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 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. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar 2023 and 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. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances. The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation's system, referred to as the FM100 Project, upgraded a 1950’s era pipeline in northwestern Pennsylvania and created approximately 330,000 Dth per day of additional transportation capacity in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County, Pennsylvania to the Transcontinental Gas Pipe Line Company, LLC ("Transco") system at Leidy, Pennsylvania. Construction activities on the expansion portion of the FM100 Project are complete and the project was placed in service in December 2021. This project is expected to provide incremental annual transportation revenues of approximately $50 million. The FM100 Project is discussed in more detail in the Capital Resources and Liquidity section that follows. For further discussion of the Pipeline and Storage segment's revenues and earnings, refer to the Results of Operations section below. Seneca’s 330,000 Dth per day of incremental pipeline capacity on the Leidy South Project, which is the companion project to the Company's FM100 Project, went in service in December 2021. The incremental pipeline capacity from this project and associated gathering system development by Midstream Company allows Seneca to increase its production and reach premium Transco Zone 6 (Non-New York) markets. On February 28, 2022, the Company entered into 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 an initial 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. Under the delayed draw mechanism of the 364-Day Credit Agreement, the Company may, through September 28, 2022, make up to three elections to borrow funds under the facility, provided that the Company may extend the period to make such elections to October 28, 2022. 30 Table of Contents From a financing perspective, the Company expects to use the proceeds from the sale of the Company's California assets, cash on hand and cash from operations, as well as short-term borrowings, to meet its financing needs for fiscal 2022. The Company is closely monitoring and responding to developments related to COVID-19 and is taking steps to limit operational impacts and the potential exposure for our workforce and customers. Refer to Risk Factors in Part I, Item 1A, Risk Factors, under Operational Risks in the Company's 2021 Form 10-K for a more complete discussion of the risks to the Company associated with the COVID-19 pandemic. CRITICAL ACCOUNTING ESTIMATES For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2021 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 June 30, 2022, the ceiling exceeded the book value of the oil and gas properties by approximately $2.4 billion. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended June 30, 2022, based on the quoted Henry Hub spot price for natural gas, was $5.13 per MMBtu. (Note: Because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for the twelve months ended June 30, 2022. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices used at June 30, 2022 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's oil and gas properties by approximately $2.1 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 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 2021 Form 10-K. RESULTS OF OPERATIONS Earnings The Company's earnings were $108.2 million for the quarter ended June 30, 2022 compared to earnings of $86.5 million for the quarter ended June 30, 2021. The increase in earnings of $21.7 million is primarily the result of higher earnings in the Exploration and Production segment, Pipeline and Storage segment and Gathering segment. Lower earnings in the Utility segment and a higher loss in the Corporate category partially offset these increases. The Company's earnings were $407.9 million for the nine months ended June 30, 2022 compared to earnings of $276.7 million for the nine months ended June 30, 2021. The increase in earnings of $131.2 million is primarily the result of higher earnings in all reportable segments, partially offset by losses in the Corporate and All Other categories. 31 Table of Contents The Company's earnings for the quarter and nine months ended June 30, 2022 include the impact of several items in the Company's Exploration and Production segment related to the completion of the sale of Seneca’s California assets, as discussed above. The Company recorded a gain on the sale of these assets of $12.7 million ($9.5 million after-tax) related to a portion of the sales price that was applied to assets that were not subject to the full cost method of accounting. The Company also recorded a loss of $44.6 million ($33.3 million after-tax) related to the termination of its remaining crude oil derivative contracts as a result of the sale. In addition, the Company incurred transaction and severance costs of $9.7 million ($7.2 million after-tax) related to the California asset sale. The Company's earnings for the nine months ended June 30, 2022 include the reduction of an OPEB regulatory liability that increased earnings by $18.5 million ($14.6 million after-tax) recorded during the quarter ended March 31, 2022 in the Utility segment in accordance with a regulatory proceeding in Distribution Corporation's Pennsylvania service territory. The Company's earnings for the nine months ended June 30, 2021 included a non-cash impairment charge of $76.2 million ($55.2 million after-tax) recorded during the quarter ended December 31, 2020 for the Exploration and Production segment's oil and gas producing properties. The Company's earnings for the nine months ended June 30, 2021 also included a gain recognized on the sale of timber properties of $51.1 million ($37.0 million after-tax) recorded during the quarter ended December 31, 2020 in the Company's All Other category. 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 the earnings discussions are after-tax amounts, unless otherwise noted. Earnings (Loss) by Segment Three Months Ended June 30, Nine Months Ended June 30, (Thousands) 2022 2021 Increase (Decrease) 2022 2021 Increase (Decrease) Exploration and Production $ 56,497 $ 39,015 $ 17,482 $ 189,987 $ 46,213 $ 143,774 Pipeline and Storage 26,599 21,948 4,651 77,236 71,060 6,176 Gathering 24,658 20,427 4,231 69,887 61,677 8,210 Utility 4,622 4,841 (219) 79,800 59,922 19,878 Total Reportable Segments 112,376 86,231 26,145 416,910 238,872 178,038 All Other — 1,039 (1,039) (7) 37,617 (37,624) Corporate (4,218) (795) (3,423) (9,024) 196 (9,220) Total Consolidated $ 108,158 $ 86,475 $ 21,683 $ 407,879 $ 276,685 $ 131,194 Exploration and Production Exploration and Production Operating Revenues Three Months Ended June 30, Nine Months Ended June 30, (Thousands) 2022 2021 Increase (Decrease) 2022 2021 Increase (Decrease) Gas (after Hedging) $ 256,383 $ 175,378 $ 81,005 $ 680,670 $ 524,417 $ 156,253 Oil (after Hedging) (1) 40,867 33,065 7,802 112,907 93,256 19,651 Gas Processing Plant 1,016 732 284 3,029 2,056 973 Other (45,628) 360 (45,988) (38,178) 1,387 (39,565) $ 252,638 $ 209,535 $ 43,103 $ 758,428 $ 621,116 $ 137,312 32 Table of Contents Production Volumes Three Months Ended June 30, Nine Months Ended June 30, 2022 2021 Increase (Decrease) 2022 2021 Increase (Decrease) Gas Production (MMcf) Appalachia 88,888 79,314 9,574 253,842 236,429 17,413 West Coast 405 431 (26) 1,210 1,300 (90) Total Production 89,293 79,745 9,548 255,052 237,729 17,323 Oil Production (Mbbl) Appalachia 7 1 6 8 2 6 West Coast 519 557 (38) 1,589 1,681 (92) Total Production 526 558 (32) 1,597 1,683 (86) Average Prices Three Months Ended June 30, Nine Months Ended June 30, 2022 2021 Increase (Decrease) 2022 2021 Increase (Decrease) Average Gas Price/Mcf Appalachia $ 5.50 $ 2.29 $ 3.21 $ 4.64 $ 2.25 $ 2.39 West Coast $ 10.29 $ 5.36 $ 4.93 $ 10.04 $ 5.83 $ 4.21 Weighted Average $ 5.52 $ 2.31 $ 3.21 $ 4.67 $ 2.27 $ 2.40 Weighted Average After Hedging $ 2.87 $ 2.20 $ 0.67 $ 2.67 $ 2.21 $ 0.46 Average Oil Price/Bbl Appalachia $ 108.47 $ 42.09 $ 66.38 $ 104.83 $ 43.13 $ 61.70 West Coast $ 110.79 $ 67.55 $ 43.24 $ 94.06 $ 56.92 $ 37.14 Weighted Average $ 110.76 $ 67.52 $ 43.24 $ 94.11 $ 56.90 $ 37.21 Weighted Average After Hedging (1) $ 77.65 $ 59.22 $ 18.43 $ 70.71 $ 55.40 $ 15.31 (1) Oil revenue and weighted average oil price after hedging for the three months and nine months ended June 30, 2022 excludes a loss on discontinuance of crude oil cash flow hedges of $44,632. This loss is presented in other revenue in the table above. 