NATIONAL FUEL GAS CO 10-Q

Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations OVERVIEW Please note that this overview is a high-level summary of items that are discussed in greater detail in subsequent sections of this report. 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. For a discussion of the Company's earnings, refer to the Results of Operations section below. 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 (“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 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. In addition, Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023. Interim settlement rates became effective on February 1, 2024 under a settlement in principle that was filed with FERC on March 27, 2024, and are estimated to increase Supply Corporation's revenues by approximately $56 million on an annual basis. The settlement remains subject to final FERC approval. For further discussion of Distribution Corporation and Supply Corporation rate matters, refer to the Rate Matters section below. As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its oil and natural gas properties in the Exploration and Production segment and that book value is subject to a quarterly ceiling test. The Company did not record an impairment under the ceiling test during the quarter ended March 31, 2024. Looking ahead, the first day of the month Henry Hub spot price for natural gas in April 2024 was $1.56 per MMBtu. Given the April price, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation at June 30, 2024 and September 30, 2024, the Company expects to experience a ceiling test impairment in each of these quarters. From a financing perspective, effective February 7, 2024, certain lenders under the Credit Agreement consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. As a result, the Company has aggregate commitments available under the Credit Agreement of $1.0 billion before February 26, 2027, and $940 million in aggregate commitments available on and after February 26, 2027 to February 25, 2028. On February 14, 2024, the Company entered into the Term Loan Agreement with six lenders. The Term Loan Agreement established a $300 million unsecured committed delayed draw term loan credit facility with a maturity date of 29 Table of Content 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 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. Repurchases under this program amounted to 96,133 shares at a total cost of $5.0 million during the quarter ended March 31, 2024. 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 the remainder of 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 volatile interest rates, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs. CRITICAL ACCOUNTING ESTIMATES For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2023 Form 10-K. There have been no material changes to that disclosure other than as set forth below. The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K. Oil and Gas Exploration and Development Costs. The Company, in its Exploration and Production segment, follows the full cost method of accounting for determining the book value of its oil and natural gas properties, with natural gas properties in the Appalachian Region being the primary component after the fiscal 2022 sale of the Company's California oil and natural gas properties. In accordance with the full cost methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company's oil and gas reserves based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s oil and gas properties at the balance sheet date. The present value of future revenues is calculated using a 10% discount factor. If the book value of the oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling. At March 31, 2024, the ceiling exceeded the book value of the oil and gas properties by approximately $3.1 million. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended March 31, 2024, based on the quoted Henry Hub spot price for natural gas, was $2.45 per MMBtu. (Note: Because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for the twelve months ended March 31, 2024. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices in the twelve-month period used at March 31, 2024 in the ceiling test calculation, the book value of the Company's oil and gas properties would have exceeded the ceiling by approximately $329.9 million (after-tax), which would have resulted in an impairment charge. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates. Looking ahead, the first day of the month Henry Hub spot price for natural gas in April 2024 was $1.56 per MMBtu. Given the April price, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation at June 30, 2024 and September 30, 2024, the Company expects to experience a ceiling test impairment in each of these quarters. It is difficult to predict what additional factors beyond price could contribute to future non-cash impairments under the SEC's full cost ceiling test. Fluctuations in or subtractions from proved reserves and increases in development costs for undeveloped reserves can have an impact on the amount of the ceiling at any point in time. For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2023 Form 10-K. 30 Table of Content RESULTS OF OPERATIONS Earnings The Company's earnings were $166.3 million for the quarter ended March 31, 2024 compared to earnings of $140.9 million for the quarter ended March 31, 2023. The increase in earnings of $25.4 million is primarily the result of higher earnings in all reportable segments as well as in the Corporate category, slightly offset by a loss in the All Other category. The Company's earnings were $299.3 million for the six months ended March 31, 2024 compared to earnings of $310.6 million for the six months ended March 31, 2023. The decrease in earnings of $11.3 million is primarily the result of lower earnings in the Exploration and Production segment. Higher earnings in the Utility segment, Gathering segment and Pipeline and Storage segment, as well as higher earnings in the Corporate category and a lower loss in the All Other category partially offset this decrease. Note that all amounts used in earnings discussions are after-tax amounts, unless otherwise noted. Earnings (Loss) by Segment Three Months Ended March 31, Six Months Ended March 31, (Thousands) 2024 2023 Increase (Decrease) 