# NATIONAL FUEL GAS CO (NFG) FY 2021 MD&A Verbatim Item 7 Management's Discussion and Analysis from NATIONAL FUEL GAS CO's 10-K for fiscal year 2021. SEC filing source: https://www.sec.gov/Archives/edgar/data/70145/000007014521000030/nfg-20210930.htm Accession: 0000070145-21-000030 Filing date: 2021-11-19 Report date: 2021-09-30 Extracted structurally from real Item 7 body heading to real Item 7A/8 boundary. Confidence: high Company profile: /company/NFG/ All MD&A years: /company/NFG/mda/ Next year: /company/NFG/mda/fy2022/ (FY 2022) 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 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 producers in the Appalachian basin. The Company also develops and produces oil reserves, primarily in California. 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. 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, along with its integrated and diversified business model positioning it to take advantage of potential opportunities to participate in the ongoing efforts to decarbonize our economy. 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 March 2021, the Company set greenhouse gas reduction targets associated with the Company's utility delivery system. To further our ongoing efforts to lower the Company's emissions profile, in September 2021 the Company also established methane intensity reduction targets at each of its businesses, as well as an absolute greenhouse gas emissions reduction target for the consolidated Company. The Company's ability to estimate accurately the time, costs and resources necessary to meet these emissions reduction targets may change as environmental exposures and opportunities change, technology advances and regulatory updates are issued. In addition to these targets, the Company understands the importance of scenario analysis to our stakeholders and plans to publish further analysis of the resilience of the Company’s businesses to a lower carbon economy, in line with the Task Force on Climate Related Financial Disclosures framework. -32- Fiscal 2021 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) 2021 and projected 2022 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) new authoritative accounting and financial reporting guidance. 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 2021 and fiscal 2020. 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 2019 to fiscal 2020 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, 2020, filed with the SEC on November 20, 2020. The Company is closely monitoring and responding to developments related to the novel coronavirus (COVID-19) and is taking steps to limit operational impacts and the potential exposure for our workforce and customers. Refer to Risk Factors in Part I, Item 1A, Risk Factors, under Operational Risks in this Form 10-K for a more complete discussion of the risks to the Company associated with the COVID-19 pandemic. The Company continues to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation's system, referred to as the FM100 Project, will upgrade a 1950’s era pipeline in northwestern Pennsylvania and create 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 system at Leidy, Pennsylvania. Construction activities for the FM100 Project are fully in progress. The FM100 Project has an expected target in-service date of December 1, 2021 and a preliminary cost estimate of approximately $240 million. This project is expected to provide incremental annual transportation revenues of approximately $50 million. The FM100 Project is discussed in more detail in the Capital Resources and Liquidity section that follows. Another project on Empire’s system, referred to as the Empire North Project, which allows for the transportation of 205,000 Dth per day of additional supplies from interconnections in Tioga County, Pennsylvania, to the TC Energy pipeline, and the Tennessee Gas Pipeline L.L.C. (TGP) 200 Line, was placed in-service during the fourth quarter of fiscal 2020. The Empire North project provided incremental transportation revenues in the Pipeline and Storage segment of $26.9 million in fiscal 2021. For further discussion of the Pipeline and Storage segment's revenues and earnings, refer to the Results of Operations section below. In advance of the expected late calendar 2021 online date for Seneca’s 330,000 Dth per day of incremental capacity on the Leidy South Project, which is the companion project to the Company's FM100 Project, the Company's Exploration and Production segment added a second horizontal drilling rig in the Appalachian region in January 2021. Production from the first pad that was drilled in connection with this additional activity is expected in early fiscal 2022, with this incremental production reaching Transco Zone 6 markets during the winter heating season. Seneca anticipates an increase in natural gas production in fiscal 2022 as a result of this incremental pipeline capacity. The Company's Exploration and Production segment continues to grow, as evidenced by an 11% growth in proved reserves from the prior year to a total of 3,853 Bcfe at September 30, 2021. The Company uses the full cost method of accounting for determining the book value of its oil and natural gas properties in the Exploration and Production segment and that book value is subject to a quarterly ceiling test. This is discussed in more detail in the Critical Accounting Estimates section that follows. In addition to the significant non-cash impairment charges under the ceiling test that the Company recorded during fiscal 2020, -33- the Company recorded a non-cash impairment charge under the ceiling test for the year ended September 30, 2021 of $76.2 million ($55.2 million after-tax), which was recorded during the quarter ended December 31, 2020. Please refer to the Critical Accounting Estimates section below for a sensitivity analysis concerning commodity price changes. 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). Refer to Item 8 at Note B — Asset Acquisitions and Divestitures for additional information concerning this sale. From a financing perspective, on February 24, 2021, the Company issued $500.0 million of 2.95% notes due March 1, 2031. The proceeds of the 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. On February 3, 2021, the Company amended its existing 364-day credit facility agreement. The amendment extends the maturity date of the facility from May 3, 2021 to December 30, 2022, and increases the commitment provided under the facility from $200.0 million to $250.0 million of unsecured committed revolving credit access. The Company entered into the amendment with a syndicate of twelve banks, all of which are also lenders under the Company's existing $750.0 million multi-year credit facility. The Company expects to use cash on hand and cash from operations, as well as short-term borrowings, to meet its financing needs for fiscal 2022. 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, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this accounting methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of 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 -34- 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 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 oil and 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, 2021, the ceiling exceeded the book value of the oil and gas properties by approximately $842.1 million. The 12-month average of the first day of the month price for crude oil for each month during 2021, based on posted Midway Sunset prices, was $56.66 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during 2021, based on the quoted Henry Hub spot price for natural gas, was $2.94 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 Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for 2021. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.)  The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the amounts the ceiling would have exceeded the book value of the Company's oil and gas properties at September 30, 2021 if natural gas prices were $0.25 per MMBtu lower than the average prices used at September 30, 2021, if crude oil prices were $5 per Bbl lower than the average prices used at September 30, 2021, and if both natural gas prices and crude oil prices were $0.25 per MMBtu and $5 per Bbl lower than the average prices used at September 30, 2021 (all amounts are presented after-tax). In all cases, these price decreases would not have resulted in an impairment charge. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.   