as well as increased volatility in the natural gas market, the Company has slowed its pace of repurchases. During the six months ended March 31, 2025, the Company executed transactions to repurchase 774,768 shares at an average price of $63.74 per share, for a total cost of $49.8 million (including broker fees and excise taxes). As of March 31, 2025, the Company has repurchased 1,921,027 shares under the share repurchase program at an average price of $59.32, for a total cost of $115.0 million (including broker fees and excise taxes). These matters are discussed further in the Capital Resources and Liquidity section that follows.

Previous wording

The Company expects to use cash on hand, cash from operations, and short-term and long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2025, including the redemption of two of the Company’s long-term debt maturities totaling $500.0 million that are scheduled to mature in 2025. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures, volatile interest rates and a change in administration at the federal level, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs.

Current wording

The Company expects to use cash on hand, cash from operations, and short-term and long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2025. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures, volatile interest rates and the ongoing impacts of federal policy changes, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs.

Previous wording

Exploration and Development Costs. The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its exploration and production properties, with natural gas properties in the Appalachian Region being the primary component after the fiscal 2022 sale of the Company's California exploration and production properties. In accordance with the full cost methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company's exploration and production reserves based on an unweighted arithmetic average of first day of the month commodity prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s exploration and production properties at the balance sheet date. The present value of future revenues is calculated using a 10% discount factor. If the book value of the exploration and production properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of such properties to the calculated ceiling. The book value of the exploration and production properties exceeded the ceiling at December 31, 2024, resulting in a non-cash impairment charge of $108.3 million ($79.1 million after-tax) for the quarter ended December 31, 2024. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended December 31, 2024, based on the quoted Henry Hub spot price for natural gas, was $2.13 per MMBtu. (Note: Because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for the twelve months ended December 31, 2024. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the additional impairment that the Company would have recorded at December 31, 2024 if natural gas prices were $0.25 per MMBtu lower than the average prices used at December 31, 2024 (all amounts are presented after-tax). These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

Current wording

Exploration and Development Costs. The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its exploration and production properties, with natural gas properties in the Appalachian Region being the primary component after the fiscal 2022 sale of the Company's California exploration and production properties. In accordance with the full cost methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company's exploration and production reserves based on an unweighted arithmetic average of first day of the month commodity prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s exploration and production properties at the balance sheet date. The present value of future revenues is calculated using a 10% discount factor. If the book value of the exploration and production properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of such properties to the calculated ceiling. At March 31, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $395.5 million. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended March 31, 2025, based on the quoted Henry Hub spot price for natural gas, was $2.44 per MMBtu. (Note: Because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for the twelve months ended March 31, 2025. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices in the twelve-month period used at March 31, 2025 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's exploration and production properties by approximately $16.4 million (after-tax), which would not have resulted in an impairment charge. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

Previous wording

The Company's earnings were $45.0 million for the quarter ended December 31, 2024 compared to earnings of $133.0 million for the quarter ended December 31, 2023. The decrease in earnings of $88.0 million is primarily the result of a loss recognized in the Exploration and Production segment. Lower earnings in the Gathering Segment and losses in the Corporate and All Other categories also contributed to the decrease. Higher earnings in the Pipeline and Storage segment and Utility segment partially offset these decreases.

Current wording

The Company's earnings were $216.4 million for the quarter ended March 31, 2025 compared to earnings of $166.3 million for the quarter ended March 31, 2024. The increase in earnings of $50.1 million is primarily the result of higher earnings in the Exploration and Production segment and Utility segment, as well as the Pipeline and Storage segment. Lower earnings in the Gathering segment and losses in the Corporate and All Other categories partially offset these increases.

Previous wording

The Company's earnings for the quarter ended December 31, 2024 included non-cash impairment charges of $141.8 million ($103.6 million after-tax) in the Exploration and Production segment, consisting mostly of ceiling test impairment charges of $108.3 million ($79.1 million after-tax), as discussed above. The remaining charges are related to the impairment of certain water disposal assets. Note that all amounts used in earnings discussions are after-tax amounts, unless otherwise noted.

