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. On June 30, 2022, the Company completed the sale of Seneca’s California assets to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing. The Company pursued this sale given the strong commodity price environment and the Company's strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances. On June 30, 2022, the Company entered into a new 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company is using the proceeds for general corporate purposes, which included using $150.0 million for the November 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date in March 2023. In March 2023, the Company utilized short-term borrowings and cash on hand to redeem the remaining long-term debt that had maturity dates in March 2023, which included $350.0 million of 3.75% notes and $49.0 million of 7.395% notes. From a financing perspective, the Company expects to use cash on hand, cash from operations, and short-term or long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2023. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures and rising interest rates, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs as discussed above. Recent turmoil with certain financial institutions has created uncertainty in the economy. While the Company has not been directly impacted, it continues to closely monitor any potential future impacts on the business. The Company has a diverse group of twelve banks that participate in its multi-year and 364-day credit facilities. All of these banks have solid investment grade credit ratings. Additionally, the Company regularly reviews the credit quality of its hedging counterparties, those that provide credit support for customers, and any other material counterparties, and has not identified any material risks as a result of the current economic uncertainty. 29 Table of Contents CRITICAL ACCOUNTING ESTIMATES For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2022 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 June 30, 2022 sale of the Company's California oil and natural gas properties. That sale is discussed in more detail in Item 1 at Note 2 - Asset Acquisitions and Divestitures. In accordance with the full cost methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company's oil and gas reserves based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s oil and gas properties at the balance sheet date. 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, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $2.7 billion. 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, 2023, based on the quoted Henry Hub spot price for natural gas, was $5.96 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, 2023. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices used at March 31, 2023 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's oil and gas properties by approximately $2.4 billion (after-tax), which would not have resulted in an impairment charge. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates. It is difficult to predict what factors could lead to future non-cash impairments under the SEC's full cost ceiling test. Fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in natural gas prices have an impact on the amount of the ceiling at any point in time. For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2022 Form 10-K. RESULTS OF OPERATIONS Earnings The Company's earnings were $140.9 million for the quarter ended March 31, 2023 compared to earnings of $167.3 million for the quarter ended March 31, 2022. The decrease in earnings of $26.4 million is primarily the result of lower earnings in the Exploration and Production segment, Pipeline and Storage segment and Utility segment. Higher earnings in the Gathering segment and the Corporate category partially offset these decreases. The Company's earnings were $310.6 million for the six months ended March 31, 2023 compared to earnings of $299.7 million for the six months ended March 31, 2022. The increase in earnings of $10.9 million is primarily the result of higher earnings in the Exploration and Production segment, Pipeline and Storage segment, Gathering segment and Corporate category. Lower earnings in the Utility segment and a loss in the All Other category partially offset these increases. The Company's earnings for the quarter and six months ended March 31, 2022 include the reduction of an OPEB regulatory liability that increased Utility segment earnings by $18.5 million ($14.6 million after-tax) in accordance with a regulatory proceeding in Distribution Corporation's Pennsylvania service territory. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in earnings discussions are after-tax amounts, unless otherwise noted. 30 Table of Contents Earnings (Loss) by Segment Three Months Ended March 31, Six Months Ended March 31, (Thousands) 2023 2022 Increase (Decrease) 2023 2022 Increase (Decrease) Exploration and Production $ 60,982 $ 71,121 $ (10,139) $ 152,174 $ 133,490 $ 18,684 Pipeline and Storage 23,858 25,470 (1,612) 53,335 50,637 2,698 Gathering 24,334 22,092 2,242 49,072 45,229 3,843 Utility 31,720 53,048 (21,328) 55,537 75,178 (19,641) Total Reportable Segments 140,894 171,731 (30,837) 310,118 304,534 5,584 All Other (69) — (69) (350) (7) (343) Corporate 55 (4,403) 4,458 802 (4,807) 5,609 Total Consolidated $ 140,880 $ 167,328 $ (26,448) $ 310,570 $ 299,720 $ 10,850 Exploration and Production Exploration and Production Operating Revenues Three Months Ended March 31, Six Months Ended March 31, (Thousands) 2023 2022 Increase (Decrease) 2023 2022 Increase (Decrease) Gas (after Hedging) $ 241,002 $ 218,486 $ 22,516 $ 514,199 $ 424,287 $ 89,912 Oil (after Hedging) 526 36,817 (36,291) 1,154 72,040 (70,886) Gas Processing Plant 209 985 (776) 583 2,013 (1,430) Other 2,815 5,305 (2,490) 5,589 7,451 (1,862) $ 244,552 $ 261,593 $ (17,041) $ 521,525 $ 505,791 $ 15,734 Production Volumes Three Months Ended March 31, Six Months Ended March 31, 2023 2022 Increase (Decrease) 2023 2022 Increase (Decrease) Gas Production (MMcf) Appalachia 93,241 83,565 9,676 183,815 164,954 18,861 West Coast — 397 (397) — 805 (805) Total Production 93,241 83,962 9,279 183,815 165,759 18,056 Oil Production (Mbbl) Appalachia 7 1 6 15 1 14 West Coast — 522 (522) — 1,070 (1,070) Total Production 7 523 (516) 15 1,071 (1,056) 31 Table of Contents Average Prices Three Months Ended March 31, Six Months Ended March 31, 2023 2022 Increase (Decrease) 2023 2022 Increase (Decrease) Average Gas Price/Mcf Appalachia $ 2.79 $ 3.97 $ (1.18) $ 3.77 $ 4.18 $ (0.41) West Coast N/M $ 10.04 N/M N/M $ 9.91 N/M Weighted Average $ 2.79 $ 4.00 $ (1.21) $ 3.77 $ 4.21 $ (0.44) Weighted Average After Hedging $ 2.58 $ 2.60 $ (0.02) $ 2.80 $ 2.56 $ 0.24 Average Oil Price/Bbl Appalachia $ 74.12 $ 78.32 $ (4.20) $ 78.25 $ 75.38 $ 2.87 West Coast N/M $ 94.95 N/M N/M $ 85.93 N/M Weighted Average $ 74.12 $ 94.93 $ (20.81) $ 78.25 $ 85.93 $ (7.68) Weighted Average After Hedging $ 74.12 $ 70.45 $ 3.67 $ 78.25 $ 67.30 $ 10.95 N/M - Not Meaningful (as a result of the sale of Seneca's West Coast assets in June 2022) 2023 Compared with 2022 Operating revenues for the Exploration and Production segment decreased $17.0 million for the quarter ended March 31, 2023 as compared with the quarter ended March 31, 2022. Gas production revenue after hedging increased $22.5 million due to the impact of a 9.3 Bcf increase in natural gas production, offset by a $0.02 per Mcf decrease in the weighted average price of natural gas after hedging. Natural gas production increased largely due to additional production from new Marcellus and Utica wells in the Appalachian region. Oil production revenue after hedging decreased $36.3 million due to the sale of the Exploration and Production segment's California assets on