NATIONAL FUEL GAS CO (NFG) FY 2022 MD&A

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

OVERVIEW

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

Corporate Responsibility

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

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

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

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Fiscal 2022 Highlights

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

1.The critical accounting estimates of the Company;

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

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

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

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

On June 30, 2022, the Company completed the sale of Seneca’s California assets to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing. The Company pursued this sale given the strong commodity price environment and the Company's strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances.

The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation's system, referred to as the FM100 Project, upgraded a 1950’s era pipeline in northwestern Pennsylvania and created approximately 330,000 Dth per day of additional transportation capacity in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County, Pennsylvania to the Transcontinental Gas Pipe Line Company, LLC ("Transco") system at Leidy, Pennsylvania. Construction activities on the expansion portion of the FM100 Project are complete and the project was placed into service in December 2021. This project will provide incremental annual transportation revenues of approximately $50 million. The FM100 Project is discussed in more detail in the Capital Resources and Liquidity section that follows. For further discussion of the Pipeline and Storage segment's revenues and earnings, refer to the Results of Operations section below.

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

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

On June 30, 2022, the Company entered into a new 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company is using the proceeds for general corporate purposes, which will include the redemption in November of a portion of the Company's outstanding long-term debt maturing in March 2023. The Company does not anticipate long-term refinancing for the $250.0 million drawn under the facility or the maturing long-term debt in March 2023.

CRITICAL ACCOUNTING ESTIMATES

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

Oil and Gas Exploration and Development Costs.  In the Company's Exploration and Production segment, gas and oil property acquisition, exploration and development costs are capitalized under the full cost method of accounting, with natural gas properties in the Appalachian region being the primary component of these capitalized costs after the June 30, 2022 sale of the Company's California oil and natural gas properties. That sale is discussed in more detail in Item 8 at Note B — Asset Acquisitions and Divestitures. Under this accounting methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.

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

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

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represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in natural gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment charge must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. At September 30, 2022, the ceiling exceeded the book value of the oil and gas properties by approximately $3.2 billion. The 12-month average of the first day of the month price for natural gas for each month during 2022, based on the quoted Henry Hub spot price for natural gas, was $6.13 per MMBtu. (Note — because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for 2022. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.)  In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices used at September 30, 2022 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's oil and gas properties by approximately $2.9 billion (after-tax), which would not have resulted in an impairment charge. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

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

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

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

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

RESULTS OF OPERATIONS

EARNINGS

2022 Compared with 2021

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

2022 Events

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

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

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

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

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

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

2021 Events

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

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

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

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Earnings (Loss) by Segment

EXPLORATION AND PRODUCTION

Revenues

Exploration and Production Operating Revenues

Production

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Average Prices

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

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

2022 Compared with 2021

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

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

Earnings

2022 Compared with 2021

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

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

In addition to the factors discussed above, the Exploration and Production segment's earnings were also impacted by the following factors. Factors that increased earnings included a 2022 gain ($9.5 million) that was recognized on the sale of the Exploration and Production segment's California non-full cost pool assets as well as a 2021 loss ($10.7 million) recognized for this segment's share of the premium paid by the Company to redeem $500 million of the Company's 4.90% notes that were scheduled to mature in December 2021. Factors that reduced earnings included a loss related to the discontinuance of this segment's crude oil cash flow hedges ($33.3 million), which was driven by the sale of the California assets, lower crude oil production ($28.2 million), higher lease operating and transportation expenses ($13.1 million), higher depletion expense ($20.3 million), higher other operating expenses ($5.4 million), an unrealized loss on a derivative asset ($3.2 million), higher other taxes ($2.5 million) and a higher effective tax rate ($6.3 million). The Company also recorded transaction and severance costs ($7.2 million) during 2022 associated with the sale of the California assets. The increase in lease operating and transportation expenses was primarily due to increased gathering and transportation costs in the Appalachian region offset by lower costs in the West Coast region due to selling the assets on June 30, 2022. The increase in depletion expense was primarily due to the increase in production, combined with a $0.03 per Mcfe increase in the depletion rate. The increase in other operating expenses was primarily attributed to abandonment costs related to certain offshore Gulf of Mexico wells formally owned by the Company. In addition, the increase in other operating expenses was attributed to operating costs associated with the Highland Field Services water treatment plants acquired at the end of fiscal 2021. The unrealized loss on a derivative asset represents an adjustment to the contingent consideration received for the sale of the California assets. The increase in other taxes was mainly attributed to increased Impact Fees in the Appalachian region as a result of an increase in natural gas prices. The Impact Fees are calculated annually based on calendar year NYMEX natural gas prices. The increase in the effective tax rate was primarily driven by a reduction to the valuation allowance recorded in fiscal 2021.