2022 Compared with 2021 Operating revenues for the Exploration and Production segment increased $43.1 million for the quarter ended June 30, 2022 as compared with the quarter ended June 30, 2021. Gas production revenue after hedging increased $81.0 million due to the impact of a 9.5 Bcf increase in natural gas production, together with a $0.67 per Mcf increase 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 increased $7.8 million due to an increase in the weighted average price of oil after hedging of $18.43 per Bbl, partially offset by the impact of a 32 Mbbl decrease in oil production. The decrease in oil production was largely due to natural production declines. These amounts were partially offset by a decrease in other revenue of $46.0 million. The decrease in other revenue is primarily attributed to a loss on discontinuance of crude oil cash flow hedges combined with royalty shut-in payments made in accordance with lease agreements. Operating revenues for the Exploration and Production segment increased $137.3 million for the nine months ended June 30, 2022 as compared with the nine months ended June 30, 2021. Gas production revenue after hedging increased $156.3 million due to the impact of a 17.3 Bcf increase in natural gas production combined with a $0.46 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 nine months ended June 30, 2022 as 33 Table of Contents compared with the nine months ended June 30, 2021. Oil production revenue after hedging increased $19.7 million due to a $15.31 per Bbl increase in the weighted average price of oil after hedging, offset by the impact of an 86 Mbbl decrease in oil production. The decrease in oil production was largely due to natural production declines. These amounts were partially offset by a decrease in other revenue of $39.6 million. The decrease in other revenue was primarily attributed to a loss on discontinuance of crude oil cash flow hedges combined with royalty shut-in payments made in accordance with lease agreements. These were partially offset by a temporary capacity release for a small portion of this segment's Leidy South transportation contract and operating revenue from Highland Field Services water treatment plants acquired at the end of fiscal 2021. The Exploration and Production segment's earnings for the quarter ended June 30, 2022 were $56.5 million, an increase of $17.5 million when compared with earnings of $39.0 million for the quarter ended June 30, 2021. The increase in earnings was due to higher natural gas production ($16.6 million), higher natural gas prices after hedging ($47.4 million), higher oil prices after hedging ($7.7 million), lower income tax expense ($3.3 million) and a gain that was recognized on the sale of Seneca's California non-full cost pool assets ($9.5 million), as discussed above. The positive earnings impact of these items was partially offset by lower oil production ($1.5 million), higher lease operating and transportation expenses ($10.1 million), higher depletion expense ($7.3 million), higher other operating expenses ($4.8 million) and higher interest expense ($2.0 million). Finally, the Company also had a loss related to discontinuance of its crude oil cash flow hedges ($33.3 million) and had transaction and severance costs ($7.2 million), all of which were driven by the sale of its California assets. The increase in lease operating and transportation expenses was primarily the result of higher gathering and transportation costs in the Appalachian region due to increased production combined with higher steam fuel costs, utilities and contract labor in the West Coast region. 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 other operating expenses was primarily attributed to the accrual of estimated abandonment costs related to certain offshore Gulf of Mexico wells that were formally owned by the Company. Several years ago, Seneca sold those wells to an operator that has since gone bankrupt, and, as a result of the bankruptcy, the cost of abandoning the wells will likely revert back to Seneca. The increase in interest expense can largely be attributed to a higher average amount of intercompany short-term borrowings outstanding combined with a higher average interest rate on such borrowings. The Exploration and Production segment's earnings for the nine months ended June 30, 2022 were $190.0 million, an increase of $143.8 million when compared with earnings of $46.2 million for the nine months ended June 30, 2021. The increase in earnings was primarily attributable to an impairment of oil and gas properties ($55.2 million) recorded during the nine months ended June 30, 2021, higher natural gas production ($30.2 million), higher natural gas prices after hedging ($93.3 million), higher oil prices after hedging ($19.3 million), higher other revenue ($4.0 million), lower interest expense ($3.2 million), lower income tax expense ($3.8 million) and a gain that was recognized on the sale of Seneca's California non-full cost pool assets ($9.5 million). The Exploration and Production segment also recognized a loss in March 2021 ($10.7 million) for its share of the premium paid by the Company to redeem $500 million of the Company’s 4.90% notes that were scheduled to mature in December 2021. These increases in earnings were partially offset by lower oil production ($3.8 million), higher lease operating and transportation expenses ($17.3 million), higher depletion expense ($14.1 million), higher other operating expenses ($7.8 million) and higher other taxes ($3.1 million). Finally, the Company also had a loss related to discontinuance of its crude oil cash flow hedges ($33.3 million) and also had transaction and severance costs ($7.2 million), all of which were driven by the sale of its California assets. The decrease in interest expense can largely be attributed to a lower average amount of intercompany long-term borrowings outstanding combined with a lower average interest rate on such borrowings. The increase in lease operating and transportation expenses was primarily the result of higher gathering and transportation costs in the Appalachian region due to increased production combined with higher steam fuel costs, well workover costs and contract labor in the West Coast region. The increase in depletion expense was primarily due to the net increase in production combined with a $0.03 per Mcf increase in the depletion rate. The increase in other operating expenses was primarily attributed to the accrual of estimated abandonment costs related to certain offshore Gulf of Mexico wells formally owned by the Company, as discussed above. In addition, the increase in other operating expenses was also attributed to an increase in operating costs associated with the Highland Field Services water treatment plants acquired at the end of fiscal 2021. The increase in other taxes was mainly attributed to increased Impact Fees in the Appalachian region as a result of an increase in natural gas prices. The Impact Fees are calculated annually based on calendar year NYMEX natural gas prices. 