2024 2023 Increase (Decrease) Exploration and Production $ 62,065 $ 60,982 $ 1,083 $ 114,548 $ 152,174 $ (37,626) Pipeline and Storage 30,737 23,858 6,879 54,792 53,335 1,457 Gathering 28,706 24,334 4,372 57,531 49,072 8,459 Utility 44,739 31,720 13,019 71,289 55,537 15,752 Total Reportable Segments 166,247 140,894 25,353 298,160 310,118 (11,958) All Other (96) (69) (27) (217) (350) 133 Corporate 121 55 66 1,349 802 547 Total Consolidated $ 166,272 $ 140,880 $ 25,392 $ 299,292 $ 310,570 $ (11,278) Exploration and Production Exploration and Production Operating Revenues Three Months Ended March 31, Six Months Ended March 31, (Thousands) 2024 2023 Increase (Decrease) 2024 2023 Increase (Decrease) Gas Produced in Appalachia (after Hedging) $ 263,382 $ 241,002 $ 22,380 $ 515,798 $ 514,199 $ 1,599 Other 1,232 3,550 (2,318) 2,835 7,326 (4,491) $ 264,614 $ 244,552 $ 20,062 $ 518,633 $ 521,525 $ (2,892) Production Volumes Three Months Ended March 31, Six Months Ended March 31, 2024 2023 Increase (Decrease) 2024 2023 Increase (Decrease) Gas Production per MMcf 102,883 93,241 9,642 203,640 183,815 19,825 31 Table of Content Average Prices Three Months Ended March 31, Six Months Ended March 31, 2024 2023 Increase (Decrease) 2024 2023 Increase (Decrease) Average Gas Price/Mcf Weighted Average $ 1.98 $ 2.79 $ (0.81) $ 2.14 $ 3.77 $ (1.63) Weighted Average After Hedging $ 2.56 $ 2.58 $ (0.02) $ 2.53 $ 2.80 $ (0.27) 2024 Compared with 2023 Operating revenues for the Exploration and Production segment increased $20.1 million for the quarter ended March 31, 2024 as compared with the quarter ended March 31, 2023. Gas production revenue after hedging increased $22.4 million due to the impact of a 9.6 Bcf increase in natural gas production, offset by a $0.02 per Mcf decrease in the weighted average price of natural gas after hedging. The increase in natural gas production was largely due to additional production from new Marcellus and Utica wells in the Appalachian region. In addition, other revenue decreased $2.3 million due to the non-recurrence of temporary capacity release revenue for a portion of this segment's transportation capacity during the quarter ended March 31, 2023. Operating revenues for the Exploration and Production segment decreased $2.9 million for the six months ended March 31, 2024 as compared with the six months ended March 31, 2023. This decrease resulted primarily from the non-recurrence of temporary capacity release revenue for a portion of this segment’s transportation capacity during the six months ended March 31, 2023, which contributed to a $4.5 million decrease in other revenue period over period. Gas production revenue after hedging increased $1.6 million due to the impact of a 19.8 Bcf increase in natural gas production, offset by a $0.27 per Mcf decrease in the weighted average price of natural gas after hedging. The increase in natural gas production was largely due to additional production from new Marcellus and Utica wells in the Appalachian region during the six months ended March 31, 2024 as compared with the six months ended March 31, 2023. The Exploration and Production segment's earnings for the quarter ended March 31, 2024 were $62.1 million, an increase of $1.1 million when compared with earnings of $61.0 million for the quarter ended March 31, 2023. The increase in earnings was attributable to higher natural gas production ($19.7 million) and lower other taxes ($1.3 million). There was also an unrealized gain recognized in the three-month period ended March 31, 2024 ($0.4 million) on contingent consideration received as part of the California asset sale, compared to an unrealized loss that was recognized in the three-month period ended March 31, 2023 ($1.8 million) on such contingent consideration. These increases were partially offset by lower natural gas prices after hedging ($2.0 million) and lower other revenue ($1.8 million) as previously discussed. Higher depletion expense ($11.7 million), higher lease operating and transportation expenses ($3.1 million) and an increase in interest expense ($2.3 million) also reduced earnings. The decrease in other taxes was primarily attributable to lower Impact Fees in the Appalachian region due to lower NYMEX pricing, which reduces the cost per well due to moving the Company into a lower rate tier. The increase in depletion expense was primarily due to the net increase in production combined with a $0.08 per Mcf increase in the depletion rate. The increase in lease operating and transportation expenses was primarily the result of higher gathering and transportation costs and higher workover expenses, offset by lower saltwater disposal expenses. The increase in interest expense can largely be attributed to higher average interest rates on intercompany short-term and long-term borrowings, partially offset by lower intercompany long-term debt balances. The Exploration and Production segment's earnings for the six months ended March 31, 2024 were $114.5 million, a decrease of $37.7 million when compared with earnings of $152.2 million for the six months ended March 31, 2023. The decrease in earnings was attributable to lower natural gas prices after hedging ($42.5 million) and lower other revenue ($3.6 million) as previously discussed. Higher depletion expense ($24.7 million), higher lease operating and transportation expenses ($7.4 million), higher other operating expenses ($4.3 million) and an increase in interest expense ($3.9 million) also reduced earnings. There was also a higher unrealized loss recognized in the six-month period ended March 31, 2024 ($2.7 million) on contingent consideration received as part of the California asset sale as compared to an unrealized loss that was recognized in the six-month period ended March 31, 2023 ($1.7 million) on such contingent consideration. These decreases were partially offset by higher natural gas production ($43.8 million), lower other taxes ($3.9 million) and a reduction in income tax expense ($1.5 million). The increase in depletion expense was primarily due to the net increase in production combined with a $0.09 per Mcf increase in the depletion rate. The increase in lease operating and transportation expenses was primarily the result of higher gathering and transportation costs combined with higher workover expenses. The increase in other operating expenses was primarily attributable to recognizing an accrual of plugging and abandonment costs related to certain wells that were formerly 32 Table of Content owned by Seneca, combined with higher general and administrative costs. 