PIPELINE AND STORAGE

Revenues

Pipeline and Storage Operating Revenues

Pipeline and Storage Throughput — (MMcf)

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2022 Compared with 2021

Operating revenues for the Pipeline and Storage segment increased $33.5 million in 2022 as compared with 2021. The increase in operating revenues was primarily due to an increase in transportation revenues of $34.1 million and an increase in storage revenues of $1.5 million, partially offset by a decrease in other revenue of $2.1 million. The increase in transportation revenues was primarily attributable to new demand charges for transportation service from Supply Corporation's FM100 Project, which was placed into service in December 2021. The increase from the FM100 Project includes the impact of a negotiated revenue step-up to Period 2 Rates that went into effect April 1, 2022, as specified in Supply Corporation's 2020 rate case settlement. This increase was partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions. The increase in storage revenues was partially due to the Period 2 Rates that went into effect April 1, 2022 related to the FM100 Project, as discussed above. In addition, the Pipeline Safety and Greenhouse Gas Regulatory Costs (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 both transportation and 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. Revenues collected through the electric surcharge mechanism are completely offset by electric power costs recorded in operation and maintenance expense. Cashout revenues are completely offset by purchased gas expense.

Transportation volume increased by 24.3 Bcf in 2022 as compared with 2021, primarily due to incremental 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 majority of Supply Corporation's and Empire's transportation and storage contracts allow either party to terminate the contract upon six or twelve months' notice effective at the end of the primary term and include "evergreen" language that allows for annual term extension(s). The amount of firm transportation capacity contracted on the Pipeline and Storage segment's facilities is expected to decrease in fiscal 2023, primarily due to the termination of two long-term contracts with a nonaffiliated party totaling 300 MDth per day. Lower contracted quantities at the time of a future rate proceeding would be taken into account and would be the basis for setting new rates. The timing of Supply Corporation's next rate filing is discussed below under Rate Matters.

Earnings

2022 Compared with 2021

The Pipeline and Storage segment’s earnings in 2022 were $102.6 million, an increase of $10.1 million when compared with earnings of $92.5 million in 2021.  The increase in earnings was primarily due to the impact of higher operating revenues of $26.5 million, as discussed above, which was partially offset by an increase in depreciation expense ($4.2 million), higher property taxes ($0.8 million), an increase in operating expenses ($7.6 million) and higher income tax expense ($2.3 million). 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 the first-time assessment of property taxes for the Empire North project's Farmington compressor station. The increase in operating expenses was primarily due to a decrease in the reserve for preliminary project costs recorded during fiscal 2021 that did not recur in fiscal 2022, as well as an increase in personnel and technology-related costs and higher vehicle fuel costs. This was partially offset by lower power costs related to Empire's electric motor drive compressor station. The Pipeline and Storage segment also experienced higher purchased gas costs ($0.7 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 income tax expense was mainly due to a reduction in benefits associated with the tax sharing agreement with affiliated companies combined with higher state income tax expense due to higher pre-tax earnings for fiscal 2022.

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GATHERING

Revenues

Gathering Operating Revenues

Gathering Volume — (MMcf)

2022 Compared with 2021

Operating revenues for the Gathering segment increased $21.6 million in 2022 as compared with 2021, which was driven primarily by a 53.3 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, Clermont and Trout Run gathering systems, which recorded increases of 17.9 Bcf, 11.7 Bcf, 10.1 Bcf and 13.6 Bcf, respectively. The increase in gathered volume can be attributed to the increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.