34 Table of Contents Pipeline and Storage Pipeline and Storage Operating Revenues Three Months Ended June 30, Nine Months Ended June 30, (Thousands) 2022 2021 Increase (Decrease) 2022 2021 Increase (Decrease) Firm Transportation $ 74,384 $ 62,886 $ 11,498 $ 212,468 $ 191,889 $ 20,579 Interruptible Transportation 442 221 221 1,298 691 607 74,826 63,107 11,719 213,766 192,580 21,186 Firm Storage Service 21,084 20,646 438 63,334 62,351 983 Interruptible Storage Service — — — — 43 (43) Other (362) 310 (672) 2,195 3,558 (1,363) $ 95,548 $ 84,063 $ 11,485 $ 279,295 $ 258,532 $ 20,763 Pipeline and Storage Throughput Three Months Ended June 30, Nine Months Ended June 30, (MMcf) 2022 2021 Increase (Decrease) 2022 2021 Increase (Decrease) Firm Transportation 175,868 174,224 1,644 601,491 586,748 14,743 Interruptible Transportation 206 181 25 1,726 1,205 521 176,074 174,405 1,669 603,217 587,953 15,264 2022 Compared with 2021 Operating revenues for the Pipeline and Storage segment increased $11.5 million for the quarter ended June 30, 2022 as compared with the quarter ended June 30, 2021. The increase in operating revenues was primarily due to increases in transportation revenues of $11.7 million and storage revenues of $0.4 million, partially offset by a decrease in other revenue of $0.7 million. The increase in transportation revenues was primarily attributable to new demand charges for transportation service from the expansion portion of Supply Corporation's FM100 Project, which was placed into service in December 2021. This increase from the FM100 Project includes the impact of a negotiated revenue step-up to Period 2 Rates that went into effect April 1, 2022 as specified in Supply Corporation's 2020 rate case settlement. 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 a surcharge for Pipeline Safety and Greenhouse Gas Regulatory Costs (PS/GHG Regulatory Costs) that went into effect in November 2020 associated with Supply Corporation's 2020 rate case settlement. The decrease in other revenue primarily reflects lower electric surcharge true-up revenues. Revenues collected through the electric surcharge mechanism are completely offset by electric power costs recorded in operation and maintenance expense. Operating revenues for the Pipeline and Storage segment increased $20.8 million for the nine months ended June 30, 2022 as compared with the nine months ended June 30, 2021. The increase in operating revenues was primarily due to increases in transportation revenues of $21.2 million and storage revenues of $1.0 million, partially offset by a decrease in other revenues of $1.4 million. The increase in transportation revenues was primarily attributable to new demand charges for transportation service from Supply Corporation's FM100 Project being placed into service as mentioned above, which includes the impact of a negotiated revenue step-up to Period 2 Rates that went into effect April 1, 2022, also mentioned above. This increase was partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions. In addition, the PS/GHG Regulatory Costs surcharge that went into effect in November 2020 associated with Supply Corporation’s 2020 rate case settlement also contributed to the increase in transportation revenues and was primarily responsible for the increase in storage revenues. The decrease in other revenue primarily reflects the non-recurrence of revenue associated with a contract buyout that occurred during the quarter ended December 31, 2020, combined with lower electric surcharge true-up revenues, partially offset by higher cashout revenues. Cashout revenues are completely offset by purchased gas expense. Transportation volume for the quarter ended June 30, 2022 increased by 1.7 Bcf from the prior year's quarter ended June 30, 2021. For the nine months ended June 30, 2022, transportation volume increased by 15.3 Bcf from the prior year's 35 Table of Contents nine-month period ended June 30, 2021. The increase in transportation volume for both the quarter and nine months ended June 30, 2022 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 lower capacity utilization with certain contract shippers. 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 June 30, 2022 were $26.6 million, an increase of $4.7 million when compared with earnings of $21.9 million for the quarter ended June 30, 2021. The increase in earnings was primarily due to the earnings impact of higher operating revenues of $9.1 million, as discussed above. These earnings increases were partially offset by an increases in operating expenses ($1.4 million), depreciation expense ($1.4 million), and income tax expense ($0.7 million). The increase in operating expenses was primarily due to higher personnel costs, vehicle fuel costs and compressor station maintenance costs. This was partially offset by lower power costs related to Empire's electric motor drive compressor station. The electric power costs are offset by an equal amount of revenue, as discussed above. The increase in depreciation expense was primarily due to incremental depreciation from Supply Corporation's FM100 Project going into service in December 2021. The increase in income tax expense was mainly attributable to higher state income taxes due to higher pre-tax earnings. The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2022 were $77.2 million, an increase of $6.1 million when compared with earnings of $71.1 million for the nine months ended June 30, 2021. The increase in earnings was primarily due to the earnings impact of higher operating revenues of $16.4 million, as discussed above, combined with an increase in other income ($0.7 million). The increase in other income was mainly due to higher non-service pension and post-retirement benefit income partially offset by a decrease in the allowance for funds used during construction (equity component) as a result of the FM100 Project being placed in service in December 2021. These earnings increases were partially offset by increases in operating expenses ($5.9 million), depreciation expense ($2.9 million) and property taxes ($0.8 million). The increase in operating expenses was primarily due to a decrease in the reserve for preliminary project costs recorded during the nine months ended June 30, 2021 that did not recur this fiscal year, as well as an increase in personnel costs and vehicle fuel costs. This was partially offset by lower power costs related to Empire's electric motor driven compressor station. The Pipeline and Storage segment also experienced higher purchased gas costs ($0.9 million), largely related to Empire's natural gas-driven compressor stations. The electric power costs and purchased gas costs are offset by an equal amount of 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 property taxes was primarily due to school taxes related to the Empire North project's Farmington compressor station that were assessed since the project went into service. Gathering Gathering Operating Revenues Three Months Ended June 30, Nine Months Ended June 30, (Thousands) 2022 2021 Increase (Decrease) 2022 2021 Increase (Decrease) Gathering Revenues $ 55,931 $ 48,656 $ 7,275 $ 160,759 $ 145,927 $ 14,832 Gathering Volume Three Months Ended June 30, Nine Months Ended June 30, 2022 2021 Increase (Decrease) 2022 2021 Increase (Decrease) Gathered Volume - (MMcf) 109,797 91,817 17,980 314,625 275,283 39,342 2022 Compared with 2021 Operating revenues for the Ga thering segment increased $7.3 million for the quarter ended June 30, 2022 as compared with the quarter ended June 30, 2021, which was driven primarily by an 18.0 Bcf increase in gathered volume. The increase in gathered volume can be attributed primarily to an increase in natural gas production on the Covington, Wellsboro, Trout Run and Clermont gathering systems, which recorded increases of 10.7 Bcf, 3.6 Bcf, 2.3 Bcf and 1.4 Bcf, respectively. The increase 36 Table of Contents 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 $14.8 million for the nine months ended June 30, 2022 as compared with the nine months ended June 30, 2021, which was driven primarily by a 39.3 Bcf increase in gathered volume. Contributors to the increase included the Trout Run, Clermont, Wellsboro and Covington gathering systems, which recorded increases of 16.0 Bcf, 8.7 Bcf, 8.3 Bcf and 6.3 Bcf, respectively. The increase in gathered