NATIONAL FUEL GAS CO

Previous wording

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.

Current wording

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. 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.

Previous wording

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.

Current wording

Other Matters, including: (a) 2025 and projected 2026 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; (e) new authoritative accounting and financial reporting guidance; and (f) effects of inflation.

Previous wording

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.

Current wording

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 2025 and fiscal 2024. 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 2023 to fiscal 2024 for the Utility segment, the Pipeline and Storage segment, and All Other and Corporate operations 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, 2024, filed with the SEC on November 22, 2024. Changes in the Integrated Upstream and Gathering segment’s results of operations from fiscal 2023 to fiscal 2024 have been included in this Form 10-K, which has been recast to reflect the treatment of the previously reported Exploration and Production segment and Gathering segment as one operating segment as a result of the Company’s change in segment reporting discussed above.

Previous wording

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.

Current wording

The Company’s Integrated Upstream and Gathering segment continues to grow, as evidenced by a 5% growth in proved reserves from the prior year to a total of 4,981 Bcfe at September 30, 2025. Production

Previous wording

The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation’s system, referred to as the Tioga Pathway Project, 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.

Current wording

The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation’s system, referred to as the Tioga Pathway Project, is an expansion and modernization project that would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC (“Transco”) capacity lease, providing access to Mid-Atlantic markets. On May 5, 2025, FERC issued the Section 7(b)/7(c) certificate for the project. Construction on the Tioga Pathway Project is expected to commence in early calendar 2026. This project has a target in-service date in late calendar 2026 and a preliminary cost estimate of approximately $101 million.

Previous wording

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.

Current wording

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

Previous wording

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

Current wording

As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its exploration and production properties and that book value is subject to a quarterly ceiling test. In addition to the non-cash impairment charges under the ceiling test that the Company recorded during fiscal 2024, the Company recorded a non-cash impairment charge under the ceiling test during the quarter ended December 31, 2024 of $108.3 million ($79.1 million after-tax). At September 30, 2025, June 30, 2025 and March 31, 2025, the ceiling exceeded the book value of the exploration and production properties, and thus, did not result in an impairment charge in any of these quarters. Please refer to the Critical Accounting Estimates section below for more details on this matter and a sensitivity analysis concerning commodity price changes.

Previous wording

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.

Current wording

The Company is a party to a syndicated Credit Agreement that provides a $1.0 billion unsecured committed revolving credit facility. In January 2025, the Company and the syndicate of banks under the Credit Agreement consented to a second one-year extension on the maturity date of the Credit Agreement, such that the Company has aggregate commitments available in the full amount of $1.0 billion through February 23, 2029. In May 2025, the number of lenders under the Credit Agreement increased to twelve as a new lender joined the syndicate, assuming a portion of an existing lender’s commitment.

Previous wording

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.

Current wording

The Company began repurchasing outstanding shares of its common stock during the quarter ended March 31, 2024 under a share repurchase program authorized by the Company’s Board of Directors. The program authorizes the Company to repurchase up to an aggregate amount of $200 million of its outstanding common stock in the open market or through privately negotiated transactions. During fiscal 2025, the Company executed transactions to repurchase 828,720 shares at an average price of $64.37 per share, for a total cost of $53.8 million (including broker fees and excise taxes). From inception to September 30, 2025, the Company has repurchased 1,974,979 shares under the share repurchase program at an average price of $59.70, for a total cost of $119.0 million (including broker fees and excise taxes). In light of the Company’s agreement to acquire CenterPoint Ohio’s natural gas utility, repurchases under the program have been suspended. The program has no fixed expiration date. These matters are discussed further in the Capital Resources and Liquidity section that follows.

Previous wording

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

Current wording

The Company expects to use cash from operations, short-term and/or long-term borrowings, and equity financing as needed to meet its financing needs for fiscal 2026, including the repayment of a $300.0 million delayed draw term loan that matures in February 2026 and any potential funding for the CenterPoint Ohio acquisition. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures, volatile interest rates and the ongoing impacts of federal policy changes, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs.

Previous wording

-36- 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.

Current wording

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.

Previous wording

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.

Current wording

Exploration and Development Costs. In the Company’s Integrated Upstream and Gathering segment, upstream property acquisition, exploration and development costs are accounted for under the full cost method of accounting. 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.

Previous wording

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

Current wording

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

Previous wording

-37- 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.