Earnings

2022 Compared with 2021

The Gathering segment’s earnings in 2022 were $101.1 million, an increase of $20.8 million when compared with earnings of $80.3 million in 2021.  The increase in earnings was primarily attributable to higher gathering revenues ($17.0 million) driven by the increase in gathered volume (discussed above). Additionally, the Gathering segment recorded an income tax benefit ($11.9 million) from the remeasurement of deferred income taxes related to a state corporate income tax rate reduction in Pennsylvania that was signed into law in July 2022 (as discussed above, in the Exploration and Production segment). Earnings also increased 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. However, the Gathering segment's earnings were negatively impacted by the recording of deferred income tax expense ($3.7 million) as an offset to the reversal of the valuation allowance recorded by the Exploration and Production segment during the quarter ended September 30, 2022. This offset is a result of the Gathering and Exploration and Production segments' subsidiaries filing a combined state tax return. Earnings also decreased due to higher operating expenses ($3.2 million), higher depreciation expense ($1.3 million) and higher income tax expense ($0.6 million). The increase in operating expenses was largely due to higher costs for labor, major overhaul maintenance of compressor units at Trout Run gathering system compressor stations during fiscal 2022 and higher costs for material used to operate the compressor stations at the Trout Run, Covington and Clermont gathering systems. The increase in depreciation expense was largely due to higher plant balances associated with the Clermont and Covington gathering systems. The increase in income tax expense was primarily driven by a higher effective state income tax rate.

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UTILITY

Revenues

Utility Operating Revenues

Utility Throughput — million cubic feet (MMcf)

Degree Days

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

2022 Compared with 2021

Operating revenues for the Utility segment increased $231.0 million in 2022 compared with 2021. The increase resulted from a $226.8 million increase in retail gas sales revenues, which was primarily due to a significant increase in the cost of gas sold (per Mcf). In addition, there was a $2.9 million increase in transportation revenues and a $1.3 million increase in other revenues. The increase in transportation revenues, despite a small decrease in throughput, was largely due to an increase in marketer sales cashouts and an increase in the system modernization tracker allocation to transportation customers, which was partially offset by the migration of residential transportation customers previously served by marketers to retail service provided by the Utility segment. The increase in other revenues was primarily due to higher capacity release revenues and higher late payment charges billed to customers.

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Purchased Gas

The cost of purchased gas is one of the Company’s largest operating expenses. Annual variations in purchased gas costs are attributed directly to changes in gas sales volume, the price of gas purchased and the operation of purchased gas adjustment clauses. Distribution Corporation recorded $498.0 million and $274.8 million of Purchased Gas expense during 2022 and 2021, respectively. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is not allowed to profit from fluctuations in gas costs. Purchased Gas expense recorded on the consolidated income statement matches the revenues collected from customers, a component of Operating Revenues on the consolidated income statement. Under mechanisms approved by the NYPSC in New York and the PaPUC in Pennsylvania, any difference between actual purchased gas costs and what has been collected from the customer is deferred on the consolidated balance sheet as either an asset, Unrecovered Purchased Gas Costs, or a liability, Amounts Payable to Customers. These deferrals are subsequently collected from the customer or passed back to the customer, subject to review by the NYPSC and the PaPUC. Absent disallowance of full recovery of Distribution Corporation’s purchased gas costs, such costs do not impact the profitability of the Company. Purchased gas costs impact cash flow from operations due to the timing of recovery of such costs versus the actual purchased gas costs incurred during a particular period. Distribution Corporation’s purchased gas adjustment clauses seek to mitigate this impact by adjusting revenues on either a quarterly or monthly basis.

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

Earnings

2022 Compared with 2021

The Utility segment’s earnings in 2022 were $68.9 million, an increase of $14.6 million when compared with earnings of $54.3 million in 2021. The increase was primarily attributable to the conclusion of a regulatory proceeding by the PaPUC in February 2022, which resulted in the reduction of an OPEB-related regulatory liability that increased earnings ($14.6 million). While the regulatory proceeding reduced base rates in Pennsylvania by $5.6 million, this impact was more than offset by a decrease in non-service post-retirement benefit costs ($11.5 million) as Distribution Corporation's Pennsylvania service territory recognized OPEB income during fiscal 2022, compared to the prior year 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 Note F — Regulatory Matters.