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 due to lower NYMEX pricing, which reduces the cost per well due to moving the Company into a lower rate tier. The reduction in income tax expense was primarily driven by lower state income tax expense as a result of both a decrease in pre-tax income and Pennsylvania's tax rate decrease, partially offset by a lower benefit from permanent differences related to stock compensation. Pipeline and Storage Pipeline and Storage Operating Revenues Three Months Ended March 31, Six Months Ended March 31, (Thousands) 2024 2023 Increase (Decrease) 2024 2023 Increase (Decrease) Firm Transportation $ 80,979 $ 73,487 $ 7,492 $ 152,475 $ 148,944 $ 3,531 Interruptible Transportation 294 307 (13) 416 1,052 (636) 81,273 73,794 7,479 152,891 149,996 2,895 Firm Storage Service 25,343 21,470 3,873 46,634 42,754 3,880 Interruptible Storage Service — — — 1 2 (1) Other 1,404 (161) 1,565 2,907 7 2,900 $ 108,020 $ 95,103 $ 12,917 $ 202,433 $ 192,759 $ 9,674 Pipeline and Storage Throughput Three Months Ended March 31, Six Months Ended March 31, (MMcf) 2024 2023 Increase (Decrease) 2024 2023 Increase (Decrease) Firm Transportation 222,258 231,081 (8,823) 422,359 455,705 (33,346) Interruptible Transportation 1,271 619 652 1,389 1,927 (538) 223,529 231,700 (8,171) 423,748 457,632 (33,884) 2024 Compared with 2023 Operating revenues for the Pipeline and Storage segment increased $12.9 million for the quarter ended March 31, 2024 as compared with the quarter ended March 31, 2023. The increase in operating revenues was primarily due to an increase in transportation revenues of $7.5 million, an increase in storage revenues of $3.9 million and an increase in other revenues of $1.6 million. The increase in transportation and storage revenues was primarily attributable to an increase in Supply Corporation's transportation and storage rates effective February 1, 2024, in accordance with the approved interim rates in connection with Supply Corporation's rate case settlement, which is pending final FERC approval. In addition, the increase in transportation and storage revenues was the result of a final true-up adjustment to a surcharge mechanism for pipeline safety and greenhouse gas costs that ended effective February 1, 2024. The increase in other revenues primarily reflects an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense. Operating revenues for the Pipeline and Storage segment increased $9.7 million for the six months ended March 31, 2024 as compared with the six months ended March 31, 2023. The increase in operating revenues was primarily due to an increase in transportation revenues of $2.9 million, an increase in storage revenues of $3.9 million, and an increase in other revenues of $2.9 million. The increase in transportation and storage revenues was primarily attributable to an increase in Supply Corporation's transportation and storage rates effective February 1, 2024 in accordance with the aforementioned Supply Corporation rate case settlement and final true-up adjustment to a surcharge for pipeline safety and greenhouse gas costs. The increase in transportation revenues was partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions. The increase in other revenues primarily reflects an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense. 33 Table of Content Transportation volume for the quarter ended March 31, 2024 decreased by 8.2 Bcf from the prior year's quarter ended March 31, 2023. For the six months ended March 31, 2024, transportation volume decreased by 33.9 Bcf from the prior year's six-month period ended March 31, 2023. The decrease in transportation volume for both the quarter and six months ended March 31, 2024 is primarily due to a decrease in volume from certain contract expirations combined with a decline in volume from warmer weather. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire. The Pipeline and Storage segment’s earnings for the quarter ended March 31, 2024 were $30.7 million, an increase of $6.8 million when compared with earnings of $23.9 million for the quarter ended March 31, 2023. The increase in earnings was primarily due to the earnings impact of higher operating revenues ($10.2 million), as discussed above. This increase was partially offset by increases in operating expenses ($1.4 million), depreciation expense ($1.4 million) and interest expense ($1.0 million). The increase in operating expenses was primarily due to an increase in personnel costs, as well as higher power costs related to Empire's electric motor drive compressor station. This increase in electric power costs is offset by an equal increase in revenue. The increase in depreciation expense was primarily due to higher average depreciable plant in service compared to the prior year. The increase in interest expense is mainly due to an increase in intercompany short-term borrowings. The Pipeline and Storage segment’s earnings for the six months ended March 31, 2024 were $54.8 million, an increase of $1.5 million when compared with earnings of $53.3 million for the six months ended March 31, 2023. The increase in earnings was primarily due to the earnings impact of higher operating revenues ($7.6 million), as discussed above. This increase was partially offset by increases in operating expenses ($2.9 million), depreciation expense ($2.0 million) and interest expense ($1.6 million). The increase in operating expenses was primarily due to higher personnel costs, as well as higher power costs related to Empire's electric motor drive compressor station. This increase in electric power costs is offset by an equal increase in revenue. The increase in depreciation expense was primarily due to higher average depreciable plant in service compared to the prior year. The increase in interest expense is mainly due to an increase in intercompany short-term borrowings. Gathering Gathering Operating Revenues Three Months Ended March 31, Six Months Ended March 31, (Thousands) 2024 2023 Increase (Decrease) 2024 2023 Increase (Decrease) Gathering Revenues $ 63,993 $ 56,981 $ 7,012 $ 126,581 $ 113,394 $ 13,187 Gathering Volume Three Months Ended March 31, Six Months Ended