Current wording

The Company's earnings for the six months ended March 31, 2025 included non-cash impairment charges of $141.8 million ($103.6 million after-tax) in the Exploration and Production segment, consisting mostly of ceiling test impairment charges of $108.3 million ($79.1 million after-tax), as discussed above. The remaining charges are related to the impairment of certain water disposal assets. Note that all amounts used in earnings discussions are after-tax amounts, unless otherwise noted.

Previous wording

Operating revenues for the Exploration and Production segment decreased $5.2 million for the quarter ended December 31, 2024 as compared with the quarter ended December 31, 2023. Gas production revenue after hedging decreased $5.2 million due to the impact of a 3.0 Bcf decrease in natural gas production partially offset by a $0.02 per Mcf increase in the weighted average price of natural gas after hedging. The decrease in natural gas production was largely due to lower production in the Marcellus and Utica wells in the Appalachian region.

Current wording

Operating revenues for the Exploration and Production segment increased $47.3 million for the quarter ended March 31, 2025 as compared with the quarter ended March 31, 2024. Gas production revenue after hedging increased $47.2 million due to the impact of a 2.6 Bcf increase in natural gas production combined with a $0.38 per Mcf increase in the weighted average price of natural gas after hedging. The increase in natural gas production was largely due to pads recently turned in line in the Appalachian region.

Previous wording

The Exploration and Production segment's loss for the quarter ended December 31, 2024 was $46.8 million, a decrease of $99.3 million when compared with earnings of $52.5 million for the quarter ended December 31, 2023. This decrease can be primarily attributed to non-cash impairments of assets ($103.6 million), including ceiling test impairments of $79.1 million and a $24.5 million impairment of certain water disposal assets recorded during the quarter ended December 31, 2024, as well as lower natural gas production ($6.0 million). In conjunction with the ceiling test impairment, there was a $1.0 million earnings reduction associated with the remeasurement of state deferred income taxes. A decline in other income ($1.7 million) also contributed to the decrease in earnings. These decreases were partially offset by higher natural gas prices after hedging ($1.9 million), lower depletion expense ($6.8 million) and lower lease operating and transportation expenses ($1.1 million). There was also an unrealized loss recognized in the three-month period ended December 31, 2024 ($0.3 million) on contingent consideration received as part of the 2022 California asset sale, compared to an unrealized loss that was recognized in the three-month period ended December 31, 2023 ($3.0 million) on such contingent consideration. The decline in other income was mainly attributed to business interruption insurance proceeds received during the quarter ended December 31, 2023 related to a pipeline outage impacting Seneca’s ability to market gas. The decrease in depletion expense was primarily due to the net decrease in production combined with a $0.06 per Mcf decrease in the depletion rate largely due to ceiling test impairments recorded in the third and fourth quarters of fiscal 2024 that lowered Seneca’s full cost pool depletable base. The decrease in lease operating and transportation expenses was primarily the result of lower gathering and transportation costs combined with lower workover and salt water disposal expenses.

Current wording

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

Previous wording

Operating revenues for the Pipeline and Storage segment increased $12.2 million for the quarter ended December 31, 2024 as compared with the quarter ended December 31, 2023. The increase in operating revenues was primarily due to an increase in transportation revenues of $9.6 million and an increase in storage revenues of $3.7 million, partially offset by a decrease in other revenues of $1.1 million. The increase in transportation and storage revenues was primarily attributable to an increase in Supply Corporation's transportation and storage rates effective February 1, 2024, in accordance with Supply Corporation's rate case settlement. The settlement was approved by FERC on June 11, 2024. The decrease in other revenues primarily reflects lower cashout revenues, which are completely offset by purchased gas expense, and an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense.