Other factors contributing to the increase in earnings included the positive earnings impact of a system modernization tracker in New York ($3.6 million), which is a rate mechanism that provides recovery of qualified leak prone pipe replacement costs, higher usage and the impact of weather on customer margins ($2.9 million), and a decrease in income tax expense ($0.6 million). These increases were partially offset by higher operating expenses ($9.5 million), which were primarily the result of higher personnel costs, transportation fuel costs, and outside services partially offset by a decrease in the provision for uncollectible accounts. The decrease in the provision for uncollectible accounts reflects the recording of incremental expense in 2021 due to the potential for future customer non-payment as a result of the COVID-19 pandemic. In addition, earnings were negatively impacted by higher interest expense ($2.0 million), which was largely the result of a higher weighted average interest rate on intercompany short-term borrowings, and higher depreciation expense ($1.8 million), primarily due to higher plant balances.

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

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warmer than normal. In 2021, the WNC contributed approximately $4.5 million to earnings, as the weather was warmer than normal.

ALL OTHER AND CORPORATE OPERATIONS

All Other and Corporate operations primarily includes the operations of Seneca’s Northeast Division and corporate operations. Seneca’s Northeast Division previously marketed timber from its New York and Pennsylvania land holdings. On December 10, 2020, the Company completed the sale of substantially all timber properties. Please refer to Item 8 at Note B — Asset Acquisitions and Divestitures for further discussion of the sale of timber properties.

Earnings

2022 Compared with 2021

All Other and Corporate operations recorded a loss of $12.7 million in 2022, a decrease of $47.3 million when compared with earnings of $34.6 million in 2021. The decrease was primarily attributable to the non-recurrence of a $51.1 million gain ($37.0 million gain after-tax) on the sale of timber properties recorded by Seneca’s Northeast Division in 2021. Changes in unrealized gains and losses on investments in equity securities also contributed to the decrease. In 2022, the Company recorded unrealized losses of $9.2 million, while in 2021, the Company recorded unrealized gains of $0.1 million.

OTHER INCOME (DEDUCTIONS)

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

Net other deductions on the Consolidated Statement of Income decreased $13.7 million in 2022 as compared to 2021. This change is primarily attributable to non-service pension and post-retirement benefit income of $3.6 million for 2022 compared to non-service pension and post-retirement benefit costs of $31.3 million for 2021. As discussed above in the Utility segment, 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. In addition, there was an increase in other interest income of $1.7 million. This was partially offset by changes in unrealized gains and losses on investments in equity securities. During 2022, the Company recorded pre-tax unrealized losses of $13.8 million. During 2021, the Company recorded pre-tax unrealized gains of $0.2 million. Other income (deductions) was also impacted by a decrease in the cash surrender value of life insurance policies of $1.9 million, as well as a decrease in allowance for funds used during construction (equity component) of $2.5 million primarily as a result of the FM100 Project being placed into service in December 2021. There was also a mark-to-market revaluation that decreased contingent consideration by $4.4 million from the sale of Seneca's California assets. For further discussion, refer to Note J — Financial Instruments.

INTEREST CHARGES

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

Interest on long-term debt decreased $21.0 million in 2022 as compared to 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.

Other interest expense increased $5.0 million in 2022 as compared to 2021. The increase was primarily due to higher average interest rates for 2022 combined with higher average short-term debt balances in 2022 compared to 2021.

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CAPITAL RESOURCES AND LIQUIDITY

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

The Company expects to have adequate amounts of cash available to meet both its short-term and long-term cash requirements for at least the next twelve months and for the foreseeable future thereafter. During 2023, cash provided by operating activities is expected to increase over the amount of cash provided by operating activities during 2022 and will be used to fund the Company's capital expenditures. There are two long-term debt maturities in March 2023, totaling $549 million. The Company expects to repay those securities through the use of cash on hand at the date of maturity and short-term borrowings. Looking at 2023 and 2024, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures in each of those years. This is expected to provide the Company with the option to consider additional growth investments, further reductions in short-term or long-term debt, and increasing the amount of cash flow returned to shareholders, either through increases to the Company’s dividend or via repurchases of common stock. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.

OPERATING CASH FLOW

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

Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the 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.

