NATIONAL FUEL GAS CO (NFG)

Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

The Company is a diversified energy company engaged principally in the production, gathering, transportation, storage and distribution of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian Basin. Current exploration and production development activities are focused primarily in the Marcellus and Utica shales, geological formations that are present in the Appalachian region of the United States. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian Basin to markets in the eastern United States and Canada. The Company’s efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas customers in the Appalachian Basin. In addition to expansion projects, the Company continues to focus on the ongoing modernization of its regulated Pipeline and Storage and Utility assets. The Company reports financial results for four business segments: Exploration and Production, Pipeline and Storage, Gathering, and Utility.

Fiscal 2024 Highlights

This Item 7, MD&A, provides information concerning:

1.The critical accounting estimates of the Company;

2.Changes in revenues and earnings of the Company under the heading, “Results of Operations;”

3.Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity” and;

4.Other Matters, including: (a) details regarding the status of Supply Corporation and Empire’s Northern Access project; (b) 2024 and projected 2025 funding for the Company’s pension and other post-retirement benefits; (c) disclosures and tables concerning market risk sensitive instruments; (d) rate matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions; (e) environmental matters; and (f) effects of inflation.

The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report, which includes a comparison of our Results of Operations and Capital Resources and Liquidity for fiscal 2024 and fiscal 2023. For a discussion of the Company’s earnings, refer to the Results of Operations section below. A discussion of changes in the Company’s results of operations from fiscal 2022 to fiscal 2023 has been omitted from this Form 10-K, but may be found in Item 7, MD&A, of the Company’s Form 10-K for the fiscal year ended September 30, 2023, filed with the SEC on November 17, 2023.

The Company’s Exploration and Production segment continues to grow, as evidenced by a 5% growth in proved reserves from the prior year to a total of 4,753 Bcfe at September 30, 2024. Production increased 19.8 Bcfe, or 5%, during the fiscal year ended September 30, 2024 to a total of 392.2 Bcfe, and is expected to increase again in fiscal 2025.

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, which 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.

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From a rate perspective, Distribution Corporation, in its Pennsylvania jurisdiction, reached a settlement with the parties to its rate case proceeding. On June 15, 2023, the PaPUC issued an order adopting the settlement in full. The settlement authorized an increase in Distribution Corporation’s annual base rate operating revenues of $23 million that became effective August 1, 2023. Distribution Corporation also filed a rate case proceeding with the NYPSC in its New York jurisdiction on October 31, 2023 seeking an increase of approximately $88 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024. After settlement negotiations, a Joint Proposal was filed with the NYPSC on September 9, 2024, that establishes a three-year rate plan allowing for an $86 million increase in annual revenue requirement over three years, with the first-year impact of $57 million in fiscal 2025 and the remainder in fiscal 2026 and fiscal 2027. It also includes standard make-whole language allowing the recovery of authorized revenues between September 30, 2024 and the start of new rates. The Joint Proposal remains subject to final NYPSC approval. 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.

As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its exploration and production properties and that book value is subject to a quarterly ceiling test. The Company recorded cumulative impairment charges under the ceiling test during fiscal 2024 of $463.7 million ($336.4 million after-tax). Looking ahead, the first day of the month Henry Hub spot price for natural gas in October 2024 and November 2024 was $2.66 per MMBtu and $1.87 per MMBtu, respectively. Given these prices, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation for the next quarter, the Company expects to experience a ceiling test impairment for the quarter ending December 31, 2024, and could record additional ceiling test impairments in fiscal 2025. Please refer to the Critical Accounting Estimates section below for a sensitivity analysis concerning commodity price changes.

The Company also recorded an impairment charge of $46.1 million ($33.8 million after-tax) in its Pipeline and Storage segment at September 30, 2024 to write down the value of certain assets associated with Supply Corporation and Empire’s Northern Access project. Additional details related to the Northern Access project are discussed further in the Other Matters section below.

From a financing perspective, given the significant impairments recorded during fiscal 2024 discussed above, under its existing indenture covenants, the Company would be precluded from issuing incremental long-term debt beginning in January 2025, for a period likely to extend to June 2025, when the remaining long-term debt outstanding under the Company’s 1974 indenture matures. However, the 1974 indenture would not prevent the Company from issuing new long-term debt to replace existing long-term debt, including borrowings under the Term Loan Agreement, or from issuing additional short-term debt. To the extent a need arises to issue incremental long-term debt, 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 the future principal and interest payments in trust would effectively relieve the Company from its obligations to comply with the 1974 indenture’s restrictions, including those on the issuance of incremental long-term debt.

In February 2024, eleven lenders in the syndicate of twelve banks under the Credit Agreement consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. In May 2024, three of the lenders in the syndicate assumed the commitments of the sole non-extending lender. As a result, the Company has aggregate commitments available under the Credit Agreement of $1.0 billion to February 25, 2028.

On February 14, 2024, the Company entered into the Term Loan Agreement with six lenders. The Term Loan Agreement established a $300 million unsecured committed delayed draw term loan credit facility with a maturity date of February 14, 2026. In April 2024, the Company elected to draw a total of $300 million under the facility. The Company used the proceeds for general corporate purposes, including the redemption of

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outstanding commercial paper. For further discussion of the Term Loan Agreement, refer to the Capital Resources and Liquidity section that follows.

The Company began repurchasing outstanding shares of 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 fiscal 2024, the Company executed transactions to repurchase 1,146,259 shares at an average price of $56.32 per share. With broker fees and excise taxes, the total cost of these repurchases amounted to $65.2 million. These matters are discussed further in the Capital Resources and Liquidity section that follows.

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

Corporate Responsibility

The Board of Directors and management recognize that the long-term interests of stockholders are served by considering the interests of customers, employees and the communities in which the Company operates. The Board retains risk oversight and general oversight of corporate responsibility and sustainability, and any related health and safety issues that might arise from the Company’s operations. The Board’s Nominating/Corporate Governance Committee oversees and provides guidance on corporate responsibility and sustainability strategies and initiatives that are of significance to the Company and its stakeholders, and may also make recommendations to the Board regarding these strategies and initiatives.

Part of the Board and management’s strategic and capital spending decision process includes identifying and assessing climate-related risks and opportunities. Management reports quarterly to the Board on critical and potentially emerging risks, including climate-related risks, as part of the Enterprise Risk Management process. Since the Company operates an integrated business with assets being utilized for, and benefiting from, the production, transportation and consumption of natural gas, the Board and management consider physical and transitional climate risks, including policy and legal risks, technological developments, shifts in market conditions, including future natural gas usage, and reputational risks, and the impact of those risks on the Company’s business. The Company reviews and considers adjustments to its approach to capital investment in response to these risks and developments, with its long-term, returns-focused approach.

The Company recognizes the important role of ongoing system modernization and efficiency in reducing greenhouse gas emissions and remains focused on reducing the Company’s carbon footprint, with these efforts positioning natural gas, and the Company’s related infrastructure, to remain an important part of the energy complex. In 2021, the Company set 2030 methane intensity reduction targets at each of its businesses, a 2030 absolute greenhouse gas emissions reduction target for the consolidated Company, and 2030 and 2050 greenhouse gas reduction targets associated with the Company’s utility delivery system. In 2022, the Company began measuring progress against these reduction targets. The Company also incorporated short-term and long-term executive compensation goals designed to incentivize and reward progress towards the Company’s emissions targets. The Company’s ability to estimate accurately the time, costs and resources necessary to meet these emissions reduction targets may change as environmental exposures and opportunities change, technology advances, and legislative and regulatory updates are issued.

CRITICAL ACCOUNTING ESTIMATES

The Company has prepared its consolidated financial statements in conformity with GAAP. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual

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results could differ from those estimates. In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Company’s most critical accounting estimates, which are defined as those estimates whereby judgments or uncertainties could affect the application of accounting policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company’s significant accounting policies, refer to Item 8 at Note A — Summary of Significant Accounting Policies.

Exploration and Development Costs.  In the Company’s Exploration and Production segment, property acquisition, exploration and development costs are capitalized under the full cost method of accounting, 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. Under this accounting methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves attributable to a cost center.

Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the full cost method of accounting (on a units-of-production basis). Unproved properties are excluded from the depletion calculation until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.

In addition to depletion under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying an unweighted arithmetic average of the first day of the month commodity prices for each month within the twelve-month period prior to the end of the reporting period (as adjusted for hedging) to estimated future production of proved reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures, which are based on current costs, associated with future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in natural gas prices. The ceiling is then compared to the capitalized cost of exploration and production properties less accumulated depletion and related deferred income taxes. If the capitalized costs of exploration and production properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment charge must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. The book value of the exploration and production properties exceeded the ceiling at September 30, 2024 as well as June 30, 2024, resulting in a cumulative non-cash impairment charge of $463.7 million ($336.4 million after-tax) for the year ended September 30, 2024. The 12-month average of the first day of the month price for

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natural gas for each month during 2024, based on the quoted Henry Hub spot price for natural gas, was $2.21 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 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 September 30, 2024 if natural gas prices were $0.25 per MMBtu lower than the average prices used at September 30, 2024 (all amounts are presented after-tax). These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

Looking ahead, the first day of the month Henry Hub spot price for natural gas in October 2024 and November 2024 was $2.66 per MMBtu and $1.87 per MMBtu, respectively. Given the October and November prices, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation for the next quarter, the Company expects to experience a ceiling test impairment for the quarter ending December 31, 2024, and could record additional ceiling test impairments in fiscal 2025.

As discussed above, the full cost method of accounting provides a ceiling to the amount of costs that can be capitalized in the full cost pool. In accordance with current authoritative guidance, the future cash outflows associated with plugging and abandoning wells are excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation.

Regulation.  The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to the FASB authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting principles for certain types of rate-regulated activities provides that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the Consolidated Statement of Income for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company’s regulatory assets and liabilities, refer to Item 8 at Note F — Regulatory Matters.

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RESULTS OF OPERATIONS

EARNINGS

2024 Compared with 2023

The Company’s earnings were $77.5 million in 2024 compared to earnings of $476.9 million in 2023. The decrease in earnings of $399.4 million was primarily the result of a loss recognized in the Exploration and Production segment compared to earnings in the prior year combined with lower earnings in the Pipeline and Storage segment. Higher earnings in the Utility segment and the Gathering segment, along with a lower loss in the Corporate category, partially offset these decreases. In the discussion that follows, all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings were impacted by the following events in 2024:

2024 Events

•Non-cash impairment charges of $473.1 million ($343.2 million after-tax) recorded during 2024 in the Exploration and Production segment, consisting mostly of ceiling test impairment charges of $463.7 million ($336.4 million after-tax). The remaining charges are related to impairments of certain water disposal assets.

•Non-cash impairment charge of $46.1 million ($33.8 million after-tax) recorded during the quarter ended September 30, 2024 in the Pipeline and Storage segment associated with the Northern Access project.

Earnings (Loss) by Segment

EXPLORATION AND PRODUCTION

Revenues

Exploration and Production Operating Revenues

Production

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Average Prices

(1)Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note J — Financial Instruments in Item 8 of this report.

2024 Compared with 2023

Operating revenues for the Exploration and Production segment increased $2.6 million in 2024 as compared with 2023. Gas production revenue after hedging increased $7.3 million primarily due to a 19.8 Bcf increase in gas production offset by a $0.11 per Mcf decrease in the weighted average realized price of gas after hedging. The increase in gas production was largely due to new Marcellus and Utica wells in the Appalachian region. Partially offsetting this increase, other revenue decreased $4.7 million due to the non-recurrence of temporary capacity release revenue for a portion of this segment’s transportation capacity in 2023.

Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.

Earnings

2024 Compared with 2023

The Exploration and Production segment experienced a loss of $164.0 million in 2024, a decrease of $396.3 million from earnings of $232.3 million in 2023. The decrease was primarily attributable to non-cash impairments of assets ($343.2 million), including an aggregate $336.4 million of ceiling test impairments recorded during the quarters ended June 30, 2024 and September 30, 2024 as well as a $6.8 million impairment of certain water disposal assets recorded during the quarter ended September 30, 2024. In conjunction with the ceiling test impairment, there was a $5.8 million earnings reduction associated with the remeasurement of state deferred income taxes. Other factors contributing to the decrease included lower natural gas prices after hedging ($34.0 million) and lower other revenue ($3.7 million), as discussed above. Higher depletion expense ($29.1 million), higher lease operating and transportation expenses ($13.7 million), higher other operating expenses ($8.9 million) and an increase in interest expense ($4.3 million) also reduced earnings. There was also a $4.1 million increase in unrealized losses related to contingent consideration received as part of the California asset sale. These decreases were partially offset by higher natural gas production ($39.8 million) combined with lower other taxes ($3.2 million) and a reduction in income tax expense ($7.3 million). The increase in depletion expense was primarily due to the net increase in production combined with a $0.06 per Mcf increase in the depletion rate. The increase in lease operating and transportation expenses was primarily the result of higher gathering and transportation costs combined with higher workover expenses. The increase in other operating expenses was primarily attributable to recognizing an accrual of plugging and abandonment costs related to certain offshore Gulf of Mexico wells and certain California wells that were sold by Seneca to operators that are now defunct or unable to cover the cost of the abandonment activities. As a result, a portion of the cost of abandoning the wells is expected to revert back to Seneca. Higher personnel costs also contributed to the increase in other operating expenses. The increase in interest expense can largely be attributed to higher average interest rates on intercompany short-term and long-term borrowings, partially offset by lower intercompany long-term debt balances. The decrease in other taxes was primarily attributable to lower Impact Fees in the Appalachian region as the Company moved into a lower rate tier due to lower NYMEX pricing. The reduction in income tax expense was primarily driven by a decrease in pre-tax income and lower state income tax expense. The lower state income taxes were a result of a decrease in Pennsylvania’s state income tax rate from 9.99% in the prior year to 8.99% in the current year, as well as a change in the mix of revenues between state jurisdictions.

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PIPELINE AND STORAGE

Revenues

Pipeline and Storage Operating Revenues

Pipeline and Storage Throughput — (MMcf)

2024 Compared with 2023

Operating revenues for the Pipeline and Storage segment increased $33.2 million in 2024 as compared with 2023. The increase in operating revenues was primarily due to an increase in transportation revenues of $20.7 million, an increase in storage revenues of $11.0 million and an increase in other revenues of $1.5 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 increase in other revenues primarily reflects an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense. This increase was partially offset by proceeds that were received during the quarter ended September 30, 2023 as a result of a contract buyout that did not recur in the current fiscal year.

