
~~(1)~~			The executive officers serve at the pleasure of the Board of Directors. The information provided relates to the Company and its principal subsidiaries. Many of the executive officers also have served or currently serve as officers or directors of other subsidiaries of the Company.



Item 1A	Risk Factors

~~As a holding company, the Company depends on its operating subsidiaries to meet its financial obligations.~~

The Company is a holding company with no significant assets other than the stock of its operating subsidiaries. In order to meet its financial needs, the Company relies exclusively on repayments of principal and interest on intercompany loans made by the Company to its operating subsidiaries and income from dividends and other cash flow from the subsidiaries. Such operating subsidiaries may not generate sufficient net income to pay upstream dividends or generate sufficient cash flow to make payments of principal or interest on such intercompany loans.STRATEGIC RISKS

The Company is dependent on capital and credit markets to successfully execute its business strategies.

The Company relies upon short-term bank borrowings, commercial paper markets and longer-term capital markets to finance capital requirements not satisfied by cash flow from operations. The Company is dependent on these capital sources to provide capital to its subsidiaries to fund operations, acquire, maintain and develop properties, and execute growth strategies. The availability and cost of credit sources may be cyclical and these capital sources may not remain available to the Company. ~~Turmoil~~Continued turmoil in credit markets, due to the ongoing COVID-19 pandemic or otherwise, may make it difficult for the Company to obtain financing on acceptable terms or at all for working capital, capital expenditures and other investments, or to refinance maturing ~~debt on favorable terms.~~debt. These difficulties could adversely affect the Company's growth strategies, operations and financial performance.

The Company's ability to borrow under its credit facilities and commercial paper agreements, and its ability to issue long-term debt under its indentures, depend on the Company's compliance with its obligations under the facilities, agreements and indentures. For example, to issue incremental long-term debt, the Company must meet an interest coverage test under its 1974 indenture. In general, the Company’s operating income, subject to certain adjustments, over a consecutive 12-month period within the 15 months preceding the debt issuance, must be not less than two times the total annual interest charges on the Company’s long-term debt, taking into account the incremental issuance. In addition, the Company must maintain a ratio of long-term debt to consolidated assets (as defined under the 1974 indenture) of not more than 60%. Depending on their magnitude, factors that reduce the Company’s operating income and/or consolidated assets, including impairments (i.e., write-downs) of the Company’s oil and natural gas properties, could contribute to the Company’s inability to meet the interest coverage test or debt-to-assets ratio. In light of impairments recognized in fiscal 2020, and potentially in fiscal 2021, the Company will be precluded from issuing incremental long-term debt for several quarters in fiscal 2021. The 1974 indenture would not preclude the Company from issuing long-term debt to replace maturing long-term debt, including the Company’s 4.90% notes, in the principal amount of $500 million, maturing in December 2021.

In addition, the Company's short-term bank loans and commercial paper are in the form of floating rate debt or debt that may have rates fixed for very short periods of time, resulting in exposure to interest rate fluctuations in the absence of interest rate hedging transactions. The cost of long-term debt, the interest rates on the Company's short-term bank loans and commercial paper and the ability of the Company to issue commercial paper are affected by its ~~debt~~ credit ratings published by S&P, Moody's Investors Service, Inc. and Fitch Ratings. 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. On March 27, 2020, the Company was downgraded by S&P to a rating of BBB- with a negative outlook, which S&P revised on June 3, 2020 to a rating of BBB- with a stable outlook. Combined with current ratings from other credit rating agencies, that downgrade increased the Company's short-term borrowing costs under its Credit Agreement. Additionally, $600 million of the Company’s outstanding long-term debt would be subject to an interest rate increase if certain fundamental changes occur that involve a material subsidiary and result in a downgrade of ~~the~~a credit ~~ratings~~rating assigned to the notes below investment grade. In addition to the $600 million, another $500 million of the Company’s outstanding long-term debt would be subject to an interest rate increase based solely on a downgrade of a credit rating assigned to the notes below investment grade, regardless of any additional fundamental changes. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets.

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Climate change, and the regulatory, legislative and capital access developments related to climate change, may adversely affect operations and financial results.

Climate change could create physical risks, which may adversely affect the Company’s operations. Physical risks include changes in weather conditions, which could cause demand for gas to increase or decrease. If there were to be any impacts from climate change to the Company’s operations and financial results, the Company expects that they would likely occur over a long period of time and thus are difficult to quantify with any degree of specificity. Extreme weather events may result in adverse physical effects on portions of the country’s gas infrastructure, which could disrupt the Company’s supply chain and ultimately its operations. Disruption of production activities, and transportation and distribution systems could result in reduced operational efficiency, and customer service interruption.

Climate change, and the laws, regulations and other initiatives to address climate change, may impact the Company’s financial results. On November 4, 2020, the U.S. withdrew from the Paris Agreement, the international effort to establish emissions reduction goals for signatory countries. It is not possible at this time to predict whether changes in the federal administration may change the country’s participation in or the terms on which the U.S. may reenter the Paris Agreement. Despite the recent federal withdrawal, state and local governments, non-governmental organizations, and financial institutions have made, and will likely continue to make, more aggressive efforts to reduce emissions and advance the objectives of the Paris Agreement. Federal, state and local legislative and regulatory initiatives proposed or adopted in recent years in an attempt to limit the effects of climate change, including greenhouse gas emissions, could have significant impacts on the energy industry including government-imposed limitations, prohibitions or moratoriums on the use of gas and oil as well as accelerated depreciation of assets and/or stranded assets. For example, the U.S. Congress has from time to time considered bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. A number of states have adopted energy strategies or plans with goals that include the reduction of greenhouse gas emissions. For example, Pennsylvania has a methane reduction framework for the oil and gas industry which has resulted in permitting changes with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. With respect to its operations in California, the Company currently complies with California cap-and-trade guidelines, which increases the Company’s cost of environmental compliance in its Exploration and Production segment operation. In addition, the NYPSC initiated a proceeding to consider climate-related financial disclosures at the utility operating level, and the NY State legislature passed the CLCPA, which created emission reduction and electric generation mandates, and could ultimately impact the Utility segment’s customer base and the Utility segment’s business. Legislation or regulation that aims to reduce greenhouse gas emissions could also include greenhouse gas emissions limits and reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. Additionally, the trend toward increased conservation, competition from renewable energy sources, and technological advances to address climate change may reduce the demand for natural gas. For further discussion of the risks associated with environmental regulation to address climate change, refer to Item 7, MD&A under the heading “Environmental Matters” and subheading “Environmental Regulation.”

Further, recent trends directed toward a low-carbon economy could shift funding away from, or limit or restrict certain sources of funding for, companies focused on fossil fuel-related development or carbon-intensive investments. To the extent financial markets view climate change and greenhouse gas emissions as a financial risk, the Company’s cost of and access to capital could be negatively impacted.

Organized opposition to the oil and gas industry could have an adverse effect on Company operations.

Organized opposition to the oil and gas industry, including exploration and production activity and pipeline expansion and replacement projects, may continue to increase as a result of, among other things, safety incidents involving gas facilities, and concerns raised by politicians, financial institutions and advocacy groups about greenhouse gas emissions, hydraulic fracturing, or fossil fuels generally. This opposition may lead to increased regulatory and legislative initiatives that could place limitations, prohibitions or moratoriums on the use of gas and oil, impose costs tied to carbon emissions, provide cost advantages to alternative energy sources, or impose mandates that increase operational costs associated with new natural gas infrastructure and

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technology. This opposition may also lead to increased litigation that could cause operational delays or restrictions, and increase the Company’s operating costs. In turn, these factors could impact the competitive position of natural gas, ultimately affecting the Company’s results of operations and cash flows.

Delays or changes in plans or costs with respect to Company projects, including regulatory delays or denials with respect to necessary approvals, permits or orders, could delay or prevent anticipated project completion and may result in asset write-offs and reduced earnings.

Construction of the Pipeline and Storage segment’s planned pipelines and storage facilities, as well as the expansion of existing facilities, is subject to various regulatory, environmental, political, legal, economic and other development risks, including the ability to obtain necessary approvals and permits from regulatory agencies on a timely basis and on acceptable terms, or at all. Existing or potential third party opposition, such as opposition from landowner and environmental groups, which are beyond our control, could materially affect the anticipated construction of a project. In addition, third parties could impede the Gathering segment’s acquisition, expansion or renewal of rights-of-way or land rights on a timely basis and on acceptable terms. Any delay in project construction may prevent a planned project from going into service when anticipated, which could cause a delay in the receipt of revenues from those facilities, result in asset write-offs and materially impact operating results or anticipated results. Additionally, delays in pipeline construction projects could impede the Exploration and Production segment's ability to transport its production to premium markets, or to fulfill obligations to sell at contracted delivery points.

FINANCIAL RISKS

As a holding company, the Company depends on its operating subsidiaries to meet its financial obligations.

The Company is a holding company with no significant assets other than the stock of its operating subsidiaries. In order to meet its financial needs, the Company relies exclusively on repayments of principal and interest on intercompany loans made by the Company to its operating subsidiaries and income from dividends. Such operating subsidiaries may not generate sufficient net income to pay upstream dividends or generate sufficient cash flow to make payments of principal or interest on such intercompany loans.

The Company may be adversely affected by economic conditions and their impact on our suppliers and customers.

Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity, including the effects of the COVID-19 pandemic, could adversely affect the Company’s revenues and cash flows or restrict its future growth. The Company is monitoring and responding to the impacts of the COVID-19 pandemic across its businesses. To date, the COVID-19 pandemic has not had a material impact on the Company. However, the Company cannot predict the extent or duration of the outbreak or whether this rapidly evolving situation will have a material impact on the Company’s workforce, supply chain, operations or financial results, including potential regulatory responses to the financial impacts associated with the COVID-19 pandemic on the Company and its customers. Economic conditions in the Company’s utility service territories, along with legislative and ~~energy marketing territories~~regulatory prohibitions on terminations of service, also impact its collections of accounts receivable. For instance, New York enacted legislation in June 2020 that prohibits residential utility terminations for nonpayment for the duration of the New York State COVID Disaster Emergency (currently running until December 3, 2020), and thereafter, the law prohibits terminations for nonpayment through March 31, 2021 for residential customers that attest to Distribution that they have experienced a change in financial circumstances due to the COVID-19 state of emergency. All of the Company’s segments are exposed to risks associated with the creditworthiness or performance of key suppliers and customers, many of which may be adversely affected by volatile conditions in the financial ~~markets.~~markets, including volatility caused by the ongoing COVID-19 pandemic. These conditions could result in financial instability or other adverse effects at any of our suppliers or customers. For example, counterparties to the Company’s commodity hedging arrangements or commodity sales contracts might not be able to perform their obligations under these arrangements or contracts. Customers of the Company’s Utility ~~and Energy Marketing segments~~segment may have

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particular trouble paying their bills during periods of declining economic activity or high commodity prices, potentially resulting in increased bad debt expense and reduced ~~earnings.~~earnings; the PaPUC has directed utilities to track extraordinary, nonrecurring incremental COVID-19 related expenses, and has authorized the creation of a utility regulatory asset but only for incremental uncollectible expenses incurred above those embedded in rates, therefore it is unclear at this time to what extent the PaPUC will, and whether the NYPSC will at all, allow rate recovery for COVID-19 pandemic related expenses. Similarly, if reductions were to occur in funding of the federal Low Income Home Energy Assistance Program, bad debt expense could increase and earnings could decrease. In addition, oil and gas exploration and production companies that are customers of the Company’s Pipeline and Storage segment may decide not to renew contracts for the same transportation capacity during periods of reduced

production due to persistent low commodity prices. Any of these events could have a material adverse effect on the Company’s results of operations, financial condition and cash flows.

~~The~~Changes in interest rates may affect the Company’s ~~credit ratings~~financing and its regulated businesses’ rates of return.

Rising interest rates may ~~not reflect all~~impair the ~~risks~~Company’s ability to cost-effectively finance capital expenditures and to refinance maturing debt. In addition, the Company’s authorized rate of ~~an investment~~return in its ~~securities.~~regulated businesses is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, the Company’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, the Company’s ability to earn its authorized rate of return may be adversely impacted.

Fluctuations in oil and gas prices could adversely affect revenues, cash flows and profitability.

Operations in the Company’s Exploration and Production segment are materially dependent on prices received for its oil and gas production. Both short-term and long-term price trends affect the economics of exploring for, developing, producing, gathering and processing oil and gas. Oil and gas prices can be volatile and can be affected by: weather conditions, natural disasters, the supply and price of foreign oil and gas, the level of consumer product demand, national and worldwide economic conditions, economic disruptions caused by terrorist activities, acts of war or major accidents, political conditions in foreign countries, the price and availability of alternative fuels, the proximity to, and availability of, sufficient capacity on transportation facilities, regional levels of supply and demand, energy conservation measures, and government regulations. The Company sells the oil and gas that it produces at a combination of current market prices, indexed prices or through fixed-price contracts. The Company hedges a significant portion of future sales that are based on indexed prices utilizing the physical sale counter-party or the financial markets. The prices the Company receives depend upon factors beyond the Company’s ~~credit ratings are an independent assessment of~~control, including the factors affecting price mentioned above. The Company believes that any prolonged reduction in oil and gas prices could restrict its ability to ~~pay~~continue the level of exploration and production activity the Company otherwise would pursue, which could have a material adverse effect on its ~~obligations. Consequently, real or anticipated~~revenues, cash flows and results of operations.

In the Company’s Pipeline and Storage segment, significant changes in the price differential between equivalent quantities of gas at different geographic locations could adversely impact the Company. For example, if the price of gas at a particular receipt point on the Company’s ~~credit ratings will generally affect~~pipeline system increases relative to the ~~market value~~price of gas at other locations, then the volume of gas received by the Company at the relatively more expensive receipt point may decrease, or the price the Company charges to transport that gas may decrease. Changes in price differentials can cause shippers to seek alternative lower priced gas supplies and, consequently, alternative transportation routes. In some cases, shippers may decide not to renew transportation contracts due to changes in price differentials. While much of the ~~specific debt instruments~~impact of lower volumes under existing contracts would be offset by the straight fixed-variable rate design, this rate design does not protect Supply Corporation or Empire where shippers do not contract for expiring capacity at the same quantity and rate. If contract renewals were to decrease, revenues and earnings in this segment may decrease. Significant changes in the price differential between futures contracts for gas having different delivery dates could also adversely impact the Company. For example, if the prices of gas futures contracts for winter deliveries to locations served by the Pipeline and Storage segment decline relative to the prices of such contracts for summer deliveries (as a result, for instance, of increased production of gas within the segment’s geographic area or other factors), then

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demand for the Company’s gas storage services driven by that ~~are rated,~~price differential could decrease. These changes could adversely affect revenues, cash flows and results of operations.

The Company has significant transactions involving price hedging of its oil and gas production as well as its fixed price sale commitments.

To protect itself to some extent against unusual price volatility and to lock in fixed pricing on oil and gas production for certain periods of time, the Company’s Exploration and Production segment regularly enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may extend over multiple years, covering as much as approximately 80% of the Company’s expected energy production during the current fiscal year, and lesser percentages of subsequent years' expected production. These contracts reduce exposure to subsequent price drops but can also limit the Company’s ability to benefit from increases in commodity prices.

Use of energy commodity price hedges also exposes the Company to the risk of nonperformance by a contract counterparty. These parties might not be able to perform their obligations under the hedge arrangements.

It is the Company’s practice that the use of commodity derivatives contracts comply with various policies in effect in respective business segments. For example, in the Exploration and Production segment, commodity derivatives contracts must be confined to the price hedging of existing and forecast production. The Company maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose the Company to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Company’s actual production of oil and gas falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.

The Dodd-Frank Act increased federal oversight and regulation of the over-the-counter derivatives markets and certain entities that participate in those markets. Although regulators have issued certain regulations, other rules that may be relevant to the Company have yet to be finalized. For discussion of the risks associated with the Dodd-Frank Act, refer to Item 7, MD&A under the heading “Market Risk Sensitive Instruments.”

You should not place undue reliance on reserve information because such information represents estimates.

This Form 10-K contains estimates of the Company’s proved oil and gas reserves and the future net cash flows from those reserves, which the Company’s petroleum engineers prepared and independent petroleum engineers audited. Petroleum engineers consider many factors and make assumptions in estimating oil and gas reserves and future net cash flows. These factors include: historical production from the area compared with production from other producing areas; the assumed effect of governmental regulation; and assumptions concerning oil and gas prices, production and development costs, severance and excise taxes, and capital expenditures. Lower oil and gas prices generally cause estimates of proved reserves to be lower. Estimates of reserves and expected future cash flows prepared by different engineers, or by the same engineers at different times, may differ substantially. Ultimately, actual production, revenues and expenditures relating to the Company’s reserves will vary from any estimates, and these variations may be material. Accordingly, the accuracy of the Company’s reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.

If conditions remain constant, then the Company is reasonably certain that its reserve estimates represent economically recoverable oil and gas reserves and future net cash flows. If conditions change in the future, then subsequent reserve estimates may be revised accordingly. You should not assume that the present value of future net cash flows from the Company’s proved reserves is the current market value of the Company’s ~~common stock. The Company’s credit ratings, however,~~estimated oil and gas reserves. In accordance with SEC requirements, the Company bases the estimated discounted future net cash flows from its proved reserves on a 12-month average of historical prices for oil and gas (based on first day of the month prices and adjusted for hedging) and on costs as of the date of the estimate, which are all discounted at the SEC mandated discount rate. Actual future prices and costs may ~~not reflect~~differ materially

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from those used in the ~~potential impact~~net present value estimate. Any significant price changes will have a material effect on the present value ~~of its common stock of risks related to structural, market or other factors discussed in this Form 10-K.~~

The Company’s need to comply with comprehensive, complex, and the sometimes unpredictable enforcement of government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.