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

The Company, in its Utility segment and Exploration and Production segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. Refer to Item 8 at Note L —

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Commitments and Contingencies under the heading “Other” for additional discussion concerning these contractual commitments as well as the amounts of future gas purchase, transportation and storage contract commitments expected to be incurred during the next five years and thereafter. Also refer to Item 8 at Note D — Leases for a discussion of the Company’s operating lease arrangements and a schedule of lease payments during the next five years and thereafter.

Net cash provided by operating activities totaled $812.5 million in 2022, an increase of $20.9 million compared with the $791.6 million provided by operating activities in 2021. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Exploration and Production segment and the Gathering segment, partially offset by lower cash provided by operating activities in the Utility segment. The increase in the 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. The decrease in 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.

INVESTING CASH FLOW

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets, including non-cash capital expenditures, totaled $829.4 million and $769.9 million in 2022 and 2021, respectively. The table below presents these expenditures:

(1)2022 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $83.0 million, $15.2 million, $10.7 million and $11.4 million, respectively, of non-cash capital expenditures.

(2)2021 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $47.9 million, $39.4 million, $4.8 million and $10.6 million, respectively, of non-cash capital expenditures.

Exploration and Production

In 2022, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $547.1 million for the Appalachian region (including $161.4 million in the Marcellus Shale area and $370.6 million in the Utica Shale area) and $18.7 million for the West Coast region. These amounts included approximately $154.3 million spent to develop proved undeveloped reserves.

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In 2021, the majority of the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $368.1 million for the Appalachian region (including $117.2 million in the Marcellus Shale area and $213.8 million in the Utica Shale area) and $13.3 million for the West Coast region. These amounts included approximately $81.2 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment’s capital expenditures for 2022 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions. In addition, the Pipeline and Storage segment capital expenditures for 2022 include expenditures related to Supply Corporation's FM100 Project ($25.2 million). 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 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 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 continue in calendar year 2022. As of September 30, 2022, approximately $211.3 million has been spent on the FM100 Project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2022.

The Pipeline and Storage segment’s capital expenditures for 2021 were primarily for expenditures related to Supply Corporation's FM100 Project ($179.0 million). In addition, the Pipeline and Storage segment capital expenditures for 2021 included additions, improvements and replacements to this segment's transmission and gas storage systems.

Gathering

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

The majority of the Gathering segment's capital expenditures for 2021 included expenditures related to the continued expansion of Midstream Company's Clermont, Covington and Wellsboro gathering systems. Midstream Company spent $23.1 million, $4.4 million and $3.7 million in 2021 on the development of the Clermont, Covington and Wellsboro gathering systems, respectively. These expenditures were largely attributable to new Clermont gathering pipelines, a new tie-in between the legacy Covington gathering system and the midstream gathering assets acquired from SWEPI LP, a subsidiary of Royal Dutch Shell plc ("Shell"), which is now referred to as the Tioga gathering system, 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.

Utility

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

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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. The purchase and sale agreement with Shell was structured, in part, as a Reverse 1031 Exchange. Refer to Item 8 at Note B — Asset Acquisitions and Divestitures 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. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances.

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Estimated Capital Expenditures

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

(1)Includes estimated expenditures for the years ended September 30, 2023, 2024 and 2025 of approximately $308 million, $95 million and $82 million, respectively, to develop proved undeveloped reserves. The Company is committed to developing its proved undeveloped reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting.

(2)Includes estimated expenditures for the years ended September 30, 2023, 2024, and 2025 of approximately $95 million, $100 million and $100 million, respectively, for system modernization and safety to enhance the reliability and safety of the system and reduce emissions.

Exploration and Production

Capital expenditures for the Exploration and Production segment in 2023 through 2025 are expected to be primarily well drilling and completion expenditures in the Appalachian region.

Pipeline and Storage

Capital expenditures for the Pipeline and Storage segment in 2023 through 2025 are expected to include: the replacement and modernization of transmission and storage facilities, the reconditioning of storage wells, improvements of compressor stations and emissions reduction initiatives.

In addition, due to the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, specifically in the Marcellus and Utica Shale producing areas, Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems. Capital expenditures in 2023 through 2025 include minimal capital expenditures related to system expansion and forecasted amounts will be adjusted in the future to incorporate any new projects that are expected to be developed by the Company.