Transportation volume decreased by 59.5 Bcf in 2024 as compared with 2023, primarily due to a decrease in volume as a result of lower capacity utilization with certain contract shippers and certain contract expirations, combined with a decline in volume from warmer weather. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

The majority of Supply Corporation’s and Empire’s transportation and storage contracts allow either party to terminate the contract upon six or twelve months’ notice effective at the end of the primary term and include “evergreen” language that allows for annual term extension(s). The Pipeline and Storage segment’s contracted transportation and storage capacity with both affiliated and unaffiliated shippers is expected to remain relatively constant in fiscal 2025.

Earnings

2024 Compared with 2023

The Pipeline and Storage segment’s earnings in 2024 were $79.7 million, a decrease of $20.8 million when compared with earnings of $100.5 million in 2023.  The decrease in earnings was primarily due to a non-cash impairment charge ($33.8 million), an increase in operating expenses ($7.6 million), an increase in interest

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expense ($3.1 million) and an increase in depreciation expense ($2.9 million). The impairment charge wrote down the carrying value of certain assets associated with Supply Corporation and Empire’s Northern Access project. Additional details related to the Northern Access project are discussed in the Other Matters section below. The increase in operating expenses was primarily due to higher personnel costs, an increase in outside services expenses (including compressor and other pipeline maintenance costs), as well as higher power costs related to Empire’s electric motor drive compressor station. This increase in electric power costs is offset by an equal increase in revenue. The increase in interest expense is mainly due to an increase in intercompany short-term borrowings along with a higher weighted average interest rate on intercompany long-term borrowings. The increase in depreciation expense was primarily due to higher average depreciable plant in service compared to the prior year, partially offset by a reduction in certain Supply Corporation depreciation rates associated with its rate case settlement. The factors that decreased earnings were partially offset by the impact of higher operating revenues ($26.2 million), as discussed above, combined with an increase in other income ($1.6 million). The increase in other income is primarily due to an increase in interest income related to a higher weighted average interest rate on intercompany short-term notes receivables and a higher average amount outstanding on those receivables.

GATHERING

Revenues

Gathering Operating Revenues

Gathering Volume — (MMcf)

2024 Compared with 2023

Operating revenues for the Gathering segment increased $13.9 million in 2024 as compared with 2023, which was driven primarily by a 27.4 Bcf increase in gathered volume. Gathered volume increased 47.7 Bcf in the Gathering segment’s eastern development areas (Trout Run and Tioga), partially offset by a 20.3 Bcf decrease in gathered volume in the Gathering segment’s western development area (Clermont). The net increase in gathered volume can be attributed to the increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.

Earnings

2024 Compared with 2023

The Gathering segment’s earnings in 2024 were $106.9 million, an increase of $7.2 million when compared with earnings of $99.7 million in 2023. The increase in earnings was mainly due to higher gathering revenues ($11.0 million) driven by the increase in gathered volume, as discussed above, and lower interest expense ($0.6 million). The decrease in interest expense was primarily due to higher capitalized interest. This increase was partially offset by higher depreciation expense ($2.4 million) and higher operating expenses ($1.3 million). The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga and Clermont gathering systems. The increase in operating expenses was largely attributable to higher material costs driven by new plant in-service and higher throughput, in addition to higher labor-related costs.

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UTILITY

Revenues

Utility Operating Revenues

Utility Throughput — million cubic feet (MMcf)

Degree Days

(1)Percents compare actual degree days to normal degree days and actual degree days to actual prior year degree days.

(2)Normal degree days changed from the NOAA 30-year degree days to NOAA 15-year degree days with the implementation of new base rates in Pennsylvania in August 2023.

2024 Compared with 2023

Operating revenues for the Utility segment decreased $245.0 million in 2024 compared with 2023. The decrease resulted from a $251.0 million decrease in retail gas sales revenue and a $1.8 million decrease in other revenues. The decrease in retail gas sales revenue was primarily due to a decrease in the cost of gas sold (per Mcf) as well as a 5.1 Bcf decrease in throughput largely due to warmer weather. These factors were partially offset by the impact of new base rates in Distribution Corporation’s Pennsylvania jurisdiction pursuant to a settlement approved by the PaPUC on June 15, 2023. Additional details regarding the base rate regulatory proceeding can be found in the Regulatory Matters section below. The decrease in other revenues was mainly due to decreases in late payment charges billed to customers ($1.7 million) and capacity release revenues ($1.2

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million), partially offset by a lower estimated refund provision for income tax benefits resulting from the 2017 Tax Reform Act ($0.9 million). The decreases in retail gas sales and other revenues were partially offset by a $7.7 million increase in transportation revenue, predominantly due to the impact of the new base rates in Pennsylvania in addition to an increase in the system modernization and system improvement tracker allocations to customers in New York.

Purchased Gas

The cost of purchased gas is one of the Company’s largest operating expenses. Annual variations in purchased gas costs are attributed directly to changes in gas sales volume, the price of gas purchased and the operation of purchased gas adjustment clauses. Distribution Corporation recorded $283.2 million and $548.2 million of Purchased Gas expense during 2024 and 2023, respectively. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation does not profit from fluctuations in gas costs. Purchased Gas expense recorded on the consolidated income statement matches the revenues collected from customers, a component of Operating Revenues on the consolidated income statement. Under mechanisms approved by the NYPSC in New York and the PaPUC in Pennsylvania, any difference between actual purchased gas costs and what has been collected from the customer is deferred on the consolidated balance sheet as either an asset, Unrecovered Purchased Gas Costs, or a liability, Amounts Payable to Customers. These deferrals are subsequently collected from the customer or passed back to the customer, subject to review by the NYPSC and the PaPUC. Absent disallowance of full recovery of Distribution Corporation’s purchased gas costs, such costs do not impact the profitability of the Company. Purchased gas costs impact cash flow from operations due to the timing of recovery of such costs versus the actual purchased gas costs incurred during a particular period. Distribution Corporation’s purchased gas adjustment clauses seek to mitigate this impact by adjusting revenues on either a quarterly or monthly basis.

Distribution Corporation contracts for firm long-term transportation and storage capacity services with rights-of-first-refusal from ten upstream pipeline companies including Supply Corporation for transportation and storage services and Empire, for transportation services. Distribution Corporation contracts for firm spot and term gas supplies with various producers, marketers and two local distribution companies to meet its gas purchase requirements. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.

Earnings

2024 Compared with 2023

The Utility segment’s earnings in 2024 were $57.1 million, an increase of $8.7 million when compared with earnings of $48.4 million in 2023. The increase was mainly due to the impact of new base rates in the Utility segment’s Pennsylvania jurisdiction ($18.1 million), the impact of system modernization and system improvement trackers in New York ($7.9 million), lower income tax expense ($4.4 million), and an increase in other income ($1.7 million). The decrease in income tax expense was largely due to an increase in tax deductions related to certain repairs and maintenance expenditures recorded in the Utility’s Pennsylvania jurisdiction as a result of updated IRS guidance published in 2023. The increase in other income was primarily driven by a decrease in non-service costs in the Utility segment’s Pennsylvania jurisdiction. These factors were partially offset by the earnings impact associated with certain revenue decreases ($8.8 million), including a decrease in regulatory adjustments ($5.3 million), a decrease in other operating revenues ($2.1 million), and a decrease due to lower usage and weather ($1.4 million). Higher operating expenses ($10.7 million), higher depreciation expense ($3.0 million), and higher interest expense ($0.9 million) were other factors that reduced earnings. The increase in operating expenses was mainly due to higher personnel costs. The increase in depreciation expense was mainly due to higher average plant balances in the New York jurisdiction and increased depreciation associated with negative net salvage (i.e., cost of removal in excess of salvage value).

The impact of weather variations on earnings in the Utility segment is mitigated by a WNA. The WNA, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the Utility segment. In addition, in periods of colder than normal weather, the WNA benefits the Utility segment’s customers. For 2024, the WNA preserved earnings of approximately $8.1 million and $5.5 million, respectively, in the Utility segment’s New York and Pennsylvania rate jurisdictions. Fiscal 2024 was the first year that a

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WNA was in effect for the Utility segment’s Pennsylvania rate jurisdiction. For 2023, the WNA preserved earnings of approximately $4.8 million in the Utility segment’s New York rate jurisdiction as the weather was warmer than normal.

ALL OTHER AND CORPORATE OPERATIONS

Earnings

2024 Compared with 2023

All Other and Corporate operations had a net loss of $2.2 million in 2024, an improvement of $1.8 million when compared with a net loss of $4.0 million in 2023. The improvement was primarily attributable to changes in unrealized gains on investments in equity securities. In 2024, the Company recorded unrealized gains of $2.4 million, while in 2023, the Company recorded unrealized gains of $0.7 million.

OTHER INCOME (DEDUCTIONS)

Although most of the variances in Other Income (Deductions) are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis (amounts below are pre-tax amounts):

Net other income on the Consolidated Statements of Income was $16.2 million in 2024 compared to net other income of $18.1 million in 2023, for a net decrease of $1.9 million. This was primarily due to a $5.6 million period-over-period increase in losses associated with revaluing the contingent consideration received from the California asset sale and a $2.8 million decrease in interest income. Partially offsetting factors included higher net gains on investments in equity securities of $2.5 million, $2.0 million of business interruption insurance proceeds received during 2024 related to a pipeline outage that impacted Seneca’s ability to market its gas, a $0.7 million increase in the allowance for funds used during construction, a $0.7 million increase in income from life insurance policies and a $0.5 million increase in non-service pension and post-retirement benefit income.

INTEREST CHARGES

Although most of the variances in Interest Charges are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis (amounts below are pre-tax amounts):

Interest on long-term debt increased $10.9 million in 2024 as compared to 2023. The increase was primarily due to higher average balances and a higher weighted average interest rate on long-term debt. In May 2023, the Company issued $300.0 million of 5.50% notes. Additionally, the Company elected to draw a total of $300.0 million under a delayed draw term loan credit facility in April 2024. The Company selected an initial six-month interest period for these borrowings, locking in a weighted average interest rate of 6.71% through the beginning of October 2024. Partially offsetting these increases, the Company redeemed 3.75% notes in November 2022 and March 2023, amounting to $500.0 million in the aggregate, and also redeemed $49.0 million of 7.395% notes in March 2023. In addition, there was an increase in capitalized interest in Midstream Company and Seneca.

Other interest expense decreased $4.0 million in 2024 as compared to 2023. The decrease was primarily due to lower average short-term debt balances in 2024 compared to 2023, partially offset by higher weighted average interest rates for 2024. There was also a net decrease in interest costs related to gas storage inventory and deferred gas costs in the Utility segment.

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CAPITAL RESOURCES AND LIQUIDITY

The primary sources and uses of cash during the last two years are summarized in the following condensed statement of cash flows:

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 2025, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures. The Company also has two long-term debt maturities in 2025, totaling $500.0 million, which the Company anticipates funding with long-term borrowings. Looking forward to 2026, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.

OPERATING CASH FLOW

Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of assets, deferred income taxes and stock-based compensation.

Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs, weather and regulatory lag may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire. Prior to October 2023, the weather impact on cash flow in the Utility segment was mitigated by a WNA solely in its New York rate jurisdiction. However, effective October 2023, the weather impact on cash flow in the Utility segment is also mitigated by a WNA in its Pennsylvania rate jurisdiction. The Pennsylvania rate jurisdiction WNA resulted from the PaPUC’s approved settlement on June 15, 2023, further discussed in the Rate Matters section below. Refer also to Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) for additional discussion.

Cash provided by operating activities in the Exploration and Production segment may vary from year to year as a result of changes in the commodity prices of natural gas as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and no cost collars, in an attempt to manage this energy commodity price risk. The pricing protection obtained from derivative financial instruments will fluctuate over time as instruments expire and are replaced with new instruments reflecting current commodity prices of natural gas.

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The Company, in its Utility segment and Exploration and Production segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for additional discussion concerning these contractual commitments as well as the amounts of future gas purchase, transportation and storage contract commitments expected to be incurred during the next five years and thereafter. Also refer to Item 8 at Note D — Leases for a discussion of the Company’s operating lease arrangements and a schedule of lease payments during the next five years and thereafter.

Net cash provided by operating activities totaled $1,066.0 million in 2024, a decrease of $171.1 million compared with the $1,237.1 million provided by operating activities in 2023. The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Exploration and Production segment and Utility segment. The decrease in the Exploration and Production segment is primarily due to lower cash receipts from natural gas production in the Appalachian region. The decrease in the Utility segment is primarily due to the timing of gas cost recovery.

INVESTING CASH FLOW

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets, including non-cash capital expenditures, totaled $942.0 million and $1.12 billion in 2024 and 2023, respectively. The table below presents these expenditures:

(1)The year ended September 30, 2023 includes $124.8 million related to the acquisition of upstream assets acquired from SWN. The acquisition cost is reported as a component of Acquisition of Upstream Assets on the Consolidated Statement of Cash Flows.

(2)2024 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $63.3 million, $14.4 million, $21.7 million and $20.6 million, respectively, of non-cash capital expenditures.

(3)2023 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $43.2 million, $31.8 million, $20.6 million and $13.6 million, respectively, of non-cash capital expenditures.

Exploration and Production

In 2024, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures in the Appalachian region, and included $76.3 million in the Marcellus Shale area and $439.9 million in the Utica Shale area. These amounts included approximately $305.6 million spent to develop proved undeveloped reserves. The Company also completed the acquisition of certain undeveloped acreage in Tioga County, Pennsylvania for $6.2 million in 2024. The acquisition included 2,083 net acres and was accounted for as an asset acquisition with the purchase price allocated to property, plant and equipment. The

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

In 2023, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures in the Appalachian region, and included approximately $292.6 million in the Marcellus Shale area and $430.7 million in the Utica Shale area. These amounts included approximately $342.0 million spent to develop proved undeveloped reserves.

On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN for total consideration of $124.8 million. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment.

Other 2023 acquisitions included the acquisition of certain upstream assets located in Lycoming County in Northeast Pennsylvania for total consideration of $11.5 million as well as the acquisition of undeveloped acreage in Tioga County, Pennsylvania for $13.6 million. The acquisition in Lycoming County included 1,145 net acres and the acquisition in Tioga County included 4,222 net acres. Both transactions were accounted for as asset acquisitions and, as such, the purchase price for each transaction was allocated to property, plant and equipment. The cost of these acquisitions is reported as a component of Capital Expenditures on the Consolidated Statement of Cash Flows.