March 31, 2024 2023 Increase (Decrease) 2024 2023 Increase (Decrease) Gathered Volume - (MMcf) 125,565 109,344 16,221 249,388 217,371 32,017 2024 Compared with 2023 Operating revenues for the Ga thering segme nt increased $7.0 million f or the quarter ended March 31, 2024 as compared with the quarter ended March 31, 2023, which was driven primarily by a 16.2 Bcf increase in gathered volume. Gathered volume on the Trout Run and Tioga gathering systems increased 17.5 Bcf and 5.3 Bcf, respectively, partially offset by a decrease of 6.6 Bcf on the Clermont gathering system. The net increase in gathered volume can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems. Operating revenue s for the Gathering segme nt increased $13.2 million for the six months ended March 31, 2024 as compared with the six months ended March 31, 2023, which was driven primarily by a 32.0 Bcf increase in gathered volume. Contributors to the increase included the Trout Run and Tioga gathering systems, which recorded increases of 29.2 Bcf and 11.6 Bcf, respectively, partially offset by the Clermont gathering system, which recorded a decrease of 8.8 Bcf. The net increase 34 Table of Content can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems. The Gathering segment’s earnings for the quarter ended March 31, 2024 were $28.7 million, an increase of $4.4 million when compared with earnings of $24.3 million for the quarter ended March 31, 2023. The increase in earnings was primarily due to higher gathering revenues ($5.5 million) driven by the increase in gathered volume, as discussed above. This increase was partially offset by higher depreciation expense ($0.5 million) and higher income tax expense ($0.5 million). The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga and Clermont gathering systems. The increase in income tax expense was due to higher state income taxes driven by higher pre-tax income. The Gathering segment’s earnings for the six months ended March 31, 2024 were $57.5 million, an increase of $8.4 million when compared with earnings of $49.1 million for the six months ended March 31, 2023 . The increase in earnings was mainly due to higher gathering revenues ($10.4 million) driven by the increase in gathered volume, as discussed above. This increase was partially offset by higher depreciation expense ($1.1 million) and higher income tax expense ($1.0 million). The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga and Clermont gathering systems. The increase in income tax expense was due to higher state income taxes driven by higher pre-tax income. Utility Utility Operating Revenues Three Months Ended March 31, Six Months Ended March 31, (Thousands) 2024 2023 Increase (Decrease) 2024 2023 Increase (Decrease) Retail Sales Revenues: Residential $ 217,924 $ 320,043 $ (102,119) $ 367,580 $ 565,484 $ (197,904) Commercial 30,393 47,569 (17,176) 51,603 82,913 (31,310) Industrial 1,307 2,787 (1,480) 2,218 4,430 (2,212) 249,624 370,399 (120,775) 421,401 652,827 (231,426) Transportation 41,761 38,581 3,180 72,559 68,093 4,466 Other (881) (1,864) 983 (1,448) (2,124) 676 $ 290,504 $ 407,116 $ (116,612) $ 492,512 $ 718,796 $ (226,284) Utility Throughput Three Months Ended March 31, Six Months Ended March 31, (MMcf) 2024 2023 Increase (Decrease) 2024 2023 Increase (Decrease) Retail Sales: Residential 27,063 27,884 (821) 45,045 48,037 (2,992) Commercial 4,293 4,384 (91) 7,093 7,378 (285) Industrial 190 267 (77) 327 418 (91) 31,546 32,535 (989) 52,465 55,833 (3,368) Transportation 22,637 22,788 (151) 40,166 41,098 (932) 54,183 55,323 (1,140) 92,631 96,931 (4,300) 35 Table of Content Degree Days Three Months Ended March 31, Percent Colder (Warmer) Than Normal 2024 2023 Normal (1) Prior Year (1) Buffalo, NY 3,326 2,705 2,820 (18.7) % (4.1) % Erie, PA (2) 3,057 2,576 2,645 (15.7) % (2.6) % Six Months Ended March 31, Buffalo, NY 5,579 4,563 4,868 (18.2) % (6.3) % Erie, PA 4,951 4,240 4,632 (14.4) % (8.5) % (1) Percents compare actual 2024 degree days to normal degree days and actual 2024 degree days to actual 2023 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 $116.6 million for the quarter ended March 31, 2024 as compared with the quarter ended March 31, 2023. This decrease resulted from a $120.8 million decrease in retail gas sales revenue, which was partially offset by a $3.2 million increase in transportation revenue and a $1.0 million increase in other revenue. The decrease in retail gas sales revenue reflects a decrease in the cost of gas sold (per Mcf) combined with a 1.0 Bcf decrease in throughput mainly due to warmer weather. It should be noted that under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation's earnings are not impacted by fluctuations in gas costs. Purchased gas expense recorded on the consolidated income statement matches the revenues collected from customers. The decrease in retail gas sales revenue was partially offset by the impact of new base rates in Distribution Corporation's Pennsylvania jurisdiction pursuant to a settlement approved by the PaPUC on June 15, 2023. Additional details regarding the base rate regulatory proceeding can be found in the Rate Matters section below. The increase in transportation revenue was also largely attributable to the impact of new base rates in Pennsylvania, as well as an increase in revenues earned under the system modernization and system improvement tracker mechanisms in Distribution Corporation's New York jurisdiction, which allow for the recovery of investments in leak prone pipe replacement. The increase in other revenue was mainly the result of a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($2.2 million), partially offset by decreases in late payment charges billed to customers ($0.7 million) and capacity release revenues ($0.6 million). Operating revenues for the Utility segment decreased $226.3 million for the six months ended March 31, 2024 as compared with the six months ended March 31, 2023. The decrease resulted from a $231.4 million decrease in retail gas sales revenue, primarily due to a decrease in the cost of gas sold (per Mcf) as well as a 3.4 Bcf decrease in throughput largely due to warmer weather. These factors were partially offset by an increase in base rates in Distribution Corporation's Pennsylvania jurisdiction, as mentioned above. The decrease in retail gas sales revenue was partially offset by a $4.5 million increase in transportation revenue and a $0.7 million increase in other revenue. The increase in transportation revenue was also predominantly due to the impact of the new base rates in Pennsylvania in addition to an increase in the system modernization and system improvement tracker allocation to customers in New York, despite a 1.0 Bcf decrease in throughput due to warmer weather. The increase in other revenue was largely due to a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($2.6 million), partially offset by decreases in late payment charges billed to customers ($1.1 million) and capacity release revenues ($1.0 million). The Utility segment’s earnings for the quarter ended March 31, 2024 were $44.7 million, an increase of $13.0 million compared to earnings of $31.7 million for the quarter ended March 31, 2023. The increase was primarily due to the impact of new base rates in the Utility segment's Pennsylvania jurisdiction ($8.5 million), lower income tax expense ($2.4 million), and the impact of system modernization and system improvement trackers in New York ($1.8 million). The decrease in income tax expense was largely due to an increase in tax deductions related to certain repairs and maintenance expenditures recorded in the Utility's Pennsylvania jurisdiction as a result of updated IRS guidance published in 2023. The Utility segment's earnings also increased $4.5 million due to the impact of higher usage and weather, with current quarter earnings benefiting from the implementation of a weather normalization adjustment (WNA) in the Utility segment's Pennsylvania jurisdiction. These increases were partially offset by higher operating expenses ($2.3 million), primarily due to higher personnel costs, and a decrease in earnings from regulatory adjustments ($1.6 million). The impact of weather variations on earnings in the Utility segment is mitigated by a WNA. Prior to October 2023, the impact of weather variations on earnings was mitigated by a WNA solely in the Utility segment’s New York rate jurisdiction. 36 Table of Content However, effective October 2023, the impact of weather variations on earnings is also mitigated by a WNA in the Utility segment’s Pennsylvania rate jurisdiction. The WNA, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the Utility segment. In addition, in periods of colder than normal weather, the WNA benefits the Utility segment's customers. For the quarter ended March 31, 2024, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $5.0 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $3.6 million, as the weather was warmer than normal in both jurisdictions. For the quarter ended March 31, 2023, the WNA preserved earnings in the Utility segment’s New York jurisdiction of approximately $3.3 million, as the weather was warmer than normal. The Utility segment’s earnings for the six months ended March 31, 2024 were $71.3 million, an increase of $15.8 million when compared with earnings of $55.5 million for the six months ended March 31, 2023. The increase was mainly due to the impact of new base rates in the Utility segment's Pennsylvania jurisdiction ($15.4 million), lower income tax expense ($4.2 million), and the impact of system modernization and system improvement trackers in New York ($2.7 million). The decrease in income tax expense was largely due to an increase in tax deductions related to certain repairs and maintenance expenditures, as discussed above. The Utility segment's earnings also increased $1.7 million due to the impact of higher usage and weather, with current year earnings benefiting from the implementation of a WNA in the Utility segment's Pennsylvania rate jurisdiction. These factors were partially offset by higher operating expenses ($5.0 million), primarily due to higher personnel costs, a decrease in earnings from regulatory adjustments ($2.0 million), and an increase in depreciation and amortization expense ($1.5 million), which was primarily the result of the higher average plant balances and increased depreciation for negative net salvage in Pennsylvania. For the six months ended March 31, 2024, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $6.4 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $4.1 million, as the weather was warmer than normal in both jurisdictions. For the six months ended March 31, 2023, the WAC preserved earnings in the Utility segment's New York rate jurisdiction of approximately $4.2 million, as the weather was warmer than normal. Corporate and All Other 2024 Compared with 2023 Corporate and All Other operations had earnings of less than $0.1 million for the quarter ended March 31, 2024, essentially flat when compared with a net loss of less than $0.1 million for the quarter ended March 31, 2023. For the six months ended March 31, 2024, Corporate and All Other operations had earnings of $1.1 million, an increase of $0.6 million when compared with earnings of $0.5 million for the six months ended March 31, 2023. The increase in earnings for the six-month period was primarily attributable to changes in unrealized gains on investments in equity securities. During the six months ended March 31, 2024, the Company recorded unrealized gains of $1.4 million. During the six months ended March 31, 2023, the Company recorded unrealized gains of $1.0 million. Other Income (Deductions) Net other income on the Consolidated Statements of Income was $6.1 million for the quarter ended March 31, 2024, compared to net other income of $2.9 million for the quarter ended March 31, 2023, for an increase of $3.2 million. This increase can be attributed primarily to a $0.5 million gain on the revaluation of the contingent consideration received from the sale of Seneca's California assets in June 2022 (compared to a loss of $2.5 million for the quarter ended March 31, 2023), as well as an increase of $0.9 million in allowance for funds used during construction and an increase in the cash surrender value of life insurance policies of $0.8 million. These increases were partially offset by a decrease in interest income of $0.9 million that was mainly due to lower interest income from investments as well as changes in unrealized gains and losses on investments in equity securities that decreased other income by $0.5 million. Net other income on the Consolidated Statement of Income was $9.8 million for the six