Gathering

The majority of the Gathering segment capital expenditures in 2023 through 2025, included in the table above, are expected to be for construction and expansion of gathering systems, as discussed below. The Gathering segment primarily invests capital to support Seneca's drilling and completion activity in their long-term development plan. Seneca has been in the process of shifting a larger share of its activity from its Western Development Area to Tioga County, Pennsylvania. As a result, the Gathering segment is expecting to see near-term increases in capital expenditures as it constructs the necessary infrastructure to support Seneca's activity in the region.

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 16 compressor stations and backbone and in-field gathering pipelines. Estimated capital expenditures in 2023 through 2025 include anticipated expenditures in the range of $150 million to $180 million for continued expansion of the Tioga gathering system.

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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. Estimated capital expenditures in 2023 through 2025 include anticipated expenditures in the range of $50 million to $70 million for the continued expansion of the Clermont gathering system.

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. Estimated capital expenditures in 2023 through 2025 include anticipated expenditures in the range of $50 million to $60 million for the continued expansion of the Wellsboro gathering system.

NFG Midstream Trout Run, LLC, a wholly-owned subsidiary of Midstream Company, continues to develop its Trout Run gathering system in Lycoming County, Pennsylvania. The Trout Run gathering system was initially placed in service in May 2012. The current system consists of three compressor stations and backbone and in-field gathering pipelines.  Estimated capital expenditures in 2023 through 2025 include anticipated expenditures in the range of $15 million to $25 million for the continued expansion of the Trout Run gathering system.

Utility

Capital expenditures for the Utility segment in 2023 through 2025 are expected to be concentrated in the areas of main and service line improvements and replacements and, to a lesser extent, the purchase of new equipment. Additionally, capital expenditures are expected to increase after 2023 largely due to the anticipated implementation of a Distribution System Improvement Charge (DSIC) mechanism in the Utility's Pennsylvania Division upon completion of the rate proceeding initiated on October 28, 2022.

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 and the Company's California assets. During fiscal 2022, capital expenditures were funded with cash from operations, short-term debt and proceeds from the sale of the Company's California assets. 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 and short-term borrowings 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.

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

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

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and thereafter associated with the Company’s pipeline, compressor and gathering system modernization and expansion projects. These amounts are a subset of the estimated capital expenditures for the Pipeline and Storage segment, Gathering segment and Utility segment that are shown above.

The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive natural gas properties, quicker development of existing natural gas properties, natural gas storage and transmission facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. 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 as well as legislative actions.

FINANCING CASH FLOW

Consolidated short-term debt decreased $98.5 million, to a total of $60.0 million, when comparing the balance sheet at September 30, 2022 to the balance sheet at September 30, 2021. The maximum amount of short-term debt outstanding during the year ended September 30, 2022 was $675.4 million. In addition to cash provided by operating activities, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. For example, elevated commodity prices relative to its existing portfolio of derivative financial instruments led to the Company posting margin of $91.7 million with a number of its derivative counterparties as of September 30, 2022. The maximum amount of margin posted during the year ended September 30, 2022 was $430.6 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. At September 30, 2022, the Company had outstanding short-term notes payable to banks of $60.0 million. The Company did not have any commercial paper outstanding at September 30, 2022.

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 a maturity date of February 26, 2027.

On June 30, 2022, the Company entered into the 364-Day Credit Agreement with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company is using the proceeds for general corporate purposes, which will include the redemption in November of a portion of the Company's outstanding long-term debt maturing in March 2023.

The Company 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

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occurring on or after July 1, 2018, not to exceed $400 million. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at September 30, 2022, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement and 364-Day Credit Agreement. On May 3, 2022, the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modified the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ended June 30, 2022, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet. Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. The 364-Day Credit Agreement includes the same debt to capitalization covenant and the same exclusions of unrealized gains or losses on derivative financial instruments as the Credit Agreement. At September 30, 2022, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement and 364-Day Credit Agreement, was .49. The constraints specified in the Credit Agreement and 364-Day Credit Agreement would have permitted an additional $2.56 billion in short-term and/or long-term debt to be outstanding at September 30, 2022 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65.

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

The Credit Agreement and 364-Day Credit Agreement contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement and 364-Day Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.