Pipeline and Storage

The Pipeline and Storage segment’s capital expenditures for 2024 and 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.

Gathering

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

The majority of the Gathering segment’s capital expenditures for 2023 included expenditures related to the continued expansion of Midstream Company’s Clermont, 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, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

Utility

The majority of the Utility segment’s capital expenditures for 2024 and 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.

Other Investing Activities

In October 2022, the Company sold $10 million of fixed income mutual fund shares held in a grantor trust that was established for the benefit of Pennsylvania ratepayers. The proceeds were used in the Utility segment’s Pennsylvania service territory during fiscal 2023 to fund the second year installment of a 5-year pass back of overcollected OPEB expenses, as well as to diversify a portion of grantor trust investments into lower risk money market mutual fund shares for purposes of funding future installments.

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Estimated Capital Expenditures

The Company’s estimated capital expenditures for the next three years are:

(1)Includes estimated expenditures for the years ended September 30, 2025, 2026 and 2027 of approximately $300 million, $205 million and $145 million, respectively, to develop proved undeveloped reserves. The Company is committed to developing its proved undeveloped reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting.

(2)Includes estimated expenditures for the years ended September 30, 2025, 2026, and 2027 of approximately $145 million, $150 million and $165 million, respectively, for system modernization and safety to enhance the reliability and safety of the system and reduce emissions.

Exploration and Production

Capital expenditures for the Exploration and Production segment in 2025 through 2027 are expected to be primarily well drilling and completion expenditures, combined with related infrastructure, in the Appalachian region.

Pipeline and Storage

Capital expenditures for the Pipeline and Storage segment in 2025 through 2027 are expected to include: the replacement and modernization of transmission and storage facilities, the reconditioning of storage wells, improvements of compressor stations and emissions reduction initiatives, as well as capital expenditures related to system expansion.

In addition, due to the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, specifically in the Marcellus and Utica Shale producing areas, Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems. An expansion and modernization project where the Company has forecasted a significant amount of investment in preliminary survey and investigation costs and/or capital expenditures in 2025 through 2027, and where a precedent agreement has been executed, is discussed below.

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. The majority of these expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. As of September 30, 2024, approximately $2.6 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at September 30, 2024.

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Gathering

The majority of the Gathering segment capital expenditures in 2025 through 2027, included in the table above, are expected to be for additional pipeline and compression infrastructure. The Gathering segment primarily invests capital to support Seneca’s drilling and completion activity in its long-term development plan. Seneca has shifted nearly all of its forward-looking activity from its Western Development Area to Tioga County, Pennsylvania. As a result, the Gathering segment is expecting to see near-term increases in capital expenditures as it constructs the necessary infrastructure to support Seneca’s activity in the region.

Utility

Capital expenditures for the Utility segment in 2025 through 2027 are expected to be concentrated in the areas of main and service line improvements and replacements that will enhance the reliability and safety of the system, emission reduction initiatives and, to a lesser extent, the purchase of new equipment.

Project Funding

During fiscal 2024 and 2023, capital expenditures were funded 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.

In the Exploration and Production segment, the Company has entered into contractual obligations to support its development activities and operations in Pennsylvania, including hydraulic fracturing and other well completion services, well tending services, well workover activities, tubing and casing purchases, production equipment purchases, water hauling services and contracts for drilling rig services. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for the amounts of contractual obligations expected to be incurred during the next five years and thereafter to support the Company’s exploration and development activities. These amounts are largely a subset of the estimated capital expenditures for the Exploration and Production segment shown above.

The Company, in its Pipeline and Storage segment, Gathering segment and Utility segment, has entered into several contractual commitments associated with various pipeline, compressor and gathering system modernization and expansion projects. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for the amounts of contractual commitments expected to be incurred during the next five years and thereafter associated with the Company’s pipeline, compressor and gathering system modernization and expansion projects. These amounts are a subset of the estimated capital expenditures for the Pipeline and Storage segment, Gathering segment and Utility segment that are shown above.

The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive natural gas properties, accelerated development of existing natural gas properties, natural gas storage and transmission facilities, natural gas generation facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. The amounts are also subject to modification for opportunities involving emission reductions and/or energy transition including investments directly related to low- and no-carbon fuels. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s business segments depends, to a large degree, upon market and regulatory conditions as well as legislative actions.

FINANCING CASH FLOW

Consolidated short-term debt decreased $196.8 million, to a total of $90.7 million, when comparing the balance sheet at September 30, 2024 to the balance sheet at September 30, 2023. The maximum amount of short-term debt outstanding during the year ended September 30, 2024 was $402.9 million. In addition to cash

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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 September 30, 2024, the Company had outstanding commercial paper of $90.7 million and did not have any short-term notes payable to banks as of September 30, 2024.

On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the “Credit Agreement”) with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. As initially entered, the Credit Agreement provided a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027. In February 2024, the Company and eleven of the banks in the syndicate consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. In May 2024, three of the banks in the syndicate assumed the commitments of the sole non-extending lender, such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion to February 25, 2028.

The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement. The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future.

On February 14, 2024, the Company entered into a Term Loan Agreement (the “Term Loan Agreement”) with six lenders, all of which are lenders under the Credit Agreement. The Term Loan Agreement provides a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company has the ability to select interest periods of one, three or six months for borrowings. 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%. In April 2024, a weighted average interest rate of 6.71% was locked in until the beginning of October 2024. The current locked in interest rate is 4.62% for $200.0 million until December 2024 and 4.58% for the remaining $100 million until January 2025.

Both the Credit Agreement and the Term Loan Agreement provide that the Company’s debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter. 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 $717.9 million. As a result, at September 30, 2024, $358.9 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 September 30, 2024, 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

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permitted an additional $3.07 billion in short-term and/or long-term debt to be outstanding at September 30, 2024 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded 0.65.

A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company’s subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources.

The Credit Agreement and the Term Loan Agreement each contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement or Term Loan Agreement, as applicable. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.

On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $297.3 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company’s credit rating is subsequently upgraded.

The Current Portion of Long-Term Debt at September 30, 2024 consisted of $50.0 million of 7.38% notes that mature in June 2025 and $450.0 million of 5.20% notes that mature in July 2025. None of the Company’s long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period. As of September 30, 2024, the future contractual obligations related to aggregate principal amounts of long-term debt, including interest expense, maturing during the next five years and thereafter are as follows: $626.0 million in 2025, $873.0 million in 2026, $640.4 million in 2027, $327.9 million in 2028, $14.8 million in 2029, and $520.9 million thereafter. Refer to Item 8 at Note H — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense. Principal payments of long-term debt are a component of cash used in financing activities while interest payments on long-term debt are a component of cash used in operating activities.

The Company’s embedded cost of long-term debt was 4.91% at September 30, 2024 and 4.69% at September 30, 2023. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.

The Company’s present liquidity position is believed to be adequate to satisfy known demands. Under the Company’s 1974 indenture, certain covenants exist that, from time to time, may preclude the Company from issuing incremental long-term debt. Given the impairments of exploration and production properties the Company recognized during the year ended September 30, 2024, the indenture covenants would preclude the Company from issuing incremental long-term debt beginning January 2025, for a period likely extending to June 2025, when the remaining debt outstanding under the 1974 indenture matures. The indenture covenants do not, however, prevent the Company from issuing new long-term debt to replace existing long-term debt, including borrowings under the Term Loan Agreement, or from issuing additional short-term debt.

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As of September 30, 2024, the Company has $50.0 million in principal and $3.2 million in interest payments remaining related to long-term debt issued under the 1974 indenture. Currently, the Company does not anticipate a need to issue incremental long-term debt and only has plans for new long-term debt to replace maturing long-term debt. To the extent a need arises to issue incremental long-term debt, 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 the future principal and interest payments in trust would effectively relieve the Company from its obligations to comply with the 1974 indenture’s restrictions, including those on the issuance of incremental long-term debt.

In addition to the covenants noted above, the Company’s 1974 indenture contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

On March 8, 2024, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of $200 million in the open market or through privately negotiated transactions, including through the use of trading plans intended to qualify under SEC Rule 10b5-1, in accordance with applicable securities laws and other restrictions. While the program has no fixed expiration date, the Company is targeting completion of this program by the end of fiscal 2025, depending on a number of factors, including but not limited to stock price, market conditions, applicable securities laws, including SEC Rule 10b-18, corporate and regulatory requirements, and capital and liquidity needs. The Company’s Board of Directors may suspend, discontinue, terminate, modify, cancel or extend the share repurchase program at any time and for any reason. During the year ended September 30, 2024, the Company executed transactions to repurchase 1,146,259 shares at an average price of $56.32 per share. With broker fees and excise taxes, the total cost of these repurchases amounted to $65.2 million. Share repurchases that settled during the year ended September 30, 2024 were funded with cash provided by operating activities and/or short-term borrowings. It is expected that future repurchases, if any, under this program will continue to be funded with cash provided by operating activities and/or through the use of short-term borrowings.

OTHER MATTERS

In addition to the environmental and other matters discussed in this Item 7 and in Item 8 at Note L — Commitments and Contingencies, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

Supply Corporation and Empire developed a project which was intended to 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”). However, after initial FERC approval on February 3, 2017, substantial litigation ensued over the next several years concerning various federal and state authorizations for the project, with the majority of the project development activities suspended pending resolution. These legal actions included, most recently, an appeal challenging FERC’s June 2022 order granting Supply Corporation and Empire an extension of time to construct the project through December 31, 2024. In March 2024, the U.S. Court of Appeals for the D.C. Circuit issued an order affirming FERC’s extension of time, with such order final as of late June 2024. Upon resolution of the extensive litigation, Supply Corporation and Empire began to assess

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next steps for the project, including a review of the status of necessary federal and state authorizations, as well as potential changes in expected capital expenditures and the related transportation rates that Supply Corporation and Empire needed to support the project. As a result of this review, and in accordance with the precedent agreements between the respective parties, Supply Corporation and Empire sent notifications to Seneca, the sole shipper for the project, indicating their intent to increase the project’s firm transportation rates to account for the anticipated increase in capital expenditures to complete the project. Upon receipt, Seneca indicated it was unwilling to accept the revised transportation rates and intended to terminate the precedent agreements for the project. The precedent agreements were subsequently terminated on October 16, 2024. Accordingly, the Company will no longer pursue construction of the Northern Access project and has taken an impairment charge of $46.1 million at September 30, 2024.

The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan). During 2024, the Company did not make any contributions to the Retirement Plan. The Company does not expect to make any contributions to the Retirement Plan in 2025. For further discussion of the Company’s Retirement Plan, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the Retirement Plan has been closed to new participants since 2003. In that regard, the average remaining service life of active participants in the Retirement Plan is approximately 6 years.

The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits. Prior to 2023, the Company had been making contributions to its VEBA trusts and/or 401(h) accounts each year. However, the Company did not make any contributions to its VEBA trusts or 401(h) accounts in 2023 or 2024, and does not anticipate making contributions to these accounts in 2025. The Company made direct payments of $0.5 million to retirees not covered by the VEBA trusts and 401(h) accounts during 2024. For further discussion of the Company’s other post-retirement benefits, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the other post-retirement benefits provided by the Company have been closed to new participants since 2003. In that regard, the average remaining service life of active participants is approximately 4 years for those eligible for other post-retirement benefits.

The Company has made certain guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the Consolidated Balance Sheets in accordance with the authoritative guidance (see Item 8 at Note J — Financial Instruments); and (ii) other obligations which are reflected on the Consolidated Balance Sheets. The Company believes that the likelihood it would be required to make payments under the guarantees is remote.

MARKET RISK SENSITIVE INSTRUMENTS

Energy Commodity Price Risk

The Company uses various derivative financial instruments (derivatives), including price swap agreements and no cost collars, as part of the Company’s overall energy commodity price risk management strategy in its Exploration and Production segment. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the Company would receive from, or pay to, the respective counterparties at September 30, 2024 to terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas transactions that are related to the financial instruments.

Rules adopted by the CFTC and other regulators related to the swaps and over-the-counter derivatives markets could adversely impact the Company. While many of those rules place specific conditions on the operations of swap dealers rather than directly on the Company, concern remains that swap dealers with whom the Company may transact will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs. Some of those rules also may apply directly to the

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Company and adversely impact its ability to trade swaps and over-the-counter derivatives, whether due to increased costs, limitations on trading capacity or for other reasons. Additionally, given the enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and anti-disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business. Should the Company violate any laws or regulations applicable to our hedging activities, it could be subject to CFTC enforcement action and material penalties and sanctions.

The authoritative guidance for fair value measurements and disclosures requires consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At September 30, 2024, the Company determined that nonperformance risk associated with its natural gas price swap agreements, natural gas no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty’s (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

The following tables disclose natural gas price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2024. At September 30, 2024, the Company had not entered into any natural gas price swap agreements extending beyond 2029.

Natural Gas Price Swap Agreements

At September 30, 2024, the Company would have received an aggregate of approximately $53.8 million to terminate the natural gas price swap agreements outstanding at that date.

At September 30, 2023, the Company had natural gas price swap agreements covering 260.0 Bcf at a weighted average fixed rate of $3.62 per Mcf.

No Cost Collars

The following table discloses the notional quantities, the weighted average ceiling price and the weighted average floor price for the no cost collars used by the Company to manage natural gas price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). At September 30, 2024, the Company had not entered into any natural gas no cost collars extending beyond 2028.

At September 30, 2024, the Company would have received an aggregate of approximately $29.1 million to terminate the natural gas no cost collars outstanding at that date.

At September 30, 2023, the Company had no cost collars agreements covering 151.3 Bcf at a weighted average ceiling price of $4.61 per Mcf and a weighted average floor price of $3.53 per Mcf.

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Foreign Exchange Risk

The Company uses foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. All of these transactions are forecasted.

The following table discloses foreign exchange contract information by expected maturity dates. The Company receives a fixed price in exchange for paying a variable price as noted in the Canadian to U.S. dollar forward exchange rates. Notional amounts (Canadian dollars) are used to calculate the contractual payments to be exchanged under contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2024. At September 30, 2024, the Company had not entered into any foreign currency exchange contracts extending beyond 2030.

At September 30, 2024, absent other positions with the same counterparties, the Company would have paid to its respective counterparties an aggregate of $0.4 million to terminate these foreign exchange contracts.

Refer to Item 8 at Note J — Financial Instruments for a discussion of the Company’s exposure to credit risk related to its derivative financial instruments.