months ended March 31, 2024, compared to net other income of $9.2 million for the six months ended March 31, 2023, for an increase of $0.6 million. This increase was primarily due to $2.0 million of business interruption insurance proceeds that Seneca received during the current fiscal year related to a pipeline outage impacting Seneca's ability to market its gas, along with an increase in the cash surrender value of life insurance policies of $1.0 million. There was also a $0.6 million increase in non-service pension and post-retirement benefit income year over year and an increase of $0.6 million in allowance for funds used during construction. These increases were partially offset by a decrease in interest income of $2.4 million that was mainly due to lower interest income from investments and a decrease in interest from hedging collateral for derivative financial instruments as well as a $3.7 37 Table of Content million loss on the revaluation of the contingent consideration received from the sale of Seneca's California assets in June 2022 (compared to a loss of $2.3 million for the six months ended March 31, 2023). Interest Expense on Long-Term Debt Interest expense on long-term debt on the Consolidated Statement of Income increased $0.9 million for the quarter ended March 31, 2024 as compared to the quarter ended March 31, 2023. This was primarily due to a higher weighted average interest rate on long-term debt. For the six months ended March 31, 2024, interest expense on long-term debt decreased $0.3 million as compared with the six months ended March 31, 2023. This decrease is primarily due to an increase in capitalized interest (mostly in Midstream Company) as a result of higher capital expenditures. This was partially offset by a higher weighted average interest rate on long-term debt. In November 2022 and March 2023, the Company redeemed 3.75% notes, which in the aggregate amounted to $500.0 million, and in March 2023, the Company also redeemed $49.0 million of 7.395% notes. These redemptions were partially offset by the issuance of $300.0 million of 5.50% notes in May 2023. CAPITAL RESOURCES AND LIQUIDITY The Company’s primary source of cash during the six-month period ended March 31, 2024 consisted of cash provided by operating activities. The Company’s primary sources of cash during the six-month period ended March 31, 2023 consisted of cash provided by operating activities, proceeds from short-term borrowings and proceeds from the sale of a fixed income mutual fund held in a grantor trust. The Company expects to have adequate amounts of cash available to meet both its short-term and long-term cash requirements for at least the next twelve months and for the foreseeable future thereafter. During the remainder of 2024, the Company expects to use cash provided by operating activities, as well as net proceeds from short-term borrowings, to fund the Company's capital expenditures. Looking forward to 2025, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures. The Company also has two long-term debt maturities in 2025, totaling $500.0 million, which the Company anticipates funding with cash on hand as well as short-term and long-term borrowings. 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, deferred income taxes and stock-based compensation. Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. 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 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. Because of the seasonal nature of the heating business in the Utility segment, revenues in this business are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the receivable balances at September 30. The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters. For storage gas inventory accounted for under the LIFO method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption "Other Accruals and Current Liabilities." Such reserve is reduced as the inventory is replenished. Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas as well as changes in production. The Company uses various 38 Table of Content derivative financial instruments, including price swap agreements and no cost collars, in an attempt to manage this energy commodity price risk. Net cash provided by operating activities totaled $586.3 million for the six months ended March 31, 2024, a decrease of $124.9 million compared with $711.2 million provided by operating activities for the six months ended March 31, 2023. The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Exploration and Production segment due to lower cash receipts from lower realized natural gas prices for this segment's natural gas production. Investing Cash Flow Expenditures for Long-Lived Assets The Company’s expenditures for long-lived assets totaled $435.7 million during the six months ended March 31, 2024 and $440.6 million during the six months ended March 31, 2023. The table below presents these expenditures: Total Expenditures for Long-Lived Assets Six Months Ended March 31, 2024 2023 Increase (Decrease) (Millions) Exploration and Production: Capital Expenditures $ 285.1 (1) $ 323.6 (2) $ (38.5) Pipeline and Storage: Capital Expenditures 42.6 (1) 33.3 (2) 9.3 Gathering: Capital Expenditures 39.5 (1) 34.1 (2) 5.4 Utility: Capital Expenditures 68.3 (1) 49.2 (2) 19.1 All Other: Capital Expenditures 0.2 0.4 (0.2) $ 435.7 $ 440.6 $ (4.9) (1) At March 31, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $44.4 million, $5.0 million, $5.5 million and $8.0 million, respectively, of non-cash capital expenditures. At September 30, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $43.2 million, $31.8 million, $20.6 million and $13.6 million, respectively, of non-cash capital expenditures. (2) At March 31, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $56.1 million, $2.2 million, $2.0 million and $4.2 million, respectively, of non-cash capital expenditures. At September 30, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $83.0 million, $15.2 million, $10.7 million and $11.4 million, respectively, of non-cash capital expenditures. Exploration and Production The Exploration and Production segment capital expenditures for the six months ended March 31, 2024 were primarily well drilling and completion expenditures in the Appalachian region, and included $52.0 million in the Marcellus Shale area and $224.9 million in the Utica Shale