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 September 30, 2022 consists of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes, that each mature in March 2023. The Company does not anticipate long-term refinancing for these maturities. None of the Company's long-term debt as of September 30, 2021 had a maturity date within the following twelve-month period. As of September 30, 2022, the future contractual obligations related to aggregate principal amounts of long-term debt, including interest expense, maturing during the next five years and thereafter are as follows: $654.1 million in 2023, $95.4 million in 2024, $589.4 million in 2025, $548.9 million in 2026, $340.4 million in 2027, and $863.5 million thereafter. Refer to Item 8

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at Note H — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense. Principal payments of long-term debt are a component of cash used in financing activities while interest payments on long-term debt are a component of cash used in operating activities.

The Company’s embedded cost of long-term debt was 4.48% at both September 30, 2022 and September 30, 2021. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.

Under the Company's existing indenture covenants at September 30, 2022, the Company would have been permitted to issue up to a maximum of approximately $2.0 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. 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 September 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 environmental and other matters discussed in this Item 7 and in Item 8 at Note L — Commitments and Contingencies, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

Supply Corporation and Empire have developed a project which would move significant prospective Marcellus and Utica production from Seneca's Western Development Area at Clermont to an Empire interconnection with the TC Energy pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York (the “Northern Access project”). The Northern Access project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. The 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 September 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

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million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2022.

The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan). The Company has been making contributions to the Retirement Plan over the last several years and anticipates that it may continue making contributions to the Retirement Plan in the future. During 2022, the Company contributed $20.4 million to the Retirement Plan. The Company anticipates that the annual contribution to the Retirement Plan in 2023 will be in the range of zero to $8.0 million. For further discussion of the Company’s Retirement Plan, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the Retirement Plan has been closed to new participants since 2003. In that regard, the average remaining service life of active participants in the Retirement Plan is approximately 6 years.

The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits. The Company has been making contributions to its VEBA trusts and/or 401(h) accounts over the last several years and does not anticipate making contributions to the VEBA trusts and/or 401(h) accounts in the near term. However, this will be subject to future review. During 2022, the Company contributed $2.8 million to its VEBA trusts. In addition, the Company made direct payments of $0.3 million to retirees not covered by the VEBA trusts and 401(h) accounts during 2022. The Company does not expect to make any contributions to its VEBA trusts in 2023. For further discussion of the Company’s other post-retirement benefits, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the other post-retirement benefits provided by the Company have been closed to new participants since 2003. In that regard, the average remaining service life of active participants is approximately 4 years for those eligible for other post-retirement benefits.

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

MARKET RISK SENSITIVE INSTRUMENTS

Energy Commodity Price Risk

The Company uses various derivative financial instruments (derivatives), including price swap agreements and no cost collars, as part of the Company’s overall energy commodity price risk management strategy in its Exploration and Production segment. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the Company would receive from, or pay to, the respective counterparties at September 30, 2022 to terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas transactions that are related to the financial instruments.

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

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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 September 30, 2022, the Company determined that nonperformance risk associated with the price swap agreements, no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

The following tables disclose natural gas price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2022. At September 30, 2022, the Company had not entered into any natural gas price swap agreements extending beyond 2026.

Natural Gas Price Swap Agreements

At September 30, 2022, the Company would have paid its respective counterparties an aggregate of approximately $512.3 million to terminate the natural gas price swap agreements outstanding at that date.

At September 30, 2021, the Company had natural gas price swap agreements covering 398.8 Bcf at a weighted average fixed rate of $2.84 per Mcf.

No Cost Collars

The following table discloses the notional quantities, the weighted average ceiling price and the weighted average floor price for the no cost collars used by the Company to manage natural gas price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). At September 30, 2022, the Company had not entered into any natural gas no cost collars extending beyond 2027.

At September 30, 2022, the Company would have had to pay an aggregate of approximately $270.5 million to terminate the natural gas no cost collars outstanding at that date.

At September 30, 2021, the Company had no cost collars agreements covering 20.9 Bcf at a weighted average ceiling price of $3.25 per Mcf and a weighted average floor price of $2.81 per Mcf.

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Foreign Exchange Risk

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

The following table discloses foreign exchange contract information by expected maturity dates. The Company receives a fixed price in exchange for paying a variable price as noted in the Canadian to U.S. dollar forward exchange rates. Notional amounts (Canadian dollars) are used to calculate the contractual payments to be exchanged under contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2022. At September 30, 2022, the Company had not entered into any foreign currency exchange contracts extending beyond 2030.