volume can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems. The Gathering segment’s earnings for the quarter ended June 30, 2022 were $24.7 million, an increase of $4.3 million when compared with earnings of $20.4 million for the quarter ended June 30, 2021. The increase in earnings was mainly due to higher gathering revenues ($5.7 million) driven by the increase in gathered volume, as discussed above. This increase was partially offset by higher operating expenses ($0.8 million) and income tax expense ($ 0.3 million). The increase in operating expenses was largely attributable to higher labor and costs for materials, as well as higher outside service costs associated with preventative maintenance overhauls on the Clermont gathering system. The Gathering segment’s earnings for the nine months ended June 30, 2022 were $69.9 million, an increase of $8.2 million when compared with earnings of $61.7 million for the nine months ended June 30, 2021. The increase in earnings was mainly due to higher gathering revenues ($11.7 million) driven by the increase in gathered volume, as discussed above. Additionally, the Gathering segment's earnings were positively impacted as a result of the Gathering segment's recognition of a loss during the quarter end March 31, 2021 ($0.7 million) for its share of the premium paid by the Company to redeem $500 million of the Company's 4.90% notes that were scheduled to mature in December 2021. The increases were partially offset by higher operating expenses ($2.2 million), depreciation expense ($1.0 million) and income tax expense ($1.0 million). The increase in operating expenses was largely attributable to higher labor costs combined with higher outside service costs associated with preventative maintenance overhauls on the Trout Run and Clermont gathering systems. The increase in depreciation expense was largely due to higher plant balances associated with the Clermont gathering system. Utility Utility Operating Revenues Three Months Ended June 30, Nine Months Ended June 30, (Thousands) 2022 2021 Increase (Decrease) 2022 2021 Increase (Decrease) Retail Sales Revenues: Residential $ 138,589 $ 94,611 $ 43,978 $ 607,626 $ 439,853 $ 167,773 Commercial 17,612 10,966 6,646 84,523 57,369 27,154 Industrial 786 497 289 4,135 2,798 1,337 156,987 106,074 50,913 696,284 500,020 196,264 Transportation 22,718 21,371 1,347 95,528 93,437 2,091 Other 243 (437) 680 (5,903) (6,568) 665 $ 179,948 $ 127,008 $ 52,940 $ 785,909 $ 586,889 $ 199,020 37 Table of Contents Utility Throughput Three Months Ended June 30, Nine Months Ended June 30, (MMcf) 2022 2021 Increase (Decrease) 2022 2021 Increase (Decrease) Retail Sales: Residential 10,344 9,776 568 59,865 57,241 2,624 Commercial 1,511 1,369 142 8,977 8,206 771 Industrial 74 65 9 466 441 25 11,929 11,210 719 69,308 65,888 3,420 Transportation 12,936 13,298 (362) 56,274 55,815 459 24,865 24,508 357 125,582 121,703 3,879 Degree Days Three Months Ended June 30, Percent Colder (Warmer) Than Normal 2022 2021 Normal (1) Prior Year (1) Buffalo, NY 912 797 794 (12.6) % 0.4 % Erie, PA 871 741 741 (14.9) % — % Nine Months Ended June 30, Buffalo, NY 6,455 5,662 5,693 (12.3) % (0.5) % Erie, PA 6,023 5,274 5,188 (12.4) % 1.7 % (1) Percents compare actual 2022 degree days to normal degree days and actual 2022 degree days to actual 2021 degree days. 2022 Compared with 2021 Operating revenues for the Utility segme n t increased $52.9 million for the quarter ended June 30, 2022 as compared with the quarter ended June 30, 2021. The increase resulted from a $50.9 million increase in retail gas sales revenue, which was primarily due to a significant increase in the cost of gas sold (per Mcf). Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is not allowed to profit from fluctuations in gas costs. In addition, there was a $1.3 million increase in transportation revenues and a $0.7 million increase in other revenues. The increase in transportation revenues, despite a 0.4 Bcf decrease in transportation throughput, is mainly due to an increase in the system modernization tracker allocation to transportation customers. The increase in other revenues was mainly the result of higher late payment charges billed to customers. Operating revenues for the Utility segment increased $199.0 million for the nine months ended June 30, 2022 as compared with the nine months ended June 30, 2021. The increase largely resulted from a $196.3 million increase in retail gas sales revenue, which was primarily due to a significant increase in the cost of gas sold (per Mcf). In addition, there was a $2.1 million increase in transportation revenues and a $0.7 million increase in other revenues. The increase in transportation revenues was largely due to an increase in the system modernization tracker allocation to transportation customers as well as a 0.5 Bcf increase in transportation throughput due to slightly colder weather during the nine months ended June 30, 2022. The increase in other revenues was largely due to higher late payment charges billed to customers and higher capacity release revenues. The Utility segment’s earnings for the quarter ended June 30, 2022 were $4.6 million, a decrease of $0.2 million when compared with earnings of $4.8 million for the quarter ended June 30, 2021. The decrease in earnings was mainly attributable to higher operating expenses ($2.6 million) due to higher personnel costs, largely offset by the impact of a system modernization tracker in New York ($1.3 million). In addition, the net effect of changes resulting from the conclusion of a regulatory proceeding by the PaPUC in February 2022, resulted in a decrease to base rates related to the elimination of OPEB expenses in Pennsylvania ($1.1 million), which was more than offset by a decrease in non-service post-retirement benefit costs ($2.6 million) as Distribution Corporation's Pennsylvania service territory recognized OPEB income during the quarter ended June 30, 2022, compared to the prior year when it recognized OPEB expenses to match against the OPEB amounts collected in base rates. 38 Table of Contents 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 June 30, 2022, the WNC increased earnings by approximately $0.6 million, as the weather was warmer than normal. For the quarter ended June 30, 2021, the WNC increased earnings by approximately $1.3 million, as the weather was warmer than normal. The Utility segment’s earnings for the nine months ended June 30, 2022 were $79.8 million, an increase of $19.9 million when compared with earnings of $59.9 million for the nine months ended June 30, 2021. The increase is primarily attributable to the conclusion of the regulatory proceeding by the PaPUC in February 2022, which resulted in a reduction in an OPEB-related regulatory liability that increased earnings ($14.6 million). The regulatory proceeding also reduced base rates in Pennsylvania, which reduced earnings for the nine-month period ($5.9 million). With the elimination of OPEB expenses in customer rates, earnings benefited from a decrease in non-service post-retirement benefit costs ($10.3 million) as Distribution Corporation's Pennsylvania service territory recognized OPEB income during the nine months ended June 30, 2022 compared to the prior year period when it recognized OPEB expenses to match against the OPEB amounts collected in base rates. Additional details related to the regulatory proceeding are discussed in the Rate Matters section below and in Item 1 at Note 11 – Regulatory Matters. The impact of a system modernization tracker in New York ($3.7 million) and higher usage and the impact of weather on customer margins ($3.2 million) also contributed to the increase in earnings when comparing the nine months ended June 30, 2022 to the nine months ended June 30, 2021. These increases were partially offset by higher operating expenses ($4.5 million), which were primarily the result of higher personnel costs partially offset by a decrease in the allowance for uncollectible accounts, and the impact of regulatory