area. These amounts included approximately $185.8 million spent to develop proved undeveloped reserves. The Exploration and Production segment capital expenditures for the six months ended March 31, 2023 were primarily well drilling and completion expenditures in the Appalachian region, and included $143.2 million in the Marcellus Shale area and $172.4 million in the Utica Shale area. These amounts included approximately $208.2 million spent to develop proved undeveloped reserves. Pipeline and Storage The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2024 and March 31, 2023 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions. 39 Table of Content 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, 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. Supply Corporation expects to file a Section 7(c) application with the FERC in late summer 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. As of March 31, 2024, approximately $1.0 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at March 31, 2024. Gathering The majority of the Gathering segment capital expenditures for the six months ended March 31, 2024 included expenditures related to the continued expansion of Midstream Company's Tioga and Clermont gathering systems. Midstream Company spent $31.2 million and $7.0 million, respectively, during the six months ended March 31, 2024 on the development of the Tioga and Clermont gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower. The majority of the Gathering segment capital expenditures for the six months ended March 31, 2023 included expenditures related to the continued expansion of Midstream Company's Clermont, Tioga and Trout Run gathering systems. Midstream Company spent $10.2 million, $16.8 million and $3.8 million, respectively, during the six months ended March 31, 2023 on the development of the Clermont, Tioga and Trout Run gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines, as well as the continued development of centralized station facilities, including increased compression horsepower, at the Clermont, Trout Run, and Tioga gathering systems. In the Tioga gathering system, expenditures were also largely attributable to the expansion of on-pad and centralized station facilities related to bringing new development online. Utility The majority of the Utility segment capital expenditures for the six months ended March 31, 2024 and March 31, 2023 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions. The Company estimates that the Utility segment capital expenditures are expected to be approximately $165 million for fiscal 2024, which is approximately $25 million higher than the estimate previously reported in the 2023 Form 10-K. This increase is due to the estimated impact of New York State’s recently enacted Roadway Excavation Quality Assurance Act. This Act requires contractors to pay state published prevailing wages on projects that require a permit to operate in a public right of way, which is expected to increase contractor charges to the Company. 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 previously overcollected OPEB expenses, as well as to diversify a portion of grantor trust investments into lower risk money market mutual fund shares. 40 Table of Content Project Funding During the six months ended March 31, 2024 and fiscal 2023, the Company has been financing capital expenditures with cash from operations and short-term debt. Going forward, the Company expects to use cash on hand, cash from operations and short-term and long-term borrowings, as needed, to finance capital expenditures. 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. 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 decreased $8.6 million, to a total of $278.9 million, when comparing the balance sheet at March 31, 2024 to the balance sheet at September 30, 2023. The maximum amount of short-term debt outstanding during the six months ended March 31, 2024 was $402.9 million. In addition to cash provided by operating activities, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing items such as capital expenditures, asset purchases, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, repurchases of stock, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. As of March 31, 2024, the Company did not have any short-term notes payable to banks and had outstanding commercial paper of $278.9 million. On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the "Credit Agreement") with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. The Credit Agreement provides a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027. Effective February 7, 2024, certain lenders under the Credit Agreement consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. As a result, the Company has aggregate commitments available under the Credit Agreement of $1.0 billion before February 26, 2027, and $940.0 million in aggregate commitments available on and after February 26, 2027 to February 25, 2028. 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 term loan with a maturity date of February 14, 2026. Pursuant to the Term Loan Agreement, there was a delayed draw mechanism and the Company elected to draw a total of $300.0 million under the facility between April 8, 2024 and April 10, 2024. The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper. Both the Credit Agreement and Term Loan Agreement require that the Company's debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter. 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 41 Table of Content any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at March 31, 2024, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under these agreements. In addition, for purposes of calculating the debt to capitalization ratio under these agreements, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet. Under the agreements, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. At March 31, 2024, the Company’s debt to capitalization ratio, as calculated under the agreements was 0.44. The constraints specified in the agreements would have permitted an additional $3.57 billion in short-term and/or long-term debt to be outstanding at March 31, 2024 before the Company’s debt to capitalization ratio exceeded 0.65. 