Interest Rate Risk

The fair value of long-term debt is $2.7 billion at September 30, 2024. This fair value amount is not intended to reflect principal amounts that the Company will ultimately be required to pay. The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt:

(1) Interest rate is a weighted average SOFR interest rate that was locked in from April 2024 until the beginning of October 2024. The current locked in interest rate is 4.62% for $200.0 million until December 2024 and 4.58% for the remaining $100 million until January 2025.

RATE MATTERS

Utility Operation

Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” As noted below, the New York division currently has a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.

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New York Jurisdiction

Distribution Corporation’s current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017 (“2017 Rate Order”). The 2017 Rate Order provided for a return on equity of 8.7% and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. On October 31, 2023, Distribution Corporation made a filing with the NYPSC seeking an increase of approximately $88 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024. A Notice of Impending Settlement Negotiations was filed with the NYPSC on March 26, 2024. Thereafter, settlement discussions with parties commenced and to facilitate these discussions, the Company requested postponements of the evidentiary hearing and agreed to extensions of the suspension period for the effective date of new base delivery rates subject to a “make-whole” provision that would permit the Company to recover or refund any revenue under-collections or over-collections, respectively, resulting from the extension period. The settlement negotiations were successful and resulted in a Joint Proposal (“JP”) that establishes a three-year rate plan allowing for an $86 million increase in annual revenue requirement over three years, with the first-year impact of $57 million in fiscal 2025 and the remainder in fiscal 2026 and fiscal 2027. The JP settles all contested issues among the signatory parties and includes, among other things, a return on equity of 9.7%, a common equity ratio of 48% for rate setting purposes, an earnings sharing mechanism, an uncollectible expense tracker, and continuation of the Company’s leak prone pipe replacement program. The revenue requirement in the JP also includes the impact of negative pension/OPEB expense. The JP was filed with the NYPSC on September 9, 2024. On November 14, 2024, the NYPSC issued an order extending the suspension period through December 31, 2024. That order also includes a “make-whole” provision from September 30, 2024 until the date new rates take effect under the final decision on the JP.

Pennsylvania Jurisdiction

On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $28.1 million. A settlement involving all active parties to the proceeding was reached and filed with the PaPUC on April 13, 2023. The settlement provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million. The PaPUC approved the settlement in full, without modification or correction, on June 15, 2023 and new rates went into effect on August 1, 2023.

On April 10, 2024, Distribution Corporation filed with the PaPUC a petition for approval of a distribution system improvement charge (“DSIC”) to recover, between base rate cases, capital expenses related to eligible property constructed or installed to rehabilitate, improve and replace portions of the Company’s natural gas distribution system. If approved as filed, the Company will be able to recover costs associated with plant placed in service on and after August 1, 2024 if its total plant in service exceeds approximately $781.3 million and its quarterly rate of return does not exceed the authorized PaPUC rate of return. As of September 30, 2024, plant placed in service for Distribution Corporation’s Pennsylvania division was $785.2 million. The DSIC petition is currently pending before the PaPUC.

Pipeline and Storage

Supply Corporation’s rate settlement, approved June 11, 2024, provides that Supply Corporation may make a rate filing for new rates to be effective at any time. As well, any party can make a filing under NGA Section 5.

Empire’s 2019 rate settlement requires a Section 4 rate case filing no later than May 1, 2025. Empire has no rate case currently on file.

ENVIRONMENTAL MATTERS

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory requirements. In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and greenhouse gas reduction targets associated with the Company’s

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utility delivery system. In 2022, the Company began measuring progress against these reduction targets. The Company’s ability to estimate accurately the time, costs and resources necessary to meet emissions targets may be impacted as environmental exposures, technology and opportunities change and regulatory and policy updates are issued.

For further discussion of the Company’s environmental exposures, refer to Item 8 at Note L — Commitments and Contingencies under the heading “Environmental Matters.”

The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

Environmental Regulation

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in the United States. These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, cap and invest and cap and trade programs, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. For example, the federal Inflation Reduction Act of 2022 (IRA) legislation was signed into law on August 16, 2022, and includes a directive for the EPA, the lead federal agency that regulates greenhouse gas emissions pursuant to the Clean Air Act, to develop a waste emissions charge (WEC) applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds. The WEC remains in the proposed rulemaking stage, and is expected to begin in calendar year 2025, covering emissions from applicable facilities reported for calendar year 2024. The regulations implemented by the EPA also impose stringent leak detection and repair requirements and address reporting and control of methane and volatile organic compound emissions, which were further expanded with EPA’s March 2024 publication and finalization of the Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources and its May 2024 finalization of the Greenhouse Gas Reporting Program, Part 98 - Subpart W Final Rule.

Additionally, a number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The New York State legislature passed the CLCPA that mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. The NYPSC has initiated and/or modified various proceedings in an effort to help the State meet these emissions reduction targets. In May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to certain exemptions. These climate change and greenhouse gas initiatives could impact the Company’s customer base and assets depending on the promulgation of final regulations and on regulatory treatment afforded in the process. The NYDEC, in conjunction with the New York State Energy Research and Development Authority, is developing a cap-and-invest program in the state, which is anticipated to be effective in calendar year 2025. The above-enumerated initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also reduce demand for natural gas and delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.

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EFFECTS OF INFLATION

The Company’s operations are sensitive to increases in the rate of inflation because of its operational and capital spending requirements in both its regulated and non-regulated businesses. For the regulated businesses, recovery of increasing costs from customers can be delayed by the regulatory process of a rate case filing. For the non-regulated businesses, prices received for services performed or products produced are determined by market factors that are not necessarily correlated to the underlying costs required to provide the service or product.

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

The Company is including the following cautionary statement in this Annual Report on Form 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:

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

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

3.Changes in the price of natural gas;

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

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

6.The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets;

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

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

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

10.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;

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

12.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;

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

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

15.The Company’s ability to complete strategic transactions;

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

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

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

19.Uncertainty of natural gas reserve estimates;

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

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

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

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

24.Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to third-party outages;

25.Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or

26.Increasing costs of insurance, changes in coverage and the ability to obtain insurance.

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

Forward-looking and other statements in this Annual Report on Form 10-K regarding methane and greenhouse gas reduction plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current and forward-looking statements regarding methane and greenhouse gas emissions may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve and assumptions that are subject to change in the future.

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INDUSTRY AND MARKET DATA DISCLOSURE

The market data and certain other statistical information used throughout this Form 10-K are based on independent industry publications, government publications or other published independent sources. Some data is also based on the Company’s good faith estimates. Although the Company believes these third-party sources are reliable and that the information is accurate and complete, it has not independently verified the information.

Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

The Company is a diversified energy company engaged principally in the production, gathering, transportation, storage and distribution of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian Basin. Current development activities are focused primarily in the Marcellus and Utica shales. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian Basin to markets in the eastern United States and Canada. The Company's efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas customers in the Appalachian Basin. The Company reports financial results for four business segments: Exploration and Production, Pipeline and Storage, Gathering, and Utility.

Corporate Responsibility

The Board of Directors and management recognize that the long-term interests of stockholders are served by considering the interests of customers, employees and the communities in which the Company operates. The Board retains risk oversight and general oversight of corporate responsibility, including environmental, social and governance (“ESG”) concerns, and any related health and safety issues that might arise from the Company’s operations. The Board’s Nominating/Corporate Governance Committee oversees and provides guidance concerning the Company’s practices and reporting with respect to corporate responsibility and ESG factors that are of significance to the Company and its stakeholders, and may also make recommendations to the Board regarding ESG initiatives and strategies, including the Company’s progress on integrating ESG factors into business strategy and decision-making.

Part of the Board and management’s strategic and capital spending decision process includes identifying and assessing climate-related risks and opportunities. Management reports quarterly to the Board on critical and potentially emerging risks, including climate-related risks, as part of the Enterprise Risk Management process. Since the Company operates an integrated business with assets being utilized for, and benefiting from, the production, transportation and consumption of natural gas, the Board and management consider physical and transitional climate risks, including policy and legal risks, technological developments, shifts in market conditions, including future natural gas usage, and reputational risks, and the impact of those risks on the Company’s business. The Company reviews and considers adjustments to its approach to capital investment in response to these risks and developments, with its long-term, returns-focused approach.

The Company recognizes the important role of ongoing system modernization and efficiency in reducing greenhouse gas emissions and remains focused on reducing the Company’s carbon footprint, with these efforts positioning natural gas, and the Company’s related infrastructure, to remain an important part of the energy complex. In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and greenhouse gas reduction targets associated with the Company’s utility delivery system. In 2022, the Company began measuring progress against these reduction targets. The Company also incorporated short-term and long-term executive compensation goals designed to incentivize and reward performance if reduction targets are met or exceeded. The Company's ability to estimate accurately the time, costs and resources necessary to meet these emissions reduction targets may change as environmental exposures and opportunities change, technology advances, and legislative and regulatory updates are issued.

Fiscal 2023 Highlights

This Item 7, MD&A, provides information concerning:

1.The critical accounting estimates of the Company;

2.Changes in revenues and earnings of the Company under the heading, “Results of Operations;”

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3.Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity” and;

4.Other Matters, including: (a) 2023 and projected 2024 funding for the Company’s pension and other post-retirement benefits; (b) disclosures and tables concerning market risk sensitive instruments; (c) rate matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions; (d) environmental matters; and (e) effects of inflation.

The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report, which includes a comparison of our Results of Operations and Capital Resources and Liquidity for fiscal 2023 and fiscal 2022. For a discussion of the Company's earnings, refer to the Results of Operations section below. A discussion of changes in the Company’s results of operations from fiscal 2021 to fiscal 2022 has been omitted from this Form 10-K, but may be found in Item 7, MD&A, of the Company’s Form 10-K for the fiscal year ended September 30, 2022, filed with the SEC on November 18, 2022.

The Company's Exploration and Production segment continues to grow, as evidenced by a 9% growth in proved reserves from the prior year to a total of 4,536 Bcfe at September 30, 2023. Production increased 19.9 Bcfe during the fiscal year ended September 30, 2023 to a total of 372.5 Bcfe, and is expected to increase again in fiscal 2024.

On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN Production Company, LLC ("SWN") for total consideration of $124.8 million. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment.

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, 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’s (“Transco”) capacity lease, providing access to Mid-Atlantic markets. The Tioga Pathway Project has a target in-service date in late calendar 2026 and a preliminary cost estimate of approximately $90 million. The Tioga Pathway Project is discussed in more detail in the Capital Resources and Liquidity section that follows.

From a rate perspective, Distribution Corporation, in its Pennsylvania jurisdiction, reached a settlement with the parties to its rate case proceeding. On June 15, 2023, the PaPUC issued an order adopting the settlement in full. The settlement authorized an increase in Distribution Corporation's annual base rate operating revenues of $23 million that became effective August 1, 2023. Distribution Corporation also filed a rate case proceeding with the NYPSC in its New York jurisdiction on October 31, 2023 seeking an increase of $88.8 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024. In addition, Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023. For further discussion of Distribution Corporation and Supply Corporation rate matters, refer to the Rate Matters section below.

From a financing perspective, on June 30, 2022, the Company entered into a 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under a Credit Agreement (as amended from time to time, the "Credit Agreement"). The 364-Day Credit Agreement provided an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company used the proceeds for general corporate purposes, which included using $150.0 million for the November 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date in March 2023. In March 2023, the Company utilized short-term borrowings and cash on hand to redeem the remaining long-term debt that had maturity dates in March 2023, which included $350.0 million of 3.75% notes and $49.0 million of 7.395% notes.

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On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. The proceeds of this debt issuance were used for general corporate purposes, including to repay all indebtedness under the $250.0 million unsecured committed delayed draw term loan under the 364-Day Credit Agreement mentioned above.

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 fiscal 2024. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures and rising interest rates, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs as discussed above.

In early 2023, turmoil with certain financial institutions created uncertainty in the economy. While the Company was not directly impacted, it continues to closely monitor any potential future impacts on the business. The Company has a diverse group of twelve banks that participate in its multi-year credit facility. All of these banks have solid investment grade credit ratings. Additionally, the Company regularly reviews the credit quality of its hedging counterparties, those that provide credit support for customers, and any other material counterparties, and has not identified any material risks as a result of the current economic uncertainty.

CRITICAL ACCOUNTING ESTIMATES

The Company has prepared its consolidated financial statements in conformity with GAAP. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Company’s most critical accounting estimates, which are defined as those estimates whereby judgments or uncertainties could affect the application of accounting policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company’s significant accounting policies, refer to Item 8 at Note A — Summary of Significant Accounting Policies.

Oil and Gas Exploration and Development Costs.  In the Company's Exploration and Production segment, gas and oil property acquisition, exploration and development costs are capitalized under the full cost method of accounting, with natural gas properties in the Appalachian region being the primary component of these capitalized costs 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 8 at Note B — Asset Acquisitions and Divestitures. Under this accounting methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.

Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the full cost method of accounting (on a units-of-production basis). Unproved properties are excluded from the depletion calculation until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.

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In addition to depletion under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying 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 (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in natural gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment charge must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. At September 30, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $794.7 million. The 12-month average of the first day of the month price for natural gas for each month during 2023, based on the quoted Henry Hub spot price for natural gas, was $3.42 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 2023. 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 September 30, 2023 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's oil and gas properties by approximately $442.9 million (after-tax), which would not have resulted in an impairment charge. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

It is difficult to predict what factors could lead to future non-cash impairments under the SEC’s full cost ceiling test. As discussed above, fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in natural gas prices have an impact on the amount of the ceiling at any point in time.

As discussed above, the full cost method of accounting provides a ceiling to the amount of costs that can be capitalized in the full cost pool. In accordance with current authoritative guidance, the future cash outflows associated with plugging and abandoning wells are excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation.

Regulation.  The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to the FASB authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting principles for certain types of rate-regulated activities provides that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the

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Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the Consolidated Statement of Income for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company’s regulatory assets and liabilities, refer to Item 8 at Note F — Regulatory Matters.

RESULTS OF OPERATIONS

EARNINGS

2023 Compared with 2022

The Company's earnings were $476.9 million in 2023 compared with earnings of $566.0 million in 2022. The decrease in earnings of $89.1 million was a result of lower earnings in all reportable segments, as well as losses in the Corporate and All Other categories. In the discussion that follows, all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings were impacted by the following events in 2022:

2022 Events

•The reversal of a deferred tax valuation allowance of $24.9 million recorded in the Exploration and Production and Gathering segments, which increased earnings in 2022.