While the Company generally refers to its Utility segment and its Pipeline and Storage segment as its "regulated segments," there are many governmental laws and regulations that have an impact on almost every aspect of the Company's businesses including, but not limited to, tax law, such as the 2017 Tax Reform Act and related regulatory action, and environmental law. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, which may increase the Company's costs, require refunds to customers or affect its business in ways that the Company cannot predict. Administrative agencies may apply existing laws and regulations in unanticipated, inconsistent or legally unsupportable ways, making it difficult to develop and complete projects, and harming the economic climate generally. New York State, for example, under the current executive administration, appears intent on imposing unattainable regulatory standards, at least with respect to certain fossil fuel energy infrastructure projects.

Various aspects of the Company's operations are subject to regulation by, among others, the EPA, the U.S. Fish and Wildlife Service, the U.S. Forestry Service, the Bureau of Land Management, the NYDEC, the PaDEP, the Pennsylvania Department of Conservation and Natural Resources, the Division of Oil, Gas and Geothermal Resources of the California Department of Conservation, the California Department of Fish and Wildlife, and in some areas, locally adopted ordinances. Administrative proceedings or increased regulation by these or other agencies could lead to operational delays or restrictions and increased expense for one or more of the Company’s ~~subsidiaries.~~reserves.

Petroleum engineering is a subjective process of estimating underground accumulations of gas and other hydrocarbons that cannot be measured in an exact manner. The process of estimating oil and gas reserves is complex. The process involves significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Future economic and operating conditions are uncertain, and changes in those conditions could cause a revision to the Company’s reserve estimates in the future. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including historical production from the area compared with production from other comparable producing areas, and the assumed effects of regulations by governmental agencies. Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves: the quantities of oil and gas that are ultimately recovered, the timing of the recovery of oil and gas reserves, the production and operating costs to be incurred, the amount and timing of future development and abandonment expenditures, and the price received for the production.

Financial accounting requirements regarding exploration and production activities may affect the Company's profitability.

The Company ~~is also subject~~accounts for its exploration and production activities under the full cost method of accounting. Each quarter, the Company must perform a "ceiling test" calculation, comparing the level of its unamortized investment in oil and gas properties to the ~~jurisdiction~~present value of the ~~Pipeline~~future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses a 12-month historical average price for oil and ~~Hazardous Materials Safety Administration (PHMSA). PHMSA issues regulations~~gas (based on first day of the month prices and ~~conducts evaluations, among other things,~~adjusted for hedging) as well as the SEC mandated discount rate. If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be "impaired," and the full cost accounting rules require that ~~set safety standards for pipelines and underground storage facilities. Compliance with new legislation could increase costs~~the investment must be written down to the ~~Company. Non-compliance~~calculated net present value. Such an instance would require the Company to recognize an immediate expense in that quarter, and its earnings would be reduced. Depending on the magnitude of any decrease in average prices, that charge could be material. Under the Company's existing indenture covenants, an impairment could restrict the Company's ability to issue incremental long-term unsecured indebtedness for a period of time, beginning with ~~this legislation~~the fourth calendar month following the impairment. For the quarter and fiscal year ended September 30, 2020, the Company recognized pre-tax impairment charges on its oil and natural gas properties of $253.4 million and $449.4 million, respectively, and the Company will be precluded from issuing incremental long-term unsecured indebtedness for several quarters in fiscal 2021. The Company could ~~result~~potentially record non-cash impairments in ~~civil penalties for pipeline safety violations. If~~future quarters depending on the commodity price environment.

OPERATIONAL RISKS

The COVID-19 global pandemic could have a material adverse effect on the Company’s business, results of operations, cash flows and financial condition.

The actual or perceived effects of a widespread public health concern or pandemic, such as COVID-19, could negatively affect our business and results of operations. While to date the Company has not experienced any material negative effects as a result of ~~these~~the COVID-19 pandemic, the situation continues to rapidly evolve and could result in material negative effects on our business and results of operations. The Company and its Pandemic Response Team are closely monitoring and responding to the impacts of the pandemic on the Company’s workforce, customers, contractors, suppliers, business continuity, and liquidity.

The protracted slowdown of broad sectors of the economy as a result of the COVID-19 pandemic has decreased the current demand for oil and has the potential to decrease the demand for natural gas, which could reduce the Company's revenues. Additionally, significant changes in legislation or ~~similar new laws or regulations~~regulatory policy to address the ~~Company incurs material costs that~~COVID-19 pandemic could adversely impact the Company. Although it is ~~unable~~not possible to ~~recover fully through rates or otherwise offset,~~predict the ~~Company's financial condition,~~ultimate impact of the COVID-19 pandemic, including on the Company’s business, results of operations, ~~and~~ cash flows ~~could be adversely affected.~~

The Company is subject to the jurisdiction of the FERC with respect to Supply Corporation, Empire and some transactions performed by other Company subsidiaries, including Seneca, Distribution Corporation and NFR. The FERC, among other things, approves the rates that Supply Corporation and Empire may charge to their natural gas transportation and/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those operations. Pursuant to the petition of a customer or state commission, or on the FERC's own initiative, the FERC has the authority to investigate whether Supply Corporation's and Empire's rates are still "just and reasonable" as required by the NGA, and if not, to adjust those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to adjust the rates it charges its natural gas transportation and/or storage customers, or if either Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation's or Empire's earnings may decrease. The FERC also possesses significant penalty authority with respect to violations of the laws and regulations it administers. Supply Corporation, Empire and, to the extent subject to FERC jurisdiction, the Company's other subsidiaries are subject to the FERC's penalty authority. In addition, the FERC exercises jurisdiction over the construction and operation of facilities used in interstate gas transmission. Also, decisions of Canadian regulatorsfinancial positions, such ~~as the National Energy Board and the Ontario Energy Board could affect the viability~~

~~and profitability of Supply Corporation and Empire projects designed to transport gas between Canada and the United States.~~

In the Company's Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC, the PaPUC and, with respect to certain transactions, the FERC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers, or to the extent Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover increased costs (including costsimpacts that may be ~~incurred~~material include, but are not limited to: (i) a significant reduction in ~~connection~~near-term demand for natural gas and/or oil; (ii) increased late or uncollectible customer payments;

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(iii) the inability for the Company’s contractors or suppliers to fulfill their contractual obligations; (iv) significant changes in the Company’s human capital management approach, increased cybersecurity threats associated with ~~governmental investigations~~work-from-home arrangements, and increased purchases of personal protective equipment as the Company prepares its return-to-work plan; (v) difficulties in obtaining financing on acceptable terms or ~~proceedings~~at all for working capital, capital expenditures and other investments, or ~~mandated infrastructure inspection, maintenance or replacement programs), earnings may decrease.~~to refinance maturing debt; and (vi) impacts on natural gas and oil pricing and the potential impairment of the recorded value of certain assets as a result of reduced projected cash flows. To the extent the duration of any of these conditions extends for a longer period of time, the adverse impact will generally be more severe.

The nature of the Company’s operations presents inherent risks of loss that could adversely affect its results of operations, financial condition and cash flows.

The Company’s operations in its various reporting segments are subject to inherent hazards and risks such as: fires; natural disasters; explosions; ~~geological formations with abnormal pressures;~~ blowouts during well drilling; collapses of wellbore casing or other tubulars; pipeline ruptures; spills; and other hazards and risks that may cause personal injury, death, property damage, environmental damage or business interruption losses. Additionally, the Company’s facilities, machinery, and equipment may be subject to sabotage. ~~Any of these~~These events, in turn, could ~~cause a loss of hydrocarbons, environmental pollution, claims for personal injury, death, property damage or business interruption, or~~lead to governmental investigations, recommendations, claims, fines or penalties. As protection against operational hazards, the Company maintains insurance coverage against some, but not all, potential losses. In addition, many of the agreements that the Company executes with contractors provide for the division of responsibilities between the contractor and the Company, and the Company seeks to obtain an indemnification from the contractor for certain of these risks. The Company ~~is not always able, however,~~also seeks, but may be unable, to secure written indemnification agreements with ~~its~~ contractors that ~~contain indemnification, and sometimes the Company is required to indemnify others.~~

~~Insurance or indemnification agreements, when obtained, may not~~ adequately protect the Company against liability from all of the consequences of the hazards described above. The occurrence of an event not fully insured or indemnified against, the imposition of fines, penalties or mandated programs by governmental authorities, the failure of a contractor to meet its indemnification obligations, or the failure of an insurance company to pay valid claims could result in substantial losses to the Company. In addition, insurance may not be available, or if available may not be adequate, to cover any or all of these risks. It is also possible that insurance premiums or other costs may rise significantly in the future, so as to make such insurance prohibitively expensive.

Hazards and risks faced by the Company, and insurance and indemnification obtained or provided by the Company, may subject the Company to litigation or administrative proceedings from time to time. Such litigation or proceedings could result in substantial monetary judgments, fines or penalties against the Company or be resolved on unfavorable terms, the result of which could have a material adverse effect on the Company’s results of operations, financial condition and cash flows.

~~Environmental regulation significantly affects the Company’s business.~~

The Company’s business operations are subject to federal, state, and local laws and regulations relating to environmental protection. These laws and regulations concern the generation, storage, transportation, disposal, emission or discharge of pollutants, contaminants, hazardous substances and greenhouse gases into the environment, the reporting of such matters, and the general protection of public health, natural resources, wildlife and the environment. For example, currently applicable environmental laws and regulations restrict the types, quantities and concentrations of materials that can be released into the environment in connection with regulated activities, limit or prohibit activities in certain protected areas, and may require the Company to investigate and/or remediate contamination at certain current and former properties regardless of whether such contamination resulted from the Company’s actions or whether such actions were in compliance with applicable laws and regulations at the time they were taken. Moreover, spills or releases of regulated substances or the discovery of currently unknown contamination could expose the Company to material losses, expenditures and environmental, health and safety liabilities. Such liabilities could include penalties, sanctions or claims for damages to persons,

~~property or natural resources brought on behalf of the government or private litigants that could cause the Company to incur substantial costs or uninsured losses.~~

In addition, the Company must obtain, maintain and comply with numerous permits, leases, approvals, consents and certificates from various governmental authorities before commencing regulated activities. In connection with such activities, the Company may need to make significant capital and operating expenditures to detect, repair and/or control air emissions, to control water discharges or to perform certain corrective actions to meet the conditions of the permits issued pursuant to applicable environmental laws and regulations. Any failure to comply with applicable environmental laws and regulations and the terms and conditions of its environmental permits and authorizations could result in the assessment of significant administrative, civil and/or criminal penalties, the imposition of investigatory or remedial obligations and corrective actions, the revocation of required permits, or the issuance of injunctions limiting or prohibiting certain of the Company’s operations.

Costs of compliance and liabilities could negatively affect the Company’s results of operations, financial condition and cash flows. In addition, compliance with environmental laws and regulations could require unexpected capital expenditures at the Company’s facilities, temporarily shut down the Company’s facilities or delay or cause the cancellation of expansion projects or oil and natural gas drilling activities. Because the costs of complying with environmental regulations are significant, additional regulation could negatively affect the Company’s business. Although the Company cannot predict the impact of the interpretation or enforcement of EPA standards or other federal, state and local laws or regulations, the Company’s costs could increase if environmental laws and regulations change.

~~For further discussion of the risks associated with environmental regulation, refer to Item 7, MD&A under the heading “Environmental Matters” and subheading “Environmental Regulation.”~~

Third ~~parties may attempt~~party attempts to breach the Company’s network security ~~which~~ could disrupt the Company’s operations and adversely affect its financial results.

The Company’s information technology systems are subject to attempts by others to gain unauthorized access, ~~through the Internet,~~ or to otherwise introduce malicious software. These attempts might be the result of industrial or other espionage, or actions by hackers seeking to harm the Company, its services or customers. These more sophisticated cyber-related attacks, as well as cybersecurity failures resulting from human error, pose a risk to the security of the Company’s systems and networks and the confidentiality, availability and integrity of the Company’s and its customers’ data. That data may be considered sensitive, confidential, or personal information that is subject to privacy and security laws and regulations. While the Company employs reasonable and appropriate controls to protect data and the Company’s systems, the Company may be vulnerable to material security breaches, lost or corrupted data, programming errors and employee errors and/or malfeasance that could lead to the unauthorized access, use, disclosure, modification or destruction of the sensitive, confidential or personal information. Attempts to breach the Company’s network security may result in disruption of the Company’s business operations and services, delays in production, theft of sensitive and valuable data, damage to our physical systems, and reputational harm. Significant expenditures may be required to remedy breaches, including restoration of customer service and enhancement of information technology systems. The Company seeks to prevent, detect and investigate these security incidents, but in some cases the Company might be unaware of an incident or its magnitude and effects. In addition to existing risks, the adoption of new technologies may also increase the Company’s exposure to data breaches or the Company’s ability to detect and remediate effects of a breach. The Company has experienced attempts to breach its network security and ~~although~~has

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received notifications from third-party service providers who have experienced data breaches where Company data was potentially impacted. Although the scope of such incidents is sometimes unknown, they could prove to be material to the Company. Even though ~~we have~~ insurance coverage is in place for cyber-related risks, if such a breach were to occur, the Company’s operations, earnings and financial condition could be adversely affected to the extent not fully covered by such insurance.

Construction of the Pipeline and Storage segment’s planned pipelines and storage facilities, as well as the expansion of existing facilities, is subject to various regulatory, environmental, political, legal, economic and other development risks, including the ability to obtain necessary approvals and permits from regulatory agencies on a timely basis and on acceptable terms, or at all. For example, the Company has in the past encountered, and may in the future encounter, delays or denials by regulatory agencies in connection with certain projects, most significantly the Northern Access 2016 project. Existing or potential third party opposition, such as opposition from landowner and environmental groups, which are beyond our control, could interfere significantly with or delay the Company’s receipt of such approvals or permits, which could materially affect the anticipated construction of a project. In addition, third parties could impede the Gathering segment’s acquisition, expansion or renewal of

rights-of-way or land rights on a timely basis and on acceptable terms. Any delay in project construction may prevent a planned project from going into service when anticipated, which could cause a delay in the receipt of revenues from those facilities. A significant construction delay in a material project, whatever the cause, or a final judgment denying a necessary permit, may result in asset write-offs and reduced earnings and an inability to complete projects as initially planned, or at all. These events could have a material adverse impact on anticipated operating results.

~~The Company could be adversely affected by the disallowance of purchased gas costs incurred by the Utility segment.~~

Tariff rate schedules in each of the Utility segment’s service territories contain purchased gas adjustment clauses which permit Distribution Corporation to file with state regulators for rate adjustments to recover increases in the cost of purchased gas. Assuming those rate adjustments are granted, increases in the cost of purchased gas have no direct impact on profit margins. Distribution Corporation is required to file an accounting reconciliation with the regulators in each of the Utility segment’s service territories regarding the costs of purchased gas. There is a risk of disallowance of full recovery of these costs if regulators determine that Distribution Corporation was imprudent in making its gas purchases. Any material disallowance of purchased gas costs could have a material adverse effect on cash flow and earnings.

~~Changes in interest rates may affect the Company’s financing and its regulated businesses’ rates of return.~~

Rising interest rates may impair the Company’s ability to cost-effectively finance capital expenditures and to refinance maturing debt. In addition, the Company’s authorized rate of return in its regulated businesses is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, the Company’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, the Company’s ability to earn its authorized rate of return may be adversely impacted.

~~Fluctuations in oil and natural gas prices could adversely affect revenues, cash flows and profitability.~~

Operations in the Company’s Exploration and Production segment are materially dependent on prices received for its oil and natural gas production. Both short-term and long-term price trends affect the economics of exploring for, developing, producing, gathering and processing oil and natural gas. Oil and natural gas prices can be volatile and can be affected by: weather conditions, natural disasters, the supply and price of foreign oil and natural gas, the level of consumer product demand, national and worldwide economic conditions, economic disruptions caused by terrorist activities, acts of war or major accidents, political conditions in foreign countries, the price and availability of alternative fuels, the proximity to, and availability of, capacity on transportation facilities, regional levels of supply and demand, energy conservation measures, and government regulations, such as regulation of greenhouse gas emissions and natural gas transportation, royalties, and price controls. The Company sells the oil and natural gas that it produces at a combination of current market prices, indexed prices or through fixed-price contracts. The Company hedges a significant portion of future sales that are based on indexed prices utilizing the physical sale counter-party or the financial markets. The prices the Company receives depend upon factors beyond the Company’s control, including the factors affecting price mentioned above. The Company believes that any prolonged reduction in oil and natural gas prices could restrict its ability to continue the level of exploration and production activity the Company otherwise would pursue, which could have a material adverse effect on its revenues, cash flows and results of operations.

To the extent that the natural gas the Company produces is priced in local markets where production occurs, the price may be affected by local or regional supply and demand factors as well as other local market dynamics such as regional pipeline capacity. Currently, the prices the Company receives for its natural gas production in the local markets where production occurs are generally lower than the relevant benchmark prices, such as NYMEX, that are used for commodity trading purposes. The difference between the benchmark price and the price the Company receives is called a differential. The Company may be unable to accurately predict natural gas differentials, which may widen significantly in the future. Numerous factors may influence local commodity pricing, such as pipeline takeaway capacity and specifications, localized storage capacity, disruptions in the midstream or downstream sectors of the industry, trade restrictions and governmental regulations. Insufficient pipeline or storage capacity, or a lack of demand or surplus of supply in any given operating area may cause the differential to widen

in that area compared to other natural gas producing areas. Increases in the differential could lead to production curtailments or otherwise have a material adverse effect on the Company’s revenues, cash flows and results of operations.