June 30, 2022. In addition, other revenue decreased $2.5 million and gas processing plant revenue decreased $0.8 million. The decrease in other revenue was attributed to higher temporary capacity releases during the quarter ended March 31, 2022 when compared to the quarter ended March 31, 2023. The decrease in gas processing plant revenue was mainly attributed to the sale of the California assets. Operating revenues for the Exploration and Production segment increased $15.7 million for the six months ended March 31, 2023 as compared with the six months ended March 31, 2022. Gas production revenue after hedging increased $89.9 million due to the impact of an 18.1 Bcf increase in natural gas production combined with a $0.24 per Mcf increase in the weighted average price of natural gas after hedging. The increase in natural gas production was largely due to additional production from new Marcellus and Utica wells in the Appalachian region during the six months ended March 31, 2023 as compared with the six months ended March 31, 2022. Oil production revenue after hedging decreased $70.9 million due to the sale of the California assets. In addition, other revenue decreased $1.9 million and gas processing plant revenue decreased $1.4 million. The decrease in other revenue was attributed to higher temporary capacity releases during the six months ended March 31, 2022 when compared to the six months ended March 31, 2023, combined with a decrease in operating revenue from this segment's water treatment plants. The decrease in gas processing plant revenue was mainly attributed to the sale of the California assets. The Exploration and Production segment's earnings for the quarter ended March 31, 2023 were $61.0 million, a decrease of $10.1 million when compared with earnings of $71.1 million for the quarter ended March 31, 2022. The decrease in earnings was attributed to lower natural gas prices after hedging ($1.3 million), lower oil production ($28.7 million), higher depletion expense ($6.4 million) and an unrealized loss on contingent consideration received as part of the California asset sale ($1.8 million). A decrease in other revenue ($2.0 million) and gas processing plant revenue ($0.6 million), both of which are discussed above, also contributed to the decrease in earnings. These decreases were partially offset by higher natural gas production ($19.1 million), lower lease operating and transportation expenses ($5.3 million), lower other operating expenses ($3.2 million), lower other taxes ($1.9 million) and higher other income ($1.0 million). The increase in depletion expense was primarily due to the net increase in production combined with a $0.05 per Mcf increase in the depletion rate. The decrease in lease operating and transportation expenses was primarily the result of the sale of the California assets, partially offset by higher gathering and transportation costs combined with higher lease operating expenses in the Appalachian region. The decrease in other operating expenses was primarily attributed to the California asset sale. The decrease in other taxes was primarily 32 Table of Contents attributed to both the impact of the sale of Seneca's California assets as well as lower Impact Fees in the Appalachian region. The increase in other income was attributed to higher interest income, as well as non-service pension and post-retirement benefit income in the quarter ended March 31, 2023 compared to non-service pension and post-retirement benefit costs in the quarter ended March 31, 2022. The Exploration and Production segment's earnings for the six months ended March 31, 2023 were $152.2 million, an increase of $18.7 million when compared with earnings of $133.5 million for the six months ended March 31, 2022. The increase in earnings was primarily attributable to higher natural gas production ($36.5 million) and higher natural gas prices after hedging ($34.5 million) as discussed above. Other factors contributing to the earnings increase included lower lease operating and transportation expenses ($11.3 million), lower other operating expenses ($6.5 million), lower other taxes ($0.9 million) and higher other income ($2.3 million). Partially offsetting these items, the Exploration and Production segment experienced lower oil production ($56.1 million), lower other revenue ($1.5 million) and lower gas processing plant revenue ($1.1 million), all of which are discussed above. Other factors that decreased earnings included higher depletion expense ($11.1 million), higher interest expense ($0.9 million), higher income tax expense ($1.1 million) and an unrealized loss on contingent consideration received as part of the California asset sale ($1.7 million). The decrease in lease operating and transportation expenses was primarily the result of the sale of the California assets, partially offset by higher gathering and transportation costs combined with higher lease operating expenses in the Appalachian region. The decrease in other operating expenses was primarily attributed to the California asset sale. The decrease in other taxes was attributed to the impact of the California asset sale, partially offset by higher Impact Fees in the Appalachian region. The increase in other income was attributed to higher interest income, as well as non-service pension and post-retirement income in the six months ended March 31, 2023 compared to non-service pension and post-retirement benefit costs in the six months ended March 31, 2022. The increase in depletion expense was primarily due to the net increase in production combined with a $0.04 per Mcf increase in the depletion rate. The increase in interest expense can largely be attributed to a higher average interest rate on intercompany short-term borrowings partially offset by lower interest on intercompany long-term borrowings due to the Company's redemption of $500.0 million of 3.75% notes during the six months ended March 31, 2023. The increase in income tax expense was primarily driven by a prior-year benefit realized from the Enhanced Oil Recovery tax credit, which did not recur in the current year as a result of the sale of the California assets. Pipeline and Storage Pipeline and Storage Operating Revenues Three Months Ended March 31, Six Months Ended March 31, (Thousands) 2023 2022 Increase (Decrease) 2023 2022 Increase (Decrease) Firm Transportation $ 73,487 $ 72,259 $ 1,228 $ 148,944 $ 138,084 $ 10,860 Interruptible Transportation 307 412 (105) 1,052 856 196 73,794 72,671 1,123 149,996 138,940 11,056 Firm Storage Service 21,470 21,451 19 42,754 42,251 503 Interruptible Storage Service — — — 2 — 2 Other (161) 1,275 (1,436) 7 2,556 (2,549) $ 95,103 $ 95,397 $ (294) $ 192,759 $ 183,747 $ 9,012 Pipeline and Storage Throughput Three Months Ended March 31, Six Months Ended March 31, (MMcf) 2023 2022 Increase (Decrease) 2023 2022 Increase (Decrease) Firm Transportation 231,081 232,030 (949) 455,705 425,623 30,082 Interruptible Transportation 619 752 (133) 1,927 1,520 407 231,700 232,782 (1,082) 457,632 427,143 30,489 33 Table of Contents 2023 Compared with 2022 Operating revenues for the Pipeline and Storage segment decreased $0.3 million for the quarter ended March 31, 2023 as compared with the quarter ended March 31, 2022. The decrease in operating revenues was primarily due to a decrease in other revenue of $1.4 million, partially offset by an increase in transportation revenues of $1.1 million. The decrease in other revenue primarily reflects an adjustment to electric surcharge revenues and lower cashout revenues. All customer surcharges and related adjustments for the electric surcharge mechanism are completely offset by an equal amount of electric power costs recorded in operation and maintenance expense. Cashout revenues are completely offset by purchased gas expense. The