Ceiling Testing Sensitivity to Commodity Price Changes [[GREPCENT_TABLE]] [["(Millions)","$0.25/MMBtu Decrease in Natural Gas Prices","","$5.00/Bbl Decrease in Crude Oil Prices","","$0.25/MMBtu Decrease in Natural Gas Prices and $5.00/Bbl Decrease in Crude Oil Prices"],["Excess of Ceiling over Book Value under Sensitivity Analysis","$","567.0","","","$","806.8","","","$","531.7"]] [[/GREPCENT_TABLE]] 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 -35- for undeveloped reserves and significant fluctuations in oil and 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 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 2021 Compared with 2020 The Company's earnings were $363.6 million in 2021 compared to a loss of $123.8 million in 2020. The increase in earnings of $487.4 million was primarily a result of higher earnings in the Exploration and Production segment, Pipeline and Storage segment, Gathering segment and All Other category. Lower earnings in the Utility segment, as well as a loss in the Corporate category, partially offset these increases. In the discussion that follows, all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings were impacted by the following events in 2021 and 2020: 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 during 2021 for the premium paid on early redemption of long-term debt. 2020 Events  •Non-cash impairment charges of $449.4 million ($326.3 million after-tax) recorded during 2020 for the Exploration and Production segment's oil and gas producing properties. •A deferred tax valuation allowance of $56.8 million established during the quarter ended March 31, 2020, primarily in the Exploration and Production and Gathering segments. -36- Earnings (Loss) by Segment [[GREPCENT_TABLE]] [["","Year Ended September 30"],["","2021","","2020","","2019"],["","(Thousands)"],["Exploration and Production","$","101,916","","","$","(326,904)","","","$","111,807"],["Pipeline and Storage","92,542","","","78,860","","","74,011"],["Gathering","80,274","","","68,631","","","58,413"],["Utility","54,335","","","57,366","","","60,871"],["Total Reported Segments","329,067","","","(122,047)","","","305,102"],["All Other","37,645","","","(269)","","","(1,811)"],["Corporate","(3,065)","","","(1,456)","","","999"],["Total Consolidated","$","363,647","","","$","(123,772)","","","$","304,290"]] [[/GREPCENT_TABLE]] EXPLORATION AND PRODUCTION Revenues Exploration and Production Operating Revenues [[GREPCENT_TABLE]] [["","Year Ended September 30"],["","2021","","2020"],["","(Thousands)"],["Gas (after Hedging)","$","705,326","","","$","470,270"],["Oil (after Hedging)","126,369","","","133,712"],["Gas Processing Plant","2,960","","","2,374"],["Other","2,042","","","1,097"],["Operating Revenues","$","836,697","","","$","607,453"]] [[/GREPCENT_TABLE]] Production [[GREPCENT_TABLE]] [["","Year Ended September 30"],["","2021","","2020"],["Gas Production (MMcf)"],["Appalachia","312,300","","","225,513"],["West Coast","1,720","","","1,889"],["Total Production","314,020","","","227,402"],["Oil Production (Mbbl)"],["Appalachia","2","","","3"],["West Coast","2,233","","","2,345"],["Total Production","2,235","","","2,348"]] [[/GREPCENT_TABLE]] -37- Average Prices  [[GREPCENT_TABLE]] [["","Year Ended September 30"],["","2021","","2020"],["Average Gas Price/Mcf"],["Appalachia","$","2.46","","","$","1.75"],["West Coast","$","6.34","","","$","3.82"],["Weighted Average","$","2.49","","","$","1.77"],["Weighted Average After Hedging(1)","$","2.25","","","$","2.07"],["Average Oil Price/Barrel (Bbl)"],["Appalachia","$","48.02","","","$","45.69"],["West Coast","$","60.50","","","$","45.94"],["Weighted Average","$","60.49","","","$","45.94"],["Weighted Average After Hedging(1)","$","56.54","","","$","56.96"]] [[/GREPCENT_TABLE]] (1)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. 2021 Compared with 2020 Operating revenues for the Exploration and Production segment increased $229.2 million in 2021 as compared with 2020. Gas production revenue after hedging increased $235.1 million primarily due to an $0.18 per Mcf increase in the weighted average price of gas after hedging coupled with an 86.6 Bcf increase in gas production. The increase in gas production was largely due to additional production from the acquisition of Appalachian upstream assets from SWEPI LP, a subsidiary of Royal Dutch Shell plc ("Shell") on July 31, 2020 combined with new Marcellus and Utica wells in the Appalachian region. This production increase occurred despite 4.0 Bcf of price-related curtailments in 2021, the majority of which occurred in the first quarter of the year. Oil production revenue after hedging decreased $7.3 million primarily due to a $0.42 per Bbl decrease in the weighted average price of oil after hedging combined with a 113 Mbbl decrease in crude oil production. In addition, other revenue increased $0.9 million and gas processing plant revenue increased $0.6 million. 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 2021 Compared with 2020 The Exploration and Production segment’s earnings for 2021 were $101.9 million, an increase of $428.8 million when compared with a loss of $326.9 million for 2020. The increase in earnings was primarily attributable to a decrease in impairments of oil and gas properties ($326.3 million during 2020 compared to $55.2 million during 2021), higher natural gas production ($141.5 million) and higher natural gas prices after hedging ($44.2 million). The establishment of a deferred tax valuation allowance in the quarter ended March 2020, as discussed more completely in Item 8 at Note G — Income Taxes, reduced earnings in 2020. The non-recurrence of this initial valuation allowance created an earnings increase in 2021 ($60.5 million). Partially offsetting this impact, the Exploration and Production segment experienced a higher effective tax rate during 2021 compared to 2020 ($6.7 million). The increase in the effective tax rate was primarily driven by a higher effective state income tax rate as a result of the Company's asset acquisition from Shell that caused a change in the mix of earnings between state jurisdictions, partially offset by a partial reversal of the valuation allowance that was established in the quarter ended March 2020. The Exploration and Production segment’s earnings were also impacted by the recognition of a loss in March 2021 ($10.7 million) 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. Partially offsetting -38- this impact, the Exploration and Production segment experienced lower interest expense ($2.5 million) due to lower weighted average interest rates resulting from the Company's issuance of a 2.95% coupon note in February 2021 as replacement debt for the 4.9% coupon note that was retired in March 2021. In addition to the factors discussed above, the Exploration and Production segment's earnings were negatively impacted by lower crude oil production ($5.1 million), lower crude oil prices after hedging ($0.7 million), higher lease operating and transportation expenses ($50.3 million), higher depletion expense ($8.2 million), higher other operating expenses ($5.3 million) and higher other taxes ($5.2 million). The increase in lease operating and transportation expenses was primarily due to increased gathering and transportation costs in the Appalachian region and costs to operate the acquired Shell assets for the entire 2021 year. In addition, the West Coast region had higher steam fuel and well workover costs. The increase in depletion expense was primarily due to the increase in production, partially offset by a $0.15 decrease in the depletion rate as a result of the asset acquisition from Shell coupled with prior period non-cash ceiling test impairments. The increase in other operating expenses was largely due to an increase in accretion costs associated with asset retirement obligations, as well as higher personnel costs. The increase in accretion costs stemmed from the asset acquisition from Shell. The increase in other taxes was mainly attributed to increased impact fees in the Appalachian region due to added wells from the Shell acquisition combined with NYMEX gas price increases, shifting fees into a higher per well tier. PIPELINE AND STORAGE Revenues Pipeline and Storage Operating Revenues [[GREPCENT_TABLE]] [["","Year Ended September 30"],["","2021","","2020"],["","(Thousands)"],["Firm Transportation","$","254,853","","","$","228,457"],["Interruptible Transportation","996","","","934"],["","255,849","","","229,391"],["Firm Storage Service","83,032","","","79,031"],["Interruptible Storage Service","48","","","42"],["","83,080","","","79,073"],["Other","4,628","","","1,140"],["","$","343,557","","","$","309,604"]] [[/GREPCENT_TABLE]] Pipeline and