Current wording

Operating revenues for the Pipeline and Storage segment increased $13.8 million for the six months ended March 31, 2025 as compared with the six months ended March 31, 2024. The $10.8 million increase in transportation revenues and $3.6 million increase in storage revenues was primarily attributable to an increase in Supply Corporation's transportation and storage rates effective February 1, 2024 in accordance with the aforementioned Supply Corporation rate case settlement and partially offset by the impact of a final true-up adjustment recorded in the quarter ended March 31, 2024 to the surcharge for pipeline safety and greenhouse gas costs that ended effective February 1, 2024. The increase in transportation revenues was also partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions. The $0.7 million decrease in other revenues primarily reflects lower cashout revenues, which are completely offset by purchased gas expense, and an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense, partially offset by the recognition of a gain on the sale of base gas during the quarter ended March 31, 2025.

Previous wording

Transportation volume for the quarter ended December 31, 2024 increased by 2.7 Bcf from the prior year's quarter ended December 31, 2023. The increase in transportation volume for the quarter ended December 31, 2024 is primarily due to an increase in volume from new long-term contracts combined with an increase in volume from colder weather. These were partially offset by lower capacity utilization with certain contract shippers and certain contract expirations and revisions. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

Current wording

Transportation volume for the quarter and six months ended March 31, 2025 increased by 11.7 Bcf and 14.4 Bcf, respectively, from the prior year's quarter and six month periods. The increase in transportation volume for both the quarter and six months ended March 31, 2025 is primarily due to an increase in volume from a new long-term contract combined with an increase in volume from colder weather. These were partially offset by lower capacity utilization with certain contract shippers and certain contract expirations and revisions. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

Previous wording

Gathered volume decreased 1.9 Bcf and 1.4 Bcf in the Gathering segment's eastern development areas (Trout Run and Tioga) and western development area (Clermont), respectively. The net decrease in gathered volume can be attributed to a decrease in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.

Current wording

Operating revenues for the Gathering segment increased $1.0 million for the quarter ended March 31, 2025 as compared with the quarter ended March 31, 2024, which was driven primarily by a 4.2 Bcf increase in gathered volume. Gathered volume increased 6.5 Bcf in the Gathering segment's eastern development areas (Tioga and Trout Run), partially offset by a 2.3 Bcf decrease in gathered volume in the Gathering segment's western development area (Clermont). The net increase in gathered volume can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.

Previous wording

The Gathering segment’s earnings for the quarter ended December 31, 2024 were $27.1 million, a decrease of $1.7 million when compared with earnings of $28.8 million for the quarter ended December 31, 2023. The decrease in earnings was primarily due to lower gathering revenues ($1.2 million) and higher depreciation expense ($0.8 million). The decrease in gathering revenues was driven by the decrease in gathered volume, as discussed above. The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga gathering system. These decreases in earnings were partially offset by a decrease in income tax expense ($0.4 million) due to lower state income taxes driven by lower pre-tax income and a reduction in the Pennsylvania state income tax rate.

Current wording

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

Previous wording

Operating revenues for the Utility segment increased $26.5 million for the quarter ended December 31, 2024 as compared with the quarter ended December 31, 2023. This increase resulted from a $24.2 million increase in retail gas sales revenue and a $2.5 million increase in other revenue, which were partially offset by a $0.2 million decrease in transportation revenue. The increase in retail gas sales revenue is primarily the result of the impact of new base delivery rates in Distribution Corporation's New York jurisdiction pursuant to a settlement approved by the NYPSC on December 19, 2024. Additional details regarding the base rate regulatory proceeding can be found in Note 10 - Regulatory Matters. This increase also reflects higher purchased gas revenues resulting from a 0.7 Bcf increase in throughput due to cooler temperatures combined with an increase in the cost of gas sold (per Mcf). It should be noted that under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation's earnings are not impacted by fluctuations in gas costs. Purchased gas expense recorded on the consolidated income statement matches the revenues collected from customers. The increase in other revenue was mainly due to the elimination of the refund provision that was required to defer and return the income tax benefits resulting from the 2017 Tax Reform Act to customers ($3.3 million). The refund provision is no longer necessary because Distribution Corporation's new base delivery rates now reflect a revenue requirement determined with the current federal income tax rate of 21% and the refund of excess accumulated deferred income taxes.