In the Company’s Pipeline and Storage segment, significant changes in the price differential between equivalent quantities of natural gas at different geographic locations could adversely impact the Company. For example, if the price of natural gas at a particular receipt point on the Company’s pipeline system increases relative to the price of natural gas at other locations, then the volume of natural gas received by the Company at the relatively more expensive receipt point may decrease, or the price the Company charges to transport that natural gas may decrease. Changes in price differentials can cause shippers to seek alternative lower priced gas supplies and, consequently, alternative transportation routes. In some cases, shippers may decide not to renew transportation contracts due to changes in price differentials. While much of the impact of lower volumes under existing contracts would be offset by the straight fixed-variable rate design utilized by Supply Corporation and Empire, this rate design does not protect Supply Corporation or Empire where shippers do not contract for expiring capacity at the same quantity and rate. If contract renewals were to decrease, revenues and earnings in the Pipeline and Storage segment may decrease. Significant changes in the price differential between futures contracts for natural gas having different delivery dates could also adversely impact the Company. For example, if the prices of natural gas futures contracts for winter deliveries to locations served by the Pipeline and Storage segment decline relative to the prices of such contracts for summer deliveries (as a result, for instance, of increased production of natural gas within the Pipeline and Storage segment’s geographic area or other factors), then demand for the Company’s natural gas storage services driven by that price differential could decrease. Such changes in price differential could also affect the Energy Marketing segment’s ability to offset its natural gas storage costs through hedging transactions. These changes could adversely affect revenues, cash flows and results of operations.

~~The Company has significant transactions involving price hedging of its oil and natural gas production as well as its fixed price purchase and sale commitments.~~

In order to protect itself to some extent against unusual price volatility and to lock in fixed pricing on oil and natural gas production for certain periods of time, the Company’s Exploration and Production segment regularly enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may at any time cover as much as approximately 80% of the Company’s expected energy production during the upcoming 12-month period. These contracts reduce exposure to subsequent price drops but can also limit the Company’s ability to benefit from increases in commodity prices. In addition, the Energy Marketing segment enters into certain hedging arrangements, primarily with respect to its fixed price purchase and sales commitments and its gas stored underground.

Under applicable accounting rules currently in effect, the Company’s hedging arrangements are subject to quarterly effectiveness tests. Inherent within those effectiveness tests are assumptions concerning the long-term price differential between different types of crude oil, assumptions concerning the difference between published natural gas price indexes established by pipelines into which hedged natural gas production is delivered and the reference price established in the hedging arrangements, assumptions regarding the levels of production that will be achieved and, with regard to fixed price commitments, assumptions regarding the creditworthiness of certain customers and their forecasted consumption of natural gas. Depending on market conditions for natural gas and crude oil and the levels of production actually achieved, it is possible that certain of those assumptions may change in the future, and, depending on the magnitude of any such changes, it is possible that a portion of the Company’s hedges may no longer be considered highly effective. In that case, gains or losses from the ineffective derivative financial instruments would be marked-to-market on the income statement without regard to an underlying physical transaction. For example, in the Exploration and Production segment, where the Company uses short positions (i.e. positions that pay off in the event of commodity price decline) to hedge forecasted sales, gains would occur to the extent that natural gas and crude oil hedge prices exceed market prices for the Company’s natural gas and crude oil production, and losses would occur to the extent that market prices for the Company’s natural gas and crude oil production exceed hedge prices.

Use of energy commodity price hedges also exposes the Company to the risk of non-performance by a contract counterparty. These parties might not be able to perform their obligations under the hedge arrangements. In addition, the Company enters into certain commodity price hedges that are cleared through the NYMEX or ICE by futures

commission merchants. Under NYMEX and ICE rules, the Company is required to post collateral in connection with such hedges, with such collateral being held by its futures commission merchants. The Company is exposed to the risk of loss of such collateral from occurrences such as financial failure of its futures commission merchants, or misappropriation or mishandling of clients’ funds or other similar actions by its futures commission merchants. In addition, the Company is exposed to potential hedging ineffectiveness in the event of a failure by one of its futures commission merchants or contract counterparties.

It is the Company’s practice that the use of commodity derivatives contracts comply with various policies in effect in respective business segments. For example, in the Exploration and Production segment, commodity derivatives contracts must be confined to the price hedging of existing and forecast production, and in the Energy Marketing segment, commodity derivatives with respect to fixed price purchase and sales commitments must be matched against commitments reasonably certain to be fulfilled. The Company maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose the Company to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Company’s actual production of oil and natural gas falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.

The Dodd-Frank Act increased federal oversight and regulation of the over-the-counter derivatives markets and certain entities that participate in those markets. The act requires the CFTC, the SEC and various banking regulators to promulgate rules and regulations implementing the act. Although regulators have issued certain regulations, other rules that may be relevant to the Company have yet to be finalized.

~~For further discussion of the risks associated with the Dodd-Frank Act, refer to Item 7, MD&A under the heading “Market Risk Sensitive Instruments.”~~

~~You should not place undue reliance on reserve information because such information represents estimates.~~

This Form 10-K contains estimates of the Company’s proved oil and natural gas reserves and the future net cash flows from those reserves that were prepared by the Company’s petroleum engineers and audited by independent petroleum engineers. Petroleum engineers consider many factors and make assumptions in estimating oil and natural gas reserves and future net cash flows. These factors include: historical production from the area compared with production from other producing areas; the assumed effect of governmental regulation; and assumptions concerning oil and natural gas prices, production and development costs, severance and excise taxes, and capital expenditures. Lower oil and natural gas prices generally cause estimates of proved reserves to be lower. Estimates of reserves and expected future cash flows prepared by different engineers, or by the same engineers at different times, may differ substantially. Ultimately, actual production, revenues and expenditures relating to the Company’s reserves will vary from any estimates, and these variations may be material. Accordingly, the accuracy of the Company’s reserve estimates is a function of the quality of available data and of engineering and geological interpretation and judgment.

If conditions remain constant, then the Company is reasonably certain that its reserve estimates represent economically recoverable oil and natural gas reserves and future net cash flows. If conditions change in the future, then subsequent reserve estimates may be revised accordingly. You should not assume that the present value of future net cash flows from the Company’s proved reserves is the current market value of the Company’s estimated oil and natural gas reserves. In accordance with SEC requirements, the Company bases the estimated discounted future net cash flows from its proved reserves on a 12-month average of historical prices for oil and natural gas (based on first day of the month prices and adjusted for hedging) and on costs as of the date of the estimate. Actual future prices and costs may differ materially from those used in the net present value estimate. Any significant price changes will have a material effect on the present value of the Company’s reserves.

Petroleum engineering is a subjective process of estimating underground accumulations of natural gas and other hydrocarbons that cannot be measured in an exact manner. The process of estimating oil and natural gas reserves is complex. The process involves significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Future economic and operating conditions are uncertain, and changes in those conditions could cause a revision to the Company’s reserve estimates in the future. Estimates of economically recoverable oil and natural gas reserves and of future net cash flows depend

upon a number of variable factors and assumptions, including historical production from the area compared with production from other comparable producing areas, and the assumed effects of regulations by governmental agencies. Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves: the quantities of oil and natural gas that are ultimately recovered, the timing of the recovery of oil and natural gas reserves, the production and operating costs incurred, the amount and timing of future development and abandonment expenditures, and the price received for the production.

The amount and timing of actual future oil and ~~natural~~ gas production and the cost of drilling are difficult to predict and may vary significantly from reserves and production estimates, which may reduce the Company’s earnings.

There are many risks in developing oil and ~~natural~~ gas, including numerous uncertainties inherent in estimating quantities of proved oil and ~~natural~~ gas reserves and in projecting future rates of production and timing of development expenditures. The future success of the Company’s Exploration and Production ~~segment~~and Gathering segments depends on its ability to develop additional oil and ~~natural~~ gas reserves that are economically recoverable, and its failure to do so may reduce the Company’s earnings. The total and timing of actual future production may vary significantly from reserves and production estimates. The Company’s drilling of development wells can involve significant risks, including those related to timing, success rates, and cost overruns, and these risks can be affected by lease and rig availability, geology, and other factors. Drilling for oil and ~~natural~~ gas can be unprofitable, not only from non-productive wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, weather conditions, governmental requirements, including completion of environmental impact analyses and compliance with other environmental laws and regulations, and shortages or delays in the delivery of equipment and services can delay drilling operations or result in their cancellation. The cost of drilling, completing, and operating wells is significant and often uncertain, and new wells may not be productive or the Company may not recover all or any portion of its investment. Production can also be delayed or made uneconomic if there is insufficient gathering, processing and transportation capacity available at an economic price to get that production to a location where it can be profitably sold. Without continued successful exploitation or acquisition activities, the Company’s reserves and revenues will decline as a result of its current reserves being depleted by production. The Company cannot make assurances that it will be able to find or acquire additional reserves at acceptable costs.

~~Financial accounting requirements regarding exploration~~REGULATORY RISKS

The Company’s need to comply with comprehensive, complex, and ~~production activities~~the sometimes unpredictable enforcement of government regulations may ~~affect~~increase its costs and limit its revenue growth, which may result in reduced earnings.

The Company’s businesses are subject to regulation under a wide variety of federal and state laws, regulations and policies. Existing statutes and regulations, including current tax rates, may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, which may increase the Company's ~~profitability.~~costs, require refunds to customers or affect its business in ways that the Company cannot predict. Administrative agencies may apply existing laws and regulations in unanticipated, inconsistent or legally unsupportable ways, making it difficult to develop and complete projects, and harming the economic climate generally.

Various aspects of the Company's operations are subject to regulation by a variety of federal and state agencies with respect to permitting and environmental requirements. In some areas, the Company’s operations may also be subject to locally adopted ordinances. Administrative proceedings or increased regulation by these agencies could lead to operational delays or restrictions and increased expense for one or more of the Company’s subsidiaries.

The Company ~~accounts~~is subject to the jurisdiction of the Pipeline and Hazardous Materials Safety Administration (PHMSA). The PHMSA issues regulations and conducts evaluations, among other things, that set safety standards for ~~its exploration~~pipelines and ~~production activities under the full cost method~~underground storage facilities. If as a result of ~~accounting. Each quarter,~~these or similar new laws or regulations the Company ~~must perform a "ceiling test" calculation, comparing~~incurs material compliance costs that it is unable to recover fully through rates or otherwise offset, the ~~level~~Company's financial condition, results of ~~its unamortized investment in oil~~operations, and ~~natural gas properties~~cash flows could be adversely affected.

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The Company is subject to the ~~present value~~jurisdiction of the ~~future net revenue projected~~FERC with respect to ~~be recovered from~~Supply Corporation, Empire and some transactions performed by other Company subsidiaries. The FERC, among other things, approves the rates that Supply Corporation and Empire may charge to their gas transportation and/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those ~~properties according~~operations. Pursuant to ~~methods prescribed~~the petition of a customer or state commission, or on the FERC's own initiative, the FERC has the authority to investigate whether Supply Corporation's and Empire's rates are still "just and reasonable" as required by the ~~SEC.~~NGA, and if not, to adjust those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to adjust the rates it charges its gas transportation and/or storage customers, or if either Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation's or Empire's earnings may decrease. In ~~determining present value,~~addition, the ~~Company uses a 12-month historical average price for oil~~FERC exercises jurisdiction over the construction and ~~natural~~operation of interstate gas ~~(based on first day~~transmission facilities and also possesses significant penalty authority with respect to violations of the ~~month prices~~laws and ~~adjusted for hedging). If, at~~regulations it administers.

The operations of Distribution Corporation are subject to the ~~end of any quarter, the amount~~jurisdiction of the ~~unamortized investment exceeds~~NYPSC, the ~~net present value of~~PaPUC and, with respect to certain transactions, the ~~projected future cash flows, such investment may be considered to be "impaired,"~~FERC. The NYPSC and the ~~full cost accounting rules require~~PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the ~~investment must~~returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is unable to obtain approval from these regulators for the rates it is requesting to charge utility customers, particularly when necessary to cover increased costs, earnings may decrease.

Environmental regulation significantly affects the Company’s business.

The Company’s business operations are subject to federal, state, and local laws and regulations relating to environmental protection including obtaining and complying with permits, leases, approvals, consents and certifications from various governmental and permit authorities. These laws and regulations concern the generation, storage, transportation, disposal, emission or discharge of pollutants, contaminants, hazardous substances and greenhouse gases into the environment, the reporting of such matters, and the general protection of public health, natural resources, wildlife and the environment. For example, currently applicable environmental laws and regulations restrict the types, quantities and concentrations of materials that can be ~~written down to~~released into the ~~calculated net present value. Such an instance would~~environment in connection with regulated activities, limit or prohibit activities in certain protected areas, and may require the Company to ~~recognize an immediate expense~~investigate and/or remediate contamination at certain current and former properties regardless of whether such contamination resulted from the Company’s actions or whether such actions were in ~~that quarter,~~compliance with applicable laws and ~~its earnings would be reduced. Depending on~~regulations at the ~~magnitude~~time they were taken. Moreover, spills or releases of ~~any decrease in average prices, that charge~~regulated substances or the discovery of currently unknown contamination could be material. Under the Company's existing indenture covenants, an impairment could restrict the Company's ability to issue additional long-term unsecured indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. For the fiscal year ended September 30, 2015,expose the Company ~~recognized pre-tax impairment charges~~to material losses, expenditures and environmental, health and safety liabilities. Such liabilities could include penalties, sanctions or claims for damages to persons, property or natural resources brought on ~~its~~behalf of the government or private litigants that could cause the Company to incur substantial costs or uninsured losses.

Costs of compliance and liabilities could negatively affect the Company’s results of operations, financial condition and cash flows. In addition, compliance with environmental laws, regulations or permit conditions could require unexpected capital expenditures at the Company’s facilities, temporarily shut down the Company’s facilities or delay or cause the cancellation of expansion projects or oil and ~~natural~~ gas ~~properties~~drilling activities. Because the costs of ~~$1.1 billion. For~~such compliance are significant, additional regulation could negatively affect the ~~fiscal year ended September 30, 2016, the Company recognized a pre-tax impairment charge on its oil and natural gas properties of $948.3 million.~~Company’s business.

Increased regulation of exploration and production activities, including hydraulic fracturing, could adversely impact the Company.

Due to the ~~burgeoning~~ Marcellus and Utica Shale ~~natural~~ gas plays in the northeast United States, together with the fiscal difficulties faced by state agencies in Pennsylvania, various state legislative and regulatory initiatives

regarding the exploration and production business have been proposed or adopted. These initiatives include potential new or updated statutes and regulations governing the drilling, casing, cementing, testing, abandonment and monitoring of wells, the protection of water supplies and restrictions on water use and water rights, hydraulic fracturing operations, surface owners’ rights and damage compensation, the spacing of wells, use and disposal

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of potentially hazardous materials, and environmental and safety issues regarding ~~natural~~ gas pipelines. New permitting fees and/or severance taxes for oil and gas production are also possible. Additionally, legislative initiatives in the U.S. Congress and regulatory studies, proceedings or rule-making initiatives at federal, state or local agencies focused on the hydraulic fracturing process, the use of underground injection control wells for produced water disposal, and related operations could result in operational delays or prohibitions and/or additional permitting, compliance, reporting and disclosure requirements. For example, the EPA has adopted regulations that establish emission performance standards for hydraulic fracturing operations as well as natural gas gathering and transmission operations. Other EPA initiatives could expand water quality and hazardous waste regulation of hydraulic fracturing and related operations. In California, legislation regarding well stimulation, including hydraulic fracturing, has been adopted. The law mandates technical standards for well construction, hydraulic fracturing water management, groundwater monitoring, seismicity monitoring during hydraulic fracturing operations and public disclosure of hydraulic fracturing fluid constituents. Additionally, the California Division of Oil, Gas & Geothermal Resources (DOGGR) adopted regulations intended to bring California’s Class II Underground Injection Control (UIC) program into compliance with the federal Safe Drinking Water Act, underrequirements, which some wells may require an aquifer exemption. DOGGR began reviewing all active UIC projects, regardless of whether an exemption is required. These and any other new state, federal or local legislative or regulatory measures could lead to ~~operational delays or restrictions,~~ increased operating costs ~~additional regulatory burdens~~ and increased risks of litigation for the Company.

The Company could be adversely affected by the disallowance of purchased gas costs incurred by the Utility segment.

GENERAL RISKS

The Company’s credit ratings may not reflect all the risks of an investment in its securities.

The Company’s credit ratings are an independent assessment of its ability to pay its obligations. Consequently, real or anticipated changes in the Company’s credit ratings will generally affect the market value of the specific debt instruments that are rated, as well as the market value of the Company’s common stock. The Company’s credit ratings, however, may not reflect the potential impact on the value of its common stock of risks related to structural, market or other factors discussed in this Form 10-K.

The increasing costs of certain employee and retiree benefits could adversely affect the Company’s results.

The Company’s earnings and cash flow may be impacted by the amount of income or expense it expends or records for employee benefit plans. This is particularly true for pension and other post-retirement benefit plans, which are dependent on actual plan asset returns and factors used to determine the value and current costs of plan benefit obligations. In addition, if medical costs rise at a rate faster than the general inflation rate, the Company might not be able to mitigate the rising costs of medical benefits. Increases to the costs of pension, other post-retirement and medical benefits could have an adverse effect on the Company’s financial results.