Storage Throughput — (MMcf) [[GREPCENT_TABLE]] [["","Year Ended September 30"],["","2021","","2020"],["Firm Transportation","770,284","","","752,773"],["Interruptible Transportation","1,460","","","2,859"],["","771,744","","","755,632"]] [[/GREPCENT_TABLE]] 2021 Compared with 2020 Operating revenues for the Pipeline and Storage segment increased $34.0 million in 2021 as compared with 2020. The increase in operating revenues was primarily due to an increase in transportation revenues of $26.5 million, an increase in storage revenues of $4.0 million and an increase in other revenues of $3.5 million. The increase in transportation revenues was primarily attributable to new demand charges for transportation service from the Empire North Project, which was placed into service during the fourth quarter of fiscal 2020. Transportation revenue also increased due to an increase in Supply Corporation's transportation rates effective February 1, 2020 in accordance with Supply Corporation's rate case settlement. The settlement was approved by the FERC on June 1, 2020. The increase in transportation revenues was partially offset by the impact of a final -39- true-up adjustment to increase revenue in 2020 associated with the Pipeline Safety and Greenhouse Gas (PS/GHG) surcharge that had been in effect under Supply Corporation's last rate case settlement (RP15-1310) but which ended with the effective date of Supply Corporation’s 2020 rate case settlement (February 1, 2020). It was also offset by a decrease in transportation revenues from miscellaneous contract revisions and terminations and a decrease in revenues from short-term seasonal contracts. The increase in storage revenues was largely attributable to an increase in Supply Corporation's storage rates related to its 2020 rate case settlement, combined with a surcharge for PS/GHG regulatory costs that went into effect in November 2020 associated with Supply Corporation’s 2020 rate case settlement. The PS/GHG regulatory costs surcharge is also applicable to transportation revenues, but it did not have a significant impact to the increase in transportation revenues for fiscal 2021. The increase in other revenues was primarily due to proceeds received during the quarter ended December 31, 2020 as a result of a contract buyout. Transportation volume increased by 16.1 Bcf in 2021 as compared with 2020, primarily due to incremental volume from the Empire North Project, which was brought online on September 15, 2020, partially offset by a decrease in volume from a decline in capacity utilization by 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. Earnings 2021 Compared with 2020 The Pipeline and Storage segment’s earnings in 2021 were $92.5 million, an increase of $13.6 million when compared with earnings of $78.9 million in 2020.  The increase in earnings was primarily due to the impact of higher operating revenues of $26.8 million, as discussed above, combined with lower income tax expense ($2.7 million). The decrease in income tax expense was mainly due to permanent differences related to stock compensation activity as well as the timing of passing back excess deferred taxes to rate payers as a result of the 2017 Tax Reform Act per the Supply Corporation 2020 rate case settlement. These earnings increases were partially offset by an increase in depreciation expense ($6.7 million), higher interest expense ($6.5 million), and an increase in operating expenses ($2.4 million). The increase in depreciation expense was due to an increase in Supply Corporation's depreciation rates associated with its 2020 rate case settlement as well as incremental depreciation from the Empire North Project going into service, both mentioned above. The increase in interest expense was primarily due to interest on additional intercompany long-term borrowings associated with the Company's June 2020 debt issuance. The increase in operating expenses was mainly due to an increase in personnel and technology-related costs, higher vehicle fuel costs and higher power costs related to Empire's electric motor drive compressor station placed into service as part of the Empire North Project mentioned above, partially offset by a decrease in the reserve for preliminary project costs. Power costs related to Empire’s electric motor drive compressor station are offset by an equal amount of revenue due to a surcharge mechanism. GATHERING Revenues Gathering Operating Revenues [[GREPCENT_TABLE]] [["","Year Ended September 30"],["","2021","","2020"],["","(Thousands)"],["Gathering","$","193,264","","","$","142,893"]] [[/GREPCENT_TABLE]] Gathering Volume — (MMcf)  [[GREPCENT_TABLE]] [["","Year Ended September 30"],["","2021","","2020"],["Gathered Volume","366,033","","","264,305"]] [[/GREPCENT_TABLE]] -40- 2021 Compared with 2020 Operating revenues for the Gathering segment increased $50.4 million in 2021 as compared with 2020, which was driven primarily by a 101.7 Bcf increase in gathered volume. The July 31, 2020 acquisition of midstream gathering assets from Shell (Tioga gathering system) was the primary driver of this increase. The Tioga gathering system and legacy Covington gathering assets recorded a 62.4 Bcf increase in gathered volume for the year ended September 30, 2021. Other contributors to the increase included the Clermont, Trout Run and Wellsboro gathering systems, which recorded increases of 16.2 Bcf, 11.9 Bcf and 11.2 Bcf, respectively. The increase in gathered volume can be attributed to the increase in Seneca's gross natural gas production in the Appalachian region, as discussed above. Earnings 2021 Compared with 2020 The Gathering segment’s earnings in 2021 were $80.3 million, an increase of $11.7 million when compared with earnings of $68.6 million in 2020.  The increase in earnings was primarily attributable to higher gathering revenues ($39.8 million) driven by the increase in gathered volume (discussed above). In 2020, the Gathering segment recorded an initial income tax benefit as an offset to the valuation allowance established in the Exploration and Production segment, as discussed above. The non-recurrence of this initial income tax benefit reduced earnings in 2021 ($3.8 million). This offset is a result of the Gathering and Exploration and Production segments’ subsidiaries filing a combined state tax return. The increase in earnings was also partially offset by higher operating expenses ($8.9 million), higher depreciation expense ($7.8 million), higher interest expense ($4.5 million) and higher income tax expense ($2.3 million). The increase in operating expenses was largely due to higher lease compression expense associated with the Tioga gathering system and major overhaul maintenance of compressor units at Clermont gathering system compressor stations during fiscal 2021. The increase in depreciation expense was largely due to higher plant balances associated with the Tioga gathering system. The increase in interest expense was primarily driven by additional intercompany long-term borrowings from the Company's long term debt issuances in June 2020 and February 2021. The Gathering segment also recognized a loss in March 2021 ($0.7 million) for its share of the premium paid by the Company to redeem $500 million of the Company's 4.90% notes that were scheduled to mature in December 2021. The increase in income tax expense was primarily driven by a higher effective state income tax rate as a result of the fiscal 2020 acquisition of midstream gathering assets from Shell that caused a change in the mix of earnings between state jurisdictions. UTILITY Revenues Utility Operating Revenues [[GREPCENT_TABLE]] [["","Year Ended September 30"],["","2021","","2020"],["","(Thousands)"],["Retail Revenues:"],["Residential","$","497,244","","","$","478,503"],["Commercial","63,954","","","61,643"],["Industrial","3,089","","","3,305"],["","564,287","","","543,451"],["Transportation","108,213","","","114,128"],["Other","(5,249)","","","(5,281)"],["","$","667,251","","","$","652,298"]] [[/GREPCENT_TABLE]] -41- Utility Throughput — million cubic feet (MMcf) [[GREPCENT_TABLE]] [["","Year Ended September 30"],["","2021","","2020"],["Retail Sales:"],["Residential","61,038","","","60,977"],["Commercial","8,741","","","8,798"],["Industrial","475","","","537"],["","70,254","","","70,312"],["Transportation","66,012","","","68,272"],["","136,266","","","138,584"]] [[/GREPCENT_TABLE]] Degree Days [[GREPCENT_TABLE]] [["","","","","","","","Percent (Warmer) Colder Than"],["Year Ended September 30","","","Normal","","Actual","","Normal(1)","","Prior Year(1)"],["2021","Buffalo, NY","","6,617","","","5,731","","","(13.4)","%","","(6.1)","%"],["","Erie, PA","","6,147","","","5,221","","","(15.1)","%","","(4.2)","%"],["2020","Buffalo, NY","","6,653","","","6,103","","","(8.3)","%","","(8.9)","%"],["","Erie, PA","","6,181","","","5,449","","","(11.8)","%","","(7.8)","%"]] [[/GREPCENT_TABLE]] (1)Percents compare actual degree days to normal degree days and actual degree days to actual prior year degree days. 2021 Compared with 2020 Operating revenues for the Utility segment increased $15.0 million in 2021 compared with 2020. The increase largely resulted from a $20.8 million increase in retail gas sales revenues. The increase in retail gas sales revenues was mainly attributable to the migration of residential transportation customers to retail service (which includes a significantly higher charge for purchased gas than transportation service), in addition to a modest increase in the cost of gas sold (per Mcf). This increase was partially offset by a $5.9 million decrease in transportation revenues. The decrease in transportation revenues was primarily due to a 2.3 Bcf decrease in transportation throughput due to the migration of residential transportation customers previously served by marketers to retail service provided by the Utility segment and warmer weather. 