At September 30, 2022, absent other positions with the same counterparties, the Company would have paid to its respective counterparties an aggregate of $1.9 million to terminate these foreign exchange contracts.

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

Interest Rate Risk

The fair value of long-term fixed rate debt is $2.5 billion at September 30, 2022. This fair value amount is not intended to reflect principal amounts that the Company will ultimately be required to pay. The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt:

RATE MATTERS

Utility Operation

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

New York Jurisdiction

Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017. The order provided for a return on equity of 8.7%, and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. The order also authorized the Company to recover approximately $15 million annually for pension and other post-employment benefit ("OPEB") expenses from customers. Because the Company's future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July, Distribution Corporation made a filing with the NYPSC to effectuate a pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022. On September 16,

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2022, the NYPSC issued an order approving the filing. With the implementation of this surcredit, Distribution Corporation will no longer be funding the pension from its New York jurisdiction and it will not be funding its VEBA trusts in its New York jurisdiction.

On August 13, 2021, the NYPSC issued an order extending the date through which qualified pipeline replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (until March 31, 2023). 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.

Pennsylvania Jurisdiction

Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007. On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $28.1 million with a proposed effective date of December 27, 2022. The Company is also proposing, among other things, to implement a weather normalization adjustment mechanism and a new energy efficiency and conservation pilot program for residential customers. The filing will be suspended for seven months by operation of law unless directed otherwise by the PaPUC.

Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC, Distribution Corporation reduced base rates by $7.7 million in order to stop collecting OPEB expenses from customers. It also began to refund to customers overcollected OPEB expenses in the amount of $50.0 million. Certain other matters in the tariff supplement were unresolved. These matters were resolved with the PaPUC's approval of an Administrative Law Judge's Recommended Decision on February 24, 2022. Concurrent with that decision, the Company discontinued regulatory accounting for OPEB expenses and recorded an $18.5 million adjustment during the quarter ended March 31, 2022 to reduce its regulatory liability for previously deferred OPEB income amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company also increased customer refunds of overcollected OPEB expenses from $50.0 million to 54.0 million. All refunds specified in the tariff supplement are being funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company's Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.

Pipeline and Storage

Supply Corporation’s 2020 rate settlement provides that no party may make a rate filing for new rates to be effective before February 1, 2024, except that Supply Corporation may file an NGA general Section 4 rate case to change rates if the corporate federal income tax rate is increased. If no case has been filed, Supply Corporation must file for rates to be effective February 1, 2025.

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

ENVIRONMENTAL MATTERS

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

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

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While changes in environmental laws and regulations could have an adverse financial impact on the Company, legislation or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

Environmental Regulation

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in the United States. These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. For example, the Inflation Reduction Act of 2022 (IRA) legislation was signed into law on August 16, 2022. The IRA includes a methane charge that is expected to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, starting in calendar year 2024. This portion of the IRA is to be administered by the EPA and potential fees will begin with emissions reported for calendar year 2024. The EPA regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented by the EPA impose more stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. The Company must continue to comply with all applicable regulations. Additionally, a number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. Pennsylvania's Governor also entered the Commonwealth into a cap-and-trade program known as the Regional Greenhouse Gas Initiative, however, the Commonwealth's participation is currently stayed due to ongoing litigation. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The NYPSC, for example, initiated a proceeding to consider climate-related financial disclosures at the utility operating company level, and the New York State legislature passed the CLCPA that mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on the promulgation of final regulations and on regulatory treatment afforded in the process. Thus far, the only regulations promulgated in connection with the CLCPA are 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. The above-enumerated initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.

EFFECTS OF INFLATION

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

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SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

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

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

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

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

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

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

6.Changes in the price of natural gas;

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

8.Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;

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

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

11.The Company's ability to complete planned strategic transactions;

12.The Company's ability to successfully integrate acquired assets and achieve expected cost synergies;

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13.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;

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

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

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

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

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

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

20.Uncertainty of gas reserve estimates;

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

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

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

24.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;

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

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

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

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

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

INDUSTRY AND MARKET DATA DISCLOSURE

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