•A $28.4 million remeasurement of accumulated deferred income taxes, primarily in the Exploration and Production and Gathering segments, related to a reduction in the Pennsylvania state corporate income tax rate that was signed into law in July 2022, which increased earnings in 2022.

•A gain recognized on the sale of Seneca's California assets of $12.7 million ($9.5 million after-tax) recorded during 2022 in the Exploration and Production segment related to a portion of the sale price that was applied to assets that were not subject to the full cost method of accounting.

•A loss of $44.6 million ($33.3 million after-tax) recorded during 2022 in the Exploration and Production segment related to the termination of this segment's remaining crude oil derivative contracts as a result of the sale of Seneca's California assets.

•Transaction and severance costs of $9.7 million ($7.2 million after-tax) incurred during 2022 in the Exploration and Production segment related to the sale of Seneca's California assets.

•The reduction of an OPEB regulatory liability that increased earnings by $18.5 million ($14.6 million after-tax) recorded during 2022 in the Utility segment in accordance with a regulatory proceeding in Distribution Corporation's Pennsylvania service territory.

Earnings (Loss) by Segment

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EXPLORATION AND PRODUCTION

Revenues

Exploration and Production Operating Revenues

Production

Average Prices

(1)Oil revenue and weighted average oil price after hedging for the year ended September 30, 2022 excludes a loss on discontinuance of crude oil cash flow hedges of $44.6 million. This loss is presented in other revenue in the table above.

(2)Prices for the year ended September 30, 2023 are not applicable (N/A) as a result of the sale of Seneca's West Coast assets in June 2022.

(3)Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note J — Financial Instruments in Item 8 of this report.

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2023 Compared with 2022

Operating revenues for the Exploration and Production segment decreased $52.0 million in 2023 as compared with 2022. Gas production revenue after hedging increased $18.4 million primarily due to a 29.4 Bcf increase in gas production offset by a $0.16 per Mcf decrease in the weighted average realized price of gas after hedging. The increase in gas production was largely due to new Marcellus and Utica wells in the Appalachian region. Oil production revenue after hedging decreased $111.3 million mainly attributable to the sale of California assets at June 30, 2022. In addition, other revenue increased $43.3 million and plant revenue decreased $2.3 million. The increase in other revenue was primarily attributable to the non-recurrence of a loss on the discontinuance of crude oil cash flow hedges as a result of the sale of California assets combined with the non-recurrence of royalty shut-in payments made in 2022 in accordance with lease agreements. These increases to other revenue were partially offset by decreases to temporary capacity release revenue and a decrease in operating revenue from this segment's water treatment plants. Finally, the decrease in gas processing plant revenues was mainly attributable to the sale of California assets combined with declining gas pricing.

Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.

Earnings

2023 Compared with 2022

The Exploration and Production segment’s earnings for 2023 were $232.3 million, a decrease of $73.8 million when compared with earnings of $306.1 million for 2022. The sale of California assets on June 30, 2022 was a large factor in the earnings variance year over year. As a result of the sale, 2023 earnings decreased due to lower oil production ($88.1 million) and the non-recurrence of a gain that was recognized on the sale of Seneca’s California non-full cost pool assets ($9.5 million). However, these factors were partially offset by the non-recurrence of a 2022 loss related to the discontinuance of its crude oil cash flow hedges ($33.3 million) and 2022 transaction and severance costs associated with the sale ($7.2 million). There was also a lower unrealized loss recognized in 2023 ($0.7 million) on contingent consideration received as part of the California asset sale as compared to the unrealized loss that was recognized in 2022 ($3.2 million) on that contingent consideration. Other factors impacted by the sale included lower lease operating and transportation expenses ($24.0 million), lower other operating expenses ($11.1 million), and lower other taxes ($6.0 million). Excluding the impact of the California sale, lease operating and transportation costs in the Appalachian region increased year over year. Other operating costs were also impacted by the non-recurrence of abandonment costs recognized in 2022 for certain offshore Gulf of Mexico wells that were formerly owned by Seneca, and other taxes was also impacted by lower Impact Fees in the Appalachain region. Aside from the earnings impact of these items, the earnings decrease reflected lower natural gas prices after hedging ($48.4 million), lower other revenue ($1.1 million) and lower gas processing plant revenue ($1.8 million), all of which are discussed above. Other factors that decreased earnings included higher depletion expense ($26.1 million), higher interest expense ($0.7 million) and higher income tax expense ($3.4 million). In 2022, the Exploration and Production segment reversed a valuation allowance ($28.6 million) on deferred tax assets related to certain state net operating loss and credit carryforwards as these deferred tax assets are now expected to be realized in the future. The Exploration and Production segment also recorded an income tax benefit ($16.2 million) in 2022 from the remeasurement of deferred income taxes related to a state corporate income tax rate reduction in Pennsylvania that was signed into law in July 2022. The law reduces the Pennsylvania corporate income tax rate to 8.99% for fiscal 2024, and starting with fiscal 2025, the rate is further reduced by 0.5% annually until it reaches 4.99% for fiscal 2032. Partially offsetting these items, the Exploration and Production segment had higher natural gas production ($62.9 million), and higher other income ($2.7 million).

The increase in depletion expense was primarily due to the increase in production, combined with a $0.06 per Mcfe increase in the depletion rate. The year over year increase in the depletion rate was mainly driven by higher capitalized costs and an increase in future development costs related to proved undeveloped wells. The increase in interest expense can largely be attributed to higher average interest rates on short-term and long-term borrowings offset partially by lower intercompany long-term debt balances. The increase in income tax expense was primarily driven by a prior-year benefit realized from the Enhanced Oil Recovery tax credit, which

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did not recur in the current year as a result of the sale of the California assets. The increase in other income was attributable to higher interest income, as well as non-service pension and post-retirement income in 2023 compared to non-service pension and post-retirement benefit costs in 2022.

PIPELINE AND STORAGE

Revenues

Pipeline and Storage Operating Revenues

Pipeline and Storage Throughput — (MMcf)

2023 Compared with 2022

Operating revenues for the Pipeline and Storage segment increased $2.1 million in 2023 as compared with 2022. The increase in operating revenues was primarily due to an increase in transportation revenues of $1.3 million, an increase in storage revenues of $0.4 million and an increase in other revenues of $0.5 million. The increase in transportation revenues was primarily attributable to new demand charges for transportation service from Supply Corporation's FM100 Project, which was placed into service in December 2021. The 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. An increase in short-term contracts also contributed to the increase in transportation revenues. These increases were partially offset by a decline in revenues associated with miscellaneous contract expirations and revisions. The increase in other revenues primarily reflects proceeds received during the quarter ended September 30, 2023 as a result of a contract buyout.

Transportation volume increased by 22.6 Bcf in 2023 as compared with 2022, primarily due to an increase in short-term contracts, as well as an increase in volume from the FM100 Project. These increases were partially offset by certain contract expirations during fiscal 2023. 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 majority of Supply Corporation's and Empire's transportation and storage contracts allow either party to terminate the contract upon six or twelve months' notice effective at the end of the primary term and include "evergreen" language that allows for annual term extension(s). The Pipeline and Storage segment's contracted transportation and storage capacity with both affiliated and unaffiliated shippers is expected to remain relatively constant in fiscal 2024.

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Earnings

2023 Compared with 2022

The Pipeline and Storage segment’s earnings in 2023 were $100.5 million, a decrease of $2.1 million when compared with earnings of $102.6 million in 2022.  The decrease in earnings was primarily due to an increase in operating expenses ($5.2 million) and an increase in depreciation expense ($2.5 million). The increase in operating expenses was primarily due to higher personnel costs, higher pipeline integrity costs and an increase in compressor maintenance costs. The increase in depreciation expense was primarily due to incremental depreciation from the FM100 Project. These earnings decreases were partially offset by the impact of higher operating revenues ($1.7 million), as discussed above, combined with higher other income ($3.6 million). The increase in other income is primarily due to a higher weighted average interest rate on intercompany short-term notes receivables along with higher non-service pension and post-retirement benefit income. This was partially offset by a decrease in allowance for funds used during construction (equity component) related to the construction of the FM100 Project along with an annual adjustment that was recorded during the current fiscal year.

GATHERING

Revenues

Gathering Operating Revenues

Gathering Volume — (MMcf)

2023 Compared with 2022

Operating revenues for the Gathering segment increased $15.5 million in 2023 as compared with 2022, which was driven primarily by a 34.0 Bcf increase in gathered volume. Gathered volume on the Tioga and Clermont gathering systems increased 36.3 Bcf and 7.1 Bcf, respectively, partially offset by a decrease of 9.4 Bcf on the Trout Run gathering system. The net increase in gathered volume can be attributed to the increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems. All references to the Tioga gathering system in this operating revenues discussion and the earnings discussion that follows include the revenues, volume and earnings of the gathering system owned by NFG Midstream Covington, LLC (Covington), which includes the gathering system previously owned by NFG Midstream Wellsboro, LLC (Wellsboro). Wellsboro was merged into Covington effective August 31, 2023. The merger of Wellsboro into Covington reflects the completion of a pipeline that connects the two systems.

Earnings

2023 Compared with 2022

The Gathering segment’s earnings in 2023 were $99.7 million, a decrease of $1.4 million when compared with earnings of $101.1 million in 2022. Income taxes were a significant factor in the year over year variation. First, earnings were negatively impacted by the non-recurrence of an income tax benefit ($11.9 million) during the quarter ended September 30, 2022 from the remeasurement of deferred income taxes related to a state corporate income tax rate reduction in Pennsylvania that was signed into law in July 2022 (as discussed above, in the Exploration and Production segment). This segment also experienced an increase in income tax expense ($1.0 million) due to higher state income tax expense. Partially offsetting these factors, earnings benefited from the non-recurrence of deferred income tax expense ($3.7 million) recognized during the quarter ended

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September 30, 2022 as an offset to the Exploration and Production segment's reversal of the deferred tax asset valuation allowance. This offset is a result of the Gathering and Exploration and Production segments' subsidiaries filing a combined state tax return. In addition to these income tax variations, earnings decreased due to higher operating expenses ($4.9 million) and higher depreciation expense ($1.4 million). The increase in operating expenses was largely attributable to higher outside service costs associated with preventative maintenance overhauls on the Clermont, Tioga and Trout Run gathering systems, higher leased compression expense on the Trout Run and Tioga gathering systems and higher labor-related costs across all of the gathering systems. The increase in depreciation expense was largely due to higher plant balances associated with the Tioga and Clermont gathering systems. These earnings decreases were partially offset by the impact of higher gathering revenues ($12.2 million) driven by the increase in gathered volume (discussed above). Additionally, earnings increased due to lower interest expense ($1.2 million) and higher other income ($0.6 million). The decrease in interest expense was primarily due to higher capitalized interest and lower interest on intercompany long-term borrowings associated with the Company's redemption of $500.0 million of 3.75% notes during 2023. The increase in other income is primarily due to lower non-service pension and post-retirement benefit expenses.

UTILITY

Revenues

Utility Operating Revenues

Utility Throughput — million cubic feet (MMcf)

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Degree Days

(1)Percents compare actual degree days to normal degree days and actual degree days to actual prior year degree days.

(2)Normal degree days changed from the NOAA 30-year degree days to NOAA 15-year degree days with the implementation of new base rates in Pennsylvania in August 2023.

2023 Compared with 2022

Operating revenues for the Utility segment increased $44.1 million in 2023 compared with 2022. The increase resulted from a $47.5 million increase in retail gas sales revenue and a $4.4 million increase in other revenues, which were partially offset by a $7.8 million decrease in transportation revenue. The increase in retail gas sales revenue was primarily due to an increase in the cost of gas sold (per Mcf), partially offset by a 2.9 Bcf decrease in throughput due to warmer weather during the winter months and a decrease in base rates. The decrease in base rates is related to a tariff filing approved by the NYPSC, which created a surcredit that temporarily eliminates pension and OPEB cost recovery from base rates effective October 1, 2022. Additional details related to the regulatory proceeding are discussed in Item 8 at Note F — Regulatory Matters. The increase in other revenues was due to an increase in capacity release revenues and a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act. The decrease in transportation revenue resulted from a 3.0 Bcf decrease in throughput due to warmer weather and the decrease in base rates, as previously mentioned. The decreases in gas retail sales revenue and transportation revenue were partially offset by an increase in revenues earned under the system modernization and system improvement tracker mechanisms in Distribution Corporation's New York jurisdiction, which allow for the recovery of investments in leak prone pipe replacement.

Purchased Gas

The cost of purchased gas is one of the Company’s largest operating expenses. Annual variations in purchased gas costs are attributed directly to changes in gas sales volume, the price of gas purchased and the operation of purchased gas adjustment clauses. Distribution Corporation recorded $548.2 million and $498.0 million of Purchased Gas expense during 2023 and 2022, respectively. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation does not profit from fluctuations in gas costs. Purchased Gas expense recorded on the consolidated income statement matches the revenues collected from customers, a component of Operating Revenues on the consolidated income statement. Under mechanisms approved by the NYPSC in New York and the PaPUC in Pennsylvania, any difference between actual purchased gas costs and what has been collected from the customer is deferred on the consolidated balance sheet as either an asset, Unrecovered Purchased Gas Costs, or a liability, Amounts Payable to Customers. These deferrals are subsequently collected from the customer or passed back to the customer, subject to review by the NYPSC and the PaPUC. Absent disallowance of full recovery of Distribution Corporation’s purchased gas costs, such costs do not impact the profitability of the Company. Purchased gas costs impact cash flow from operations due to the timing of recovery of such costs versus the actual purchased gas costs incurred during a particular period. Distribution Corporation’s purchased gas adjustment clauses seek to mitigate this impact by adjusting revenues on either a quarterly or monthly basis.

Distribution Corporation contracts for firm long-term transportation and storage capacity services with rights-of-first-refusal from ten upstream pipeline companies including Supply Corporation for transportation and storage services and Empire, for transportation services. Distribution Corporation contracts for firm spot

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and term gas supplies with various producers, marketers and two local distribution companies to meet its gas purchase requirements. Additional discussion of the Utility segment’s gas purchases appears under the heading “Sources and Availability of Raw Materials” in Item 1.

Earnings

2023 Compared with 2022

The Utility segment’s earnings in 2023 were $48.4 million, a decrease of $20.5 million when compared with earnings of $68.9 million in 2022. The decrease in earnings was due in part to the impact of a proceeding in the Utility's Pennsylvania service territory during the quarter ended March 31, 2022 that allowed for a favorable one-time adjustment of $14.6 million to recognize the cumulative amount of OPEB income, previously deferred as a regulatory liability in that jurisdiction, which did not recur in 2023. In addition to the non-recurrence of this transaction, there was a decrease in OPEB income ($2.4 million) in the Utility's Pennsylvania service territory.