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 $274.8 million and $263.1 million of Purchased Gas expense during 2021 and 2020, 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. -42- 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 2021 Compared with 2020 The Utility segment’s earnings in 2021 were $54.3 million, a decrease of $3.1 million when compared with earnings of $57.4 million in 2020. The decrease in earnings was primarily attributable to higher operating expenses ($2.6 million), which were largely a result of higher personnel costs and an increase to the allowance for uncollectible accounts, higher depreciation expense ($1.7 million) primarily due to higher plant balances, higher income tax expense ($1.2 million), and the impacts of lower usage and weather on customer margins ($1.1 million). The increase to the allowance for uncollectible accounts is related to the COVID-19 pandemic as the Company recorded incremental expense due to the potential for future customer non-payment, given the current economic environment. These decreases were partially offset by the positive earnings impact related to the system modernization tracker ($3.7 million). The system modernization tracker is a rate mechanism in the Utility segment's New York jurisdiction that provides recovery of qualified leak prone pipe replacement costs. 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 2021, the WNC contributed approximately $4.5 million to earnings, as the weather was warmer than normal. In 2020, the WNC contributed approximately $3.5 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 NFR, the operations of Seneca’s Northeast Division and corporate operations. NFR previously marketed natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania. NFR completed the sale of its commercial and industrial contracts and certain other assets on August 1, 2020. This sale, in conjunction with the turn back of NFR's residential customers to Distribution Corporation, effectively ended NFR's 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 2021 Compared with 2020 All Other and Corporate operations had earnings of $34.6 million in 2021, an increase of $36.3 million when compared with a loss of $1.7 million in 2020. The increase in earnings was primarily attributable to the gain recognized on the sale of timber properties by Seneca's Northeast Division for $51.1 million ($37.0 million after-tax). This gain was offset by changes in unrealized gains on investments in equity securities. In 2021, the Company recorded unrealized gains of $0.1 million, while in 2020, the Company recorded unrealized gains of $1.3 million. 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): -43- Interest on long-term debt increased $31.4 million in 2021 as compared to 2020. 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 increase is due largely to the higher average long-term debt balance stemming from the issuance of $500.0 million of 5.50% notes in June 2020. This increase was partially offset by 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 decreased $2.2 million in 2021 as compared to 2020. The decrease was primarily due to lower average short-term debt balances in 2021 compared to 2020 combined with lower average interest rates for 2021. CAPITAL RESOURCES AND LIQUIDITY The primary sources and uses of cash during the last two years are summarized in the following condensed statement of cash flows: [[GREPCENT_TABLE]] [["","Year Ended September 30"],["","2021","","2020"],["","(Millions)"],["Provided by Operating Activities","$","791.6","","","$","740.8"],["Capital Expenditures","(751.7)","","","(716.2)"],["Acquisition of Upstream Assets and Midstream Gathering Assets","\u2014","","","(506.3)"],["Net Proceeds from Sale of Timber Properties","104.6","","","\u2014"],["Other Investing Activities","13.8","","","(1.1)"],["Reduction of Long-Term Debt","(515.7)","","","\u2014"],["Change in Notes Payable to Banks and Commercial Paper","128.5","","","(25.2)"],["Net Proceeds from Issuance of Long-Term Debt","495.3","","","493.0"],["Net Proceeds from Issuance (Repurchase) of Common Stock","(3.7)","","","161.6"],["Dividends Paid on Common Stock","(163.1)","","","(153.3)"],["Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash","$","99.6","","","$","(6.7)"]] [[/GREPCENT_TABLE]] The Company expects to have adequate amounts of cash to meet both its short-term and long-term cash requirements. During 2022, cash provided by operating activities is expected to increase over the amount of cash provided by operating activities during 2021 and will be used to meet the Company's dividend requirements and reduce short-term borrowings. Capital expenditures in 2022 are expected to decrease as shown in the Estimated Capital Expenditures table shown below. There are no scheduled repayments of long-term debt in 2022. Looking at 2023 through 2024, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures in each of those years, which could lead to further capital investments in the business or reductions in short-term borrowings and a net reduction in long-term debt in 2023 while still allowing the Company to meet its dividend requirements. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future. OPERATING CASH FLOW Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, deferred income taxes 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 -44- 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 and crude oil 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 — 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 $791.6 million in 2021, an increase of $50.8 million compared with the $740.8 million provided by operating activities in 2020. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Pipeline and Storage segment, 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 Pipeline and Storage segment was primarily due to higher cash receipts from transportation and storage service, which largely reflects an increase in Supply Corporation's transportation and storage rates effective February 1, 2020 and an increase in demand charges for transportation services from the Empire North Project that was placed in service during September 2020. 