Current wording

Operating revenues for the Utility segment increased $53.2 million for the quarter ended March 31, 2025 as compared with the quarter ended March 31, 2024. This increase resulted from a $46.6 million increase in retail gas sales revenue, a $3.0 million increase in transportation revenue, and a $3.6 million increase in other revenue. The increases in retail gas sales and transportation revenues reflect the impact of new base delivery rates in Distribution Corporation's New York jurisdiction pursuant to a settlement approved by the NYPSC on December 19, 2024. Additional details regarding the base rate regulatory proceeding can be found in Note 10 - Regulatory Matters. The increase in retail gas sales revenue also reflects higher purchased gas revenues resulting from a 6.3 Bcf increase in throughput due to colder temperatures combined with an increase in the cost of gas sold (per Mcf). It should be noted that under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation's earnings are not impacted by fluctuations in gas costs. Purchased gas expense recorded on the consolidated income statement matches the revenues collected from customers. The increase in transportation revenue also reflects a 2.4 Bcf increase in throughput due primarily to colder temperatures. The increase in other revenue was mainly due to the elimination of the refund provision that was required to defer and return the income tax benefits resulting from the 2017 Tax Reform Act to customers ($4.8 million), partially offset by decreases in capacity release revenues ($0.6 million), other gas revenues ($0.3 million), and late payment charges billed to customers ($0.2 million). The refund provision is no longer necessary because Distribution Corporation's new base delivery rates now reflect a revenue requirement determined with the current federal income tax rate of 21% and the refund of excess accumulated deferred income taxes.

Previous wording

The impact of weather variations on cash flows and customer bills in the Utility segment is mitigated by a WNA. The WNA, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the Utility segment. In addition, in periods of colder than normal weather, the WNA benefits the Utility segment's customers. For the quarter ended December 31, 2024, the WNA preserved earnings of approximately $2.0 million and $1.2 million, respectively, in the Utility segment’s New York and Pennsylvania rate jurisdictions, as the weather was warmer than normal in both jurisdictions. For the quarter ended December 31, 2023, the WNA preserved earnings of approximately $1.4 million in the Utility segment’s New York jurisdiction and $0.5 million in the Utility segment's Pennsylvania jurisdiction, as the weather was warmer than normal.

Current wording

The impact of weather variations on cash flows and customer bills in the Utility segment is mitigated by a WNA. The WNA, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the Utility segment. In addition, in periods of colder than normal weather, the WNA benefits the Utility segment's customers. For the quarter ended March 31, 2025, the WNA preserved earnings of approximately $0.6 million in the Utility segment’s New York rate jurisdiction, as the weather was warmer than normal. The earnings preserved by the WNA in the Utility segment's Pennsylvania rate jurisdiction were negligible. For the quarter ended March 31, 2024, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $5.0 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $3.6 million, as the weather was warmer than normal in both jurisdictions.

Previous wording

Corporate and All Other operations recorded a net loss of $0.3 million for the quarter ended December 31, 2024, a decrease of $1.4 million when compared with earnings of $1.1 million for the quarter ended December 31, 2023. The decrease was primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the quarter ended December 31, 2024, the Company recorded unrealized losses of $2.1 million. During the quarter ended December 31, 2023, the Company recorded unrealized gains of $0.8 million. These changes were partially offset by realized gains from investment securities sold in the current quarter ($1.2 million). There were no realized gains or losses during the quarter ended December 31, 2023.

Current wording

For the six months ended March 31, 2025, Corporate and All Other operations recorded a net loss of $3.4 million, a decrease of $4.5 million when compared with earnings of $1.1 million for the six months ended March 31, 2024. The decrease was primarily attributable to higher interest expense ($3.2 million) mainly due to a higher average amount of long-term borrowings, combined with changes in unrealized gains and losses on investments in equity securities. During the six months ended March 31, 2025, the Company recorded unrealized losses of $2.1 million. During the six months ended March 31, 2024, the Company recorded unrealized gains of $1.4 million. These changes were partially offset by realized gains from investment securities sold during the current six-month period ($1.2 million) and an increase in interest income on temporary cash investments ($1.2 million).