Significant shareholders or potential shareholders may attempt to effect changes at the Company or acquire control over the Company, which could adversely affect the Company’s results of operations and financial condition.

Shareholders of the Company may from time to time engage in proxy solicitations, advance shareholder proposals or otherwise attempt to effect changes or acquire control over the Company. Campaigns by shareholders to effect changes at publicly traded companies are sometimes led by investors seeking to increase short-term shareholder value through actions such as financial restructuring, increased debt, special dividends, stock repurchases or sales of assets or the entire company. Additionally, activist shareholders may submit proposals to promote an environmental, social or governance position. Responding to proxy contests and other actions by activist shareholders can be costly and time-consuming, disrupting the Company’s operations and diverting the attention of the Company’s Board of Directors and senior management from the pursuit of business strategies. As a result, shareholder campaigns could adversely affect the Company’s results of operations and financial condition.



Item 1B			Unresolved Staff Comments

None.

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Item 2			Properties

General Information on Facilities

The net investment of the Company in property, plant and equipment was ~~$5.0~~$6.0 billion at September 30, ~~2018.~~2020. The Exploration and Production segment constitutes ~~27.5%~~30.7% of this investment, and is primarily located in ~~California and in~~ the Appalachian region of the United ~~States.~~States and in California. Approximately ~~61.4%~~55.9% of the Company's investment in net

property, plant and equipment was in the Utility and Pipeline and Storage segments, whose operations are located primarily in western and central New York and ~~northwestern~~western Pennsylvania. The Gathering segment constitutes ~~9.9%~~13.3% of the Company’s investment in net property, plant and equipment, and is located in northwestern Pennsylvania. The remaining 0.1% of the Company's net investment in property, plant and equipment ~~consisted of the~~falls within All Other ~~category~~ and Corporate ~~operations (1.2%), or $0.1 billion.~~operations. During the past five years, the Company has made significant additions to property, plant and equipment in order to expand its exploration and production and gathering operations in the Appalachian region of the United States and to expand and improve transmission and distribution facilities for ~~transportation~~ customers in New York and Pennsylvania. Net property, plant and equipment has ~~decreased $175~~increased $666 million, or ~~3.4%~~12.5%, since September 30, ~~2013.~~2015. The five year increase is net of impairments of oil and gas producing properties recorded in 2016 and 2020 ($948 million and $449 million, respectively). It is also net of $53.4 million of timber assets that were reclassified as Assets Held for Sale at September 30, 2020.

The Exploration and Production segment had a net investment in property, plant and equipment of ~~$1.4~~$1.8 billion at September 30, ~~2018.~~2020.

The Pipeline and Storage segment had a net investment of ~~$1.6~~$1.8 billion in property, plant and equipment at September 30, ~~2018.~~2020. Transmission pipeline represents 36% of this segment’s total net investment and includes ~~2,259~~2,265 miles of pipeline utilized to move large volumes of gas throughout its service area. Storage facilities represent ~~16%~~15% of this segment’s total net investment and consist of 3130 storage fields operating at a combined working gas level of 77.2 Bcf, three of which are jointly owned and operated with other interstate gas pipeline companies, and ~~394~~389 miles of pipeline. Net investment in storage facilities includes ~~$81.2~~$82.8 million of gas stored underground-noncurrent, representing the cost of the gas utilized to maintain pressure levels for normal operating purposes as well as gas maintained for system balancing and other purposes, including that needed for no-notice transportation service. The Pipeline and Storage segment has 3233 compressor stations with ~~174,407~~227,356 installed ~~compressor~~ horsepower that represent ~~26%~~31% of this segment’s total net investment in property, plant and equipment.

The Pipeline and Storage segments’ facilities provided the capacity to meet Supply Corporation’s 2020 peak day sendout for transportation service of 1,935 MMcf, which occurred on February 14, 2020. Withdrawals from storage of 592.2 MMcf provided approximately 31% of the requirements on that day.

The Gathering segment had a net investment of ~~$0.5~~$0.8 billion in property, plant and equipment at September 30, ~~2018.~~2020. Gathering lines and related ~~compressors~~compressor stations represent substantially all of this segment’s total net investment, including ~~152~~333 miles of ~~lines~~pipelines utilized to move Appalachian production (including Marcellus and Utica ~~Shales)~~shales) to various transmission pipeline receipt points. The Gathering segment has 723 compressor stations with ~~69,340~~118,800 installed ~~compressor~~ horsepower.

The Utility segment had a net investment in property, plant and equipment of ~~$1.5~~$1.6 billion at September 30, ~~2018.~~2020. The net investment in its gas distribution network (including ~~14,898~~14,972 miles of distribution pipeline) and its service connections to customers represent approximately ~~48%~~49% and ~~33%~~32%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, ~~2018.~~

The Pipeline and Storage segments’ facilities provided the capacity to meet Supply Corporation’s 2018 peak day sendout for transportation service of 2,361 MMcf, which occurred on January 5, 2018. Withdrawals from storage of 628.9 MMcf provided approximately 27% of the requirements on that day.2020.

Company maps are included in Exhibit 99.2 of this Form 10-K and are incorporated herein by reference.

Exploration and Production Activities

The Company is engaged in the exploration for and the development of natural gas and oil reserves in ~~California and~~ the Appalachian region of the United ~~States.~~States and in California. The ~~Company has been increasing its emphasis~~Company's development activities in the Appalachian region are focused primarily in the Marcellus and Utica ~~Shales.~~shales. Further discussion of oil and gas producing activities is included in Item 8, Note ~~L -~~O — Supplementary Information for Oil and Gas Producing Activities. Note LO sets forth proved developed and undeveloped reserve information for Seneca. The September 30, ~~2018, 2017~~2020, 2019 and ~~2016~~2018 reserves shown in Note LO are valued using an unweighted arithmetic

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average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. The reserves were estimated by Seneca’s geologists and engineers and were audited by independent petroleum engineers from Netherland, Sewell & Associates, Inc. Note LO discusses the qualifications of the Company's reservoir engineers, internal controls over the reserve estimation process and audit of the reserve estimates and changes in proved developed and undeveloped oil and natural gas reserves year over year.

~~Seneca’s~~Seneca's proved developed and undeveloped natural gas reserves increased from ~~1,973~~2,950 Bcf at September 30, ~~2017~~2019 to ~~2,357~~3,325 Bcf at September 30, ~~2018.~~2020. This increase is attributed to extensions and discoveries of ~~522~~7 Bcf and

~~upward revisions~~ acquisitions of ~~previous estimates of 93~~684 Bcf partially offset by downward revisions of 88 Bcf and production of ~~163 Bcf and sales of minerals in place of 68~~227 Bcf. Of the total ~~upward~~net downward gas revisions of 9388 Bcf, 968 Bcf were a result of negative price-related revisions and 179 Bcf were from 17 Pennsylvania PUD locations (two in the Marcellus Shale and 15 in the Utica Shale) removed due to the Company having no near term plans to develop these reserves. These are offset in part by upward revisions of 48 Bcf for five PUD locations added back to proved reserves in 2020 (after removing one in 2016 and four in 2017 due to scheduling delays beyond five year rule expirations) and 51 Bcf due to positive performance improvements and 2 Bcf were a result of higher gas prices, partially offset by 5 Bcf of PUD locations that were removed. The sales of minerals in place were primarily the result of Marcellus reserves that were sold in the Western Development Area as part of the joint development agreement (JDA)on producing wells combined with ~~IOG CRV - Marcellus, LLC (IOG)(57 Bcf), coupled with the sale of Seneca’s Sespe Field area in May 2018 (11 Bcf)~~longer laterals on certain wells.

Seneca’s proved developed and undeveloped oil reserves decreased from ~~30,207~~24,873 Mbbl at September 30, ~~2017~~2019 to ~~27,663~~22,100 Mbbl at September 30, ~~2018.~~2020. The decrease of 2,773 Mbbl is attributed to production of ~~2,535~~2,348 Mbbl ~~primarily occurring in the West Coast region,~~ and ~~sales~~downward revisions of ~~minerals in place~~previous estimates of ~~4,787~~713 Mbbl, partially offset by extensions and discoveries of ~~2,301~~288 Mbbl, ~~and upward~~primarily occurring in the West Coast region. Downward revisions ~~of previous estimates of 2,477 Mbbl. The sales of minerals in place~~ were ~~primarily the result of the aforementioned sale of Seneca’s Sespe Field area in May 2018. Upward revisions of 2,477 Mbbl were~~mainly a result of ~~both higher~~lower oil prices of ~~1,975~~1,818 Mbbl partially offset by positive revisions of 1,105 Mbbl, which were a combination of 688 Mbbl due to operational cost efficiencies and ~~upward revisions associated with performance improvements of 502 Mbbl.~~417 Mbbl due to field performance.

On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from ~~2,154~~3,099 Bcfe at September 30, ~~2017~~2019 to ~~2,523~~3,458 Bcfe at September 30, ~~2018.~~2020. This increase is attributed to acquisitions of 684 Bcfe and extensions and discoveries of ~~536 Bcfe and upward revisions of previous estimates of 108~~9 Bcfe, partially offset by production of ~~178~~241 Bcfe and ~~sales~~downward revisions of ~~minerals in place~~previous estimates of 9793 Bcfe.

Seneca’s proved developed and undeveloped natural gas reserves increased from ~~1,675~~2,357 Bcf at September 30, ~~2016~~2018 to ~~1,973~~2,950 Bcf at September 30, ~~2017.~~2019. This increase iswas attributed to extensions and discoveries of ~~386~~687 Bcf and net upward revisions of previous estimates of 91104 Bcf, partially offset by production of ~~157 Bcf and sales of minerals in place of 22~~198 Bcf. Of the total net upward gas revisions of 91104 Bcf, ~~125~~152 Bcf were a result of ~~higher gas prices for Marcellus Shale, Utica Shale and other reservoirs, and 20 Bcf were a result of upward~~positive revisions due to performance improvements and ~~lease operating expense reductions,~~7 Bcf in upward revisions for one PUD location added back to proved reserves, partially offset by 5455 Bcf offor six PUD locations that were removed. The sales of minerals in place were the result of Marcellus and Utica reserves that were sold in the Western Development Area (primarily in Forest, Elk, McKean and Cameron counties in Pennsylvania) in September 2017.

Seneca’s proved developed and undeveloped oil reserves ~~increased~~decreased from ~~29,009~~27,663 Mbbl at September 30, ~~2016~~2018 to ~~30,207~~24,873 Mbbl at September 30, ~~2017.~~2019. The ~~increase is~~decrease was attributed to ~~extensions and discoveries of 674 Mbbl and upward revisions of previous estimates of 3,293 Mbbl, partially offset by~~ production of ~~2,740~~2,323 Mbbl, primarily occurring in the West Coast region, and ~~sales of minerals in place of 29 Mbbl. Upward~~downward revisions of ~~3,293~~previous estimates of 1,254 Mbbl, partially offset by extensions and discoveries of 787 Mbbl. Downward revisions of 1,254 Mbbl were largely a result of ~~both higher oil prices of 1,623 Mbbl and upward revisions associated with~~reduced performance ~~improvements of 1,670 Mbbl. The sales of minerals in place were the result of aforementioned sales of reserves in the Western Development Area.~~from producing wells mainly at Seneca's Midway Sunset field.

On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from ~~1,849~~2,523 Bcfe at September 30, ~~2016~~2018 to ~~2,154~~3,099 Bcfe at September 30, ~~2017.~~2019. This increase iswas attributed to extensions and discoveries of ~~391~~692 Bcfe and upward revisions of previous estimates of ~~110~~96 Bcfe, partially offset by production of ~~174 Bcfe and sales of minerals in place of 22~~212 Bcfe.

At September 30, ~~2018,~~2020, the Company’s Exploration and Production segment had delivery commitments for production of ~~2,036~~2,327 Bcfe (mostly natural gas as commitments for crude oil were insignificant). The Company expects to meet those commitments through ~~proved reserves, including~~ the future development of reserves that are currently classified as proved ~~undeveloped~~ reserves and future extensions and discoveries.

-25-

The following is a summary of certain oil and gas information taken from Seneca’s records. All monetary amounts are expressed in U.S. dollars.

Production

For The Year Ended September 30
2018 2017 2016
United States
Appalachian Region
Average Sales Price per Mcf of Gas $ 2.36
(1) $ 2.52
(1) $ 1.94
(1)
Average Sales Price per Barrel of Oil $ 57.76
   $ 48.27
   $ 52.15

Average Sales Price per Mcf of Gas (after hedging) $ 2.49
   $ 2.93
   $ 3.01

Average Sales Price per Barrel of Oil (after hedging) $ 57.76
   $ 48.27
   $ 52.15

Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $ 0.69
(1) $ 0.71
(1) $ 0.73
(1)
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) 440
(1) 422
(1) 385
(1)
West Coast Region
Average Sales Price per Mcf of Gas $ 4.86
   $ 4.00
   $ 3.25

Average Sales Price per Barrel of Oil $ 66.39
   $ 46.14
   $ 35.26

Average Sales Price per Mcf of Gas (after hedging) $ 4.86
   $ 4.00
   $ 3.25

Average Sales Price per Barrel of Oil (after hedging) $ 58.66
   $ 53.85
   $ 57.97

Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $ 2.98
   $ 2.91
   $ 2.47

Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) 48
   53
   56

Total Company
Average Sales Price per Mcf of Gas $ 2.40
   $ 2.55
   $ 1.97

Average Sales Price per Barrel of Oil $ 66.38
   $ 46.18
   $ 35.42

Average Sales Price per Mcf of Gas (after hedging) $ 2.52
   $ 2.95
   $ 3.02

Average Sales Price per Barrel of Oil (after hedging) $ 58.66
   $ 53.87
   $ 57.91

Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced $ 0.91
   $ 0.96
   $ 0.96

Average Production per Day (in MMcf Equivalent of Gas and Oil Produced) 488
   475
   441


	For The Year Ended September 30
	2020			2019			2018
United States
Appalachian Region
Average Sales Price per Mcf of Gas	$	1.75	(1)	$	2.40	(1)	$	2.36	(1)
Average Sales Price per Barrel of Oil	$	45.69		$	57.14		$	57.76
Average Sales Price per Mcf of Gas (after hedging)	$	2.05		$	2.41		$	2.49
Average Sales Price per Barrel of Oil (after hedging)	$	45.69		$	57.14		$	57.76
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	$	0.68	(1)	$	0.67	(1)	$	0.69	(1)
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	616		(1)	537		(1)	440		(1)
West Coast Region
Average Sales Price per Mcf of Gas	$	3.82		$	5.15		$	4.86
Average Sales Price per Barrel of Oil	$	45.94		$	64.18		$	66.39
Average Sales Price per Mcf of Gas (after hedging)	$	3.82		$	5.15		$	4.86
Average Sales Price per Barrel of Oil (after hedging)	$	56.97		$	61.66		$	58.66
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	$	3.14		$	3.47		$	2.98
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	44			43			48
Total Company
Average Sales Price per Mcf of Gas	$	1.77		$	2.43		$	2.40
Average Sales Price per Barrel of Oil	$	45.94		$	64.17		$	66.38
Average Sales Price per Mcf of Gas (after hedging)	$	2.07		$	2.44		$	2.52
Average Sales Price per Barrel of Oil (after hedging)	$	56.96		$	61.65		$	58.66
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	$	0.84		$	0.88		$	0.91
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	660			580			488

~~(1)~~

The Marcellus Shale fields (which exceed 15% of total reserves at September 30, 2018, 2017 and 2016) contributed 412 MMcfe, 399 MMcfe and 372 MMcfe of daily production in 2018, 2017 and 2016, respectively. The average lifting costs (per Mcfe) were $0.69 in 2018, $0.71 in 2017 and $0.72 in 2016. The Utica Shale fields (which exceed 15% of total reserves at September 30, 2018) contributed 26 MMcfe of daily production in 2018. The average lifting costs (per Mcfe) were $0.64 in 2018. The average sales price for the Marcellus and Utica Shale fields (per Mcfe) were $2.36 ($2.49 after hedging) in 2018, $2.52 ($2.93 after hedging) in 2017 and $1.94 ($3.01 after hedging) in 2016.

(1)Average sales prices per Mcf of gas reflect sales of gas in the Marcellus and Utica Shale fields. The Marcellus Shale fields (which exceed 15% of total reserves at September 30, 2020, 2019 and 2018) contributed 463 MMcfe, 447 MMcfe and 412 MMcfe of daily production in 2020, 2019 and 2018, respectively. The average lifting costs (per Mcfe) were $0.70 in 2020, $0.68 in 2019 and $0.69 in 2018. The Utica Shale fields (which exceed 15% of total reserves at September 30, 2020, 2019 and 2018) contributed 151 MMcfe, 88 MMcfe and 26 MMcfe of daily production in 2020, 2019 and 2018, respectively. The average lifting costs (per Mcfe) were $0.62 in 2020, $0.63 in 2019 and $0.64 in 2018.