The earnings impact of the reduction in the New York jurisdiction's base rates in 2023 resulting from the NYPSC tariff filing related to pension and OPEB costs discussed above ($12.0 million), combined with an increase in operating costs ($2.0 million) associated with the elimination of fringe benefit credits being applied to service and non-service pension and OPEB costs, was offset by a decrease in other deductions associated with non-service pension and OPEB costs ($14.0 million). With the elimination of pension and OPEB expenses in customer rates, Distribution Corporation’s New York service territory did not recognize any pension and OPEB expenses during 2023 compared to the prior year when it recognized pension and OPEB expenses to match against the pension and OPEB amounts collected in base rates.

Other factors that contributed to the earnings decrease in the Utility segment included higher operating expenses ($6.8 million) and higher interest expense ($8.6 million). The increase in operating expenses was mainly due to higher personnel costs and outside services. The increase in interest expense was largely the result of a higher weighted average interest rate on intercompany short-term borrowings combined with higher average short-term debt balances. There were also several factors that helped to reduce the earnings decrease year over year. The Utility segment's earnings benefited from the impact of the system modernization and system improvement trackers in New York ($3.8 million), lower income tax expense ($3.5 million) in New York and Pennsylvania, of which $1.7 million relates to a methodology change for the repair and maintenance tax deduction in Pennsylvania, higher capacity release revenues ($1.6 million), and a regulatory adjustment ($1.5 million). The Utility's Pennsylvania service territory also benefited from new rates that went into effect August 1, 2023 ($0.8 million).

The impact of weather variations on earnings in the Utility segment's New York rate jurisdiction is largely mitigated by that jurisdiction's weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment's New York customers. For both 2023 and 2022, the WNC contributed approximately $4.8 million to earnings, as the weather was warmer than normal. Effective October 2023, the weather impact on cash flow in the Utility segment will also be mitigated by a WNC in its Pennsylvania rate jurisdiction.

ALL OTHER AND CORPORATE OPERATIONS

Earnings

2023 Compared with 2022

All Other and Corporate operations had a net loss of $4.0 million in 2023, an improvement of $8.7 million when compared with a net loss of $12.7 million in 2022. The improvement was primarily attributable to changes in unrealized gains and losses on investments in equity securities. In 2023, the Company recorded unrealized gains of $0.7 million, while in 2022, the Company recorded unrealized losses of $9.2 million. Other contributing factors include an increase in the cash surrender value of life insurance policies ($1.3 million), an increase in interest income on temporary cash investments ($1.3 million) and lower non-service pension and post-retirement benefit costs ($2.1 million). These changes were partially offset by a decrease in realized gains

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from sales of investments in equity securities ($2.9 million), as well as an increase in operating expenses as a result of an increase in professional services ($2.7 million).

OTHER INCOME (DEDUCTIONS)

Although most of the variances in Other Income (Deductions) are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis (amounts below are pre-tax amounts):

Net other income on the Consolidated Statements of Income was $18.1 million in 2023 compared to net other deductions of $1.5 million in 2022, for a net increase of $19.6 million. This was mostly due to changes in unrealized and realized gains and losses on investments in equity securities of $10.4 million, along with an increase in the cash surrender value of life insurance policies of $1.3 million. Higher interest income of $5.0 million also contributed to the increase, which resulted from an increase in interest on temporary cash investments, an increase in interest on a larger undercollection of gas costs over the prior year in Distribution Corporation and an increase in interest income earned on investments. The mark-to-market valuation adjustment for the contingent consideration received from the sale of Seneca's California assets in June 2022 was a loss of $0.9 million during 2023 as compared to a loss of $4.4 million during 2022. There was also a $1.9 million increase in non-service pension and post-retirement benefit income year over year. Offsetting these increases was a $2.3 million reduction in allowance for funds used during construction.

INTEREST CHARGES

Although most of the variances in Interest Charges are discussed in the earnings discussion by segment above, the following is a summary on a consolidated basis (amounts below are pre-tax amounts):

Interest on long-term debt decreased $8.6 million in 2023 as compared to 2022. The Company redeemed $150.0 million of the $500.0 million 3.75% notes in November 2022. In addition, $350.0 million of $500.0 million 3.75% notes and $49.0 million of 7.395% notes were redeemed in March 2023. These redemptions were partially offset by the issuance of $300.0 million of 5.50% notes in May 2023.

Other interest expense increased $10.1 million in 2023 as compared to 2022. The increase was primarily due to higher weighted average interest rates for 2023 partially offset by lower average short-term debt balances in 2023 compared to 2022.

CAPITAL RESOURCES AND LIQUIDITY

The primary sources and uses of cash during the last two years are summarized in the following condensed statement of cash flows:

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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 2024, cash provided by operating activities is forecasted to be lower than 2023 largely due to a decrease in working capital sources, but is expected to be more than enough to fund the Company's capital expenditures. Looking forward to 2025, 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 cash on hand and short-term and long-term borrowings. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.

OPERATING CASH FLOW

Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, deferred income taxes, the reduction of an other post-retirement regulatory liability and stock-based compensation.

Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. 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 Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire. Prior to October 2023, the weather impact on cash flow in the Utility segment was mitigated by a WNC solely in its New York rate jurisdiction. However, effective October 2023, the weather impact on cash flow in the Utility segment will also be mitigated by a WNC in its Pennsylvania rate jurisdiction. Refer to Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) for additional discussion.

Cash provided by operating activities in the Exploration and Production segment may vary from year to year as a result of changes in the commodity prices of natural gas as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and no cost collars, in an attempt to manage this energy commodity price risk.

The Company, in its Utility segment and Exploration and Production segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for additional discussion concerning these contractual commitments as well as the amounts of future gas purchase, transportation and storage contract commitments expected to be incurred during the next five years and thereafter. Also refer to Item 8 at Note D — Leases for a discussion of the Company’s operating lease arrangements and a schedule of lease payments during the next five years and thereafter.

Net cash provided by operating activities totaled $1,237.1 million in 2023, an increase of $424.6 million compared with the $812.5 million provided by operating activities in 2022. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Exploration and Production segment and Utility segment. The increase in the Exploration and Production segment is primarily due to higher cash receipts from natural gas production, net of royalty and working interests. The increase in the Utility segment is primarily due to the timing of gas cost recovery and the timing of customer receivable balance collections.

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INVESTING CASH FLOW

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets, including non-cash capital expenditures, totaled $1.12 billion and $829.4 million in 2023 and 2022, respectively. The table below presents these expenditures:

(1)The year ended September 30, 2023 includes $124.8 million related to the acquisition of upstream assets acquired from SWN. The acquisition cost is reported as a component of Acquisition of Upstream Assets on the Consolidated Statement of Cash Flows.

(2)2023 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $43.2 million, $31.8 million, $20.6 million and $13.6 million, respectively, of non-cash capital expenditures.

(3)2022 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $83.0 million, $15.2 million, $10.7 million and $11.4 million, respectively, of non-cash capital expenditures.

Exploration and Production

In 2023, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures in the Appalachian region and included $292.6 million in the Marcellus Shale area and $430.7 million in the Utica Shale area. These amounts included approximately $342.0 million spent to develop proved undeveloped reserves.

On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN for total consideration of $124.8 million. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment.

Other 2023 acquisitions included the acquisition of certain upstream assets located in Lycoming County in Northeast Pennsylvania for total consideration of $11.5 million as well as the acquisition of undeveloped acreage in Tioga County, Pennsylvania for $13.6 million. The acquisition in Lycoming County included 1,145 net acres and the acquisition in Tioga County included 4,222 net acres. Both transactions were accounted for as asset acquisitions and, as such, the purchase price for each transaction was allocated to property, plant and equipment. The cost of these acquisitions is reported as a component of Capital Expenditures on the Consolidated Statement of Cash Flows.

In 2022, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $547.1 million for the Appalachian region (including $161.4 million in the Marcellus Shale area and $370.6 million in the Utica Shale area) and $18.7 million for the

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West Coast region. These amounts included approximately $154.3 million spent to develop proved undeveloped reserves.

Pipeline and Storage

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

The Pipeline and Storage segment’s capital expenditures for 2022 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions. In addition, the Pipeline and Storage segment capital expenditures for 2022 include expenditures related to Supply Corporation's FM100 Project ($25.2 million).

Gathering

The majority of the Gathering segment's capital expenditures for 2023 included expenditures related to the continued expansion of Midstream Company's Clermont, Tioga and Trout Run gathering systems, as discussed below. The Tioga gathering system refers to the gathering system owned by NFG Midstream Covington, LLC (Covington), which includes the gathering system previously owned by NFG Midstream Wellsboro, LLC (Wellsboro). Wellsboro was merged into Covington effective August 31, 2023. The merger of Wellsboro into Covington reflects the completion of a pipeline that connects the two systems. Midstream Company spent $20.7 million, $71.2 million and $10.8 million, respectively, in 2023 on the development of the Clermont, Tioga and Trout Run gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

The majority of the Gathering segment's capital expenditures for 2022 included expenditures related to the continued expansion of Midstream Company's Clermont, Covington, Trout Run and Wellsboro gathering systems. Midstream Company spent $20.9 million, $27.0 million, $4.9 million and $2.3 million in 2022 on the development of the Clermont, Covington, Trout Run and Wellsboro gathering systems, respectively. These expenditures were largely attributable to the installation of new in-field gathering pipelines in the Clermont gathering system, as well as the continued expansion of centralized station facilities, including increased compression horsepower at the Clermont, Trout Run, and Wellsboro gathering systems. In Covington, expenditures were largely attributable to the installation of in-field gathering pipelines and upgraded station facilities related to new development.

Utility

The majority of the Utility segment’s capital expenditures for 2023 and 2022 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.

Other Investing Activities

In October 2021, the Company sold $30 million of fixed income mutual fund shares held in a grantor trust that was established for the benefit of Pennsylvania ratepayers. The proceeds were used in the Utility segment’s Pennsylvania service territory to fund a one-time customer bill credit of $25 million in October 2021 for previously overcollected OPEB expenses and the first year installment of a 5-year pass back of an additional $29 million in previously overcollected OPEB expenses in accordance with new rates that went into effect on October 1, 2021. In October 2022, the Company sold an additional $10 million of fixed income mutual fund shares held in the grantor trust. The proceeds from this sale were used to fund the second year installment of the 5-year pass back of overcollected OPEB expenses, as well as to diversify a portion of grantor trust investments into lower risk money market mutual fund shares. Please refer to the Rate Matters section that follows for additional discussion of this matter.

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In March 2022, the Company completed the sale of certain oil and gas assets located in Tioga County, Pennsylvania effective as of October 1, 2021. The Company received net proceeds of $13.5 million from this sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. 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.

On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which were in the Exploration and Production segment, 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. The fair value of the contingent consideration was $7.3 million at September 30, 2023. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 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. 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.

Estimated Capital Expenditures

The Company’s estimated capital expenditures for the next three years are:

(1)Includes estimated expenditures for the years ended September 30, 2024, 2025 and 2026 of approximately $315 million, $225 million and $120 million, respectively, to develop proved undeveloped reserves. The Company is committed to developing its proved undeveloped reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting.

(2)Includes estimated expenditures for the years ended September 30, 2024, 2025, and 2026 of approximately $115 million, $115 million and $120 million, respectively, for system modernization and safety to enhance the reliability and safety of the system and reduce emissions.

Exploration and Production

Capital expenditures for the Exploration and Production segment in 2024 through 2026 are expected to be primarily well drilling and completion expenditures in the Appalachian region.

Pipeline and Storage

Capital expenditures for the Pipeline and Storage segment in 2024 through 2026 are expected to include: the replacement and modernization of transmission and storage facilities, the reconditioning of storage wells, improvements of compressor stations and emissions reduction initiatives, as well as capital expenditures related to system expansion.

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In addition, due to the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, specifically in the Marcellus and Utica Shale producing areas, Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems. An expansion and modernization project where the Company has forecasted a significant amount of investment in preliminary survey and investigation costs and/or capital expenditures in 2024 through 2026, and where a precedent agreement has been executed, is discussed below.

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’s (“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. Supply Corporation expects to file a Section 7(c) application with the FERC in the second half of calendar 2024. The Tioga Pathway project has a projected in-service date of late calendar year 2026 and an estimated capital cost of approximately $90 million. The majority of these expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. As of September 30, 2023, less than $0.1 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at September 30, 2023.

Gathering

The majority of the Gathering segment capital expenditures in 2024 through 2026, included in the table above, are expected to be for construction and expansion of gathering systems, as discussed below. The Gathering segment primarily invests capital to support Seneca's drilling and completion activity in their long-term development plan. Seneca has shifted a larger share of its forward-looking activity from its Western Development Area to Tioga County, Pennsylvania. As a result, the Gathering segment is expecting to see near-term increases in capital expenditures as it constructs the necessary infrastructure to support Seneca's activity in the region.

Utility

Capital expenditures for the Utility segment in 2024 through 2026 are expected to be concentrated in the areas of main and service line improvements and replacements that will enhance the reliability and safety of the system, emission reduction initiatives and, to a lesser extent, the purchase of new equipment.

Project Funding

During fiscal 2023 and 2022, capital expenditures were funded with cash from operations and short-term debt. Capital expenditures in fiscal 2022 were also funded with proceeds from the sale of the Company's California assets. 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 recovery in the Utility segment.

In the Exploration and Production segment, the Company has entered into contractual obligations to support its development activities and operations in Pennsylvania, including hydraulic fracturing and other well completion services, well tending services, well workover activities, tubing and casing purchases, production equipment purchases, water hauling services and contracts for drilling rig services. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for the amounts of contractual obligations expected to be incurred during the next five years and thereafter to support the Company’s exploration and development activities. These amounts are largely a subset of the estimated capital expenditures for the Exploration and Production segment shown above.

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The Company, in its Pipeline and Storage segment, Gathering segment and Utility segment, has entered into several contractual commitments associated with various pipeline, compressor and gathering system modernization and expansion projects. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for the amounts of contractual commitments expected to be incurred during the next five years and thereafter associated with the Company’s pipeline, compressor and gathering system modernization and expansion projects. These amounts are a subset of the estimated capital expenditures for the Pipeline and Storage segment, Gathering segment and Utility segment that are shown above.