Previous wording

Net other income on the Consolidated Statements of Income was $7.7 million for the quarter ended December 31, 2024, compared to net other income of $3.7 million for the quarter ended December 31, 2023, for an increase of $4.0 million. This increase can be attributed primarily to a $5.2 million increase in non-service pension and post-retirement benefit income along with a $3.8 million benefit from the quarter-over-quarter revaluation of the contingent consideration received from the 2022 California asset sale. These increases were offset by quarter-over-quarter changes in the value of investment securities. During the quarter ended December 31, 2024, there were net losses of $1.2 million on investment securities. However, during the quarter ended December 31, 2023, there were net gains of $1.3 million on investment securities. Another offsetting factor was the non-recurrence of $2.0 million of business interruption insurance proceeds received during the quarter ended December 31, 2023 related to a pipeline outage that impacted Seneca's ability to market its gas.

Current wording

Net other income on the Consolidated Statements of Income was $23.0 million for the six months ended March 31, 2025, compared to net other income of $9.8 million for the six months ended March 31, 2024, for an increase of $13.2 million. This increase can be attributed primarily to a $16.4 million increase in non-service pension and post-retirement benefit income, as discussed above, along with a $3.0 million benefit from the year-over-year revaluation of the contingent consideration received from the 2022 California asset sale. These increases were offset by year-over-year changes in the value of investment securities. During the six months ended March 31, 2025, there were net losses of $1.1 million on investment securities. However, during the six months ended March 31, 2024, there were net gains of $2.0 million on investment securities. Another offsetting factor was the non-recurrence of $2.0 million of business interruption insurance proceeds received during the six months ended March 31, 2024 related to a pipeline outage that impacted Seneca's ability to market its gas, along with a $0.5 million decrease in interest income and a $0.4 million decrease in income related to life insurance policies.

Previous wording

Interest expense on long-term debt on the Consolidated Statement of Income increased $4.9 million for the quarter ended December 31, 2024 as compared to the quarter ended December 31, 2023. In April 2024, the Company elected to draw a total of $300.0 million under a delayed draw term loan credit facility, which was the primary driver of the increase. These borrowings had a locked-in weighted average interest rate of 6.30% for the quarter ended December 31, 2024.

Current wording

Interest expense on long-term debt on the Consolidated Statement of Income increased $11.2 million for the quarter ended March 31, 2025 as compared to the quarter ended March 31, 2024. For the six months ended March 31, 2025, interest expense on long-term debt increased $16.1 million as compared with the six months ended March 31, 2024. In April 2024, the Company elected to draw a total of $300.0 million under a delayed draw term loan credit facility. These borrowings had a locked-in weighted average interest rate of 5.81% and 6.05% for the quarter and six months ended March 31, 2025, respectively. Additionally, on February 19, 2025, the Company issued $500 million of 5.50% notes and $500 million of 5.95% notes. On March 6, 2025, the Company redeemed $450 million of 5.20% notes and $500 million of 5.50% notes and paid early redemption premiums totaling $2.4 million that were recorded as interest expense on long-term debt in the Exploration and Production and Gathering segments.

Previous wording

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

Current wording

The Company’s primary source of cash during the six-month period ended March 31, 2025 consisted of cash provided by operating activities and net proceeds from short-term and long-term borrowings. The Company’s primary source of cash during the six-month period ended March 31, 2024 consisted of cash provided by operating activities.

Previous wording

The Company expects to have adequate amounts of cash available to meet both its short-term and long-term cash requirements for at least the next twelve months and for the foreseeable future thereafter. During the remainder of 2025, the Company expects to use cash provided by operating activities, as well as net proceeds from short-term and long-term borrowings, to fund the Company's capital expenditures. Looking forward to 2026, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures. The Company also has two long-term debt maturities in 2025, totaling $500.0 million, which the Company anticipates funding with long-term borrowings. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.

Current wording

The Company expects to have adequate amounts of cash available to meet both its short-term and long-term cash requirements for at least the next twelve months and for the foreseeable future thereafter. During the remainder of 2025, the Company expects to use cash provided by operating activities to fund the Company's capital expenditures. Looking forward to 2026, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures. The Company also has a delayed draw term loan that matures in February 2026, which the Company anticipates funding with cash on hand as well as short-term or long-term borrowings. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.