increase in transportation revenues was primarily attributable to Period 2 Rates that went into effect April 1, 2022. These Period 2 Rates were a negotiated revenue step-up as part of the FM100 Project that was placed into service in December 2021, as specified in Supply Corporation's 2020 rate case settlement. An increase in short-term contracts also contributed to the increase in transportation revenues. These increases were partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions. Operating revenues for the Pipeline and Storage segment increased $9.0 million for the six months ended March 31, 2023 as compared with the six months ended March 31, 2022. The increase in operating revenues was primarily due to an increase in transportation revenues of $11.1 million and an increase in storage revenues of $0.5 million, partially offset by a decrease in other revenue of $2.5 million. The increase in transportation revenues was primarily attributable to new demand charges for transportation service from Supply Corporation's FM100 Project, which was placed into service in December 2021. The increase from the FM100 Project includes the impact of a negotiated revenue step-up to Period 2 Rates that went into effect April 1, 2022, as mentioned above. An increase in short-term contracts also contributed to the increase in transportation revenues. These increases were partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions. The increase in storage revenues was mainly due to the Period 2 Rates that went into effect April 1, 2022 related to the FM100 Project, as discussed above, as well as an increase in reservation charges for storage service from several new contracts that went into effect. The decrease in other revenue primarily reflects an adjustment to electric surcharge revenues and lower cashout revenues. Transportation volume for the quarter ended March 31, 2023 decreased by 1.1 Bcf from the prior year's quarter ended March 31, 2022. For the six months ended March 31, 2023, transportation volume increased by 30.5 Bcf from the prior year's six-month period ended March 31, 2022. The increase in transportation volume for the six-month period primarily reflects an increase in volume from the FM100 Project, which was brought online in December 2021, as well as an increase in short-term contracts. These were partially offset by certain contract terminations during the six months ended March 31, 2023. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire. The Pipeline and Storage segment’s earnings for the quarter ended March 31, 2023 were $23.9 million, a decrease of $1.6 million when compared with earnings of $25.5 million for the quarter ended March 31, 2022. The decrease in earnings was primarily due to an increase in operating expenses of $2.2 million, combined with the earnings impact of lower operating revenues of $0.2 million, as discussed above. The increase in operating expenses was primarily due to higher personnel costs, higher pipeline integrity costs and an increase in compressor maintenance costs. This was partially offset by lower power costs related to Empire's electric motor drive compressor station. This reduction in electric power costs is offset by an equal reduction in revenue, as discussed above. These earnings decreases were partially offset by an increase in other income of $0.9 million, which was primarily due to a higher weighted average interest rate on intercompany short-term notes receivables along with higher non-service pension and post-retirement benefit income. This was partially offset by a decrease in the allowance for funds used during construction (equity component) related to an annual adjustment that was recorded during the current quarter. The Pipeline and Storage segment’s earnings for the six months ended March 31, 2023 were $53.3 million, an increase of $2.7 million when compared with earnings of $50.6 million for the six months ended March 31, 2022. The increase in earnings was primarily due to the earnings impact of higher operating revenues of $7.1 million, as discussed above, combined with an increase in other income ($1.5 million). The increase in other income is primarily due to a higher weighted average interest rate on intercompany short-term notes receivables along with higher non-service pension and post-retirement benefit income. This was partially offset by a decrease in allowance for funds used during construction (equity component) related to the construction of the FM100 Project that was placed into service in December 2021 along with an annual adjustment that was recorded during the current fiscal year. These earnings increases were partially offset by increases in operating expenses ($3.7 million), depreciation expense ($1.6 million) and interest expense ($0.9 million). The increase in operating expenses was primarily due to higher personnel costs, higher pipeline integrity costs and an increase in compressor maintenance costs. This was partially offset by lower power costs related to Empire's electric motor drive compressor station. This reduction in electric 34 Table of Contents power costs is offset by an equal reduction in revenue, as discussed above. The increase in depreciation expense was primarily due to incremental depreciation from the FM100 Project going into service in December 2021. The increase in interest expense was mainly due to higher interest rates on security deposits and intercompany short-term borrowings, partially offset by a decrease in interest on intercompany long-term borrowings due to the Company's redemption of $500.0 million of 3.75% notes during the six months ended March 31, 2023. Gathering Gathering Operating Revenues Three Months Ended March 31, Six Months Ended March 31, (Thousands) 2023 2022 Increase (Decrease) 2023 2022 Increase (Decrease) Gathering Revenues $ 56,981 $ 52,604 $ 4,377 $ 113,394 $ 104,829 $ 8,565 Gathering Volume Three Months Ended March 31, Six Months Ended March 31, 2023 2022 Increase (Decrease) 2023 2022 Increase (Decrease) Gathered Volume - (MMcf) 109,344 103,736 5,608 217,371 204,829 12,542 2023 Compared with 2022 Operating revenues for the Ga thering segment increased $4.4 million for the quarter ended March 31, 2023 as compared with the quarter ended March 31, 2022, which was driven primarily by a 5.6 Bcf increase in gathered volume. The increase in gathered volume can be attributed primarily to an increase in natural gas production on the Covington and Clermont gathering systems, which recorded increases of 14.9 Bcf and 4.2 Bcf, respectively, partially offset by decreases on the Trout Run and Wellsboro gathering systems, which recorded decreases of 8.6 Bcf and 4.9 Bcf, respectively. The net increase can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems. Operating revenue s for the Gathering segment increased $8.6 million for the six months ended March 31, 2023 as compared with the six months ended March 31, 2022, which was driven primarily by a 12.5 Bcf increase in gathered volume. Contributors to the increase included the Covington and Clermont gathering systems, which recorded increases of 31.1 Bcf and 5.7 Bcf, respectively, partially offset by the Trout Run and Wellsboro gathering systems, which recorded decreases of 18.6 Bcf and 5.7 Bcf, respectively. The net increase 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, 2023 were $24.3 million, an increase of $2.2 million when compared with earnings of $22.1 million for the quarter ended March 31, 2022. The increase in earnings was mainly due to higher gathering revenues ($3.5 million) driven by the increase in gathered volume, as discussed above. These increases were partially offset by higher operating expenses ($0.9 million) and higher depreciation expense ($0.4 million). The increase in operating expenses was largely