true-up adjustments ($1.0 million). The decrease in the allowance for uncollectible accounts is related to the COVID-19 pandemic as the Company recorded incremental expense due to the potential for customer non-payment, given the economic environment, during 2021. For the nine months ended June 30, 2022 , the WNC increased earnings by approximately $4.8 million, as the weather was warmer than normal. For the nine months ended June 30, 2021, the WNC increased earnings by approximately $4.5 million, as the weather was warmer than normal. Corporate and All Other 2022 Compared with 2021 Corporate and All Other operations had a loss of $4.2 million for the quarter ended June 30, 2022, a decrease of $4.4 million when compared with earnings of $0.2 million for the quarter ended June 30, 2021. The decrease in earnings was primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the quarter ended June 30, 2022, the Company recorded unrealized losses of $2.7 million. During the quarter ended June 30, 2021, the Company recorded unrealized gains of $0.8 million. For the nine months ended June 30, 2022 , Corporate and All Other operations had a loss of $9.0 million, a decrease of $46.8 million when compared with earnings of $37.8 million for the nine months ended June 30, 2021 . The decrease in earnings was primarily attributable to the non-recurrence of a $51.1 million gain ($37.0 million gain after-tax) on sale of timber properties recorded by Seneca’s Northeast Division during the nine months ended June 30, 2021. The decrease can also be attributed to unrealized losses on investments in equity securities of $8.0 million during the nine months ended June 30, 2022 compared to unrealized gains on investments in equity securities of $0.5 million during the nine months ended June 30, 2021. Other Income (Deductions) Net other deductions on the Consolidated Statement of Income was $5.6 million for the quarter ended June 30, 2022, compared to net other deductions of $2.0 million for the quarter ended June 30, 2021. This change is primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the quarter ended June 30, 2022, the Company recorded pre-tax unrealized losses of $3.9 million. During the quarter ended June 30, 2021, the Company recorded pre-tax unrealized gains of $1.1 million and pre-tax realized gains of $0.7 million. Other income (deductions) was also impacted by the change in cash surrender value of life insurance policies, with the change in value for the quarter ended June 30, 2022 decreasing $0.7 million from the change in value for the quarter ended June 30, 2021, as well as a decrease in allowance for funds used during construction (equity component) of $1.2 million. This was partially offset by a decrease in 39 Table of Contents non-service pension and post-retirement benefit costs of $3.7 million for the quarter ended June 30, 2022 compared to the quarter ended June 30, 2021. As discussed above in the Utility, this is largely related to the February 2022 conclusion of the regulatory proceeding in Distribution Corporation's Pennsylvania service territory that addressed Distribution Corporation's recovery of OPEB expenses. Net other income on the Consolidated Statement of Income was $3.3 million for the nine months ended June 30, 2022, compared to net other deductions of $15.1 million for the nine months ended June 30, 2021. This change is primarily attributable to non-service pension and post-retirement benefit income of $4.5 million for the nine months ended June 30, 2022 compared to non-service pension and post-retirement benefit costs of $28.1 million for the nine months ended June 30, 2021. This is largely related to the February 2022 conclusion of a regulatory proceeding, as discussed in the previous paragraph. This was partially offset by changes in realized and unrealized gains and losses on investments in equity securities. During the nine months ended June 30, 2022, the Company recorded pre-tax realized gains of $4.4 million and pre-tax unrealized losses of $11.8 million. During the nine months ended June 30, 2021, the Company recorded pre-tax realized gains of $4.0 million and pre-tax unrealized gains of $0.6 million. Other income (deductions) was also impacted by the change in cash surrender value of life insurance policies, with the change in value for the nine months ended June 30, 2022 decreasing $1.6 million from the change in value for the nine months ended June 30, 2021, as well as a decrease in allowance for funds used during construction (equity component) of $0.6 million. Interest Expense on Long-Term Debt Interest expense on long-term debt on the Consolidated Statement of Income was relatively flat for the quarter ended June 30, 2022 as compared to the quarter ended June 30, 2021. For the nine months ended June 30, 2022, interest expense on long-term debt decreased $21.0 million as compared with the nine months ended June 30, 2021. The Company redeemed $500.0 million of 4.90% notes in March 2021 and paid an early redemption premium of $15.7 million that was recorded as interest expense on long-term debt. The remaining decrease is due largely to a lower weighted average interest rate on long-term debt, stemming from the Company's issuance of $500.0 million of 2.95% notes in February 2021, which replaced $500.0 million of 4.90% notes that were retired in March 2021. CAPITAL RESOURCES AND LIQUIDITY The Company’s primary sources of cash during the nine-month period ended June 30, 2022 consisted of cash provided by operating activities, net proceeds from short-term borrowings, proceeds from the sale of a fixed income mutual fund in a grantor trust and net proceeds from the sale of oil and gas producing properties. The Company’s primary sources of cash during the nine-month period ended June 30, 2021 consisted of cash provided by operating activities, net proceeds from the sale of timber properties and net proceeds from the issuance of long-term debt. 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 2022, cash provided by operating activities is expected to increase over the amount of cash provided by operating activities when compared to the same period in 2021 and, when combined with cash on hand, will be used to fund the Company's capital expenditures. There are no scheduled repayments of long-term debt in the remainder of 2022. Looking at 2023 through 2024, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures in each of those years, which could lead to further capital investments in the business or reductions in short-term borrowings and a net reduction in long-term debt in 2023 while still allowing the Company to meet its dividend requirements. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future. Operating Cash Flow Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, deferred income taxes, the reduction of an other post-retirement regulatory liability and stock-based compensation. Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from 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 40 Table of Contents 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. Net cash provided by operating activities totaled $654.0 million for the nine months ended June 30, 2022, a decrease of $17.8 million compared with $671.8 million provided by operating activities for the nine months ended June 30, 2021. The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Utility segment, slightly offset by higher cash provided by operating activities in the Exploration and Production Segment and Gathering Segment. The decrease in the Utility segment is primarily due to lower rates in the Utility segment's Pennsylvania service territory that went into effect October 1, 2021 combined with the timing of gas cost recovery, timing of gas receivables and other regulatory true-ups. The rates that went into effect included a one-time customer bill credit of $25 million in October 2021 for previously overcollected OPEB expenses and the beginning of a 5-year pass back of an additional $29 million in previously overcollected OPEB expenses. Please refer to the Rate Matters section that follows for additional discussion of this matter. The increase in Exploration and Production segment and the Gathering segment was primarily due to higher cash receipts from natural gas production and gathering services in the Appalachian region. Investing Cash Flow Expenditures for Long-Lived Assets The Company’s expenditures for long-lived assets totaled $564.2 million during the nine months ended June 30, 2022 and $509.7 million during the nine months ended June 30, 2021. The table below presents these expenditures: Total Expenditures for Long-Lived Assets Nine Months Ended June 30, 2022 2021 Increase (Decrease) (Millions) Exploration and Production: Capital Expenditures $ 405.7 (1) $ 263.8 (2) $ 141.9 Pipeline and Storage: Capital Expenditures 58.2 (1) 155.5 (2) (97.3) Gathering: Capital Expenditures 28.6 (1) 25.6 (2) 3.0 Utility: Capital Expenditures 71.0 (1) 66.7 (2) 4.3 All Other: Capital Expenditures 0.7 0.2 0.5 Eliminations — (2.1) 2.1 $ 564.2 $ 509.7 $ 54.5 (1) At June 30, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $62.0 million, $5.2 million, $2.5 million and $4.7 million, respectively, of non-cash capital expenditures. At September 30, 2021, 41 Table of Contents 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. (2) At June 30, 2021, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $49.7 million, $25.8 million, $0.9 million and $5.1 million, respectively, of non-cash capital expenditures. At September 30, 2020, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $45.8 million, $17.3 million, $13.5 million and $10.7 million, respectively, of non-cash capital expenditures. Exploration and Production The Exploration and Production segment capital expenditures for the nine months ended June 30, 2022 were primarily well drilling and completion expenditures and included approximately $387.0 million for the Appalachian region (including $123.0 million in the Marcellus Shale area and $253.4 million in the Utica Shale area) and $18.7 million for the West Coast region. These amounts included approximately $130.8 million spent to develop proved undeveloped reserves. The Exploration and Production segment's capital expenditures for fiscal 2022 are expected to be in the range of $525 million to $550 million. The Exploration and Production segment capital expenditures for the nine months ended June 30, 2021 were primarily well drilling and completion expenditures and included approximately $255.8 million for the Appalachian region (including $79.8 million in the Marcellus Shale area and $155.6 million in the Utica Shale area) and $8.0 million for the West Coast region. These amounts included approximately $68.5 million spent to develop proved undeveloped reserves. Pipeline and Storage The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2022 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2022 included expenditures related to Supply Corporation's FM100 Project ($23.0 million), which is discussed below. The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2021 were primarily for expenditures related to Supply Corporation's FM100 Project ($115.4 million). In addition, the Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2021 included additions, improvements and replacements to this segment’s transmission and gas storage systems. In light of the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, specifically in the Marcellus and Utica Shale producing areas, Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems. Supply Corporation has developed its FM100 Project, which upgraded a 1950's era pipeline in northwestern Pennsylvania and created approximately 330,000 Dth per day of additional transportation capacity in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County to the Transcontinental Gas Pipe Line Company, LLC (“Transco”) system at Leidy, Pennsylvania. Supply Corporation and Transco executed a precedent agreement whereby Transco has leased this additional capacity ("Lease") as part of a Transco expansion project ("Leidy South"), creating incremental transportation capacity to Transco Zone 6 (Non-New York) markets. Seneca is an anchor shipper on Leidy South, which provides it with an outlet to premium markets from both its Eastern and Western development areas. Construction activities on the expansion portion of the FM100 project are complete and the project commenced partial in-service on December 1, 2021, with full in-service on December 19, 2021. Abandonment activities on the project will continue in calendar year 2022. As of June 30, 2022, approximately $209.2 million has been spent on the FM100 project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at June 30, 2022. Supply Corporation and Empire have developed a project which would move significant prospective Marcellus and Utica production from Seneca's Western Development Area at Clermont to an Empire interconnection with the TC Energy pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York (the “Northern Access project”). The Northern Access project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. On February 3, 2017, the Company received FERC approval of the project. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean 42 Table of Contents Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order, and FERC's decisions were appealed. The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. 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 June 30, 2022, approximately $55.8 million has been spent on the Northern Access project, including $24.2 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 June 30, 2022. Gathering The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2022 included expenditures related to the continued expansion of Midstream Company's Clermont and Covington gathering systems, as discussed below. Midstream Company spent $13.4 million and $12.9 million, respectively, during the nine months ended June 30, 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, which is part of Midstream Covington. The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2021 were for the continued expansion of Midstream Company's Clermont and Wellsboro gathering systems. Midstream Company spent $15.1 million and $3.7 million, respectively, during the nine months ended June 30, 2021 on the development of the Clermont and Wellsboro gathering systems. These expenditures were largely attributable to new Clermont gathering pipelines, as well as the continued development of centralized station facilities, including increased compression horsepower at the Clermont and Wellsboro gathering systems and additional dehydration on the Clermont gathering system. NFG Midstream Clermont, LLC, a wholly-owned subsidiary of Midstream Company, continues to develop an extensive gathering system with compression in the Pennsylvania counties of McKean, Elk and Cameron. The Clermont gathering system was initially placed in service in July 2014. The current system consists of three compressor stations and backbone and in-field gathering pipelines. The total cost estimate for the continued buildout will be dependent on the nature and timing of Seneca's long-term plans. NFG Midstream Covington, LLC, a wholly-owned subsidiary of Midstream Company, operates its Covington gathering system as well as the Tioga gathering system acquired from Shell on July 31, 2020, both in Tioga County, Pennsylvania. The current Covington gathering system consists of two compressor stations and backbone and in-field gathering pipelines. The Tioga gathering system consists of 13 compressor stations and backbone and in-field gathering pipelines. NFG Midstream Wellsboro, LLC, a wholly-owned subsidiary of Midstream Company, continues to develop its Wellsboro gathering system in Tioga County, Pennsylvania. The current system consists of one compressor station and backbone and in-field gathering pipelines. Utility The majority of the Utility segment capital expenditures for the nine months ended June 30, 2022 and June 30, 2021 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions. The Utility segment's capital expenditures for fiscal 2022 are expected to be in the range of $100 million to $110 million. Other Investing Activities On December 10, 2020, the Company completed the sale of substantially all timber properties in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme Allegheny Land Company II LLC for net proceeds of $104.6 million. After purchase price adjustments and transaction costs, a gain of $51.1 million was recognized on the sale of these assets ($37.0 million after-tax). The sale of the timber properties completed a reverse like-kind exchange pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchange”). On July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from Shell for total consideration of $506.3 million. 