Previous wording

Net cash provided by operating activities totaled $220.1 million for the three months ended December 31, 2024, a decrease of $50.8 million compared with $270.9 million provided by operating activities for the three months ended December 31, 2023. The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Exploration and Production segment due to lower cash receipts from natural gas production in the Appalachian region.

Current wording

Net cash provided by operating activities totaled $473.9 million for the six months ended March 31, 2025, a decrease of $112.4 million compared with $586.3 million provided by operating activities for the six months ended March 31, 2024. The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Utility segment and Exploration and Production segment. The decrease in the Utility segment is driven by the timing of gas cost recovery, partially offset by the impact of higher revenues resulting from the base rate increase in Distribution Corporation's New York rate jurisdiction. The decrease in the Exploration and Production segment is due to the timing of cash receipts and hedge settlements from natural gas production in the Appalachian region.

Previous wording

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

Current wording

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

Previous wording

(1)At December 31, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $56.3 million, $4.4 million, $6.0 million and $4.9 million, respectively, of non-cash capital expenditures. At September 30, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $63.3 million, $14.4 million, $21.7 million and $20.6 million, respectively, of non-cash capital expenditures.

Current wording

(1)At March 31, 2025, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $44.8 million, $2.4 million, $6.8 million and $4.8 million, respectively, of non-cash capital expenditures. At September 30, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $63.3 million, $14.4 million, $21.7 million and $20.6 million, respectively, of non-cash capital expenditures.

Previous wording

(2)At December 31, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $74.9 million, $5.5 million, $11.1 million and $6.4 million, respectively, of non-cash capital expenditures. At September 30, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $43.2 million, $31.8 million, $20.6 million and $13.6 million, respectively, of non-cash capital expenditures.

Current wording

(2)At March 31, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $44.4 million, $5.0 million, $5.5 million and $8.0 million, respectively, of non-cash capital expenditures. At September 30, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $43.2 million, $31.8 million, $20.6 million and $13.6 million, respectively, of non-cash capital expenditures.

Previous wording

The Exploration and Production segment capital expenditures for the three months ended December 31, 2024 were primarily well drilling and completion expenditures in the Appalachian region, and included $27.5 million in the Marcellus Shale area and $90.9 million in the Utica Shale area. These amounts included approximately $34.6 million spent to develop proved undeveloped reserves.

Current wording

The Exploration and Production segment capital expenditures for the six months ended March 31, 2025 were primarily well drilling and completion expenditures in the Appalachian region, and included $84.3 million in the Marcellus Shale area and $137.8 million in the Utica Shale area. These amounts included approximately $105.4 million spent to develop proved undeveloped reserves.

Previous wording

The Exploration and Production segment capital expenditures for the three months ended December 31, 2023 were primarily well drilling and completion expenditures in the Appalachian region, and included $37.5 million in the Marcellus Shale area and $120.2 million in the Utica Shale area. These amounts included approximately $106.0 million spent to develop proved undeveloped reserves.

Current wording

The Exploration and Production segment capital expenditures for the six months ended March 31, 2024 were primarily well drilling and completion expenditures in the Appalachian region, and included $52.0 million in the Marcellus Shale area and $224.9 million in the Utica Shale area. These amounts included approximately $185.8 million spent to develop proved undeveloped reserves.

Previous wording

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

Current wording

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

Previous wording

Supply Corporation concluded an Open Season on August 25, 2023, and based on post-open season discussions, has designed a project that would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC (“Transco”) capacity lease, providing access to Mid-Atlantic markets (“Tioga Pathway Project”). The Tioga Pathway Project involves the construction of approximately 19 miles of new pipeline and the replacement of approximately four miles of existing pipeline on the Supply Corporation system. Supply Corporation has executed a Precedent Agreement with Seneca for 190,000 Dth per day of transportation capacity and filed a Section 7(c) application with the FERC on August 21, 2024. The Tioga Pathway Project has a projected in-service date of late calendar year 2026 and an estimated capital cost of approximately $101 million. As of December 31, 2024, approximately $3.2 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at December 31, 2024.