attributable to higher leased compression and material costs on the Trout Run and Covington gathering systems combined with higher labor costs across all of the gathering systems. The increase in depreciation expense was largely due to higher plant balances associated with the Covington and Clermont gathering systems. The Gathering segment’s earnings for the six months ended March 31, 2023 were $49.1 million, an increase of $3.9 million when compared with earnings of $45.2 million for the six months ended March 31, 2022. The increase in earnings was mainly due to higher gathering revenues ($6.8 million) driven by the increase in gathered volume, as discussed above. This increase was partially offset by higher operating expenses ($2.1 million) and higher depreciation expense ($0.7 million). The increase in operating expenses was largely attributable to higher leased compression costs on the Trout Run and Covington gathering systems, higher material costs on the Clermont and Covington gathering systems and higher labor costs across all of the gathering systems. The increase in depreciation expense was largely due to higher plant balances associated with the Covington and Clermont gathering systems. 35 Table of Contents Utility Utility Operating Revenues Three Months Ended March 31, Six Months Ended March 31, (Thousands) 2023 2022 Increase (Decrease) 2023 2022 Increase (Decrease) Retail Sales Revenues: Residential $ 320,043 $ 286,329 $ 33,714 $ 565,484 $ 469,037 $ 96,447 Commercial 47,569 41,668 5,901 82,913 66,910 16,003 Industrial 2,787 2,193 594 4,430 3,350 1,080 370,399 330,190 40,209 652,827 539,297 113,530 Transportation 38,581 43,159 (4,578) 68,093 72,810 (4,717) Other (1,864) (4,147) 2,283 (2,124) (6,147) 4,023 $ 407,116 $ 369,202 $ 37,914 $ 718,796 $ 605,960 $ 112,836 Utility Throughput Three Months Ended March 31, Six Months Ended March 31, (MMcf) 2023 2022 Increase (Decrease) 2023 2022 Increase (Decrease) Retail Sales: Residential 27,884 32,026 (4,142) 48,037 49,521 (1,484) Commercial 4,384 4,923 (539) 7,378 7,466 (88) Industrial 267 268 (1) 418 392 26 32,535 37,217 (4,682) 55,833 57,379 (1,546) Transportation 22,788 25,745 (2,957) 41,098 43,338 (2,240) 55,323 62,962 (7,639) 96,931 100,717 (3,786) Degree Days Three Months Ended March 31, Percent Colder (Warmer) Than Normal 2023 2022 Normal (1) Prior Year (1) Buffalo, NY 3,290 2,820 3,161 (14.3) % (10.8) % Erie, PA 3,108 2,645 2,973 (14.9) % (11.0) % Six Months Ended March 31, Buffalo, NY 5,543 4,868 4,865 (12.2) % 0.1 % Erie, PA 5,152 4,632 4,533 (10.1) % 2.2 % (1) Percents compare actual 2023 degree days to normal degree days and actual 2023 degree days to actual 2022 degree days. 2023 Compared with 2022 Operating revenues for the Utility segment increased $37.9 million for the quarter ended March 31, 2023 as compared with the quarter ended March 31, 2022. The increase resulted largely from a $40.2 million increase in retail gas sales revenue. This increase primarily reflects an increase in the cost of gas sold (per Mcf), partially offset by a 4.7 Bcf decrease in throughput due to warmer weather and a decrease in base rates. It should be noted that under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is not allowed to profit from fluctuations in gas costs. Purchased gas expense recorded on the consolidated income statement matches the revenues collected from customers. Revenues collected in 2023 reflect not only the current cost of gas but also the collection of previously deferred under collected gas costs. The decrease in base rates is related to a tariff filing approved by the NYPSC, which created a surcredit that temporarily eliminates pension and 36 Table of Contents OPEB cost recovery from base rates effective October 1, 2022. Additional details related to the regulatory proceeding are discussed in the Rate Matters section and in Item 1 at Note 11 - Regulatory Matters. In addition to the overall increase in retail gas sales revenue, there was a $2.3 million increase in other revenues. The increase in other revenues is the result of higher capacity release revenues ($1.1 million) and a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($1.4 million). Partially offsetting the impact of higher retail gas sales revenue and other revenues, there was a $4.6 million decrease in transportation revenues. The decrease in transportation revenues is mainly attributable to a decrease in base rates, as a result of the NYPSC tariff filing related to pension and OPEB costs discussed above, as well as a 3.0 Bcf decrease in throughput due to warmer weather. The decrease in transportation revenues was partially offset by an increase in the system modernization tracker allocation to transportation customers. Operating revenues for the Utility segment increased $112.8 million for the six months ended March 31, 2023 as compared with the six months ended March 31, 2022. The increase largely resulted from a $113.5 million increase in retail gas sales revenue and a $4.0 million increase in other revenues, which were partially offset by a $4.7 million decrease in transportation revenues. The increase in retail gas sales revenue was primarily due to a considerable increase in the cost of gas sold (per Mcf) partially offset by a decrease in base rates, as a result of the NYPSC tariff filing related to pension and OPEB costs discussed above, as well as a 1.5 Bcf decrease in throughput due to warmer weather. The increase in other revenues was largely due to higher capacity release revenues ($1.8 million), a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($0.9 million), a positive regulatory adjustment ($0.9 million), and higher late payment charges billed to customers ($0.5 million). The decrease in transportation revenues was largely due to a 2.2 Bcf decrease in transportation throughput during the six months ended March 31, 2023 and the decrease in base rates, as previously mentioned. The decrease in transportation revenues was partially offset by an increase in the system modernization tracker allocation to transportation customers. The Utility segment’s earnings for the quarter ended March 31, 2023 were $31.7 million, a decrease of $21.3 million when compared with earnings of $53.0 million for the quarter ended March 31, 2022. The decrease in earnings was primarily attributable to the non-recurrence of an adjustment that increased earnings by $14.6 million during the quarter ended March 31, 2022. The adjustment, which resulted from the conclusion of a proceeding in the Utility's Pennsylvania service territory, recognized the cumulative amount of OPEB income in that jurisdiction that previously had been deferred as a regulatory liability. In addition to the non-recurrence of this transaction, there was a decrease in OPEB income ($1.7 million) in the Utility's Pennsylvania service territory quarter over quarter. Other factors contributing to the decrease included a decrease in usage due to warmer weather ($2.9 million), higher interest expense ($3.4 million), and higher operating expenses ($1.7 million). The increase in interest expense was largely the result of a higher weighted average interest rate on intercompany short-term borrowings. The increase in operating expenses was mainly due to higher personnel costs and an increase in the accrual for uncollectible accounts. An additional decrease of $6.3 million resulted from a reduction in the New York jurisdiction’s base rates as a result of the NYPSC tariff filing related to pension and OPEB costs discussed above, which temporarily eliminated the recovery of pension and OPEB expenses effective October 1, 2022. This was offset by a decrease in non-service pension and post-retirement benefit costs ($6.6 million), as Distribution Corporation’s New York service territory ceased recognizing pension and OPEB