43 Table of Contents The purchase and sale agreement with Shell was structured, in part, as a Reverse 1031 Exchange. Refer to Item 8, Note B – Asset Acquisitions and Divestitures, of the Company’s 2021 Form 10-K for additional information concerning the Company’s acquisition of certain upstream assets and midstream gathering assets from Shell. 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. 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 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. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar 2023 and 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. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. 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. Project Funding Over the past two years, the Company has been financing capital expenditures with cash from operations, short-term and long-term debt, common stock, and proceeds from the sale of timber properties. During the nine months ended June 30, 2022 and June 30, 2021, capital expenditures were funded with cash from operations and short-term debt. The Company issued long-term debt and common stock in June 2020 to help finance the acquisition of upstream assets and midstream gathering assets from Shell. The financing of the asset acquisition from Shell was completed in December 2020 when the Company completed the sale of substantially all of its timber properties, through the completion of the Reverse 1031 Exchange discussed above. Going forward, the Company expects to use cash on hand, cash from operations, short-term borrowings and proceeds from the sale of the Company's California assets to finance capital expenditures. The level of short-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by the timing of gas cost recovery in the Utility segment. It will also depend on natural gas production, and the associated commodity price realizations, as well as the level of hedging collateral deposits in the Exploration and Production 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 oil and gas properties, quicker development of existing oil and 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. 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 other business segments depends, to a large degree, upon market and regulatory conditions. Financing Cash Flow Consolidated short-term debt increased $241.5 million, to a total of $400.0 million, when comparing the balance sheet at June 30, 2022 to the balance sheet at September 30, 2021. The maximum amount of short-term debt outstanding during the nine months ended June 30, 2022 was $675.4 million. In addition to cash provided by operating activities, the Company 44 Table of Contents 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, elevated commodity prices relative to its existing portfolio of derivative financial instruments led to the Company posting margin of $154.5 million with a number of its derivative counterparties as of June 30, 2022. The maximum amount of margin posted during the nine months ended June 30, 2022 was $464.2 million. The Company's margin deposits are reflected on the balance sheet as a current asset titled Hedging Collateral Deposits. To meet these margin requirements and other near-term cash flow needs, the Company utilized short-term debt in the form of commercial paper and borrowings under its revolving credit facility. As of June 30, 2022, the Company had short-term notes payable to banks of $400.0 million. The Company did not have any commercial paper outstanding at June 30, 2022. On June 30, 2022, the Company received $240.9 million in proceeds, after customary closing adjustments, related to the sale of the Company's California assets. Subsequent to June 30, 2022, these proceeds were used to reduce the amount of short-term notes payable to banks. On February 28, 2022, the Company entered into 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 an initial 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. Under the delayed draw mechanism of the 364-Day Credit Agreement, the Company may, through September 28, 2022, make up to three elections to borrow funds under the facility, provided that the Company may extend the period to make such elections to October 28, 2022. 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 June 30, 2022, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement. On May 3, 2022, the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modifies 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 balance sheet. Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. At June 30, 2022, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement, was .53. The constraints specified in the Credit Agreement would have permitted an additional $1.99 billion in short-term and/or long-term debt to be outstanding at June 30, 2022 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 contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other 45 Table of Contents borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. On February 24, 2021, the Company issued $500.0 million of 2.95% notes due March 1, 2031. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.3 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 4.95%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded. The proceeds of this debt issuance were used for general corporate purposes, including the redemption of $500.0 million of the Company's 4.90% notes on March 11, 2021 that were scheduled to mature in December 2021. The Company redeemed those notes for $515.7 million, plus accrued interest. The Current Portion of Long-Term Debt at June 30, 2022 consists of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes that mature in March 2023. None of the Company's long-term debt as of September 30, 2021 had a maturity date within the following twelve-month period. The Company’s embedded cost of long-term debt was 4.48% at both June 30, 2022 and June 30, 2021. Under the Company’s existing indenture covenants at June 30, 2022, the Company would have been permitted to issue up to a maximum of approximately $1.89 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, 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 $99.0 million (or 3.7%) of the Company’s long-term debt (as of June 30, 2022) 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. During the nine months ended June 30, 2022, the Company contributed $19.3 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $2.7 million to its VEBA trusts for its other post-retirement benefits. In the remainder of 2022, the Company expects to contribute approximately $1.1 million to its Retirement Plan. In the remainder of 2022, the Company expects to contribute approximately $0.2 million to its VEBA trusts. 