Current wording

Supply Corporation concluded an Open Season on August 25, 2023, and based on post-open season discussions, has designed a project that would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC (“Transco”) capacity lease, providing access to Mid-Atlantic markets (“Tioga Pathway Project”). The Tioga Pathway Project involves the construction of approximately 19 miles of new pipeline and the replacement of approximately four miles of existing pipeline on the Supply Corporation system. Supply Corporation has executed a Precedent Agreement with Seneca for 190,000 Dth per day of transportation capacity and filed a Section 7(c) application with the FERC on August 21, 2024. On February 13, 2025, the FERC issued the Environmental Assessment for the project. The Tioga Pathway Project has a projected in-service date of late calendar year 2026 and an estimated capital cost of approximately $101 million. As of March 31, 2025, approximately $4.0 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at March 31, 2025.

Previous wording

The majority of the Gathering segment capital expenditures for the three months ended December 31, 2024 included expenditures related to the continued expansion of Midstream Company's Tioga gathering system. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online and system optimization, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

Current wording

The majority of the Gathering segment capital expenditures for the six months ended March 31, 2025 included expenditures related to the continued expansion of Midstream Company's Tioga and Trout Run gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online and system optimization, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

Previous wording

The majority of the Gathering segment capital expenditures for the three months ended December 31, 2023 included expenditures related to the continued expansion of Midstream Company's Tioga and Clermont gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

Current wording

The majority of the Gathering segment capital expenditures for the six months ended March 31, 2024 included expenditures related to the continued expansion of Midstream Company's Tioga and Clermont gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

Previous wording

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

Current wording

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

Previous wording

During the quarter ended December 31, 2024 and fiscal 2024, the Company has been financing capital expenditures with cash from operations and short-term debt. Going forward, the Company expects to use cash on hand, cash from operations and short-term or long-term borrowings, as needed, to finance capital expenditures. The level of short-term and/or long-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production and the associated commodity price realizations in the Exploration and Production segment. It will also likely depend on the timing of gas cost and base rate recovery in the Utility segment.

Current wording

During the six months ended March 31, 2025 and fiscal 2024, the Company has been financing capital expenditures with cash from operations and short-term debt. Going forward, the Company expects to use cash on hand, cash from operations and short-term or long-term borrowings, as needed, to finance capital expenditures. The level of short-term and/or long-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production and the associated commodity price realizations in the Exploration and Production segment. It will also likely depend on the timing of gas cost and base rate recovery in the Utility segment.

Previous wording

Consolidated short-term debt increased $109.3 million when comparing the balance sheet at December 31, 2024 to the balance sheet at September 30, 2024. The maximum amount of short-term debt outstanding during the three months ended December 31, 2024 was $253.9 million. In addition to cash provided by operating activities, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing items such as capital expenditures, asset purchases, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, repurchases of stock, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. As of December 31, 2024, the Company had outstanding commercial paper of $200.0 million and did not have any short-term notes payable to banks as of December 31, 2024.

Current wording

Consolidated short-term debt increased $117.7 million when comparing the balance sheet at March 31, 2025 to the balance sheet at September 30, 2024. The maximum amount of short-term debt outstanding during the six months ended March 31, 2025 was $327.8 million. In addition to cash provided by operating activities, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing items such as capital expenditures, asset purchases, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, repurchases of stock, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. As of March 31, 2025, the Company had outstanding commercial paper of $208.4 million and did not have any short-term notes payable to banks.

Previous wording

On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the “Credit Agreement”) with a syndicate of twelve banks. The Credit Agreement provided a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027. In February 2024, the Company and eleven of the banks in the syndicate consented to a one-year extension of the maturity date of the Credit Agreement, from February 26, 2027 to February 25, 2028. In May 2024, three of the banks in the syndicate assumed the commitments of the sole non-extending lender. In January 2025, the Company and the eleven banks in the syndicate consented to a second one-year extension of the maturity date, from February 25, 2028 to February 23, 2029, such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion through February 23, 2029.