expenses. Partially offsetting these decreases, the Utility segment also experienced the positive earnings impact of a system modernization tracker in New York ($1.7 million), interest earned on deferred gas costs ($0.7 million), and lower income tax expense ($0.8 million) when comparing the quarter ended March 31, 2023 to the quarter ended March 31, 2022. The impact of weather variations on earnings in the Utility segment's New York rate jurisdiction is mitigated by that jurisdiction's weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment's New York customers. For the quarter ended March 31, 2023, the WNC increased earnings by approximately $3.3 million, as the weather was warmer than normal. For the quarter ended March 31, 2022, the WNC increased earnings by approximately $1.5 million, as the weather was warmer than normal. The Utility segment’s earnings for the six months ended March 31, 2023 were $55.5 million, a decrease of $19.7 million when compared with earnings of $75.2 million for the six months ended March 31, 2022. The decrease is primarily attributable to the non-recurrence of an adjustment that increased earnings by $14.6 million during the quarter ended March 31, 2022, as discussed above. In addition to the non-recurrence of this transaction, there was a decrease in OPEB income ($1.6 million) in the Utility's Pennsylvania service territory period over period. The reduction in the New York jurisdiction's base rates resulting from the NYPSC tariff filing also discussed above ($10.1 million), higher interest expense primarily due to a 37 Table of Contents higher weighted average interest rate on intercompany short-term borrowings ($5.4 million), and higher operating expenses ($4.1 million) resulting from higher personnel costs and an increase in the accrual for uncollectible accounts also contributed to the decrease in earnings. Given the elimination of pension and OPEB expense in customer rates, earnings benefited from a decrease in non-service pension and OPEB costs ($10.2 million) in Distribution Corporation's New York service territory, as a result of the NYPSC tariff filing, discussed above. In addition, the impact of a system modernization tracker in New York ($2.6 million), higher other operating revenues ($1.7 million), and lower income tax expense ($0.7 million) partially offset the decrease in earnings when comparing the six months ended March 31, 2023, to the six months ended March 31, 2022. Other operating revenues increased largely due to higher capacity release revenues. For the six months ended March 31, 2023, the WNC increased earnings by approximately $4.2 million, as the weather was warmer than normal. For the six months ended March 31, 2022, the WNC increased earnings by approximately $4.1 million, as the weather was warmer than normal. Corporate and All Other 2023 Compared with 2022 Corporate and All Other operations had a net loss of less than $0.1 million for the quarter ended March 31, 2023, a decrease in net loss of $4.4 million when compared with the quarter ended March 31, 2022 . The reduction in net loss was primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the quarter ended March 31, 2023, the Company recorded unrealized gains of $0.8 million. During the quarter ended March 31, 2022, the Company recorded unrealized losses of $1.7 million. Also contributing to the reduction in net loss were changes in cash surrender value of life insurance policies, which increased in value $0.4 million during the current quarter compared to a decrease in value of $0.7 million during the prior-year second quarter. For the six months ended March 31, 2023, Corporate and All Other operations had earnings of $0.5 million, an increase of $5.3 million when compared with a net loss of $4.8 million for the six months ended March 31, 2022. The increase in earnings was primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the six months ended March 31, 2023, the Company recorded unrealized gains of $1.0 million. During the six months ended March 31, 2022, the Company recorded unrealized losses of $5.3 million. Lower non-service pension and post-retirement benefit costs ($1.0 million) also contributed to the increase in earnings. These changes were partially offset by a decrease in realized gains from sales of investments in equity securities ($2.9 million). Other Income (Deductions) Net other income on the Consolidated Statement of Income was $2.9 million for the quarter ended March 31, 2023, compared to net other income of $10.0 million for the quarter ended March 31, 2022. This change is primarily attributable to an $11.2 million decrease in non-service pension and post-retirement benefit income quarter over quarter. This is largely related to lower non-service post-retirement benefit income in the Utility’s Pennsylvania service territory stemming from the conclusion of a rate proceeding in the Utility’s Pennsylvania service territory during the quarter ended March 31, 2022. As a result of that proceeding, a one-time adjustment was recorded to reduce a regulatory liability in that jurisdiction by $18.5 million. This decrease in OPEB income was partially offset by an $8.3 million decrease in non-service pension and post-retirement benefit expense in the Utility’s New York Service territory as a result of a tariff filing that became effective October 1, 2022. Additional details related to the regulatory proceedings are discussed in the Rate Matters section and in Item 1, Note 11 – Regulatory Matters. Net other income on the Consolidated Statement of Income was $9.2 million for the six months ended March 31, 2023, compared to net other income of $8.9 million for the six months ended March 31, 2022. Higher interest income of $4.6 million contributed to the increase. This was primarily due to an increase in interest on temporary cash investments, increased interest on a larger undercollection of gas costs over the prior year in Distribution Corporation and an increase in interest received from hedging collateral deposits in the Exploration and Production segment. Changes in unrealized and realized gains and losses on investments in equity securities also increased other income by $5.1 million period over period. Offsetting these increases, there was a $5.0 million reduction in non-service pension and post-retirement benefit income period over period. As discussed above, the Utility's Pennsylvania service territory recorded a one-time adjustment that resulted in $18.5 million of income during the quarter ended March 31, 2022. The resulting earnings reduction in 2023 was largely offset by a $12.9 million decrease in non-service pension and post-retirement benefit expense in the Utility's New York service territory as a result of the 38 Table of Contents tariff filing that became effective October 1, 2022. Other offsetting factors include a mark-to-market adjustment that reduced the value of the contingent consideration received from the sale of Seneca's California assets in June 2022 and a $1.9 million reduction in allowance for funds used during construction. Interest Expense on Long-Term Debt Interest expense on long-term debt on the Consolidated Statement of Income decreased $2.5 million for the quarter ended March 31, 2023 as compared to the quarter ended March 31, 2022. For the six months ended March 31, 2023, interest expense on long-term debt decreased $3.0 million as compared with the six months ended March 31, 2022. This was primarily due to the March 2023 redemptions of $350.0 million of the $500.0 million 3.75% note and the $49.0 million 7.395% note. In addition, $150.0 million of the $500.0 million 3.75% note was redeemed in November 2022, which also contributed to the decrease. CAPITAL RESOURCES AND LIQUIDITY 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’s primary sources of cash during the six-month period ended March 31, 2022 consisted of cash provided by operating activities, net proceeds from short-term borrowings, proceeds from the sale of a fixed income mutual fund held in a grantor trust and net proceeds from the sale of oil and gas properties. 