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. None of the Company's long-term debt as of March 31, 2024 and September 30, 2023 had a maturity date within the following twelve-month period. The Company’s embedded cost of long-term debt was 4.69% at March 31, 2024 and 4.58% at March 31, 2023. Under the Company’s existing indenture covenants at March 31, 2024, the Company would have been permitted to issue up to a maximum of approximately $4.02 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by the debt to capitalization ratio constraint under the Credit Agreement and Term Loan Agreement, as discussed above). 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 March 31, 2024) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. 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, 42 Table of Content discontinue, terminate, modify, cancel or extend the share repurchase program at any time and for any reason. During the quarter ended March 31, 2024, the Company executed transactions to repurchase 96,133 shares for $5.0 million. Share repurchases that settled during the quarter ended March 31, 2024 were funded with cash provided by operating activities and/or short-term borrowings. It is expected that future repurchase, if any, under this program will continue to be funded with cash provided by operating activities and/or through the use of short-term borrowings. OTHER MATTERS In addition to the legal proceedings disclosed in Part II, Item 1 of this report, 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. On June 29, 2022, the Company received an extension of time from FERC, until December 31, 2024, to construct the project, which was affirmed on March 29, 2024, by the U.S. Court of Appeals for the D.C. Circuit. In light of the recent D.C. Circuit decision, the Company is evaluating next steps for the project, including the status of various regulatory approvals, the $500 million preliminary cost estimate, and the potential in-service date. As of March 31, 2024, approximately $55.0 million has been spent on the Northern Access project, including $24.4 million that has been spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet. The remaining $30.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2024. The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the six months ended March 31, 2024. In the remainder of fiscal 2024, the Company expects its contributions to the Retirement Plan to be in the range of zero to $5.0 million. The Company did not make any contributions to its VEBA trusts for its other post-retirement benefits during the six months ended March 31, 2024, and does not anticipate making any such contributions during the remainder of fiscal 2024. Market Risk Sensitive 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 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 March 31, 2024, the Company determined that nonperformance risk associated with its natural gas price 43 Table of Content 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. For a complete discussion of all other market risk sensitive instruments used by the Company, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2023 Form 10-K. 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. 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 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 CLCPA. 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 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, beginning October 1, 2024, the Company will be able to recover costs associated with plant placed in service on and after August 1, 2024 if it exceeds approximately $781.3 million of net plant as of July 31, 2024 and its quarterly rate of return does not exceed the authorized PaPUC rate of return. The DSIC petition is currently pending before the PaPUC. 44 Table of Content Pipeline and Storage Supply Corporation filed an NGA Section 4 rate case on July 31, 2023 proposing rate increases to be effective February 1, 2024. On March 8, 2024, Supply Corporation and the parties in the case reached a settlement in principle (the Settlement) to resolve the rate case. Supply Corporation’s March 11, 2024 motion to put in place Interim Settlement Rates effective February 1, 2024, was approved by FERC’s Chief Administrative Law Judge on March 12, 2024. The Settlement was filed with FERC on March 27, 2024 and remains pending. The “black box” settlement provides for new rates and resolves all issues in the proceeding. The Interim Settlement Rates are estimated to increase Supply Corporation’s revenues on a yearly basis by approximately $56 million, assuming current contract levels. The Settlement generally provides for the continuation of current depreciation rates with minimal changes. Under the Settlement, 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 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 1 at Note 7 — Commitments and Contingencies under the heading “Environmental Matters.” 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, and these regulations continue to be further expanded upon with the recent publication (March 2024) and finalization of the Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources. The Company must continue to comply with all applicable regulations. 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 regulations to implement the CLCPA and on regulatory treatment afforded in the process. 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 45 Table of Content 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 Quarterly Report on Form 10-Q 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. Changes in the price of natural gas; 3. 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; 4. 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; 5. The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets; 6. Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas; 7. 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; 8. The creditworthiness or performance of the Company’s key suppliers, customers and counterparties; 9. 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; 46 Table of Content 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; 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 Quarterly Report on Form 10-Q 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. Item 3. Quantitative and Qualitative Disclosures About Market Risk Refer to the "Market Risk Sensitive Instruments" section in Item 2 – MD&A. 47 Table of Content