Current wording

The Company is a party to a syndicated Credit Agreement (as amended from time to time, the “Credit Agreement”) that provides a $1.0 billion unsecured committed revolving credit facility. In January 2025, the Company and the eleven banks in the syndicate consented to a second one-year extension of the maturity date of the Credit Agreement, such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion through February 23, 2029.

Previous wording

On February 14, 2024, the Company entered into a Term Loan Agreement (the “Term Loan Agreement”) with six lenders, all of which are lenders under the Credit Agreement. The Term Loan Agreement provides a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company has the ability to select interest periods of one, three or six months for borrowings. In April 2024, pursuant to the delayed draw mechanism, the Company elected to draw a total of $300.0 million under the facility. After deducting debt issuance costs, the net proceeds to the Company amounted to $299.4 million. The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper. Borrowings under the Term Loan Agreement currently bear interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10%, plus a spread of 1.375%. The current locked-in interest rate is 5.78% until February 2025.

Current wording

On February 14, 2024, the Company entered into a Term Loan Agreement (the “Term Loan Agreement”) with six lenders, all of which are lenders under the Credit Agreement. The Term Loan Agreement provides a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company has the ability to select interest periods of one, three or six months for borrowings. In April 2024, pursuant to the delayed draw mechanism, the Company elected to draw a total of $300.0 million under the facility. After deducting debt issuance costs, the net proceeds to the Company amounted to $299.4 million. The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper. Borrowings under the Term Loan Agreement currently bear interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10%, plus a spread of 1.375%. The current weighted average locked-in interest rate is 5.79% until mid-May 2025.

Previous wording

Both the Credit Agreement and the Term Loan Agreement provide that the Company's debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since that date, the Company recorded non-cash, after-tax ceiling test impairments totaling $797.0 million. As a result, at December 31, 2024, $398.5 million was added back to the Company's total capitalization for purposes of calculating the debt to capitalization ratio under the Credit Agreement and the Term Loan Agreement. In addition, for purposes of calculating the debt to capitalization ratio, the following amounts included in Accumulated Other Comprehensive Income (Loss) on the Company's consolidated balance sheet will be excluded from the determination of comprehensive shareholders’ equity: all unrealized gains or losses on commodity-related derivative financial instruments, and up to $10 million in unrealized gains or losses on other derivative financial instruments. As a result of these exclusions, such unrealized gains or losses will not positively or negatively affect the calculation of the debt to capitalization ratio. At December 31, 2024, the Company’s debt to capitalization ratio, as calculated under the agreements, was 0.48. The constraints specified in the Credit Agreement and the Term Loan Agreement would have permitted an additional $2.97 billion in short-term and/or long-term debt to be outstanding at December 31, 2024 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded 0.65.

Current wording

Both the Credit Agreement and the Term Loan Agreement provide that the Company's debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since that date, the Company recorded non-cash, after-tax ceiling test impairments totaling $797.0 million. As a result, at March 31, 2025, $398.5 million was added back to the Company's total capitalization for purposes of calculating the debt to capitalization ratio under the Credit Agreement and the Term Loan Agreement. In addition, for purposes of calculating the debt to capitalization ratio, the following amounts included in Accumulated Other Comprehensive Income (Loss) on the Company's consolidated balance sheet will be excluded from the determination of comprehensive shareholders’ equity: all unrealized gains or losses on commodity-related derivative financial instruments, and up to $10 million in unrealized gains or losses on other derivative financial instruments. As a result of these exclusions, such unrealized gains or losses will not positively or negatively affect the calculation of the debt to capitalization ratio. At March 31, 2025, the Company’s debt to capitalization ratio, as calculated under the agreements, was 0.47. The constraints specified in the Credit Agreement and the Term Loan Agreement would have permitted an additional $3.21 billion in short-term and/or long-term debt to be outstanding at March 31, 2025 before the Company’s debt to capitalization ratio exceeded 0.65.

Previous wording

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

Current wording

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