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 2023, cash provided by operating activities is expected to increase when compared to the same period in 2022 and will be used to fund the Company's capital expenditures. Based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures in 2024. This is expected to provide the Company with the option to consider additional growth investments, further reductions in short-term debt, and increasing the amount of cash flow returned to shareholders, either through increases to the Company’s dividend or via repurchases of common stock. 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 Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire. Because of the seasonal nature of the heating business in the Utility segment, revenues in this business are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the receivable balances at September 30. 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 derivative financial instruments, including price swap agreements and no cost collars, in an attempt to manage this energy commodity price risk. 39 Table of Contents Net cash provided by operating activities totaled $711.2 million for the six months ended March 31, 2023, an increase of $285.6 million compared with $425.6 million provided by operating activities for the six months ended March 31, 2022. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Exploration and Production segment primarily due to higher cash receipts from natural gas production in the Appalachian region and higher realized natural gas prices, after hedging. Investing Cash Flow Expenditures for Long-Lived Assets The Company’s expenditures for long-lived assets totaled $440.6 million during the six months ended March 31, 2023 and $376.2 million during the six months ended March 31, 2022. The table below presents these expenditures: Total Expenditures for Long-Lived Assets Six Months Ended March 31, 2023 2022 Increase (Decrease) (Millions) Exploration and Production: Capital Expenditures $ 323.6 (1) $ 274.0 (2) $ 49.6 Pipeline and Storage: Capital Expenditures 33.3 (1) 38.5 (2) (5.2) Gathering: Capital Expenditures 34.1 (1) 20.0 (2) 14.1 Utility: Capital Expenditures 49.2 (1) 43.3 (2) 5.9 All Other: Capital Expenditures 0.4 0.4 — $ 440.6 $ 376.2 $ 64.4 (1) At March 31, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $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. (2) At March 31, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $52.5 million, $3.5 million, $3.4 million and $4.1 million, respectively, of non-cash capital expenditures. At September 30, 2021, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $47.9 million, $39.4 million, $4.8 million and $10.6 million, respectively, of non-cash capital expenditures. Exploration and Production 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 (including $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. The Exploration and Production segment capital expenditures for the six months ended March 31, 2022 were primarily well drilling and completion expenditures and included approximately $258.8 million for the Appalachian region (including $84.8 million in the Marcellus Shale area and $166.8 million in the Utica Shale area) and $15.2 million for the West Coast region. These amounts included approximately $93.4 million spent to develop proved undeveloped reserves. Pipeline and Storage The Pipeline and Storage segment capital expenditures for the six months ended 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. The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2022 were primarily for expenditures related to Supply Corporation's FM100 Project ($21.0 million). In addition, the Pipeline and Storage segment capital expenditures for the 40 Table of Contents six months ended March 31, 2022 included additions, improvements and replacements to this segment’s transmission and gas storage systems. Gathering 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, Covington, Trout Run and Wellsboro gathering systems, as discussed below. Midstream Company spent $10.2 million, $10.4 million, $3.8 million and $6.4 million, respectively, during the six months ended March 31, 2023 on the development of the Clermont, Covington, Trout Run, and Wellsboro 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 Wellsboro gathering systems. In the Tioga gathering system, which is part of Midstream Covington, expenditures were largely attributable to the expansion of on-pad and centralized station facilities related to bringing new development online. The majority of the Gathering segment capital expenditures for the six months ended March 31, 2022 included expenditures related to the continued expansion of Midstream Company's Clermont and Covington gathering systems. Midstream Company spent $8.7 million and $10.6 million, respectively, during the six months ended March 31, 2022 on the development of the Clermont and Covington gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines in the Clermont gathering system, as well as the development of new gathering facilities, including new in-field gathering pipelines and station upgrades in the Tioga gathering system. Utility The majority of the Utility segment capital expenditures for the six months ended March 31, 2023 and March 31, 2022 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions. Other Investing Activities In October 2021, the Company sold $30 million of fixed income mutual fund shares held in a grantor trust that was established for the benefit of Pennsylvania ratepayers. The proceeds were used in the Utility segment’s Pennsylvania service territory to fund a one-time customer bill credit of $25 million in October 2021 for previously overcollected OPEB expenses and the first year installment of a 5-year pass back of an additional $29 million in previously overcollected OPEB expenses in accordance with new rates that went into effect on October 1, 2021. In October 2022, the Company sold an additional $10 million of fixed income mutual fund shares held in the grantor trust. The proceeds from this sale were used to fund the second year installment of the 5-year pass back of overcollected OPEB expenses as well as to diversify a portion of grantor trust investments into lower risk money market mutual fund shares. Please refer to the Rate Matters section that follows for additional discussion of this matter. In March 2022, the Company completed the sale of certain oil and gas assets located in Tioga County, Pennsylvania effective as of October 1, 2021. The Company received net proceeds of $13.5 million from this sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale. On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which are in the Exploration and Production segment, to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing. The fair value of the contingent consideration was $5.9 million at March 31, 2023. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company 41 Table of Contents recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances. On March 22, 2023, the Company entered into a purchase and sale agreement to acquire certain upstream assets located in Potter and Tioga counties, Pennsylvania from SWN Production Company, LLC effective as of January 1, 2023 for total consideration of $127.0 million, subject to certain purchase price adjustments at closing. These assets are contiguous with existing Company owned upstream assets in Pennsylvania. The Company made a deposit of $12.7 million at the signing of the purchase and sale agreement and intends to finance the remaining acquisition cost using short and/or long-term borrowings. The transaction is expected to close before the end of June 2023. Project Funding Over the past two years, the Company has been financing capital expenditures with cash from operations, short-term debt and proceeds from the sale of the Company's California assets. During the six months ended March 31, 2023 and March 31, 2022, capital expenditures were funded with cash from operations and short-term debt. Going forward, the Company expects to use cash on hand, cash from operations and short-term or long-term borrowings, as needed, to finance capital expenditures. The level of short-term and/or long-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production, and the associated commodity price realizations, as well as the level of hedging collateral deposits 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, quicker 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 carbon emission reductions and/or energy transition including investments directly related to low- and no-carbon fuels. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s business segments depends, to a large degree, upon market and regulatory conditions as well as legislative actions. Financing Cash Flow Consolidated short-term debt increased $350.0 million, to a total of $410.0 million, when comparing the balance sheet at March 31, 2023 to the balance sheet at September 30, 2022. The maximum amount of short-term debt outstanding during the six months ended March 31, 2023 was $410.0 million. In addition to cash provided by operating activities, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. For example, during the six months ended March 31, 2023, the Company repaid $549.0 million of long-term debt with maturity dates in March 2023. The Company utilized short-term borrowings and cash on hand to redeem the maturities, resulting in an increase in the short-term debt balance. As of March 31, 2023, the Company had outstanding commercial paper of $160.0 million and short-term notes payable to banks of $250.0 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. On June 30, 2022, the Company entered into the 364-Day Credit Agreement with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company used the proceeds for general corporate purposes, which included using $150.0 million for the November 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date in March 2023. 42 Table of Contents 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. The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at March 31, 2023, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement and 364-Day Credit Agreement. On May 3, 2022, the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modified the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ended June 30, 2022, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet. Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. The 364-Day Credit Agreement includes the same debt to capitalization covenant and the same exclusions of unrealized gains or losses on derivative financial instruments as the Credit Agreement. At March 31, 2023, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement and 364-Day Credit Agreement, was .45. The constraints specified in the Credit Agreement and 364-Day Credit Agreement would have permitted an additional $3.20 billion in short-term and/or long-term debt to be outstanding at March 31, 2023 before the Company’s debt to capitalization ratio exceeded .65. A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. 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 364-Day Credit Agreement 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 and 364-Day Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. None of the Company's long-term debt as of March 31, 2023 had a maturity date within the following twelve-month period. The Current Portion of Long-Term Debt at September 30, 2022 consisted of $500.0 million of 3.75% notes ($150.0 million of which was subsequently paid in November 2022) and $49.0 million of 7.395% notes, that each had maturity dates in March 2023. The Company utilized short-term borrowings and cash on hand to repay $150.0 million of these maturities in November 2022 and the remaining $399.0 million in March 2023. The Company’s embedded cost of long-term debt was 4.58% at March 31, 2023 and 4.48% at March 31, 2022. Under the Company’s existing indenture covenants at March 31, 2023, the Company would have been permitted to issue up to a maximum of approximately $3.73 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by debt to capitalization ratio constraints under the Company's Credit Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy known demands. 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, 43 Table of Contents 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 2.4%) of the Company’s long-term debt (as of March 31, 2023) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived. OTHER MATTERS In addition to the 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. The Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project. The Company will update the $500 million preliminary cost estimate and expected in-service date for the project when there is further clarity on the timing of receipt of necessary regulatory approvals. As of March 31, 2023, approximately $55.9 million has been spent on the Northern Access project, including $24.3 million that has been spent to study the project. The remaining $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2023. The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) or its VEBA trusts for its other post-retirement benefits during the six months ended March 31, 2023, and does not anticipate making any such contributions during the remainder of fiscal 2023. 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. 44 Table of Contents The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At March 31, 2023, the Company determined that nonperformance risk associated with its natural gas price swap agreements, natural gas no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates. 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 2022 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 Pennsylvania 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. The 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. The order also authorized the Company to recover approximately $15 million annually for pension and OPEB expenses from customers. Because the Company's future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July 2022, Distribution Corporation made a filing with the NYPSC to effectuate a pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022. On September 16, 2022, the NYPSC issued an order approving the filing. The surcredit will remain in effect until modified by the NYPSC in another proceeding, or until December 31, 2024, whichever is earlier. With the implementation of this surcredit, Distribution Corporation will no longer be funding the Retirement Plan or its VEBA trusts in its New York jurisdiction. 