Productive Wells


	Appalachian Region		West Coast Region		Total Company
At September 30, 2020	Gas	Oil	Gas	Oil	Gas	Oil
Productive Wells — Gross	881	—	—	1,865	881	1,865
Productive Wells — Net	768	—	—	1,831	768	1,831

-26-

Appalachian
Region

West Coast
Region
Total Company
At September 30, 2018 Gas Oil Gas Oil Gas Oil
Productive Wells — Gross 472
—
—
1,917
472
1,917
Productive Wells — Net 367
—
—
1,884
367
1,884

Developed and Undeveloped Acreage

At September 30, 2018
Appalachian
Region

West Coast
Region

Total
Company
Developed Acreage
— Gross 527,544
17,101
544,645
— Net 518,518
15,769
534,287
Undeveloped Acreage
— Gross 355,110
120
355,230
— Net 341,074
30
341,104
Total Developed and Undeveloped Acreage
— Gross 882,654
17,221
899,875
— Net 859,592
(1) 15,799
875,391


At September 30, 2020	Appalachian Region		West Coast Region	Total Company
Developed Acreage
— Gross	659,046		17,042	676,088
— Net	649,296		15,409	664,705
Undeveloped Acreage
— Gross	711,022		—	711,022
— Net	664,336		—	664,336
Total Developed and Undeveloped Acreage
— Gross	1,370,068		17,042	1,387,110
— Net	1,313,632	(1)	15,409	1,329,041

~~(1)~~

Of the 859,592 Total Developed and Undeveloped Net Acreage in the Appalachian region as of September 30, 2018, there are a total of 800,683 net acres in Pennsylvania. Of the 800,683 total net acres in Pennsylvania, shale development in the Marcellus, Utica or Geneseo shales has occurred on approximately 57,846 net acres, or 7.2% of Seneca’s total net acres in Pennsylvania. The high amount of developed acreage in the table largely reflects development in the Upper Devonian geological formation and masks the potential for development beneath this formation, which includes the Marcellus, Utica and Geneseo shales.

(1)Of the 1,313,632 Total Developed and Undeveloped Net Acreage in the Appalachian region as of September 30, 2020, there are a total of 1,243,444 net acres in Pennsylvania. Of the 1,243,444 total net acres in Pennsylvania, shale development in the Marcellus, Utica or Geneseo shales has occurred on approximately 101,990 net acres, or 8.2% of Seneca’s total net acres in Pennsylvania. Developed Acreage in the table reflects previous development activities in the Upper Devonian formation, but does not include the potential for development beneath this formation in areas of previous development, which includes the Marcellus, Utica and Geneseo shales.

As of September 30, ~~2018,~~2020, the aggregate amount of gross undeveloped acreage expiring in the next three years and thereafter are as follows: ~~3,704 acres in 2019 (3,704 net acres), 446 acres in 2020 (356 net acres), 2~~967 acres in 2021 (2(695 net acres), 4,882 acres in 2022 (4,403 net acres), 2,973 acres in 2023 (2,648 net acres) and ~~37,830~~209,665 acres thereafter ~~(36,735~~(205,344 net acres). The remaining ~~313,248~~492,535 gross acres ~~(300,307~~(451,246 net acres) represent non-expiring oil and gas rights owned by the Company. Of the acreage that is currently scheduled to expire in ~~2019, 2020~~2021, 2022 and ~~2021,~~2023, Seneca has no4.2 Bcf of associated proved undeveloped gas reserves. As a part of its management approved development plan, Seneca generally commences development of these reserves prior to the expiration of the leases and/or proactively extends/renews these leases.

Drilling Activity


	Productive			Dry
For the Year Ended September 30	2020	2019	2018	2020	2019	2018
United States
Appalachian Region
Net Wells Completed
— Exploratory	—	—	4.00	1.00	—	—
— Development(1)	39.84	40.00	41.40	6.50	7.00	9.00
West Coast Region
Net Wells Completed
— Exploratory	—	—	—	—	—	—
— Development	34.00	44.00	15.00	—	1.00	—
Total Company
Net Wells Completed
— Exploratory	—	—	4.00	1.00	—	—
— Development	73.84	84.00	56.40	6.50	8.00	9.00

(1)Fiscal 2020 and 2019 Appalachian region dry wells include 4.5 and 3 net wells, respectively, drilled in 2011 that were never completed under a joint venture in which the Company was the nonoperator. The Company became the operator of the properties in 2017 and plugged and abandoned the wells in 2020 and 2019 after the Company determined it would not continue development activities. The remaining 2

-27-

Productive Dry
For the Year Ended September 30 2018 2017 2016 2018 2017 2016
United States
Appalachian Region
Net Wells Completed
— Exploratory 4.00
9.00
1.00
—
—
—
— Development 41.40
25.40
31.80
9.00
3.00
1.00
West Coast Region
Net Wells Completed
— Exploratory —
—
—
—
—
—
— Development 15.00
14.00
25.00
—
—
—
Total Company
Net Wells Completed
— Exploratory 4.00
9.00
1.00
—
—
—
— Development 56.40
39.40
56.80
9.00
3.00
1.00

dry wells in fiscal 2020, 4 dry wells in 2019 and 9 dry wells in 2018 relate to plugged and abandoned well locations where preparatory top-hole drilling operations had commenced but further development activities (e.g., vertical and horizontal drilling, hydraulic fracturing, etc.) did not proceed as a result of changes to the Company’s development plans.

Present Activities

At September 30, 2018
Appalachian
Region
West Coast Region Total Company
Wells in Process of Drilling(1)
— Gross 63.00
—
63.00
— Net 48.50
—
48.50


At September 30, 2020	Appalachian Region	West Coast Region	Total Company
Wells in Process of Drilling(1)
— Gross	56.00	—	56.00
— Net	49.00	—	49.00

(1)Includes wells awaiting completion.


~~(1)~~Item 3			~~Includes wells awaiting completion.~~Legal Proceedings



~~Item 3~~	~~Legal Proceedings~~

On September 13, 2017, the PaDEP sent a draft Consent Assessment of Civil Penalty (CACP) to Seneca, in relation to an alleged violation of the Pennsylvania Oil and Gas Act, as well as PaDEP rules and regulations regarding gas migration relating to Seneca’s drilling activities. The amount of the penalty sought by the PaDEP is not material to the Company. The draft CACP alleges a violation identified by the PaDEP in 2011. Seneca disputes the alleged violation and will vigorously defend its position in negotiations with the PaDEP.

For a discussion of various environmental and other matters, refer to Part II, Item 7, MD&A and Item 8 at Note IL — Commitments and Contingencies.

For a discussion of certain rate matters involving the NYPSC, refer to Part II, Item 7, MD&A of this report under the heading "Other Matters - Rate ~~and Regulatory~~ Matters."



Item 4			Mine Safety Disclosures

Not Applicable.

-28-

PART II



Item 5			Market for the Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

At September 30, ~~2018,~~2020, there were ~~10,751~~9,993 registered shareholders of Company common stock. The common stock is listed and traded on the New York Stock Exchange under the trading symbol "NFG". Information regarding the market for the Company’s common equity and related stockholder matters appears under Item 12 at Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters and Item 8 at Note EH — Capitalization and Short-Term Borrowings.

On July ~~2, 2018,~~1, 2020, the Company issued a total of ~~6,616~~10,620 unregistered shares of Company common stock to the ~~eight~~ten non-employee directors of the Company then serving on the Board of Directors of the Company, ~~827~~consisting of 1,062 shares to each such ~~director. On July 16, 2018, the Company issued 707 unregistered shares of Company stock to Steven C. Finch, who joined the Board on July 12, 2018 as a non-employee~~ director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended September 30, ~~2018.~~2020. These transactions were exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as transactions not involving a public offering.

Issuer Purchases of Equity Securities

Period
Total Number
of Shares
Purchased(a)

Average Price
Paid per
Share

Total Number of
Shares Purchased
as Part of
Publicly Announced
Share Repurchase
Plans or Programs

Maximum Number
of Shares that May
Yet Be Purchased Under Share Repurchase Plans or Programs(b)
July 1-31, 2018 9,542
$ 54.66
—
6,971,019
Aug. 1-31, 2018 10,972
$ 55.51
—
6,971,019
Sept. 1-30, 2018 10,311
$ 56.63
—
6,971,019
Total 30,825
$ 55.62
—
6,971,019


Period	Total Number of Shares Purchased(a)	Average Price Paid per Share		Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs	Maximum Number of Shares that May Yet Be Purchased Under Share Repurchase Plans or Programs(b)
July 1-31, 2020	14,195	$	39.77	—	6,971,019
Aug. 1-31, 2020	13,455	$	44.50	—	6,971,019
Sept. 1-30, 2020	12,891	$	43.26	—	6,971,019
Total	40,541	$	42.45	—	6,971,019

~~(a)~~

Represents (i) shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock-based compensation awards for the payment of applicable withholding taxes. During the quarter ended September 30, 2018, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 30,825 shares purchased other than through a publicly announced share repurchase program, 28,089 were purchased for the Company’s 401(k) plans and 2,736 were purchased as a result of shares tendered to the Company by holders of stock-based compensation awards.


~~(b)~~	In September 2008, the Company’s Board of Directors authorized the repurchase of eight million shares of the Company’s common stock. The repurchase program has no expiration date. The Company has not repurchased any shares since September 17, 2008 and has no plans to make further purchases in the near future.

(a)Represents (i) shares of common stock of the Company purchased with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock-based compensation awards for the payment of applicable withholding taxes. During the quarter ended September 30, 2020, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 40,541 shares purchased other than through a publicly announced share repurchase program, 40,265 were purchased for the Company’s 401(k) plans and 276 were purchased as a result of shares tendered to the Company by holders of stock-based compensation awards.

(b)In September 2008, the Company’s Board of Directors authorized the repurchase of eight million shares of the Company’s common stock. The repurchase program has no expiration date. The Company has not repurchased any shares since September 17, 2008 and has no plans to make further purchases in the near future.

-29-

Performance Graph

The following graph compares the Company’s common stock performance with the performance of the S&P 500 Index, the ~~PHLX~~S&P Mid Cap 400 Gas Utility ~~Sector~~ Index and the S&P ~~500~~1500 Oil & Gas Exploration & Production ~~SUB Industry~~ Index ~~GICS Level 4~~ for the period September 30, ~~2013~~2015 through September 30, ~~2018.~~2020. The graph assumes that the value of the investment in the Company’s common stock and in each index was $100 on September 30, ~~2013~~2015 and that all dividends were reinvested.


	2013	2014	2015	2016	2017	2018		2015	2016	2017	2018	2019	2020
National Fuel	$100	$104	$76	$85	$92	$94	National Fuel	$100	$112	$120	$123	$106	$96
S&P 500 Index	$100	$120	$119	$137	$163	$192	S&P 500 Index	$100	$115	$137	$161	$168	$194
PHLX Utility Sector Index (UTY)	$100	$116	$122	$144	$162	$167
S&P 500 Oil & Gas Exp & Prod SUB Industry Index GICS Level 4 (S5OILP)	$100	$108	$63	$76	$68	$85
S&P Mid Cap 400 Gas Utility Index (S4GASU)							S&P Mid Cap 400 Gas Utility Index (S4GASU)	$100	$126	$146	$164	$171	$121
S&P 1500 Oil & Gas Exp & Prod Index (S15OILP)							S&P 1500 Oil & Gas Exp & Prod Index (S15OILP)	$100	$119	$105	$132	$85	$47

Source: Bloomberg

The performance graph above is furnished and not filed for purposes of Section 18 of the Securities Exchange Act of 1934 and will not be incorporated by reference into any registration statement filed under the Securities Act of 1933 unless specifically identified therein as being incorporated therein by reference. The performance graph is not soliciting material subject to Regulation 14A.

-30-



Item 6			Selected Financial Data


	Year Ended September 30																Year Ended September 30
	2018			2017			2016			2015			2014				2020		2019		2018		2017		2016
	(Thousands, except per share amounts and number of registered shareholders)																(Thousands, except per share amounts and number of registered shareholders)
Summary of Operations																Summary of Operations
Operating Revenues:																Operating Revenues:
Utility and Energy Marketing Revenues	$	812,474		$	755,485		$	624,602		$	860,618		$	1,103,149		Utility and Energy Marketing Revenues	$	728,336	$	860,985	$	812,474	$	755,485	$	624,602
Exploration and Production and Other Revenues	569,808			617,666			611,766			696,709			808,595			Exploration and Production and Other Revenues	611,885		636,528		569,808		617,666		611,766
Pipeline and Storage and Gathering Revenues	210,386			206,730			216,048			203,586			201,337			Pipeline and Storage and Gathering Revenues	206,070		195,819		210,386		206,730		216,048
																	1,546,291		1,693,332		1,592,668		1,579,881		1,452,416
	1,592,668			1,579,881			1,452,416			1,760,913			2,113,081
Operating Expenses:																Operating Expenses:
Purchased Gas	337,822			275,254			147,982			349,984			605,838			Purchased Gas	233,890		386,265		337,822		275,254		147,982
Operation and Maintenance:																Operation and Maintenance:
Utility and Energy Marketing	200,780			199,293			192,512			203,249			196,534			Utility and Energy Marketing	181,051		171,472		168,885		169,731		192,512
Exploration and Production and Other	141,381			145,099			160,201			184,024			188,622			Exploration and Production and Other	148,856		147,457		139,546		141,010		160,201
Pipeline and Storage and Gathering	100,245			98,200			88,801			82,730			77,922			Pipeline and Storage and Gathering	108,640		111,783		101,338		90,918		88,801
Property, Franchise and Other Taxes	84,393			84,995			81,714			89,564			90,711			Property, Franchise and Other Taxes	88,400		88,886		84,393		84,995		81,714
Depreciation, Depletion and Amortization	240,961			224,195			249,417			336,158			383,781			Depreciation, Depletion and Amortization	306,158		275,660		240,961		224,195		249,417
Impairment of Oil and Gas Producing Properties	—			—			948,307			1,126,257			—			Impairment of Oil and Gas Producing Properties	449,438		—		—		—		948,307
	1,105,582			1,027,036			1,868,934			2,371,966			1,543,408				1,516,433		1,181,523		1,072,945		986,103		1,868,934
Operating Income (Loss)	487,086			552,845			(416,518		)	(611,053		)	569,673			Operating Income (Loss)	29,858		511,809		519,723		593,778		(416,518)
Other Income (Expense):																Other Income (Expense):
Other Income	4,697			7,043			9,820			8,039			9,461
Interest Income	6,766			4,113			4,235			3,922			4,170

Other Income (Deductions)																Other Income (Deductions)	(17,814)		(15,542)		(21,174)		(29,777)		14,055

Interest Expense on Long-Term Debt	(110,946		)	(116,471		)	(117,347		)	(95,916		)	(90,194		)	Interest Expense on Long-Term Debt	(110,012)		(101,614)		(110,946)		(116,471)		(117,347)
Other Interest Expense	(3,576		)	(3,366		)	(3,697		)	(3,555		)	(4,083		)	Other Interest Expense	(7,065)		(5,142)		(3,576)		(3,366)		(3,697)
Income (Loss) Before Income Taxes	384,027			444,164			(523,507		)	(698,563		)	489,027			Income (Loss) Before Income Taxes	(105,033)		389,511		384,027		444,164		(523,507)
Income Tax Expense (Benefit)	(7,494		)	160,682			(232,549		)	(319,136		)	189,614			Income Tax Expense (Benefit)	18,739		85,221		(7,494)		160,682		(232,549)

Net Income (Loss) Available for Common Stock	$	391,521		$	283,482		$	(290,958	)	$	(379,427	)	$	299,413		Net Income (Loss) Available for Common Stock	$	(123,772)	$	304,290	$	391,521	$	283,482	$	(290,958)
Per Common Share Data																Per Common Share Data

Basic Earnings (Loss) per Common Share	$	4.56		$	3.32		$	(3.43	)	$	(4.50	)	$	3.57		Basic Earnings (Loss) per Common Share	$	(1.41)	$	3.53	$	4.56	$	3.32	$	(3.43)
Diluted Earnings (Loss) per Common Share	$	4.53		$	3.30		$	(3.43	)	$	(4.50	)	$	3.52		Diluted Earnings (Loss) per Common Share	$	(1.41)	$	3.51	$	4.53	$	3.30	$	(3.43)
Dividends Declared	$	1.68		$	1.64		$	1.60		$	1.56		$	1.52		Dividends Declared	$	1.76	$	1.72	$	1.68	$	1.64	$	1.60
Dividends Paid	$	1.67		$	1.63		$	1.59		$	1.55		$	1.51		Dividends Paid	$	1.75	$	1.71	$	1.67	$	1.63	$	1.59
Dividend Rate at Year-End	$	1.70		$	1.66		$	1.62		$	1.58		$	1.54		Dividend Rate at Year-End	$	1.78	$	1.74	$	1.70	$	1.66	$	1.62
At September 30:																At September 30:
Number of Registered Shareholders	10,751			11,211			11,751			12,147			12,654			Number of Registered Shareholders	9,993		10,359		10,751		11,211		11,751