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, largely stemming from the July 31, 2020 acquisition of upstream assets and midstream gathering assets from Shell. The decrease in Utility segment is primarily due to the timing of gas cost recovery and the timing of receivable collections. INVESTING CASH FLOW Expenditures for Long-Lived Assets The Company’s expenditures for long-lived assets, including non-cash capital expenditures, totaled $769.9 million and $1.2 billion in 2021 and 2020, respectively. The table below presents these expenditures: [[GREPCENT_TABLE]] [["","Year Ended September 30"],["","2021","","","2020"],["","(Millions)"],["Exploration and Production:"],["Capital Expenditures(3)","$","381.4","","(1)","","$","670.4","","(2)"],["Pipeline and Storage:"],["Capital Expenditures","$","252.3","","(1)","","$","166.7","","(2)"],["Gathering:"],["Capital Expenditures(4)","$","34.7","","(1)","","$","297.8","","(2)"],["Utility:"],["Capital Expenditures","$","100.8","","(1)","","$","94.3","","(2)"],["All Other and Corporate:"],["Capital Expenditures","$","0.5","","","","$","0.5"],["Eliminations","$","0.2","","","","$","(1.1)"],["Total Expenditures","$","769.9","","","","$","1,228.6"]] [[/GREPCENT_TABLE]] -45- (1)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. (2)2020 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $45.8 million, $17.3 million, $13.5 million and $10.7 million, respectively, of non-cash capital expenditures. (3)2020 includes $282.8 million related to the acquisition of upstream assets acquired from Shell, of which $281.7 million is included in Property, Plant and Equipment and $1.1 million is included in Materials, Supplies and Emission Allowances. The acquisition cost is reported as a component of Acquisition of Upstream Assets and Midstream Gathering Assets on the Consolidated Statement of Cash Flows. (4)2020 includes $223.5 million related to the acquisition of midstream gathering assets acquired from Shell, of which $223.4 million is included in Property, Plant and Equipment and $0.1 million is included in Materials, Supplies and Emission Allowances. The acquisition cost is reported as a component of Acquisition of Upstream Assets and Midstream Gathering Assets on the Consolidated Statement of Cash Flows. Exploration and Production In 2021, the majority of the Exploration and Production segment capital expenditures were 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. In 2020, the majority of the Exploration and Production segment capital expenditures were well drilling and completion expenditures, and also included $282.8 million of expenditures related to the acquisition of upstream assets acquired from Shell on July 31, 2020. The acquisition included over 400,000 net acres in Appalachia, with approximately 200,000 net acres in Tioga County. The proved developed and undeveloped natural gas reserves associated with this acquisition amounted to 684,141 MMcf in 2020. Capital expenditures were approximately $639.7 million for the Appalachian region (including $412.0 million in the Marcellus Shale area and $204.6 million in the Utica Shale area) and $30.7 million for the West Coast region. These amounts included approximately $219.9 million spent to develop proved undeveloped reserves. Pipeline and Storage The Pipeline and Storage segment’s capital expenditures for 2021 were primarily for expenditures related to Supply Corporation's FM100 Project ($179.0 million), which is discussed below. 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. The majority of the Pipeline and Storage segment’s capital expenditures for 2020 were related to additions, improvements and replacements to this segment's transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for 2020 included expenditures related to the Empire North Project ($68.9 million), Supply Corporation's Line N to Monaca Project ($4.1 million) and Supply Corporation's FM100 Project ($3.7 million). Gathering 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, as discussed below. Midstream Company spent $23.1 million, $4.4 million and $3.7 million, respectively, in 2021 on the development of the Clermont, Covington and Wellsboro gathering systems. 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 Shell (now referred to as the Tioga gathering system), as well as the continued development of centralized station facilities, including increased compression -46- horsepower at the Clermont and Wellsboro gathering systems and additional dehydration on the Clermont gathering system. The majority of the Gathering segment's capital expenditures for 2020 were for the acquisition of midstream gathering assets from Shell in the amount of $223.5 million. These gathering assets, including approximately 238 miles of gathering pipeline, support the upstream assets in Tioga County that the Exploration and Production segment acquired from Shell, as discussed above, and are interconnected with various interstate pipelines, including the Company's Empire pipeline systems. In addition, the Gathering segment's capital expenditures included expenditures related to the continued expansion of Midstream Company's Trout Run, Clermont, and Wellsboro gathering systems. Midstream Company spent $36.5 million, $19.7 million and $17.3 million, respectively, in 2020 on the development of the Trout Run, Clermont and Wellsboro gathering systems. These expenditures were largely attributable to the continued development of centralized station facilities, including increased compression horsepower at the Trout Run and Wellsboro gathering systems and additional dehydration on the Clermont gathering system. The Trout Run expenditures also included costs to construct new pipeline and station facilities to bring a third party producer online. Utility The majority of the Utility segment’s capital expenditures for 2021 and 2020 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions. Other Investing Activities 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 $506.3 million. The purchase and sale agreement with Shell was structured, in part, as a Reverse 1031 Exchange. Refer to Item 8 at Note B — Asset Acquisitions and Divestitures for additional information concerning the Company’s acquisition of certain upstream assets and midstream gathering assets from Shell. Estimated Capital Expenditures The Company’s estimated capital expenditures for the next three years are: [[GREPCENT_TABLE]] [["","Year Ended September 30"],["","2022","","2023","","2024"],["","(Millions)"],["Exploration and Production(1)","$","425","","","$","415","","","$","400"],["Pipeline and Storage","125","","","90","","","85"],["Gathering","55","","","65","","","80"],["Utility(2)","95","","","105","","","105"],["All Other","\u2014","","","\u2014","","","\u2014"],["","$","700","","","$","675","","","$","670"]] [[/GREPCENT_TABLE]] (1)Includes estimated expenditures for the years ended September 30, 2022, 2023 and 2024 of approximately $161 million, $128 million and $56 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, 2022, 2023 and 2024 of approximately $70 million, $75 million and $75 million, respectively, for system modernization and safety to enhance the reliability and safety of the system and reduce emissions. -47- Exploration and Production Estimated capital expenditures in 2022 for the Exploration and Production segment include approximately $410 million for the Appalachian region and $15 million for the West Coast region. Estimated capital expenditures in 2023 for the Exploration and Production segment include approximately $400 million for the Appalachian region and $15 million for the West Coast region. Estimated capital expenditures in 2024 for the Exploration and Production segment include approximately $385 million for the Appalachian region and $15 million for the West Coast region. Pipeline and Storage Capital expenditures for the Pipeline and Storage segment in 2022 through 2024 are expected to include: construction of new pipeline and compressor stations to support expansion projects, the replacement of transmission and storage lines, the reconditioning of storage wells and improvements of compressor stations. Expansion projects where the Company has begun to make significant investments of preliminary survey and investigation costs and/or where shipper agreements have been executed are described below.   In light of the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia — specifically in the Marcellus and Utica Shale producing areas — Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica gas production to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems. Supply Corporation has developed its FM100 Project, which will upgrade a 1950's era pipeline in northwestern Pennsylvania and create 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. A precedent agreement has been executed by Supply Corporation and Transco whereby this additional capacity is expected to be leased by Transco ("Lease") and become part of a Transco expansion project ("Leidy South") that will create incremental transportation capacity to Transco Zone 6 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. FERC issued the Section 7(c) certificate on July 17, 2020 and Supply Corporation accepted it on August 14, 2020. FERC issued a Notice to Proceed on February 22, 2021, and the Lease was fully executed on that date. Construction activities are fully in progress. The FM100 Project has an expected target in-service date of December 1, 2021 and a preliminary cost estimate of approximately $240 million. As of September 30, 2021, approximately $186.2 million has been capitalized as Construction Work in Progress for this project. The remaining expenditures expected to be spent on the project are included in Pipeline and Storage estimated capital expenditures in the table above. Supply Corporation and Empire have developed a project which would move significant prospective Marcellus and Utica production from Seneca's Western Development Area at Clermont to an Empire interconnection with the TC Energy pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York (the “Northern Access project”). The Northern Access project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. On February 3, 2017, the Company received FERC approval of the project. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order, and FERC's decisions were appealed. The Second Circuit Court of Appeals -48- issued an order upholding the FERC waiver orders. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project. 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, 2021, approximately $55.7 million has been spent on the Northern Access project, including $24.1 million that has been spent to study the project. The remaining $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2021. Because it is difficult to predict the timing of the resolution of the litigation process, no estimated capital expenditures for the Northern Access project are included in the table above. Gathering The majority of the Gathering segment capital expenditures in 2022 through 2024, included in the table above, are expected to be for construction and expansion of gathering systems, as discussed below. 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 2022 through 2024 include anticipated expenditures in the range of $80 million to $100 million for the continued expansion of the Clermont gathering system. NFG Midstream Covington, LLC, a wholly-owned subsidiary of Midstream Company, operates its Covington gathering system as well as the Tioga gathering system acquired from Shell on July 31, 2020, both in Tioga County, Pennsylvania. The current Covington gathering system consists of two compressor stations and backbone and in-field gathering pipelines. The Tioga gathering system consists of 13 compressor stations and backbone and in-field gathering pipelines. Estimated capital expenditures in 2022 through 2024 include anticipated expenditures in the range of $90 million to $110 million for continued expansion of the Tioga 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 2022 through 2024 include anticipated expenditures of less than $10 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 2022 through 2024 include anticipated expenditures of less than $10 million for the continued expansion of the Trout Run gathering system. Utility Capital expenditures for the Utility segment in 2022 through 2024 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. Project Funding Over the past two years, the Company has been financing capital expenditures with cash from operations, short-term and long-term debt, common stock, and proceeds from the sale of timber properties. During fiscal 2021, capital expenditures were funded with cash from operations and short-term debt. The Company issued long-term debt and common stock in June 2020 to help finance the acquisition of upstream assets and midstream gathering assets from Shell. The financing of the asset acquisition from Shell was completed in -49- 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 natural gas and crude oil production and the associated commodity price realizations. In the Exploration and Production segment, the Company has entered into contractual obligations to support its development activities and operations in Pennsylvania and California, including hydraulic fracturing and other well completion services, well tending services, well workover activities, tubing and casing purchases, production equipment purchases, contracts for drilling rig services and fuel purchases for steam generation. 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 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 oil and gas properties, quicker development of existing oil and gas properties, natural gas storage and transmission facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market and regulatory conditions. FINANCING CASH FLOW Consolidated short-term debt increased $128.5 million when comparing the balance sheet at September 30, 2021 to the balance sheet at September 30, 2020. The maximum amount of short-term debt outstanding during the year ended September 30, 2021 was $182.3 million. 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, exploration and development expenditures, 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. Given the significant rise in gas prices toward the end of the fiscal year, the Company was required to post margin on some of its outstanding derivative financial instruments. As a result, the Company accessed the commercial paper markets to meet its short-term borrowing needs. The Company’s margin deposits are reflected on the balance sheet as a current asset titled Hedging Collateral Deposits. The Company expects its outstanding Credit Agreements (as defined below) to provide ample liquidity should gas prices continue to increase and additional margin calls be required by our counterparties. At September 30, 2021, the Company had outstanding commercial paper of $158.5 million. The Company did not have any outstanding short-term notes payable to banks at September 30, 2021. The Company maintains $1.0 billion of unsecured committed revolving credit access across two facilities. On October 25, 2018, the Company entered into a Fourth Amended and Restated Credit Agreement ("Credit Agreement") with a syndicate of twelve banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through October 25, 2023. In addition to the Credit Agreement, on February 3, 2021, the Company amended its existing 364-Day Credit Agreement to extend the maturity date -50- thereof from May 3, 2021 to December 30, 2022, and to increase the lenders' commitments thereunder from $200.0 million to $250.0 million, among other changes (as amended, the "Amended 364-Day Credit Agreement"). Twelve banks are parties to the Amended 364-Day Credit Agreement, all of which are also lenders under the Credit Agreement. The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future. The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $250 million. This provision also applies to the Amended 364-Day Credit Agreement. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at September 30, 2021, $190.7 million was added back to the Company's total capitalization for purposes of the facility, and the Company’s debt to capitalization ratio, as calculated under the facility, was .59. The constraints specified in both the Credit Agreement and Amended 364-Day Credit Agreement would have permitted an additional $884.2 million in short-term and/or long-term debt to be outstanding at September 30, 2021 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 Amended 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 the Amended 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. On June 3, 2020, the Company issued $500.0 million of 5.50% notes due January 15, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company -51- amounted to $493.0 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 7.50%, if there is 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, which included the payment of a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020 and the repayment and refinancing of short-term debt. None of the Company’s long-term debt at September 30, 2021 and September 30, 2020 had a maturity date within the next twelve months. As of September 30, 2021, 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: $117.8 million in 2022, $654.1 million in 2023, $95.4 million in 2024, $589.4 million in 2025, $548.9 million in 2026, and $1,203.9 million thereafter. Refer to Item 8 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% and 4.85% at September 30, 2021 and September 30, 2020, respectively. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt. On June 2, 2020, the Company completed a public offering and sale of 4,370,000 shares of the Company's common stock, par value $1.00 per share, at a price of $39.50 per share. After deducting fees, commissions and other issuance costs, the net proceeds to the Company amounted to $165.8 million. The proceeds of this issuance were used to fund a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020. Under the Company's existing indenture covenants at September 30, 2021, the Company would have been permitted to issue up to a maximum of approximately $1.6 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by debt to capitalization ratio constraints under the Company’s Credit Agreement and Amended 364-Day Credit Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test. The Company’s 1974 indenture pursuant to which $99.0 million (or 3.7%) of the Company’s long-term debt (as of September 30, 2021) 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. -52- 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. 