The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive natural gas properties, accelerated development of existing natural gas properties, natural gas storage and transmission facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. The amounts are also subject to modification for opportunities involving emission reductions and/or energy transition including investments directly related to low- and no-carbon fuels. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s business segments depends, to a large degree, upon market and regulatory conditions as well as legislative actions.

FINANCING CASH FLOW

Consolidated short-term debt increased $227.5 million, to a total of $287.5 million, when comparing the balance sheet at September 30, 2023 to the balance sheet at September 30, 2022. The maximum amount of short-term debt outstanding during the year ended September 30, 2023 was $422.3 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, asset purchases, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. During fiscal 2023, the Company repaid $549.0 million of long-term debt with maturity dates in March 2023 and issued $300.0 million of additional long-term debt in May 2023. The net reduction in long-term debt resulted in an increase in the short-term debt balance. As of September 30, 2023, the Company had outstanding commercial paper of $287.5 million. The Company did not have any short-term notes payable to banks as of September 30, 2023.

On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the "Credit Agreement") with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. The Credit Agreement provides a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027.

On June 30, 2022, the Company entered into a 364-Day Credit Agreement (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 provided an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company used the proceeds for general corporate purposes, which included using $150.0 million for the November 25, 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date of March 1, 2023. All indebtedness under the 364-Day Credit Agreement was repaid on May 18, 2023.

The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future.

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The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement, which provides 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 July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at September 30, 2023, $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 twelve banks under the initial Credit Agreement. The amendment further modified 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 consolidated 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 September 30, 2023, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement was 0.46. The constraints specified in the Credit Agreement would have permitted an additional $3.17 billion in short-term and/or long-term debt to be outstanding at September 30, 2023 before the Company’s debt to capitalization ratio exceeded 0.65.

A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. 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. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.

On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $297.3 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded. The proceeds of this debt issuance were used for general corporate purposes, including to repay all indebtedness under the $250.0 million unsecured committed delayed draw term loan under the 364-Day Credit Agreement.

None of the Company's long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period. The Current Portion of Long-Term Debt at September 30, 2022 consisted of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes, that each had maturity dates in March 2023. The Company utilized short-term borrowings and cash on hand to repay $150.0 million of these maturities in November 2022 and the remaining $399.0 million in March 2023. As of September 30, 2023, the future

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contractual obligations related to aggregate principal amounts of long-term debt, including interest expense, maturing during the next five years and thereafter are as follows: $111.9 million in 2024, $605.9 million in 2025, $565.4 million in 2026, $640.4 million in 2027, $327.9 million in 2028, and $535.7 million thereafter. Refer to Item 8 at Note H — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense. Principal payments of long-term debt are a component of cash used in financing activities while interest payments on long-term debt are a component of cash used in operating activities.

The Company’s embedded cost of long-term debt was 4.69% at September 30, 2023 and 4.48% at September 30, 2022. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.

Under the Company's existing indenture covenants at September 30, 2023, the Company would have been permitted to issue up to a maximum of approximately $3.43 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by the debt to capitalization ratio constraint under the Company's Credit Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

The Company’s 1974 indenture pursuant to which $50.0 million (or 2.1%) of the Company’s long-term debt (as of September 30, 2023) 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.

OTHER MATTERS

In addition to the environmental and other matters discussed in this Item 7 and in Item 8 at Note L — Commitments and Contingencies, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

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”). The Northern Access project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. The

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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, which is the subject of an ongoing appeal at the U.S. Court of Appeals for the D.C. Circuit. 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, including the completion of ongoing litigation. As of September 30, 2023, approximately $55.9 million has been spent on the Northern Access project, including $24.3 million that has been spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet. The remaining $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2023.

The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan). During 2023, the Company did not make any contributions to the Retirement Plan. Estimated contributions to the Retirement Plan in 2024 will be in the range of zero to $5.0 million. For further discussion of the Company’s Retirement Plan, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the Retirement Plan has been closed to new participants since 2003. In that regard, the average remaining service life of active participants in the Retirement Plan is approximately 6 years.

The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits. The Company has been making contributions to its VEBA trusts and/or 401(h) accounts over the last several years and does not anticipate making contributions to the VEBA trusts and/or 401(h) accounts in the near term. However, this will be subject to future review. During 2023, the Company did not make any contributions to its VEBA trusts. However, the Company made direct payments of $0.2 million to retirees not covered by the VEBA trusts and 401(h) accounts during 2023. The Company does not expect to make any contributions to its VEBA trusts in 2024. For further discussion of the Company’s other post-retirement benefits, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the other post-retirement benefits provided by the Company have been closed to new participants since 2003. In that regard, the average remaining service life of active participants is approximately 4 years for those eligible for other post-retirement benefits.

The Company has made certain guarantees on behalf of its subsidiaries. The guarantees relate primarily to: (i) obligations under derivative financial instruments, which are included on the Consolidated Balance Sheets in accordance with the authoritative guidance (see Item 7, MD&A under the heading “Critical Accounting Estimates - Accounting for Derivative Financial Instruments”); and (ii) other obligations which are reflected on the Consolidated Balance Sheets. The Company believes that the likelihood it would be required to make payments under the guarantees is remote.

MARKET RISK SENSITIVE INSTRUMENTS

Energy Commodity Price Risk

The Company uses various derivative financial instruments (derivatives), including price swap agreements and no cost collars, as part of the Company’s overall energy commodity price risk management strategy in its Exploration and Production segment. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the Company would receive from, or pay to, the respective counterparties at September 30, 2023 to terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas transactions that are related to the financial instruments.

On July 21, 2010, the Dodd-Frank Act was signed into law.  The Dodd-Frank Act required the CFTC, SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation, and includes provisions related to the swaps and over-the-counter derivatives markets that are designed to promote transparency, mitigate systemic risk and protect against market abuse.  Although regulators have adopted

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several final regulations, other rules that may impact the Company have yet to be finalized. Rules adopted by the CFTC and other regulators could adversely impact the Company. While many of those rules place specific conditions on the operations of swap dealers rather than directly on the Company, concern remains that swap dealers with whom the Company may transact will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs. Some of those rules also may apply directly to the Company and adversely impact its ability to trade swaps and over-the-counter derivatives, whether due to increased costs, limitations on trading capacity or for other reasons. Additionally, given the enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and anti-disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business. Should the Company violate any laws or regulations applicable to our hedging activities, it could be subject to CFTC enforcement action and material penalties and sanctions. The Company cannot predict the impact that evolving application of the Dodd-Frank Act may have on its operations.

The authoritative guidance for fair value measurements and disclosures requires consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At September 30, 2023, 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.

The following tables disclose natural gas price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2023. At September 30, 2023, the Company had not entered into any natural gas price swap agreements extending beyond 2028.

Natural Gas Price Swap Agreements

At September 30, 2023, the Company would have paid its respective counterparties an aggregate of approximately $2.5 million to terminate the natural gas price swap agreements outstanding at that date.

At September 30, 2022, the Company had natural gas price swap agreements covering 207.3 Bcf at a weighted average fixed rate of $2.98 per Mcf.

No Cost Collars

The following table discloses the notional quantities, the weighted average ceiling price and the weighted average floor price for the no cost collars used by the Company to manage natural gas price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). At September 30, 2023, the Company had not entered into any natural gas no cost collars extending beyond 2027.

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At September 30, 2023, the Company would have received an aggregate of approximately $16.0 million to terminate the natural gas no cost collars outstanding at that date.

At September 30, 2022, the Company had no cost collars agreements covering 213.5 Bcf at a weighted average ceiling price of $4.24 per Mcf and a weighted average floor price of $3.40 per Mcf.

Foreign Exchange Risk

The Company uses foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. All of these transactions are forecasted.

The following table discloses foreign exchange contract information by expected maturity dates. The Company receives a fixed price in exchange for paying a variable price as noted in the Canadian to U.S. dollar forward exchange rates. Notional amounts (Canadian dollars) are used to calculate the contractual payments to be exchanged under contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2023. At September 30, 2023, the Company had not entered into any foreign currency exchange contracts extending beyond 2030.

At September 30, 2023, absent other positions with the same counterparties, the Company would have paid to its respective counterparties an aggregate of $1.3 million to terminate these foreign exchange contracts.

Refer to Item 8 at Note J — Financial Instruments for a discussion of the Company’s exposure to credit risk related to its derivative financial instruments.

Interest Rate Risk

The fair value of long-term fixed rate debt is $2.2 billion at September 30, 2023. This fair value amount is not intended to reflect principal amounts that the Company will ultimately be required to pay. The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt:

RATE MATTERS

Utility Operation

Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” As noted below, the New York division currently has a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through

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operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.

New York Jurisdiction

Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017 ("2017 Rate Order"). The 2017 Rate Order provided for a return on equity of 8.7% and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. On October 31, 2023, Distribution Corporation made a filing with the NYPSC seeking an increase of $88.8 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024 that includes the maximum suspension period permitted under the New York Public Service Law ("2023 Rate Filing"). The Company is also proposing, among other things, to continue its leak prone pipe replacement program and to implement a number of initiatives that will facilitate achievement of the emissions reduction goals of the Climate Leadership and Community Protection Act.

The 2017 Rate Order authorized the Company to recover approximately $15 million annually for pension and OPEB expenses from customers. Because the Company's future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July 2022, Distribution Corporation made a filing with the NYPSC to effectuate a temporary pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022. On September 16, 2022, the NYPSC issued an order approving the filing. With the implementation of this surcredit, Distribution Corporation ceased funding the Retirement Plan and its VEBA trusts in its New York jurisdiction. The 2023 Rate Filing proposes to keep the rate recovery of pension and OPEB costs at zero in the rate year and reflect the $15 million of savings in new base delivery rates.

On August 13, 2021, the NYPSC issued an order extending the date through which qualified pipeline replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (until March 31, 2023). On December 9, 2022, the Company filed a petition with the NYPSC to effectuate a system improvement tracker through which qualified pipeline replacement costs through September 30, 2024 would be tracked and recovered, and to recover certain deferred costs associated with the existing system modernization tracker, effective April 1, 2023. The NYPSC approved the petition by order dated March 17, 2023 contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to October 1, 2024. The 2023 Rate Filing proposes to stop accruing and collecting revenues under its current system modernization and system improvement trackers and shift those revenues into the Company’s new base delivery rates. In the absence of a multi-year rate plan settlement, the Company is requesting that it be allowed to reinstate a tracking mechanism similar to the existing system modernization tracker.

Pennsylvania Jurisdiction

Distribution Corporation’s delivery rates effective through July 31, 2023 in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007. On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $28.1 million. A settlement involving all active parties to the proceeding was reached and filed with the PaPUC on April 13, 2023. The settlement provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million. The PaPUC approved the settlement in full, without modification or correction, on June 15, 2023 and new rates went into effect on August 1, 2023.

Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC, Distribution Corporation reduced base rates by $7.7 million in order to stop collecting OPEB expenses from customers. It also began to refund to customers overcollected OPEB expenses in the amount of $50.0 million. All matters with respect to this tariff supplement were finalized on February 24, 2022 with the PaPUC's approval of an Administrative Law Judge's Recommended Decision. Concurrent with that decision, the Company discontinued regulatory accounting for OPEB expenses and recorded an $18.5 million adjustment during the quarter ended March 31,

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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 Company also increased customer refunds of overcollected OPEB expenses from $50.0 million to $54.0 million. All 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 filed a NGA Section 4 rate case at FERC on July 31, 2023 proposing rate increases to be effective February 1, 2024. The proposed rates reflect an annual cost of service of $385.4 million, a rate base of $1.32 billion and a proposed cost of equity of 15.12%. If the proposed rate increases finally approved at the end of the proceeding exceed the rates that were in effect at July 31, 2023, but are less than rates put into effect subject to refund on February 1, 2024, Supply Corporation would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2023, such lower rates will become effective prospectively from the effective date provided by the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at July 31, 2023.

Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1, 2025.

ENVIRONMENTAL MATTERS

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory requirements. In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and greenhouse gas reduction targets associated with the Company’s utility delivery system. In 2022, the Company began measuring progress against these reduction targets. The Company's ability to estimate accurately the time, costs and resources necessary to meet emissions targets may be impacted as environmental exposures, technology and opportunities change and regulatory and policy updates are issued.

For further discussion of the Company's environmental exposures, refer to Item 8 at Note L — Commitments and Contingencies under the heading “Environmental Matters.”

The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

Environmental Regulation

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in the United States. These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. For example, the federal Inflation Reduction Act of 2022 (IRA) legislation was signed into law on August 16, 2022. The IRA includes a methane charge that is expected to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, starting in calendar year 2024. This portion of the IRA is to be administered by the EPA and potential fees will begin with emissions reported for calendar year 2024. The EPA is the lead federal agency that regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented by the EPA impose stringent leak detection and repair requirements and address reporting and control of methane and volatile organic compound emissions. The Company must

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continue to comply with all applicable regulations. Additionally, a number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The NYPSC, for example, initiated a proceeding to consider climate-related financial disclosures at the utility operating company level, and the New York State legislature passed the CLCPA that mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. In May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to certain exemptions. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on the promulgation of final regulations and on regulatory treatment afforded in the process. The NYDEC has until January 1, 2024 to issue further rules and regulations implementing the CLCPA. The NYDEC, in conjunction with the New York State Energy Research and Development Authority, is also in the early phases of developing a cap-and-invest program in the state, which is anticipated to be effective in 2025. The above-enumerated initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. 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.

EFFECTS OF INFLATION

The Company’s operations are sensitive to increases in the rate of inflation because of its operational and capital spending requirements in both its regulated and non-regulated businesses. For the regulated businesses, recovery of increasing costs from customers can be delayed by the regulatory process of a rate case filing. For the non-regulated businesses, prices received for services performed or products produced are determined by market factors that are not necessarily correlated to the underlying costs required to provide the service or product.

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

The Company is including the following cautionary statement in this Annual Report on Form 10-K to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no

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assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:

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

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

3.The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets;

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

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

6.Changes in the price of natural gas;

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

8.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;

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

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

11.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;

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

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

14.The Company's ability to complete strategic transactions;

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

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

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

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

19.Uncertainty of natural gas reserve estimates;

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

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

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

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

24.Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to third-party outages;

25.Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or

26.Increasing costs of insurance, changes in coverage and the ability to obtain insurance.

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

Forward-looking and other statements in this Annual Report on Form 10-K regarding methane and greenhouse gas reduction plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current and forward-looking statements regarding methane and greenhouse gas emissions may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve and assumptions that are subject to change in the future.