-109-

Retirement Plan Other Post-Retirement Benefits
Year Ended September 30 Year Ended September 30
2018 2017 2016 2018 2017 2016
(Thousands)
Change in Benefit Obligation
Benefit Obligation at Beginning of Period $ 1,054,826
$ 1,097,421
$ 1,026,190
$ 462,619
$ 526,138
$ 464,987
Service Cost 9,921
11,969
11,710
1,830
2,449
2,331
Interest Cost 33,006
38,383
42,315
14,801
19,007
20,386
Plan Participants’ Contributions —
—
—
2,894
2,717
2,558
Retiree Drug Subsidy Receipts —
—
—
1,545
1,553
1,925
Actuarial (Gain) Loss (50,218 ) (32,466 ) 76,309
(21,039 ) (62,215 ) 60,402
Benefits Paid (61,845 ) (60,481 ) (59,103 ) (26,664 ) (27,030 ) (26,451 )
Benefit Obligation at End of Period $ 985,690
$ 1,054,826
$ 1,097,421
$ 435,986
$ 462,619
$ 526,138
Change in Plan Assets
Fair Value of Assets at Beginning of Period $ 910,719
$ 869,775
$ 834,870
$ 514,017
$ 494,320
$ 477,959
Actual Return on Plan Assets 42,652
84,279
87,008
20,657
40,157
37,415
Employer Contributions 32,980
17,146
7,000
2,896
3,853
2,839
Plan Participants’ Contributions —
—
—
2,894
2,717
2,558
Benefits Paid (61,845 ) (60,481 ) (59,103 ) (26,664 ) (27,030 ) (26,451 )
Fair Value of Assets at End of Period $ 924,506
$ 910,719
$ 869,775
$ 513,800
$ 514,017
$ 494,320
Net Amount Recognized at End of Period (Funded Status) $ (61,184 ) $ (144,107 ) $ (227,646 ) $ 77,814
$ 51,398
$ (31,818 )
Amounts Recognized in the Balance Sheets Consist of:
Non-Current Liabilities $ (61,184 ) $ (144,107 ) $ (227,646 ) $ (4,919 ) $ (4,972 ) $ (49,467 )
Non-Current Assets —
—
—
82,733
56,370
17,649
Net Amount Recognized at End of Period $ (61,184 ) $ (144,107 ) $ (227,646 ) $ 77,814
$ 51,398
$ (31,818 )
Accumulated Benefit Obligation $ 946,763
$ 1,010,179
$ 1,039,408
N/A
N/A
N/A
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30
Discount Rate 4.30 % 3.77 % 3.60 % 4.31 % 3.81 % 3.70 %
Rate of Compensation Increase 4.70 % 4.70 % 4.70 % 4.70 % 4.70 % 4.70 %

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Retirement Plan Other Post-Retirement Benefits
Year Ended September 30 Year Ended September 30
2018 2017 2016 2018 2017 2016
(Thousands)
Components of Net Periodic Benefit Cost
Service Cost $ 9,921
$ 11,969
$ 11,710
$ 1,830
$ 2,449
$ 2,331
Interest Cost 33,006
38,383
42,315
14,801
19,007
20,386
Expected Return on Plan Assets (61,715 ) (59,718 ) (59,369 ) (31,482 ) (31,458 ) (31,535 )
Amortization of Prior Service Cost (Credit) 938
1,058
1,234
(429 ) (429 ) (912 )
Recognition of Actuarial Loss(1) 37,205
42,687
32,248
10,558
18,415
5,530
Net Amortization and Deferral for Regulatory Purposes 9,027
469
3,957
15,028
6,108
17,123
Net Periodic Benefit Cost $ 28,382
$ 34,848
$ 32,095
$ 10,306
$ 14,092
$ 12,923
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30
Effective Discount Rate for Benefit Obligations 3.77 % 3.60 % 4.25 % 3.81 % 3.70 % 4.50 %
Effective Rate for Interest on Benefit Obligations 3.23 % 3.60 % 4.25 % 3.29 % 3.70 % 4.50 %
Effective Discount Rate for Service Cost 4.00 % 3.60 % 4.25 % 4.10 % 3.70 % 4.50 %
Effective Rate for Interest on Service Cost 3.73 % 3.60 % 4.25 % 3.98 % 3.70 % 4.50 %
Expected Return on Plan Assets 7.00 % 7.00 % 7.25 % 6.25 % 6.50 % 6.75 %
Rate of Compensation Increase 4.70 % 4.70 % 4.75 % 4.70 % 4.70 % 4.75 %


	Retirement Plan									Other Post-Retirement Benefits
	Year Ended September 30									Year Ended September 30
	2020			2019			2018			2020			2019			2018
	(Thousands)
Components of Net Periodic Benefit Cost
Service Cost	$	9,318		$	8,482		$	9,921		$	1,609		$	1,519		$	1,830
Interest Cost	29,930			38,378			33,006			12,913			17,145			14,801
Expected Return on Plan Assets	(60,063)			(62,368)			(61,715)			(29,232)			(30,157)			(31,482)
Amortization of Prior Service Cost (Credit)	729			826			938			(429)			(429)			(429)

Recognition of Actuarial Loss(1)	39,384			32,096			37,205			535			5,962			10,558
Net Amortization and Deferral for Regulatory Purposes	5,359			2,493			9,027			25,596			16,481			15,028
Net Periodic Benefit Cost	$	24,657		$	19,907		$	28,382		$	10,992		$	10,521		$	10,306
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30
Effective Discount Rate for Benefit Obligations	3.15		%	4.30		%	3.77		%	3.17		%	4.31		%	3.81		%
Effective Rate for Interest on Benefit Obligations	2.81		%	4.03		%	3.23		%	2.84		%	4.05		%	3.29		%
Effective Discount Rate for Service Cost	3.31		%	4.40		%	4.00		%	3.39		%	4.43		%	4.10		%
Effective Rate for Interest on Service Cost	3.12		%	4.29		%	3.73		%	3.30		%	4.39		%	3.98		%
Expected Return on Plan Assets	6.40		%	6.75		%	7.00		%	5.70		%	6.00		%	6.25		%
Rate of Compensation Increase	4.70		%	4.70		%	4.70		%	4.70		%	4.70		%	4.70		%


~~(1)~~	Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach.

(1)Distribution Corporation’s New York jurisdiction calculates the amortization of the actuarial loss on a vintage year basis over 10 years, as mandated by the NYPSC. All the other subsidiaries of the Company utilize the corridor approach.

The Net Periodic Benefit Cost in the table above includes the effects of regulation. The Company recovers pension and other post-retirement benefit costs in its Utility and Pipeline and Storage segments in accordance with the applicable regulatory commission authorizations. Certain of those commission authorizations established tracking mechanisms which allow the Company to record the difference between the amount of pension and other post-retirement benefit costs recoverable in rates and the amounts of such costs as determined under the existing authoritative guidance as either a regulatory asset or liability, as appropriate. Any activity under the tracking mechanisms (including the amortization of pension and other post-retirement regulatory assets and liabilities) is reflected in the Net Amortization and Deferral for Regulatory Purposes line item above.

In addition to the Retirement Plan discussed above, the Company also has Non-Qualified benefit plans that cover a group of management employees designated by the Chief Executive Officer of the Company. These plans provide for defined benefit payments upon retirement of the management employee, or to the spouse upon death of the management employee. The net periodic benefit costs associated with these plans were ~~$6.8~~$8.9 million, $7.6 million and ~~$7.5~~$6.8 million in ~~2018, 2017~~2020, 2019 and ~~2016,~~2018, respectively. The ~~accumulated~~components of net periodic benefit ~~obligations for the~~cost other than service costs associated with these plans ~~were $70.6 million, $72.5 million and $72.4 million at September 30, 2018, 2017 and 2016, respectively. The~~are presented in Other Income (Deductions) on

-110-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

the Consolidated Statements of Income. The accumulated benefit obligations for the plans were $78.7 million, $79.8 million and $70.6 million at September 30, 2020, 2019 and 2018, respectively. The projected benefit obligations for the plans were ~~$86.1~~$98.1 million, ~~$88.9~~$99.5 million and ~~$91.7~~$86.1 million at September 30, ~~2018, 2017~~2020, 2019 and ~~2016,~~2018, respectively. At September 30, ~~2018, $11.5~~2020, $14.5 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining ~~$74.6~~$83.6 million is recorded in Other Deferred Credits on the Consolidated Balance Sheets. At September 30, ~~2017, $14.1~~2019, $13.2 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining ~~$74.8~~$86.3 million was recorded in Other Deferred Credits on the Consolidated Balance Sheets. At September 30, ~~2016, $9.8~~2018, $11.5 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining ~~$81.9~~$74.6 million was recorded in Other Deferred Credits on the Consolidated Balance Sheets. The weighted average discount rates for these plans were ~~4.02%~~1.92%, ~~3.22%~~2.77% and ~~2.80%~~4.02% as of September 30, ~~2018, 2017~~2020, 2019 and ~~2016,~~2018, respectively and the weighted average rates of compensation increase for these plans were ~~7.75%~~8.00%, ~~7.75%~~8.00% and 7.75% as of September 30, ~~2018, 2017~~2020, 2019 and ~~2016,~~2018, respectively.

The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal ~~2018,~~2020, the changes in such amounts during ~~2018,~~2020, as well as the amounts expected to be recognized in net periodic benefit cost in fiscal ~~2019~~2021 are presented in the table below:

Retirement
Plan

Other
Post-Retirement
Benefits

Non-Qualified
Benefit Plans
(Thousands)
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1)
Net Actuarial Gain (Loss) $ (135,527 ) $ 1,193
$ (22,818 )
Prior Service (Cost) Credit (5,195 ) 3,258
—
Net Amount Recognized $ (140,722 ) $ 4,451
$ (22,818 )
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2018(1)
Decrease (Increase) in Actuarial Loss, excluding amortization(2) $ 31,155
$ 10,213
$ (2,035 )
Change due to Amortization of Actuarial Loss 37,205
10,558
3,549
Prior Service (Cost) Credit 938
(429 ) —
Net Change $ 69,298
$ 20,342
$ 1,514
Amounts Expected to be Recognized in Net Periodic
Benefit Cost in the Next Fiscal Year(1)

Net Actuarial Loss $ (32,096 ) $ (5,962 ) $ (3,558 )
Prior Service (Cost) Credit (826 ) 429
—
Net Amount Expected to be Recognized $ (32,922 ) $ (5,533 ) $ (3,558 )


	Retirement Plan		Other Post-Retirement Benefits		Non-Qualified Benefit Plans
	(Thousands)
Amounts Recognized in Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities(1)
Net Actuarial Loss	$	(215,330)	$	(28,044)	$	(34,065)
Prior Service (Cost) Credit	(3,641)		2,401		0
Net Amount Recognized	$	(218,971)	$	(25,643)	$	(34,065)
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2020(1)
Increase in Actuarial Loss, excluding amortization(2)	$	(38,568)	$	(1,180)	$	(5,929)
Change due to Amortization of Actuarial Loss	39,384		535		5,341

Prior Service (Cost) Credit	729		(429)		0
Net Change	$	1,545	$	(1,074)	$	(588)
Amounts Expected to be Recognized in Net Periodic Benefit Cost in the Next Fiscal Year(1)
Net Actuarial Loss	$	(36,814)	$	(849)	$	(5,852)
Prior Service (Cost) Credit	(631)		429		0
Net Amount Expected to be Recognized	$	(37,445)	$	(420)	$	(5,852)


~~(1)~~	~~Amounts presented are shown before recognizing deferred taxes.~~


~~(2)~~	~~Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial (Gain) Loss amounts presented in the Change in Benefit Obligation.~~

(1)Amounts presented are shown before recognizing deferred taxes.

(2)Amounts presented include the impact of actuarial gains/losses related to return on assets, as well as the Actuarial (Gain) Loss amounts presented in the Change in Benefit Obligation.

In order to adjust the funded status of its pension (tax-qualified and non-qualified) and other post-retirement benefit plans at September 30, ~~2018,~~2020, the Company recorded a ~~$75.3~~$3.8 million decrease to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a ~~$15.9~~$3.9 million (pre-tax) ~~increase~~decrease to Accumulated Other Comprehensive Income.

-111-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The effect of the discount rate change for the Retirement Plan in 2020 was to increase the projected benefit obligation of the Retirement Plan by $61.3 million. The mortality improvement projection scale was updated, which decreased the projected benefit obligation of the Retirement Plan in 2020 by $3.3 million. Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2020 by $7.9 million. The effect of the discount rate change for the Retirement Plan in 2019 was to increase the projected benefit obligation of the Retirement Plan by $128.4 million. The effect of the discount rate change for the Retirement Plan in 2018 was to decrease the projected benefit obligation of the Retirement Plan by $58.1 million. The mortality improvement projection scale was updated, which decreased the projected benefit obligation of the Retirement Plan in 2018 by $3.3 million. Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2018 by $11.2 million. The effect of the discount rate change for the Retirement Plan in 2017 was to decrease the projected benefit obligation of the Retirement Plan by $20.5 million. The effect of the discount rate change for the Retirement Plan in 2016 was to increase the projected benefit obligation of the Retirement Plan by $78.5 million.

The Company made cash contributions totaling ~~$33.0~~$24.6 million to the Retirement Plan during the year ended September 30, ~~2018.~~2020. The Company expects that the annual contribution to the Retirement Plan in ~~2019~~2021 will be in the range of ~~$29.0~~$15.0 million to ~~$35.0~~$25.0 million.

The following Retirement Plan benefit payments, which reflect expected future service, are expected to be paid by the Retirement Plan during the next five years and the five years thereafter: ~~$65.7 million in 2019; $65.9 million in 2020; $66.3~~$66.8 million in 2021; ~~$66.5~~$67.2 million in 2022; ~~$66.6~~$67.4 million in 2023; $67.4 million in 2024; $67.1 million in 2025; and ~~$330.9~~$326.8 million in the five years thereafter.

The effect of the discount rate change in 2020 was to increase the other post-retirement benefit obligation by $25.4 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2020 by $2.5 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2020 by $6.5 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.

The effect of the discount rate change in 2019 was to increase the other post-retirement benefit obligation by $57.2 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2019 by $3.9 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2019 by $18.9 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.

The effect of the discount rate change in 2018 was to decrease the other post-retirement benefit obligation by $25.8 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2018 by $2.4 million. Other actuarial experience increased the other post-retirement benefit obligation in 2018 by $7.3 million ~~the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.~~

The effect of the discount rate change in 2017 was to decrease the other post-retirement benefit obligation by $6.2 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2017 by $5.7 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2017 by $50.3 million primarily attributable to a revision in assumed per-capita claims cost, premiums, retiree ~~contributions and retiree drug subsidy assumptions based on actual experience.~~

The effect of the discount rate change in 2016 was to increase the other post-retirement benefit obligation by $49.4 million. Other actuarial experience increased the other post-retirement benefit obligation in 2016 by $11.0 million primarily attributable to a revision in assumed per-capita claims cost, premiums, participant contributions and drug subsidy assumptions based on actual experience.

The Medicare Prescription Drug, Improvement, and Modernization Act of 2003 provides for a prescription drug benefit under Medicare (Medicare Part D), as well as a federal subsidy to sponsors of retiree health care benefit plans that provide a benefit that is at least actuarially equivalent to Medicare Part D.

The estimated gross other post-retirement benefit payments and gross amount of Medicare Part D prescription drug subsidy receipts are as follows (dollars in thousands):


							Benefit Payments		Subsidy Receipts
	Benefit Payments		Subsidy Receipts
2019	$	27,821	$	(1,858	)
2020	$	28,692	$	(1,996	)
2021	$	29,455	$	(2,128	)	2021	$	28,361	$	(1,950)
2022	$	29,979	$	(2,260	)	2022	$	28,820	$	(2,064)
2023	$	30,426	$	(2,386	)	2023	$	29,085	$	(2,172)
2024 through 2028	$	153,855	$	(13,325	)
2024						2024	$	29,192	$	(2,273)
2025						2025	$	29,231	$	(2,356)
2026 through 2030						2026 through 2030	$	143,696	$	(12,763)

-112-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Assumed health care cost trend rates as of September 30 were:

2018 2017 2016
Rate of Medical Cost Increase for Pre Age 65 Participants 5.59 % (1) 5.67 % (1) 5.75 % (1)
Rate of Medical Cost Increase for Post Age 65 Participants 4.75 % (1) 4.75 % (1) 4.75 % (1)
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits 7.89 % (1) 8.45 % (1) 9.00 % (1)
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement 4.75 % (1) 4.75 % (1) 4.75 % (1)
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy 7.18 % (1) 7.33 % (1) 7.20 % (1)


	2020			2019			2018
Rate of Medical Cost Increase for Pre Age 65 Participants	5.42	%	(1)	5.50	%	(1)	5.59	%	(1)
Rate of Medical Cost Increase for Post Age 65 Participants	4.75	%	(1)	4.75	%	(1)	4.75	%	(1)
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits	6.80	%	(1)	7.35	%	(1)	7.89	%	(1)
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement	4.75	%	(1)	4.75	%	(1)	4.75	%	(1)
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy	6.20	%	(1)	6.84	%	(1)	7.18	%	(1)


~~(1)~~	~~It was assumed that this rate would gradually decline to 4.5% by 2039.~~

(1)It was assumed that this rate would gradually decline to 4.5% by 2039.

The health care cost trend rate assumptions used to calculate the per capita cost of covered medical care benefits have a significant effect on the amounts reported. If the health care cost trend rates were increased by 1% in each year, the other post-retirement benefit obligation as of October 1, ~~2018~~2020 would increase by ~~$51.3~~$61.7 million. This 1% change would also have increased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for ~~2018~~2020 by ~~$2.9~~$2.5 million. If the health care cost trend rates were decreased by 1% in each year, the other post-retirement benefit obligation as of ~~October��~~October 1, ~~2018~~2020 would decrease by ~~$42.8~~$51.5 million. This 1% change would also have decreased the aggregate of the service and interest cost components of net periodic post-retirement benefit cost for ~~2018~~2020 by ~~$2.1~~$1.8 million.

The Company made cash contributions totaling $2.8 million to its VEBA trusts during the year ended September 30, ~~2018.~~2020. In addition, the Company made direct payments of ~~$0.1~~$0.3 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, ~~2018.~~2020. The Company expects that the annual contribution to its VEBA trusts in ~~2019~~2021 will be in the range of $2.5 million to ~~$4.0~~$3.0 million.