Current wording

-36- value of the reserves to their present value in any given period causes a reduction in future depletion expense. At September 30, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $1.1 billion (after-tax). The 12-month average of the first day of the month price for natural gas for each month during 2025, based on the quoted Henry Hub spot price for natural gas, was $3.10 per MMBtu. (Note: Because actual pricing of the Company’s producing properties varies 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 2025. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices in the twelve-month period used at September 30, 2025 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company’s exploration and production properties by approximately $677.2 million (after-tax), which would not have resulted in an impairment charge. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

Previous wording

The Company’s earnings were $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:

Current wording

The Company’s earnings were $518.5 million in 2025 compared to earnings of $77.5 million in 2024. The increase in earnings of $441.0 million was primarily the result of current year earnings recognized in the Integrated Upstream and Gathering segment compared to a prior year loss combined with higher earnings in the Pipeline and Storage, and Utility segments. A higher loss in the Corporate category partially offset these increases. 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 2025 and 2024:

Previous wording

•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.

Current wording

•Non-cash impairment charges of $473.1 million ($343.2 million after-tax) recorded during 2024 in the Integrated Upstream and Gathering 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.

Previous wording

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.

Current wording

Operating revenues for the Integrated Upstream and Gathering segment increased $4.3 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. Gathering revenue increased $1.6 million driven primarily by an increase in gathered volume in this segment’s eastern development areas (Trout Run and Tioga). The increase in gathered volume can be attributed to an increase in gross natural gas production by producers connected to the gathering systems. 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.

Previous wording

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.

Current wording

(1)Includes aggregate ceiling test impairments of $336.4 million recorded during the quarters ended June 30, 2024 and September 30, 2024 and a $6.8 million impairment of certain water disposal assets recorded during the quarter ended September 30, 2024.

Previous wording

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.

Current wording

Operating revenues for the Pipeline and Storage segment increased $15.2 million in 2025 as compared with 2024. For the twelve months ended September 30, 2025, the $12.3 million increase in transportation revenues and $4.4 million increase in storage revenues were 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. This increase was partially offset by the impact of a final true-up adjustment recorded during the year ended September 30, 2024 to the surcharge for pipeline safety and greenhouse gas costs that ended effective February 1, 2024. The increase in transportation revenues was also partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions. The $1.4 million decrease in other revenues primarily reflects lower cashout revenues, which are completely offset by purchased gas expense, and an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense.

Previous wording

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.

Current wording

Transportation volume increased by 26.9 Bcf in 2025 as compared with 2024, primarily due to an increase in volume from colder weather. This increase was partially offset by lower capacity utilization with certain contract shippers and certain contract expirations and revisions. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

Previous wording

-41- 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.

Current wording

(1)An impairment charge recognized during the year ended September 30, 2024 wrote down the carrying value of certain assets associated with Supply Corporation and Empire’s Northern Access project.

Previous wording

(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.

Current wording

(2)Normal degree days changed from NOAA 30-year degree days to NOAA 15-year degree days with the implementation of new base rates in New York effective October 2024.

Previous wording

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

Current wording

Operating revenues for the Utility segment increased $120.3 million in 2025 compared with 2024. The increase resulted from a $109.6 million increase in retail gas sales revenue, a $0.7 million increase in transportation revenue and a $10.0 million increase in other revenue. The increases in retail gas sales and transportation revenues reflect the impact of new base delivery rates in Distribution Corporation’s New York jurisdiction pursuant to a settlement approved by the NYPSC on December 19, 2024. Additional details regarding the base rate regulatory proceeding can be found in the Rate Matters section below. The increase in retail gas sales revenue also reflects higher revenues collected from customers for purchased gas costs resulting from a 9.3 Bcf increase in throughput mainly due to colder weather combined with an increase in the cost of gas sold (per Mcf). The increase in transportation revenue also reflects a 3.9 Bcf increase in throughput due primarily to colder weather, partially offset by the amortization of certain regulatory assets in accordance with the New York rate settlement. The increase in other revenue was largely due to the elimination of the refund provision that required the Utility segment to defer and return the income tax benefits resulting from the 2017 Tax Reform Act to customers ($12.0 million). The refund provision is no longer necessary because Distribution Corporation’s new base delivery rates now reflect the current federal income tax rate of 21%. This increase in other revenue was partially offset by decreases in other gas revenues ($0.8 million), capacity release revenues ($0.8 million), and late payment charges billed to customers ($0.4 million).

Previous wording

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.

Current wording

-44- 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.

Previous wording

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

Current wording

Utility segment. In addition, in periods of colder than normal weather, the WNA benefits the Utility segment’s customers. For 2025, the WNA preserved earnings of approximately $3.9 million and $1.7 million, respectively, in the Utility segment’s New York and Pennsylvania rate jurisdictions as the weather was warmer than normal on a cycle-bill basis in both jurisdictions. 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 as the weather was warmer than normal on a cycle-bill basis in both jurisdictions.

Previous wording

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.