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 will continue making contributions to the Retirement Plan. During 2021, the Company contributed $20.0 million to the Retirement Plan. The Company anticipates that the annual contribution to the Retirement Plan in 2022 will be in the range of $20.0 million to $25.0 million. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments or through cash on hand, cash from operations or short-term borrowings. 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 anticipates that it will continue making contributions to the VEBA trusts and/or 401(h) accounts. During 2021, 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 2021. The Company anticipates that the annual contribution to its VEBA trusts in 2022 will be in the range of $2.5 million to $3.0 million. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments. 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 5 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 and crude oil, 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, 2021 to -53- terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas and crude oil 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 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, 2021, the Company determined that nonperformance risk 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 and crude oil 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, 2021. At September 30, 2021, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2026. Natural Gas Price Swap Agreements [[GREPCENT_TABLE]] [["","Expected Maturity Dates"],["","2022","","2023","","2024","","2025","","2026","","Total"],["Notional Quantities (Equivalent Bcf)","202.3","","","112.7","","","59.2","","","22.9","","","1.7","","","398.8"],["Weighted Average Fixed Rate (per Mcf)","$","2.84","","","$","2.88","","","$","2.81","","","$","2.83","","","$","2.83","","","$","2.84"],["Weighted Average Variable Rate (per Mcf)","$","4.99","","","$","3.74","","","$","3.31","","","$","3.12","","","$","2.99","","","$","4.27"]] [[/GREPCENT_TABLE]] At September 30, 2021, the Company would have paid its respective counterparties an aggregate of approximately $569.8 million to terminate the natural gas price swap agreements outstanding at that date. At September 30, 2020, the Company had natural gas price swap agreements covering 259.4 Bcf at a weighted average fixed rate of $2.69 per Mcf. Crude Oil Price Swap Agreements [[GREPCENT_TABLE]] [["","Expected Maturity Dates"],["","2022","","2023","","2024","","2025","","Total"],["Notional Quantities (Equivalent Bbls)","1,296,000","","","480,000","","","120,000","","","120,000","","","2,016,000"],["Weighted Average Fixed Rate (per Bbl)","$","57.40","","","$","58.48","","","$","50.30","","","$","50.32","","","$","56.81"],["Weighted Average Variable Rate (per Bbl)","$","74.26","","","$","68.96","","","$","64.61","","","$","61.51","","","$","71.66"]] [[/GREPCENT_TABLE]] -54- At September 30, 2021, the Company would have paid its respective counterparties an aggregate of approximately $29.9 million to terminate the crude oil price swap agreements outstanding at that date. At September 30, 2020, the Company had crude oil price swap agreements covering 1,548,000 Bbls at a weighted average fixed rate of $57.87 per Bbl. No Cost Collars The following table discloses the notional quantities, the weighted average ceiling price and the weighted average floor price for the no cost collars used by the Company to manage natural gas price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). At September 30, 2021, the Company had not entered into any natural gas no cost collars extending beyond 2024. [[GREPCENT_TABLE]] [["","Expected Maturity Dates"],["","2022","","2023","","2024","","Total"],["Natural Gas"],["Notional Quantities (Equivalent Bcf)","2.3","","","17.1","","","1.5","","","20.9"],["Weighted Average Ceiling Price (per Mcf)","$","2.86","","","$","3.29","","","$","3.29","","","$","3.25"],["Weighted Average Floor Price (per Mcf)","$","2.35","","","$","2.87","","","$","2.87","","","$","2.81"]] [[/GREPCENT_TABLE]] At September 30, 2021, the Company would have had to pay an aggregate of approximately $17.4 million to terminate the natural gas no cost collars outstanding at that date. At September 30, 2020, the Company had no cost collars agreements covering 27.3 Bcf at a weighted average ceiling price of $2.87 per Mcf and a weighted average floor price of $2.35 per Mcf. Foreign Exchange Risk The Company uses foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. All of these transactions are forecasted. The following table discloses foreign exchange contract information by expected maturity dates. The Company receives a fixed price in exchange for paying a variable price as noted in the Canadian to U.S. dollar forward exchange rates. Notional amounts (Canadian dollars) are used to calculate the contractual payments to be exchanged under contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2021. At September 30, 2021, the Company had not entered into any foreign currency exchange contracts extending beyond 2030. [[GREPCENT_TABLE]] [["","Expected Maturity Dates"],["","2022","","2023","","2024","","2025","","2026","","Thereafter","","Total"],["Notional Quantities (Canadian Dollar in millions)","$","16.1","","","$","14.7","","","$","12.9","","","$","10.9","","","$","1.9","","","$","4.2","","","$","60.7"],["Weighted Average Fixed Rate ($Cdn/$US)","$","1.29","","","$","1.29","","","$","1.29","","","$","1.28","","","$","1.35","","","$","1.40","","","$","1.30"],["Weighted Average Variable Rate ($Cdn/$US)","$","1.28","","","$","1.28","","","$","1.28","","","$","1.28","","","$","1.31","","","$","1.35","","","$","1.28"]] [[/GREPCENT_TABLE]] At September 30, 2021, absent other positions with the same counterparties, the Company would have received from its respective counterparties an aggregate of $0.7 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 $2.9 billion at September 30, 2021. This fair value amount is not intended to reflect principal amounts that the Company will ultimately be required to pay. The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt: -55- [[GREPCENT_TABLE]] [["","Principal Amounts by Expected Maturity Dates"],["","2022","","2023","","2024","","2025","","2026","","Thereafter","","Total"],["","(Dollars in millions)"],["Long-Term Fixed Rate Debt","$","\u2014","","$","549.0","","$","\u2014","","$","500.0","","$","500.0","","$","1,100.0","","$","2,649.0"],["Weighted Average Interest Rate Paid","\u2014","","4.1%","","\u2014","","5.4%","","5.5%","","3.7%","","4.5%"]] [[/GREPCENT_TABLE]] RATE MATTERS Utility Operation Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” Neither the New York or Pennsylvania divisions currently have a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill. New York Jurisdiction Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017. The order directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. On August 13, 2021, the NYPSC issued an order extending the date through which qualified leak prone pipe replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (until March 31, 2023). The extension is contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to April 1, 2023. In New York, on March 13, 2020, in response to the COVID-19 pandemic, the Company agreed to NYPSC Staff’s request that the Company suspend service terminations and disconnections. Thereafter, on June 17, 2020, New York enacted a law that prohibits utilities from terminating or disconnecting services to any residential customer for non-payment for the duration of the state disaster emergency. While that legislation expired on March 31, 2021, new legislation was enacted in May 2021 that prohibits utility terminations for non-payment for residential and small commercial customers who experienced a change in financial circumstances due to the COVID-19 state of emergency, with such prohibition running for a period of one hundred eighty days after either the New York State COVID-19 state of emergency is lifted or expires or December 31, 2021, whichever is earlier. On June 24, 2021, the New York State COVID-19 state of emergency expired. Updated guidance issued by the NYPSC on July 6, 2021 confirmed that qualified customers are protected from termination through December 21, 2021 and