Investment Valuation

The Retirement Plan assets and other post-retirement benefit assets are valued under the current fair value framework. See Note FI — Fair Value Measurements for further discussion regarding the definition and levels of fair value hierarchy established by the authoritative guidance.

The inputs or methodologies used for valuing securities are not necessarily an indication of the risk associated with investing in those securities. Below is a listing of the major categories of plan assets held as of September 30, ~~2018~~2020 and ~~2017,~~2019, as well as the associated level within the fair value hierarchy in which the fair value measurements in their entirety fall, based on the lowest level input that is significant to the fair value measurement in its entirety (dollars in thousands):

-113-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	At September 30, 2020
	Total Fair Value		Level 1		Level 2		Level 3		Measured at NAV(7)
Retirement Plan Investments
Domestic Equities(1)	$	188,939	$	118,124	$	0	$	0	$	70,815
International Equities(2)	94,603		0		0		0		94,603
Global Equities(3)	77,736		0		0		0		77,736
Domestic Fixed Income(4)	512,693		2,000		457,381		0		53,312
International Fixed Income(5)	20,201		0		20,201		0		0
Global Fixed Income(6)	79,595		0		0		0		79,595

Real Estate	106,167		0		0		471		105,696
Cash Held in Collective Trust Funds	18,023		0		0		0		18,023
Total Retirement Plan Investments	1,097,957		120,124		477,582		471		499,780
401(h) Investments	(80,511)		(8,809)		(35,021)		(35)		(36,646)
Total Retirement Plan Investments (excluding 401(h) Investments)	$	1,017,446	$	111,315	$	442,561	$	436	$	463,134
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash	(650)
Total Retirement Plan Assets	$	1,016,796

Total Fair
Value Amounts at
September 30, 2018
Level 1 Level 2 Level 3
Measured
at NAV(7)
Retirement Plan Investments
Domestic Equities(1) $ 223,300
$ 139,885
$ —
$ —
$ 83,415
International Equities(2) 100,832
—
—
—
100,832
Global Equities(3) 85,942
—
—
—
85,942
Domestic Fixed Income(4) 434,392
1,640
382,348
—
50,404
International Fixed Income(5) 416
416
—
—
—
Global Fixed Income(6) 72,382
—
—
—
72,382
Real Estate 53,878
—
—
3,194
50,684
Cash Held in Collective Trust Funds 26,191
—
—
—
26,191
Total Retirement Plan Investments 997,333
141,941
382,348
3,194
469,850
401(h) Investments (67,817 ) (9,695 ) (26,114 ) (218 ) (31,790 )
Total Retirement Plan Investments (excluding 401(h) Investments) $ 929,516
$ 132,246
$ 356,234
$ 2,976
$ 438,060
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (5,010 )
Total Retirement Plan Assets $ 924,506

Total Fair
Value
Amounts at
September 30, 2017
Level 1 Level 2 Level 3
Measured
at NAV(7)
Retirement Plan Investments
Domestic Equities(1) $ 290,716
$ 209,421
$ —
$ —
$ 81,295
International Equities(2) 123,069
—
—
—
123,069
Global Equities(3) 121,008
—
—
—
121,008
Domestic Fixed Income(4) 348,501
1,664
346,837
—
—
International Fixed Income(5) 422
422
—
—
—
Global Fixed Income(6) 75,428
—
—
—
75,428
Real Estate 3,391
—
—
3,391
—
Cash Held in Collective Trust Funds 26,058
—
—
—
26,058
Total Retirement Plan Investments 988,593
211,507
346,837
3,391
426,858
401(h) Investments (64,728 ) (14,026 ) (23,001 ) (225 ) (27,476 )
Total Retirement Plan Investments (excluding 401(h) Investments) $ 923,865
$ 197,481
$ 323,836
$ 3,166
$ 399,382
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash (13,146 )
Total Retirement Plan Assets $ 910,719


	At September 30, 2019
	Total Fair Value		Level 1		Level 2		Level 3		Measured at NAV(7)
Retirement Plan Investments
Domestic Equities(1)	$	175,812	$	114,324	$	0	$	0	$	61,488
International Equities(2)	81,631		0		0		0		81,631
Global Equities(3)	70,095		0		0		0		70,095
Domestic Fixed Income(4)	493,839		1,784		439,255		0		52,800
International Fixed Income(5)	17,744		0		17,744		0		0
Global Fixed Income(6)	75,329		0		0		0		75,329

Real Estate	107,764		0		0		3,154		104,610
Cash Held in Collective Trust Funds	18,310		0		0		0		18,310
Total Retirement Plan Investments	1,040,524		116,108		456,999		3,154		464,263
401(h) Investments	(73,688)		(8,205)		(32,295)		(223)		(32,965)
Total Retirement Plan Investments (excluding 401(h) Investments)	$	966,836	$	107,903	$	424,704	$	2,931	$	431,298
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash	1,613
Total Retirement Plan Assets	$	968,449


~~(1)~~	~~Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds.~~


~~(2)~~	~~International Equities are comprised of collective trust funds.~~


~~(3)~~	~~Global Equities are comprised of collective trust funds.~~


~~(4)~~	~~Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds.~~


~~(5)~~	~~International Fixed Income securities are comprised mostly of an exchange traded fund.~~

(1)Domestic Equities include mostly collective trust funds, common stock, and exchange traded funds.

(2)International Equities are comprised of collective trust funds.

(3)Global Equities are comprised of collective trust funds.

(4)Domestic Fixed Income securities include mostly collective trust funds, corporate/government bonds and mortgages, and exchange traded funds.

(5)International Fixed Income securities are comprised mostly of corporate/government bonds.

(6)Global Fixed Income securities are comprised of a collective trust fund.

(7)Reflects the authoritative guidance related to investments measured at net asset value (NAV).

-114-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	At September 30, 2020
	Total Fair Value		Level 1		Level 2		Level 3		Measured at NAV(1)
Other Post-Retirement Benefit Assets held in VEBA Trusts
Collective Trust Funds — Global Equities	$	153,923	$	0	$	0	$	0	$	153,923


Exchange Traded Funds — Fixed Income	301,290		301,290		0		0		—

Cash Held in Collective Trust Funds	13,841		0		0		0		13,841
Total VEBA Trust Investments	469,054		301,290		0		0		167,764
401(h) Investments	80,511		8,809		35,021		35		36,646
Total Investments (including 401(h) Investments)	$	549,565	$	310,099	$	35,021	$	35	$	204,410
Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative)	(1,680)
Total Other Post-Retirement Benefit Assets	$	547,885


	At September 30, 2019
	Total Fair Value		Level 1		Level 2		Level 3		Measured at NAV(1)
Other Post-Retirement Benefit Assets held in VEBA Trusts


Collective Trust Funds — Global Equities	$	167,966	$	0	$	0	$	0	$	167,966
Exchange Traded Funds — Fixed Income	275,296		275,296		0		0		0

Cash Held in Collective Trust Funds	8,229		0		0		0		8,229
Total VEBA Trust Investments	451,491		275,296		0		0		176,195
401(h) Investments	73,688		8,205		32,295		223		32,965
Total Investments (including 401(h) Investments)	$	525,179	$	283,501	$	32,295	$	223	$	209,160
Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative)	(1,052)
Total Other Post-Retirement Benefit Assets	$	524,127


~~(6)~~			~~Global Fixed Income securities are comprised of a collective trust fund.~~


~~(7)~~	~~Reflects the authoritative guidance related to investments measured at the net asset value (NAV) practical expedient.~~

Total Fair
Value
Amounts at
September 30, 2018
Level 1 Level 2 Level 3
Measured
at NAV(1)
Other Post-Retirement Benefit Assets held in VEBA Trusts
Collective Trust Funds — Domestic Equities $ 125,295
$ —
$ —
$ —
$ 125,295
Collective Trust Funds — International Equities 47,245
—
—
—
47,245
Exchange Traded Funds — Fixed Income 265,667
265,667
—
—
—
Cash Held in Collective Trust Funds 7,894
—
—
—
7,894
Total VEBA Trust Investments 446,101
265,667
—
—
180,434
401(h) Investments 67,817
9,695
26,114
218
31,790
Total Investments (including 401(h) Investments) $ 513,918
$ 275,362
$ 26,114
$ 218
$ 212,224
Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) (118 )
Total Other Post-Retirement Benefit Assets $ 513,800

Total Fair
Value
Amounts at
September 30, 2017
Level 1 Level 2 Level 3
Measured
at NAV(1)
Other Post-Retirement Benefit Assets held in VEBA Trusts
Collective Trust Funds — Domestic Equities $ 130,864
$ —
$ —
$ —
$ 130,864
Collective Trust Funds — International Equities 52,063
—
—
—
52,063
Exchange Traded Funds — Fixed Income 256,099
256,099
—
—
—
Cash Held in Collective Trust Funds 9,569
—
—
—
9,569
Total VEBA Trust Investments 448,595
256,099
—
—
192,496
401(h) Investments 64,728
14,026
23,001
225
27,476
Total Investments (including 401(h) Investments) $ 513,323
$ 270,125
$ 23,001
$ 225
$ 219,972
Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative) 694

Total Other Post-Retirement Benefit Assets $ 514,017


~~(1)~~	~~Reflects the authoritative guidance related to investments measured at the net asset value (NAV) practical expedient.~~

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)~~

(1)Reflects the authoritative guidance related to investments measured at net asset value (NAV).

The fair values disclosed in the above tables may not be indicative of net realizable value or reflective of future fair values. Furthermore, although the Company believes its valuation methods are appropriate and consistent with other market participants, the use of different methodologies or assumptions to determine the fair value of certain financial instruments could result in a different fair value measurement at the reporting date.

The following tables provide a reconciliation of the beginning and ending balances of the Retirement Plan and other post-retirement benefit assets measured at fair value on a recurring basis where the determination of fair value includes significant unobservable inputs (Level 3). For the years ended September 30, ~~2018~~2020 and September 30, ~~2017,~~2019, there were no0 transfers from Level 1 to Level 2. In addition, as shown in the following tables, there were no0 transfers in or out of Level 3.

-115-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Retirement Plan Level 3 Assets
(Thousands)

Real
Estate

Excluding
401(h)
Investments
Total

Balance at September 30, 2016 $ 2,970
$ (188 ) $ 2,782
Unrealized Gains/(Losses) 421
(37 ) 384
Balance at September 30, 2017 3,391

(225 )
3,166
Unrealized Gains/(Losses) 188
(19 ) 169
Sales (385 ) 26
(359 )
Balance at September 30, 2018 $ 3,194
$ (218 ) $ 2,976


	Retirement Plan Level 3 Assets (Thousands)
	Real Estate		Excluding 401(h) Investments		Total


Balance at September 30, 2018							$	3,194	$	(218)	$	2,976

Unrealized Gains/(Losses)	(37)		(5)		(42)

Sales	(3)		0		(3)
Balance at September 30, 2019	3,154		(223)		2,931

Unrealized Gains/(Losses)	(2,683)		188		(2,495)

Sales	0		0		0
Balance at September 30, 2020	$	471	$	(35)	$	436

Other Post-Retirement Benefit Level 3 Assets
(Thousands)

401(h)
Investments

Balance at September 30, 2016 $ 188

Unrealized Gains/(Losses) 37

Balance at September 30, 2017 225

Unrealized Gains/(Losses) 19

Sales (26 )
Balance at September 30, 2018 $ 218


	Other Post-Retirement Benefit Level 3 Assets (Thousands)
	401(h) Investments

Balance at September 30, 2018	$	218

Unrealized Gains/(Losses)	5

Sales	0
Balance at September 30, 2019	223

Unrealized Gains/(Losses)	(188)
Sales	0
Balance at September 30, 2020	$	35

The Company’s assumption regarding the expected long-term rate of return on plan assets is ~~6.75%~~6.00% (Retirement Plan) and ~~6.00%~~5.40% (other post-retirement benefits), effective for fiscal ~~2019.~~2021. The return assumption reflects the anticipated long-term rate of return on the plan’s current and future assets. The Company utilizes projected capital market conditions and the plan’s target asset class and investment manager allocations to set the assumption regarding the expected return on plan assets.

The long-term investment objective of the Retirement Plan trust, the VEBA trusts and the 401(h) accounts is to achieve the target total return in accordance with the Company’s risk tolerance. Assets are diversified utilizing a mix of equities, fixed income and other securities (including real estate). The target allocation for the Retirement Plan and the VEBA trusts (including 401(h) accounts) is 30-50% equity securities, 50-70% fixed income securities (including return-seeking investments) and 0-15% other (including return-seeking investments). Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. The assets of the Retirement Plan trusts, VEBA trusts and the 401(h) accounts have no significant concentrations of risk in any one country (other than the United States), industry or entity.

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)~~

Investment managers are retained to manage separate pools of assets. Comparative market and peer group performance of individual managers and the total fund are monitored on a regular basis, and reviewed by the Company’s Retirement Committee on at least a quarterly basis.

The Company determines the service and interest cost components of net periodic benefit cost using the spot rate approach, which uses individual spot rates along the yield curve that correspond to the timing of each benefit payment in order to determine the discount rate. The individual spot rates along the yield curve are determined by an above mean methodology in that the coupon interest rates that are in the lower 50th percentile

-116-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

are excluded based on the assumption that the Company would not utilize more expensive (i.e. lower yield) instruments to settle its liabilities.

Note IL — Commitments and Contingencies

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 to comply with regulatory requirements.

It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs. At September 30, ~~2018,~~2020, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately ~~$7.6~~$6.4 million, which includes a ~~$4.1~~$3.4 million estimated minimum liability to remediate a former manufactured gas plant site located in New York. In March 2018, the NYDEC issued a Record of Decision for this New York site and the minimum liability reflects the remedy selected in the Record of Decision. The Company's liability for such clean-up costs has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at September 30, ~~2018.~~2020. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 42 years and the Company is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could ~~could~~ have an adverse financial impact on the Company.

Northern Access Project

On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access project described herein. ~~On April 7, 2017,~~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 onin January ~~27,~~of 2017). ~~On April 21, 2017, Supply Corporation and Empire filed a Petition for Review in the~~The United States Court of Appeals for the Second Circuit (the “Second Circuit Court of Appeals”) held in the Company’s favor in its appeal of this decision, vacating the NYDEC denial and remanding to the NYDEC. The NYDEC subsequently issued a second denial, which the Company has appealed to the Second Circuit Court of Appeals. The court has held this appeal in abeyance pending the outcome of the ~~NYDEC's Notice~~FERC waiver appeal, described below. While the Company’s initial appeal was pending before the Second Circuit Court of Denial with respect to National Fuel's application for the Water Quality Certification, and on May 11, 2017, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. On August 6, 2018,Appeals, the 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. ~~Rehearing~~FERC denied rehearing requests associated with its Order and FERC's decisions have been ~~filed at FERC.~~appealed and are pending in a separate action before the Second Circuit Court of Appeals. In ~~light of~~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 ~~pending legal actions and the need to complete necessary project development activities in advance of construction, the target in-service date for the project is expected~~permits to be ~~no earlier than~~preempted. The Company remains committed to the first half of fiscal 2022. As a result of the decision of the NYDEC, Supply Corporation and Empire evaluated the capitalized project costs for impairment as of September 30, 2018 and determined that an impairment charge was not required. The evaluation considered probability weighted scenarios of undiscounted future net cash flows, including a scenario assuming construction of the pipeline, as well as a scenario where the project does not proceed. Further developments or indicators of an unfavorable resolution could result in the impairment of a significant portion of the project costs, which totaled $76.2 million at September 30, 2018. The project costs are included within Property, Plant and Equipment and Deferred Charges on the Consolidated Balance Sheet.

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)~~

project.

Other

The Company, in its Utility ~~segment, Energy Marketing~~ 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. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: ~~$297.9 million in 2019, $102.9 million in 2020, $86.6~~$181.9 million in 2021, ~~$152.5~~$111.3 million in 2022, ~~$162.8~~$120.9 million in 2023, $129.3 million in 2024, $146.3 million in 2025 and ~~$1,606.0~~$1,128.2 million thereafter. Gas prices within the gas purchase contracts are variable based on NYMEX prices adjusted for basis. In the Utility segment, these costs are subject to state commission review, and are being recovered in customer rates. Management believes that, to the extent any stranded pipeline costs are generated

-117-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers.

The Company has entered into leases for the use of compressors, drilling rigs, buildings and other items. These leases are accounted for as operating leases. The future lease commitments during the next five years and thereafter are as follows: $18.6 million in 2019, $4.6 million in 2020, $4.0 million in 2021, $3.2 million in 2022, $2.7 million in 2023 and $12.4 million thereafter.

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. As of September 30, ~~2018,~~2020, the future contractual commitments related to the system modernization and expansion projects are ~~$105.1 million in 2019, $6.8 million in 2020, $6.1~~$98.3 million in 2021, ~~$5.1~~$6.4 million in 2022, $3.4 million in 2023, $3.3 million in 2024, $3.3 million in 2025 and ~~$13.3~~$10.3 million thereafter.

The Company, in its Exploration and Production segment, has entered into contractual obligations ~~associated with~~to support its development activities and operations in Pennsylvania and California, including hydraulic fracturing and ~~fuel.~~other well completion services, well tending services, well workover activities, tubing and casing, production equipment, contracts for drilling rig services and fuel purchases for steam generation. The future contractual commitments are ~~$86.2~~$109.3 million in ~~2019 and $24.8~~2021, $15.2 million in ~~2020.~~2022 and $0.7 million in 2023. There are no contractual commitments extending beyond ~~2020.~~2023.