Current wording

Net other income on the Consolidated Statements of Income was $36.4 million in 2025 compared to net other income of $16.2 million in 2024, for a net increase of $20.2 million. This increase can be attributed primarily to a $22.4 million increase in non-service pension and post-retirement benefit income combined with a $5.8 million change in the year-over-year revaluation of the contingent consideration received as part of the sale of the Company’s California oil properties in 2022. These increases were partially offset by year-over-year changes in the value of investment securities. During the year ended September 30, 2025, there were net gains of $0.5 million on investment securities, compared to net gains of $3.5 million on investment securities during the year ended September 30, 2024. Also offsetting these increases, was a decrease in interest income of $2.7 million, and the non-recurrence of $2.0 million of business interruption insurance proceeds received during the year ended September 30, 2024 related to a pipeline outage that impacted Seneca’s ability to market its gas.

Previous wording

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.

Current wording

Interest on long-term debt increased $18.1 million in 2025 as compared to 2024. These increases are primarily due to higher average balances and a higher weighted average interest rate on long-term debt. On February 19, 2025, the Company issued $500.0 million of 5.50% notes and $500.0 million of 5.95% notes. On March 6, 2025, the Company redeemed $450.0 million of 5.20% notes due July 2025 and $500.0 million of 5.50% notes due January 2026 and paid early redemption premiums totaling $2.4 million that were recorded as interest expense on long-term debt in the Integrated Upstream and Gathering segment. The Company also redeemed $50.0 million of 7.38% notes on June 13, 2025. In addition, in April 2024, the Company elected to draw a total of $300.0 million under a delayed draw term loan credit facility. These borrowings had a locked-in weighted average interest rate of 5.97% for 2025.

Previous wording

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.

Current wording

Other interest expense decreased $0.9 million in 2025 as compared to 2024. The decrease was primarily due to lower weighted average interest rates on short-term debt for 2025 and lower average short-term debt balances in 2025 compared to 2024.

Previous wording

The Company expects to have adequate amounts of cash available to meet both its short-term and long-term cash requirements for at least the next twelve months and for the foreseeable future thereafter. During 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.

Current wording

The Company expects to have adequate amounts of cash available to meet both its short-term and long-term cash requirements for at least the next twelve months and for the foreseeable future thereafter. During 2026, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures. The Company has a delayed draw term loan that matures in February 2026, which the Company anticipates repaying with cash from operations as well as short-term or long-term borrowings. Looking forward to 2027, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures. These cash flow projections include the impact of the CenterPoint Ohio acquisition but do not reflect the impact of other acquisitions or divestitures that may arise in the future.

Previous wording

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.

Current wording

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. The weather impact on cash flow in the Utility segment is mitigated by a WNA in both its New York and Pennsylvania rate jurisdictions. Refer also to Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) for additional discussion.

Previous wording

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.

Current wording

Cash provided by operating activities in the Integrated Upstream and Gathering 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.

Previous wording

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.

Current wording

-47- 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.

Previous wording

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.

Current wording

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 Integrated Upstream and Gathering segment and Utility segment. The decrease in the Integrated Upstream and Gathering segment is primarily due to lower cash receipts from natural gas production. The decrease in the Utility segment is primarily due to the timing of gas cost recovery.

Previous wording

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:

Current wording

The Company’s expenditures for long-lived assets, including non-cash capital expenditures, totaled $918.1 million, $942.0 million and $1,123.6 billion in 2025, 2024 and 2023, respectively. The table below presents these expenditures:

Previous wording

(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.

Current wording

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

Previous wording

(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.

Current wording

(3)2024 capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment include $85.0 million, $14.4 million and $20.6 million, respectively, of non-cash capital expenditures.

Previous wording

(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.

Current wording

(4)2023 capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment include $63.8 million, $31.8 million and $13.6 million, respectively, of non-cash capital expenditures.

Previous wording

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.

Current wording

In 2025, the Integrated Upstream and Gathering segment capital expenditures were primarily upstream well drilling and completion expenditures in the Appalachian region, including $141.8 million spent in the Marcellus Shale area and $351.2 million spent in the Utica Shale area. These amounts included approximately $246.3 million spent to develop proved undeveloped reserves. Integrated Upstream and Gathering segment capital expenditures also 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.

Previous wording

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

Current wording

In 2024, the Integrated Upstream and Gathering segment capital expenditures were primarily upstream well drilling and completion expenditures in the Appalachian region, including $76.3 million spent in the Marcellus Shale area and $439.9 million spent 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 cost of this acquisition is reported as a component of Capital Expenditures on the Consolidated Statement of Cash Flows. Integrated Upstream and Gathering segment capital expenditures also 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.

Previous wording

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.

Current wording

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