are eligible for a deferred payment agreement without the requirement of a down payment, late fees, penalties or interest on arrears incurred during the COVID-19 state of emergency. It is uncertain at this point as to whether there would be any regulatory relief for utilities with regard to an increase in costs associated with the COVID-19 pandemic, but it is one of many issues currently being considered in a generic NYPSC proceeding entitled “Proceeding on Motion of the Commission Regarding the Effects of COVID-19 on Utility Service” (Case No. 20-M-0266). Correspondence from NYPSC Staff has recommended that utilities rely on existing avenues of relief for these costs, and has identified additional, more stringent requirements that must be met to achieve relief. Pennsylvania Jurisdiction Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007. The rate settlement does not specify any requirement to file a future rate case. On July 22, 2021, Distribution Corporation filed a supplement to its current Pennsylvania tariff proposing to reduce base rates effective October 1, 2021 by $7.7 million in order to stop collecting other post-employment benefit (“OPEB”) expenses from customers at this time, to begin to refund to customers overcollected OPEB expenses in the amount of $50.0 million, and to make certain other adjustments to further reduce Distribution -56- Corporation’s regulatory liability associated with OPEB expenses. The PaPUC issued an order approving this tariff supplement on September 15, 2021 and new rates went into effect on October 1, 2021. On September 21, 2021, a complaint was filed in this proceeding. While new rates, including associated refunds, went into effect on October 1, 2021, certain other adjustments called for by the tariff supplement that allow Distribution Corporation to reduce its regulatory liability and its OPEB expenses will not be recorded in the Company’s consolidated financial statements until the complaint is resolved. The PaPUC has assigned the matter to the Office of Administrative Law Judge. The refunds specified in the tariff supplement will be 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 will no longer fund the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction. On March 26, 2020, the PaPUC ratified an Emergency Order that established a Service Termination Moratorium intended to continue during the pendency of Governor Wolf’s March 6, 2020 Proclamation of Disaster Emergency associated with the COVID-19 pandemic. On May 13, 2020, the Company (and other Pennsylvania local distribution companies) received a Secretarial Letter from the PaPUC regarding COVID-19 pandemic cost tracking and regulatory assets. The Secretarial Letter directs utilities to track “extraordinary, nonrecurring incremental COVID-19 related expenses” so the Commission can understand the impact of these expenses on the utilities’ finances. It also authorizes the creation of a utility regulatory asset, but only for incremental uncollectible expenses incurred above those embedded in rates (and incurred since the issuance of the Emergency Order). On October 8, 2020, the Commission issued an order ending the Service Termination Moratorium effective November 9, 2020, imposing a list of enhanced customer protections that expired on March 31, 2021 ("Modified Termination Moratorium"). On March 11, 2021, the Commission adopted an order lifting the Modified Termination Moratorium effective April 1, 2021, and authorizing utilities to return to the regular collections process with certain modifications to customer payment arrangements. On July 15, 2021, the Commission issued an order indicating that after September 30, 2021, customer payment arrangements will adhere to the traditional provisions of the Public Utility Code and Commission regulations. The October and March orders expanded the aforementioned potential utility regulatory asset to include all incremental COVID-19 related expenses incurred above those embedded in rates resulting from directives contained in the orders. The Company continues to monitor this item for potential deferral opportunity. Pipeline and Storage Supply Corporation’s rate settlement, approved June 1, 2020, 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. Supply Corporation has no rate case currently on file. Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1, 2025. ENVIRONMENTAL MATTERS The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory requirements. In March 2021, the Company set greenhouse gas reduction targets associated with the Company's utility delivery system. To further our ongoing efforts to lower the Company's emissions profile, in September 2021 the Company also established methane intensity reduction targets at each of its businesses, as well as an absolute greenhouse gas emissions reduction target for the consolidated Company. The Company's ability to estimate accurately the time, costs and resources necessary to meet emissions targets may change as environmental exposures and opportunities change and regulatory updates are issued. For further discussion of the Company's environmental exposures, refer to Item 8 at Note L — Commitments and Contingencies under the heading “Environmental Matters.” -57- 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. The U.S. Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented by EPA impose 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, other federal regulatory agencies are beginning to address greenhouse gas emissions through changes in their regulatory oversight approach and policies. A number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines and is in the process of evaluating cap-and-trade programs (e.g., Regional Greenhouse Gas Initiative). In California, the Company currently complies with California cap-and-trade rules, which increases the Company's cost of environmental compliance in its Exploration and Production segment. On April 23, 2021, California's Governor issued an executive order directing California Geologic Energy Management Division to stop issuing hydraulic fracturing permits by 2024, which does not have a direct impact on the plans of the Exploration and Production segment as those plans do not involve fracking. The executive order also directed the California Air Resources Board to investigate phasing out oil extraction by 2045, which may result in permitting delays and new legislative action in support of the directive. 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. 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. -58- NEW AUTHORITATIVE ACCOUNTING AND FINANCIAL REPORTING GUIDANCE For discussion of the recently issued authoritative accounting and financial reporting guidance, refer to Item 8 at Note A — Summary of Significant Accounting Policies under the heading “New Authoritative Accounting and Financial Reporting Guidance.” 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.The length and severity of the ongoing COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity; 6.Changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services; 7.Changes in the price of natural gas or oil; 8.The creditworthiness or performance of the Company’s key suppliers, customers and counterparties; 9.Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions; 10.Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves; -59- 11.Delays or changes in costs or plans with respect to Company projects or related projects of other companies, including disruptions due to the COVID-19 pandemic, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators; 12.The Company's ability to complete planned strategic transactions; 13.The Company's ability to successfully integrate acquired assets and achieve expected cost synergies; 14.Changes in price differentials between similar quantities of natural gas or oil at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations; 15.The impact of information technology disruptions, cybersecurity or data security breaches; 16.Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations; 17.Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits;  18.Other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date; 19.The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company; 20.Uncertainty of oil and gas reserve estimates; 21.Significant differences between the Company’s projected and actual production levels for natural gas or oil; 22.Changes in demographic patterns and weather conditions; 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; 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. 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.