46 Table of Contents The Company, in its Exploration and Production segment, entered into contractual obligations for the nine months ended June 30, 2022 to spend $67.3 million for hydraulic fracturing services work through June 1, 2024. Market Risk Sensitive Instruments On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act required the CFTC, SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation, and includes provisions related to the swaps and over-the-counter derivatives markets that are designed to promote transparency, mitigate systemic risk and protect against market abuse. Although regulators have issued certain regulations, other rules that may impact the Company have yet to be finalized. Rules developed by the CFTC and other regulators could impact the Company. While many of those rules place specific conditions on the operations of swap dealers and major swap participants, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs. Additionally, given the enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and 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 continues to monitor these enforcement and other regulatory developments, but cannot predict the impact that evolving application of the Dodd-Frank Act may have on its operations. The authoritative guidance for fair value measurements and disclosures 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 June 30, 2022, 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 2021 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.” Neither the New York or Pennsylvania divisions currently have 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. 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). The extension is contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to April 1, 2023. In response to the COVID-19 pandemic, various legislative actions and NYPSC Staff requests resulted in the Company suspending service terminations and disconnections. All legislative prohibitions have expired and the Company has agreed to refrain from terminating residential customers (1) with a pending application for arrears payments through the Emergency Rental Assistance Program administered by the Office of Temporary Disability and (2) participating in the Company’s Statewide Low Income Program (EAP) through September 1, 2022. 47 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. The rate settlement does not specify any requirement to file a future rate case. On July 22, 2021, Distribution Corporation filed a supplement to its current Pennsylvania tariff proposing to reduce base rates effective October 1, 2021 by $7.7 million in order to stop collecting other post-employment benefit (“OPEB”) expenses from customers, to begin to refund to customers overcollected OPEB expenses in the amount of $50.0 million, to suspend all regulatory accounting for OPEB expenses and record the cumulative amount of OPEB income previously deferred as a regulatory liability, and to make certain other adjustments to further reduce Distribution Corporation’s regulatory liability associated with OPEB expenses. The PaPUC issued an order approving this tariff supplement on September 15, 2021 and new rates went into effect on October 1, 2021. On September 21, 2021, a complaint was filed in the proceeding. While new rates, including associated refunds, went into effect on October 1, 2021, the Company decided to wait for resolution of the complaint before suspending regulatory accounting for OPEB expenses and recording the cumulative amount of OPEB income previously deferred as a regulatory liability in its consolidated financial statements. The PaPUC assigned the matter to an Administrative Law Judge who, on January 6, 2022, issued a Recommended Decision approving a settlement reached by parties to the complaint proceeding. Under the terms of the settlement, customer refunds of overcollected OPEB expenses increased from $50.0 million to $54.0 million. The Recommended Decision was approved by the PaPUC on February 24, 2022. Accordingly, the Company suspended regulatory accounting for OPEB expenses at that time 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 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 March 2021, the Company set greenhouse gas reduction targets associated with the Company's utility delivery system. To further our ongoing efforts to lower the Company's emissions profile, in September 2021 the Company also established methane intensity reduction targets at each of its businesses, as well as an absolute greenhouse gas emissions reduction target for the consolidated Company. 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. The U.S. Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented by EPA impose 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, other federal regulatory agencies are beginning to address greenhouse gas emissions through changes 48 Table of Contents in their regulatory oversight approach and policies. A number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. In New York, 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 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. NYDEC finalized its Part 203 Oil and Gas Sector Rule in March 2022, which establishes monitoring, operational, and reporting requirements with respect to methane and volatile organic compound emissions and significantly increases leak detection and repair (LDAR) inspections, repair and replacement obligations, recordkeeping, reporting, and notification requirements for multiple sources along natural gas metering and regulating stations, transmission pipelines, compressor stations, storage facilities, and gathering lines. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines and is in the process of evaluating cap-and-trade programs (e.g., Regional Greenhouse Gas Initiative). 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. 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. 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. 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 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: 49 Table of Contents 1. Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing; 2. Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design, retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal; 3. The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets; 4. Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas; 5. Changes in economic conditions, including inflationary pressures 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. The length and severity of the ongoing COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity; 9. Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; 10. Impairments under the SEC’s full cost ceiling test for natural gas reserves; 11. Increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, including disruptions due to the COVID-19 pandemic, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; 12. The Company's ability to complete planned strategic transactions; 13. The Company's ability to successfully integrate acquired assets and achieve expected cost synergies; 14. 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; 15. The impact of information technology disruptions, cybersecurity or data security breaches; 16. Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability, 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; 17. Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits; 18. Other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date; 19. The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; 20. Negotiations with the collective bargaining units representing the Company's workforce, including potential work stoppages during negotiations; 21. Uncertainty of gas reserve estimates; 22. Significant differences between the Company’s projected and actual production levels for natural gas; 23. Changes in demographic patterns and weather conditions (including those related to climate change); 24. Changes in the availability, price or accounting treatment of derivative financial instruments; 50 Table of Contents 25. 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; 26. Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war; 27. Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or 28. 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. Item 3. Quantitative and Qualitative Disclosures About Market Risk Refer to the "Market Risk Sensitive Instruments" section in Item 2 – MD&A.