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 via 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. On January 19, 2023, the NYPSC issued an order in its Effects of COVID-19 on Utility Service (20-M-0266) and Energy Affordability for Low Income Utility Customers (14-M-0565) proceedings whereby a Phase 2 Utility Arrears Relief Program was authorized. Specifically, the order directed Distribution Corporation and certain other New York utilities to, among other things, address arrears on residential non-energy affordability program (EAP) ratepayer accounts that did not receive a credit under the NYPSC’s Phase 1 program and small commercial ratepayer accounts by issuing a one-time bill credit to such customers to reduce or eliminate accrued arrears through May 1, 2022. The credits shall be processed within 90 days of the effective date of the order, provided that residential non-EAP customers who had their service disconnected for non-payment in 2022 shall be allowed the opportunity to have their service reinstated in order to receive the credit through June 30, 2023. The order further directs utilities to suspend residential service terminations for non-payment while arrears credits are applied to accounts through March 1, 2023, or 30 days after credits have been applied, whichever is later. The order authorizes the utilities to recover the Phase 2 costs (the arrears credits and associated carrying charges) through a surcharge. Utilities proposed various offsets to Phase 2 program costs, and Distribution Corporation has proposed certain offsets as part of an uncollectible expense reconciliation proposal. On February 17, 2023, Distribution Corporation made a filing with the NYPSC seeking approval of its uncollectible expense reconciliation mechanism and a determination is pending. Application of the proposed offsets and collection periods will be determined when the NYPSC rules on the uncollectible expense reconciliation filing. 45 Table of Contents Pennsylvania Jurisdiction Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007. On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $28.1 million with a proposed effective date of December 27, 2022. On December 8, 2022, the PaPUC issued an order suspending the filing until July 27, 2023 by operation of law unless directed otherwise by the PaPUC. Following discovery, the submission of testimony and an evidentiary hearing, the parties to the proceeding agreed to a settlement that authorizes, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million as of August 1, 2023. On April 13, 2023, Distribution Corporation filed a joint petition with the PaPUC seeking approval of the settlement on behalf of all active parties to the proceeding. The joint petition is currently pending before the PaPUC. Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC, Distribution Corporation reduced base rates by $7.7 million in order to stop collecting OPEB expenses from customers. It also began to refund to customers overcollected OPEB expenses in the amount of $50.0 million. All matters with respect to this tariff supplement were finalized on February 24, 2022 with the PaPUC's approval of an Administrative Law Judge's Recommended Decision. Concurrent with that decision, the Company discontinued regulatory accounting for OPEB expenses and recorded an $18.5 million adjustment during the quarter ended March 31, 2022 to reduce its regulatory liability for previously deferred OPEB income amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company also increased customer refunds of overcollected OPEB expenses from $50.0 million to $54.0 million. All refunds specified in the tariff supplement are being funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company's Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction. Pipeline and Storage Supply Corporation’s 2020 rate settlement provides that no party may make a rate filing for new rates to be effective before February 1, 2024, except that Supply Corporation may file an NGA general Section 4 rate case to change rates if the corporate federal income tax rate is increased. If no case has been filed, Supply Corporation must file for rates to be effective February 1, 2025. Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1, 2025. Environmental Matters The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory requirements. In 2021, the Company set methane intensity reduction targets at each of its businesses, an absolute greenhouse gas emissions reduction target for the consolidated Company, and greenhouse gas reduction targets associated with the Company’s utility delivery system. In 2022, the Company began measuring progress against these reduction targets. The Company's ability to estimate accurately the time, costs and resources necessary to meet emissions targets may change as environmental exposures and opportunities change and regulatory updates are issued. For further discussion of the Company's environmental exposures, refer to Item 1 at Note 8 — 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 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 regulates greenhouse gas 46 Table of Contents emissions pursuant to the Clean Air Act. The regulations implemented by the EPA impose more stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. 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. Pennsylvania's Governor also entered the Commonwealth into a cap-and-trade program known as the Regional Greenhouse Gas Initiative, however, the Commonwealth's participation is currently stayed due to ongoing litigation. 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. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on the promulgation of final regulations and on regulatory treatment afforded in the process. Thus far, the only regulations promulgated in connection with the CLCPA are statewide greenhouse gas emissions limits established by the NYDEC in 6 NYCRR Part 496, effective December 30, 2020. The NYDEC has until January 1, 2024 to issue further rules and regulations implementing the statute and had indicated that it will initiate regulatory proceedings to investigate development of a cap-and-invest program in New York. The above-enumerated initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years. Effects of Inflation The Company’s operations are sensitive to increases in the rate of inflation because of its operational and capital spending requirements in both its regulated and non-regulated businesses. For the regulated businesses, recovery of increasing costs from customers can be delayed by the regulatory process of a rate case filing. For the non-regulated businesses, prices received for services performed or products produced are determined by market factors that are not necessarily correlated to the underlying costs required to provide the service or product. Safe Harbor for Forward-Looking Statements The Company is including the following cautionary statement in this 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. 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; 47 Table of Contents 2. Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design, retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; 3. The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets; 4. Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas; 5. Changes in economic conditions, including inflationary pressures, supply chain issues, liquidity challenges, and global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; 6. Changes in the price of natural gas; 7. The creditworthiness or performance of the Company’s key suppliers, customers and counterparties; 8. Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; 9. Impairments under the SEC’s full cost ceiling test for natural gas reserves; 10. Increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; 11. The Company's ability to complete planned strategic transactions; 12. Changes in price differentials between similar quantities of natural gas sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; 13. The impact of information technology disruptions, cybersecurity or data security breaches; 14. Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability and costs, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; 15. 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 48 Table of Contents 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.