INDUSTRY AND MARKET DATA DISCLOSURE

The market data and certain other statistical information used throughout this Form 10-K are based on independent industry publications, government publications or other published independent sources. Some data is also based on the Company's good faith estimates. Although the Company believes these third-party sources are reliable and that the information is accurate and complete, it has not independently verified the information.

Item 7 Management’s Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

The Company is a diversified energy company engaged principally in the production, gathering, transportation, storage and distribution of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current development activities are focused primarily in the Marcellus and Utica shales. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian basin to markets in the eastern United States and Canada. The Company's efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas customers in the Appalachian basin. The Company reports financial results for four business segments: Exploration and Production, Pipeline and Storage, Gathering, and Utility.

Corporate Responsibility

The Board of Directors and management recognize that the long-term interests of stockholders are served by considering the interests of customers, employees and the communities in which the Company operates. The Board retains risk oversight and general oversight of corporate responsibility, including environmental, social and governance (“ESG”) concerns, and any related health and safety issues that might arise from the Company’s operations. The Board’s Nominating/Corporate Governance Committee oversees and provides guidance concerning the Company’s practices and reporting with respect to corporate responsibility and ESG factors that are of significance to the Company and its stakeholders, and may also make recommendations to the Board regarding ESG initiatives and strategies, including the Company’s progress on integrating ESG factors into business strategy and decision-making.

Part of the Board and management’s strategic and capital spending decision process includes identifying and assessing climate-related risks and opportunities. Management reports quarterly to the Board on critical and potentially emerging risks, including climate-related risks, as part of the Enterprise Risk Management process. Since the Company operates an integrated business with assets being utilized for, and benefiting from, the production, transportation and consumption of natural gas, the Board and management consider physical and transitional climate risks, including policy and legal risks, technological developments, shifts in market conditions, including future natural gas usage, and reputational risks, and the impact of those risks on the Company’s business. In March 2022, the Company published its inaugural Climate Report, analyzing climate-related transitional and physical risks, and describing our strategy for addressing those risks, as well as the resiliency of that strategy under a carbon constrained scenario. The Company reviews and considers adjustments to its approach to capital investment in response to these transitional developments, with its long-term, returns-focused approach.

The Company recognizes the important role of ongoing system modernization and efficiency in reducing greenhouse gas emissions and remains focused on reducing the Company’s carbon footprint, with these efforts positioning natural gas, and the Company’s related infrastructure, to remain an important part of the energy complex. In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and greenhouse gas reduction targets associated with the Company’s utility delivery system. In 2022, the Company began measuring progress against these reduction targets. The Company also incorporated short-term and long-term executive compensation goals designed to incentivize and reward performance if reduction targets are met or exceeded. The Company's ability to estimate accurately the time, costs and resources necessary to meet these emissions reduction targets may change as environmental exposures and opportunities change, technology advances, and legislative and regulatory updates are issued.

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Fiscal 2022 Highlights

This Item 7, MD&A, provides information concerning:

1.The critical accounting estimates of the Company;

2.Changes in revenues and earnings of the Company under the heading, “Results of Operations;”

3.Operating, investing and financing cash flows under the heading “Capital Resources and Liquidity” and;

4.Other Matters, including: (a) 2022 and projected 2023 funding for the Company’s pension and other post-retirement benefits; (b) disclosures and tables concerning market risk sensitive instruments; (c) rate matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions; (d) environmental matters; and (e) effects of inflation.

The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report, which includes a comparison of our Results of Operations and Capital Resources and Liquidity for fiscal 2022 and fiscal 2021. For a discussion of the Company's earnings, refer to the Results of Operations section below. A discussion of changes in the Company’s results of operations from fiscal 2020 to fiscal 2021 has been omitted from this Form 10-K, but may be found in Item 7, MD&A, of the Company’s Form 10-K for the fiscal year ended September 30, 2021, filed with the SEC on November 19, 2021.

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. The Company pursued this sale given the strong commodity price environment and the Company's strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 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. 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. One project on Supply Corporation's system, referred to as the FM100 Project, upgraded a 1950’s era pipeline in northwestern Pennsylvania and created approximately 330,000 Dth per day of additional transportation capacity in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County, Pennsylvania to the Transcontinental Gas Pipe Line Company, LLC ("Transco") system at Leidy, Pennsylvania. Construction activities on the expansion portion of the FM100 Project are complete and the project was placed into service in December 2021. This project will provide incremental annual transportation revenues of approximately $50 million. The FM100 Project is discussed in more detail in the Capital Resources and Liquidity section that follows. For further discussion of the Pipeline and Storage segment's revenues and earnings, refer to the Results of Operations section below.

The Company's Exploration and Production segment continues to grow, as evidenced by an 8% growth in proved reserves from the prior year to a total of 4,172 Bcfe at September 30, 2022. Production increased 25.1 Bcfe during the fiscal year ended September 30, 2022 to a total of 352.5 Bcfe, and is expected to increase again in fiscal 2023. The December 2021 commencement of service for Seneca’s 330,000 Dth per day of incremental pipeline capacity on the Leidy South Project, which was the companion project of the Company's FM100 Project, contributed to the production growth in fiscal 2022. This incremental pipeline capacity provides Seneca with the ability to reach premium Transco Zone 6 (Non-New York) markets.

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On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the "Credit Agreement") with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. The Credit Agreement provides a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027.

On June 30, 2022, the Company entered into a new 364-Day Credit Agreement (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 elected to draw $250.0 million under the facility on October 27, 2022. The Company is using the proceeds for general corporate purposes, which will include the redemption in November of a portion of the Company's outstanding long-term debt maturing in March 2023. The Company does not anticipate long-term refinancing for the $250.0 million drawn under the facility or the maturing long-term debt in March 2023.

CRITICAL ACCOUNTING ESTIMATES

The Company has prepared its consolidated financial statements in conformity with GAAP. The preparation of these financial statements requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates. In the event estimates or assumptions prove to be different from actual results, adjustments are made in subsequent periods to reflect more current information. The following is a summary of the Company’s most critical accounting estimates, which are defined as those estimates whereby judgments or uncertainties could affect the application of accounting policies and materially different amounts could be reported under different conditions or using different assumptions. For a complete discussion of the Company’s significant accounting policies, refer to Item 8 at Note A — Summary of Significant Accounting Policies.

Oil and Gas Exploration and Development Costs.  In the Company's Exploration and Production segment, gas and oil property acquisition, exploration and development costs are capitalized under the full cost method of accounting, with natural gas properties in the Appalachian region being the primary component of these capitalized costs 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 8 at Note B — Asset Acquisitions and Divestitures. Under this accounting methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.

Proved reserves are estimated quantities of reserves that, based on geologic and engineering data, appear with reasonable certainty to be producible under existing economic and operating conditions. Such estimates of proved reserves are inherently imprecise and may be subject to substantial revisions as a result of numerous factors including, but not limited to, additional development activity, evolving production history and continual reassessment of the viability of production under varying economic conditions. The estimates involved in determining proved reserves are critical accounting estimates because they serve as the basis over which capitalized costs are depleted under the full cost method of accounting (on a units-of-production basis). Unproved properties are excluded from the depletion calculation until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.

In addition to depletion under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test

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represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying 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 (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in natural gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment charge must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. At September 30, 2022, the ceiling exceeded the book value of the oil and gas properties by approximately $3.2 billion. The 12-month average of the first day of the month price for natural gas for each month during 2022, based on the quoted Henry Hub spot price for natural gas, was $6.13 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 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 September 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 $2.9 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 impairments under the SEC’s full cost ceiling test. As discussed above, fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in natural gas prices have an impact on the amount of the ceiling at any point in time.

As discussed above, the full cost method of accounting provides a ceiling to the amount of costs that can be capitalized in the full cost pool. In accordance with current authoritative guidance, the future cash outflows associated with plugging and abandoning wells are excluded from the computation of the present value of estimated future net revenues for purposes of the full cost ceiling calculation.

Regulation.  The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to the FASB authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting principles for certain types of rate-regulated activities provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the income statement for the period in which the discontinuance of regulatory

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accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company’s regulatory assets and liabilities, refer to Item 8 at Note F — Regulatory Matters.

RESULTS OF OPERATIONS

EARNINGS

2022 Compared with 2021

The Company's earnings were $566.0 million in 2022 compared with earnings of $363.6 million in 2021. The increase in earnings of $202.4 million was primarily a result of higher earnings in all reportable segments, slightly offset by losses in the Corporate and All Other categories. In the discussion that follows, all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings were impacted by the following events in 2022 and 2021:

2022 Events

•The reversal of a deferred tax valuation allowance of $24.9 million recorded in the Exploration and Production and Gathering segments.

•A $28.4 million remeasurement of accumulated deferred income taxes, primarily in the Exploration and Production and Gathering segments, related to a reduction in the Pennsylvania state corporate income tax rate that was signed into law in July 2022.

•A gain recognized on the sale of Seneca's California assets of $12.7 million ($9.5 million after-tax) recorded during 2022 in the Exploration and Production segment related to a portion of the sale price that was applied to assets that were not subject to the full cost method of accounting.

•A loss of $44.6 million ($33.3 million after-tax) recorded during 2022 in the Exploration and Production segment related to the termination of this segment's remaining crude oil derivative contracts as a result of the sale of Seneca's California assets.

•Transaction and severance costs of $9.7 million ($7.2 million after-tax) incurred during 2022 in the Exploration and Production segment related to the sale of Seneca's California assets.

•The reduction of an OPEB regulatory liability that increased earnings by $18.5 million ($14.6 million after-tax) recorded during 2022 in the Utility segment in accordance with a regulatory proceeding in Distribution Corporation's Pennsylvania service territory.

2021 Events

•Non-cash impairment charges of $76.2 million ($55.2 million after-tax) recorded during 2021 for the Exploration and Production segment's oil and gas producing properties.

•A gain recognized on the sale of timber properties of $51.1 million ($37.0 million after-tax) recorded during 2021 in the Company's All Other category.

•A loss of $15.7 million ($11.4. million after-tax) recorded in the Exploration and Production and Gathering segments during 2021 for the premium paid on early redemption of long-term debt.

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Earnings (Loss) by Segment

EXPLORATION AND PRODUCTION

Revenues

Exploration and Production Operating Revenues

Production

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Average Prices

(1)Oil revenue and weighted average oil price after hedging for the year ended September 30, 2022 excludes a loss on discontinuance of crude oil cash flow hedges of $44.6 million. This loss is presented in other revenue in the table above.

(2)Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note J — Financial Instruments in Item 8 of this report.

2022 Compared with 2021

Operating revenues for the Exploration and Production segment increased $173.8 million in 2022 as compared with 2021. Gas production revenue after hedging increased $224.8 million primarily due to a $0.46 per Mcf increase in the weighted average price of gas after hedging coupled with a 28.9 Bcf increase in gas production. The increase in gas production was largely due to new Marcellus and Utica wells in the Appalachian region. Oil production revenue after hedging decreased $12.8 million primarily due to a 631 Mbbl decrease in crude oil production, partially offset by a $14.26 per Bbl increase in the weighted average price of oil after hedging. The decrease in oil production is mainly attributed to the sale of California assets at June 30, 2022. In addition, other revenue decreased $38.8 million and plant revenue increased $0.6 million. The decrease in other revenue was primarily attributed to a loss on the discontinuance of crude oil cash flow hedges related to the sale of California assets combined with royalty shut-in payments made in accordance with lease agreements. These were partially offset by a temporary capacity release of Leidy South and TC Pipeline transportation contracts. Finally, other revenue also increased from Highland Field Services water treatment plants acquired at the end of fiscal 2021.

Refer to further discussion of derivative financial instruments in the “Market Risk Sensitive Instruments” section that follows. Refer to the tables above for production and price information.

Earnings

2022 Compared with 2021

The Exploration and Production segment’s earnings for 2022 were $306.1 million, an increase of $204.2 million when compared with earnings of $101.9 million for 2021. The increase in earnings was primarily attributable to higher natural gas prices after hedging ($126.3 million), higher natural gas production ($51.3 million), and higher oil prices after hedging ($18.1 million). Additionally, a $55.2 million impairment was recorded during 2021 that did not recur during 2022. Certain deferred tax adjustments during 2022 also contributed to the earnings increase. The Exploration and Production segment reversed a valuation allowance ($28.6 million) on deferred tax assets related to certain state net operating loss and credit carryforwards as these deferred tax assets are now expected to be realized in the future. The Exploration and Production segment also recorded an income tax benefit ($16.2 million) from the remeasurement of deferred income taxes related to a state corporate income tax rate reduction in Pennsylvania that was signed into law in July 2022. The law

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reduces the Pennsylvania corporate income tax rate to 8.99% for fiscal 2024, and starting with fiscal 2025, the rate is further reduced by 0.5% annually until it reaches 4.99% for fiscal 2032.

In addition to the factors discussed above, the Exploration and Production segment's earnings were also impacted by the following factors. Factors that increased earnings included a 2022 gain ($9.5 million) that was recognized on the sale of the Exploration and Production segment's California non-full cost pool assets as well as a 2021 loss ($10.7 million) recognized for this segment's 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. Factors that reduced earnings included a loss related to the discontinuance of this segment's crude oil cash flow hedges ($33.3 million), which was driven by the sale of the California assets, lower crude oil production ($28.2 million), higher lease operating and transportation expenses ($13.1 million), higher depletion expense ($20.3 million), higher other operating expenses ($5.4 million), an unrealized loss on a derivative asset ($3.2 million), higher other taxes ($2.5 million) and a higher effective tax rate ($6.3 million). The Company also recorded transaction and severance costs ($7.2 million) during 2022 associated with the sale of the California assets. The increase in lease operating and transportation expenses was primarily due to increased gathering and transportation costs in the Appalachian region offset by lower costs in the West Coast region due to selling the assets on June 30, 2022. The increase in depletion expense was primarily due to the increase in production, combined with a $0.03 per Mcfe increase in the depletion rate. The increase in other operating expenses was primarily attributed to abandonment costs related to certain offshore Gulf of Mexico wells formally owned by the Company. In addition, the increase in other operating expenses was attributed to operating costs associated with the Highland Field Services water treatment plants acquired at the end of fiscal 2021. The unrealized loss on a derivative asset represents an adjustment to the contingent consideration received for the sale of the California assets. 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. The increase in the effective tax rate was primarily driven by a reduction to the valuation allowance recorded in fiscal 2021.

PIPELINE AND STORAGE

Revenues

Pipeline and Storage Operating Revenues