The Company is involved in other litigation arising in the normal course of business. In addition to the regulatory matters discussed in Note CF — Regulatory Matters, the Company is involved in other regulatory matters arising in the normal course of business. These other litigation and regulatory matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and 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 other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.

Note JM — Business Segment Information

The Company reports financial results for ~~five~~4 segments: Exploration and Production, Pipeline and Storage, Gathering ~~Utility~~ and ~~Energy Marketing.~~Utility. The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors.

The Exploration and Production segment, through Seneca, is engaged in exploration for and development of natural gas and oil reserves in ~~California and~~ the Appalachian region of the United ~~States.~~States and in California.

The Pipeline and Storage segment operations are regulated by the FERC for both Supply Corporation and Empire. Supply Corporation transports and stores natural gas for utilities (including Distribution Corporation), natural gas marketers, ~~(including NFR),~~ exploration and production companies (including Seneca) and pipeline companies in the northeastern United States markets. Empire transports and stores natural gas for major industrial companies, utilities (including Distribution Corporation) and power producers in New York State. Empire also transports natural gas for natural gas marketers ~~along with~~and exploration and production companies (including Seneca) from natural gas producing areas in Pennsylvania to markets in New York and to interstate pipeline delivery points ~~for~~with access to additional markets in the northeastern United States and Canada.

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)~~

The Gathering segment is comprised of Midstream Company’s operations. Midstream Company builds, owns and operates natural gas processing and pipeline gathering facilities in the Appalachian region and currently provides gathering services to Seneca.

The Utility segment operations are regulated by the NYPSC and the PaPUC and are carried out by Distribution Corporation. Distribution Corporation sells natural gas to retail customers and provides natural gas transportation services in western New York and northwestern Pennsylvania.

The Energy Marketing segment is comprised of NFR’s operations. NFR markets natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania, offering competitively priced natural gas for its customers.

The data presented in the tables below reflects financial information for the segments and reconciliations to consolidated amounts. The accounting policies of the segments are the same as those described in Note A —

-118-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Summary of Significant Accounting Policies. Sales of products or services between segments are billed at regulated rates or at market rates, as applicable. The Company evaluates segment performance based on income before discontinued operations ~~extraordinary items and cumulative effects of changes in accounting~~ (when applicable). When ~~these items are~~this is not applicable, the Company evaluates performance based on net income.


	Year Ended September 30, 2020
	Exploration and Production		Pipeline and Storage		Gathering		Utility		Total Reportable Segments		All Other		Corporate and Intersegment Eliminations		Total Consolidated
	(Thousands)
Revenue from External Customers(1)	$	607,453	$	205,998	$	72	$	642,855	$	1,456,378	$	89,435	$	478	$	1,546,291
Intersegment Revenues	$	0	$	103,606	$	142,821	$	9,443	$	255,870	$	836	$	(256,706)	$	0
Interest Income	$	698	$	1,475	$	545	$	2,262	$	4,980	$	860	$	(833)	$	5,007
Interest Expense	$	58,098	$	32,731	$	10,877	$	22,150	$	123,856	$	66	$	(6,845)	$	117,077
Depreciation, Depletion and Amortization	$	172,124	$	53,951	$	22,440	$	55,248	$	303,763	$	1,716	$	679	$	306,158
Income Tax Expense (Benefit)	$	(41,472)	$	28,613	$	18,191	$	13,274	$	18,606	$	210	$	(77)	$	18,739
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties	$	449,438	$	0	$	0	$	0	$	449,438	$	0	$	0	$	449,438
Segment Profit: Net Income (Loss)	$	(326,904)	$	78,860	$	68,631	$	57,366	$	(122,047)	$	(269)	$	(1,456)	$	(123,772)
Expenditures for Additions to Long-Lived Assets	$	670,455	$	166,652	$	297,806	$	94,273	$	1,229,186	$	39	$	(608)	$	1,228,617
	At September 30, 2020
	(Thousands)
Segment Assets	$	1,979,028	$	2,204,971	$	945,199	$	2,067,852	$	7,197,050	$	113,571	$	(345,686)	$	6,964,935


	Year Ended September 30, 2018																									Year Ended September 30, 2019
	Exploration and Production			Pipeline and Storage		Gathering			Utility		Energy Marketing		Total Reportable Segments			All Other			Corporate and Intersegment Eliminations			Total Consolidated				Exploration and Production		Pipeline and Storage		Gathering		Utility		Total Reportable Segments		All Other		Corporate and Intersegment Elimination		Total Consolidated
	(Thousands)																									(Thousands)
Revenue from External Customers(1)	$	564,547		$	210,345	$	41		$	674,726	$	137,748	$	1,587,407		$	4,601		$	660		$	1,592,668		Revenue from External Customers(1)	$	632,740	$	195,808	$	11	$	715,813	$	1,544,372	$	148,582	$	378	$	1,693,332
Intersegment Revenues	$	—		$	89,981	$	107,856		$	12,800	$	826	$	211,463		$	—		$	(211,463	)	$	—		Intersegment Revenues	$	0	$	92,475	$	127,064	$	11,629	$	231,168	$	1,127	$	(232,295)	$	0
Interest Income	$	1,479		$	2,748	$	1,106		$	1,591	$	685	$	7,609		$	388		$	(1,231	)	$	6,766		Interest Income	$	1,107	$	2,982	$	546	$	1,809	$	6,444	$	1,291	$	(1,670)	$	6,065
Interest Expense	$	54,288		$	31,383	$	9,560		$	26,753	$	22	$	122,006		$	—		$	(7,484	)	$	114,522		Interest Expense	$	54,777	$	29,142	$	9,406	$	23,443	$	116,768	$	21	$	(10,033)	$	106,756
Depreciation, Depletion and Amortization	$	124,274		$	43,463	$	17,313		$	53,253	$	275	$	238,578		$	1,627		$	756		$	240,961		Depreciation, Depletion and Amortization	$	154,784	$	44,947	$	20,038	$	53,832	$	273,601	$	1,291	$	768	$	275,660
Income Tax Expense (Benefit)	$	(41,962	)	$	17,806	$	(17,677	)	$	15,258	$	632	$	(25,943	)	$	1,493		$	16,956		$	(7,494	)	Income Tax Expense (Benefit)	$	32,978	$	23,238	$	20,895	$	13,967	$	91,078	$	(955)	$	(4,902)	$	85,221

Segment Profit: Net Income (Loss)	$	180,632		$	97,246	$	83,519		$	51,217	$	373	$	412,987		$	(112	)	$	(21,354	)	$	391,521		Segment Profit: Net Income (Loss)	$	111,807	$	74,011	$	58,413	$	60,871	$	305,102	$	(1,811)	$	999	$	304,290
Expenditures for Additions to Long-Lived Assets	$	380,677		$	92,832	$	61,728		$	85,648	$	40	$	620,925		$	1		$	(20,324	)	$	600,602		Expenditures for Additions to Long-Lived Assets	$	491,889	$	143,005	$	49,650	$	95,847	$	780,391	$	128	$	727	$	781,246
	At September 30, 2018																									At September 30, 2019
	(Thousands)																									(Thousands)
Segment Assets	$	1,568,563		$	1,848,180	$	533,608		$	1,921,971	$	50,971	$	5,923,293		$	78,109		$	35,084		$	6,036,486		Segment Assets	$	1,972,776	$	1,893,514	$	547,995	$	1,991,338	$	6,405,623	$	122,241	$	(65,707)	$	6,462,157

-119-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Year Ended September 30, 2017

Exploration
and
Production

Pipeline
and
Storage
Gathering Utility
Energy
Marketing

Total
Reportable
Segments

All
Other

Corporate
and
Intersegment
Elimination

Total
Consolidated
(Thousands)
Revenue from External Customers(1) $ 614,599
$ 206,615
$ 115
$ 626,899
$ 128,586
$ 1,576,814
$ 2,173
$ 894
$ 1,579,881
Intersegment Revenues $ —
$ 87,810
$ 107,566
$ 13,072
$ 794
$ 209,242
$ —
$ (209,242 ) $ —
Interest Income $ 707
$ 1,467
$ 994
$ 1,051
$ 571
$ 4,790
$ 213
$ (890 ) $ 4,113
Interest Expense $ 53,702
$ 33,717
$ 9,142
$ 28,492
$ 47
$ 125,100
$ —
$ (5,263 ) $ 119,837
Depreciation, Depletion and Amortization $ 112,565
$ 41,196
$ 16,162
$ 52,582
$ 279
$ 222,784
$ 661
$ 750
$ 224,195
Income Tax Expense (Benefit) $ 66,093
$ 40,947
$ 29,694
$ 24,894
$ 891
$ 162,519
$ (247 ) $ (1,590 ) $ 160,682
Segment Profit: Net Income (Loss) $ 129,326
$ 68,446
$ 40,377
$ 46,935
$ 1,509
$ 286,593
$ (342 ) $ (2,769 ) $ 283,482
Expenditures for Additions to Long-Lived Assets $ 253,057
$ 95,336
$ 32,645
$ 80,867
$ 36
$ 461,941
$ 39
$ 137
$ 462,117
At September 30, 2017
(Thousands)
Segment Assets $ 1,407,152
$ 1,929,788
$ 580,051
$ 2,013,123
$ 60,937
$ 5,991,051
$ 76,861
$ 35,408
$ 6,103,320


	Year Ended September 30, 2016																							Year Ended September 30, 2018
	Exploration and Production			Pipeline and Storage		Gathering		Utility		Energy Marketing		Total Reportable Segments			All Other		Corporate and Intersegment Eliminations			Total Consolidated				Exploration and Production		Pipeline and Storage		Gathering		Utility		Total Reportable Segments		All Other		Corporate and Intersegment Eliminations		Total Consolidated
	(Thousands)																							(Thousands)
Revenue from External Customers(1)	$	607,113		$	215,674	$	374	$	531,024	$	93,578	$	1,447,763		$	3,753	$	900		$	1,452,416		Revenue from External Customers(1)	$	564,547	$	210,345	$	41	$	674,726	$	1,449,659	$	142,349	$	660	$	1,592,668
Intersegment Revenues	$	—		$	90,755	$	89,073	$	13,123	$	884	$	193,835		$	—	$	(193,835	)	$	—		Intersegment Revenues	$	0	$	89,981	$	107,856	$	12,800	$	210,637	$	826	$	(211,463)	$	0
Interest Income	$	858		$	770	$	297	$	1,737	$	422	$	4,084		$	117	$	34		$	4,235		Interest Income	$	1,479	$	2,748	$	1,106	$	1,591	$	6,924	$	1,073	$	(1,231)	$	6,766
Interest Expense	$	55,434		$	33,327	$	8,872	$	27,582	$	49	$	125,264		$	—	$	(4,220	)	$	121,044		Interest Expense	$	54,288	$	31,383	$	9,560	$	26,753	$	121,984	$	22	$	(7,484)	$	114,522
Depreciation, Depletion and Amortization	$	139,963		$	43,273	$	15,282	$	48,618	$	278	$	247,414		$	1,260	$	743		$	249,417		Depreciation, Depletion and Amortization	$	124,274	$	43,463	$	17,313	$	53,253	$	238,303	$	1,902	$	756	$	240,961
Income Tax Expense (Benefit)	$	(334,029	)	$	50,241	$	24,334	$	25,602	$	2,460	$	(231,392	)	$	561	$	(1,718	)	$	(232,549	)	Income Tax Expense (Benefit)	$	(41,962)	$	17,806	$	(17,677)	$	15,258	$	(26,575)	$	2,125	$	16,956	$	(7,494)
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties	$	948,307		$	—	$	—	$	—	$	—	$	948,307		$	—	$	—		$	948,307

Segment Profit: Net Income (Loss)	$	(452,842	)	$	76,610	$	30,499	$	50,960	$	4,348	$	(290,425	)	$	778	$	(1,311	)	$	(290,958	)	Segment Profit: Net Income (Loss)	$	180,632	$	97,246	$	83,519	$	51,217	$	412,614	$	261	$	(21,354)	$	391,521
Expenditures for Additions to Long-Lived Assets	$	256,104		$	114,250	$	54,293	$	98,007	$	34	$	522,688		$	37	$	326		$	523,051		Expenditures for Additions to Long-Lived Assets	$	380,677	$	92,832	$	61,728	$	85,648	$	620,885	$	41	$	(20,324)	$	600,602
	At September 30, 2016																							At September 30, 2018
	(Thousands)																							(Thousands)
Segment Assets	$	1,323,081		$	1,680,734	$	534,259	$	2,021,514	$	63,392	$	5,622,980		$	77,138	$	(63,731	)	$	5,636,387		Segment Assets	$	1,568,563	$	1,848,180	$	533,608	$	1,921,971	$	5,872,322	$	129,080	$	35,084	$	6,036,486


~~(1)~~	~~All Revenue from External Customers originated in the United States.~~

(1)All Revenue from External Customers originated in the United States.

~~NATIONAL FUEL GAS COMPANY~~


Geographic Information	At September 30
	2020		2019		2018
	(Thousands)
Long-Lived Assets:
United States	$	6,597,313	$	6,099,534	$	5,491,895

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)~~

Geographic Information At September 30
2018 2017 2016
(Thousands)
Long-Lived Assets:
United States $ 5,491,895
$ 5,285,040
$ 5,223,356

Note KN — Quarterly Financial Data (unaudited)

In the opinion of management, the following quarterly information includes all adjustments necessary for a fair statement of the results of operations for such periods. Per common share amounts are calculated using the weighted average number of shares outstanding during each quarter. The total of all quarters may differ from the per common share amounts shown on the Consolidated Statements of Income. Those per common share amounts are based on the weighted average number of shares outstanding for the entire fiscal year. Because of the seasonal nature of the Company’s heating business, there are substantial variations in operations reported on a quarterly basis.

-120-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Quarter Ended
Operating
Revenues

Operating
Income

Net Income
Available for
Common Stock

Earnings per
Common Share

Basic Diluted
(Thousands, except per common share amounts)
2018
9/30/2018 $ 289,196
$ 80,629
$ 37,995
(1) $ 0.44
$ 0.44
6/30/2018 $ 342,912
$ 107,760
$ 63,025
$ 0.73
$ 0.73
3/31/2018 $ 540,905
$ 156,702
$ 91,847
(2) $ 1.07
$ 1.06
12/31/2017 $ 419,655
$ 141,995
$ 198,654
(3) $ 2.32
$ 2.30
2017
9/30/2017 $ 286,937
$ 87,395
$ 45,577
$ 0.53
$ 0.53
6/30/2017 $ 348,369
$ 123,354
$ 59,714
$ 0.70
$ 0.69
3/31/2017 $ 522,075
$ 169,957
$ 89,283
$ 1.05
$ 1.04
12/31/2016 $ 422,500
$ 172,139
$ 88,908
$ 1.04
$ 1.04


Quarter Ended	Operating Revenues		Operating Income (Loss)		Net Income (Loss) Available for Common Stock			Earnings (Loss) per Common Share

								Basic		Diluted
	(Thousands, except per common share amounts)
2020
9/30/2020	$	287,989	$	(173,979)	$	(145,545)	(1)	$	(1.60)	$	(1.60)
6/30/2020	$	323,019	$	80,397	$	41,250	(2)	$	0.47	$	0.47
3/31/2020	$	491,095	$	(24,580)	$	(106,068)	(3)	$	(1.23)	$	(1.23)
12/31/2019	$	444,188	$	148,020	$	86,591		$	1.00	$	1.00
2019
9/30/2019	$	293,341	$	83,940	$	47,282		$	0.55	$	0.54
6/30/2019	$	357,200	$	112,827	$	63,753		$	0.74	$	0.73
3/31/2019	$	552,544	$	153,359	$	90,595		$	1.05	$	1.04
12/31/2018	$	490,247	$	161,683	$	102,660	(4)	$	1.19	$	1.18


~~(1)~~	~~Includes a $3.5 million increase to income tax expense associated with the remeasurement of accumulated~~

(1)Includes a non-cash $253.4 million impairment charge ($183.7 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.

(2)Includes a non-cash $18.2 million impairment charge ($13.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties.

(3)Includes a non-cash $177.8 million impairment charge ($129.3 million after tax) associated with the Exploration and Production segment's oil and gas producing properties and a $56.8 million valuation allowance recorded against certain deferred tax assets.

(4)Includes a $5.0 million reduction to income tax expense associated with the remeasurement of accumulated deferred income taxes in accordance with the 2017 Tax Reform Act.


~~(2)~~	~~Includes a $4.0 million increase to income tax expense associated with the remeasurement of accumulated~~

~~deferred income taxes in accordance with the 2017 Tax Reform Act.~~


~~(3)~~	~~Includes a $111.0 million reduction to income tax expense associated with the remeasurement of accumulated~~

~~deferred income taxes in accordance with the 2017 Tax Reform Act.~~

Note LO — Supplementary Information for Oil and Gas Producing Activities (unaudited, except for Capitalized Costs Relating to Oil and Gas Producing Activities)

The Company follows authoritative guidance related to oil and gas exploration and production activities that aligns the reserve estimation and disclosure requirements with the requirements of the SEC Modernization of Oil and Gas Reporting rule, which the Company also follows. The SEC rules require companies to value their year-end reserves using 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.

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)~~

The following supplementary information is presented in accordance with the authoritative guidance regarding disclosures about oil and gas producing activities and related SEC accounting rules. All monetary amounts are expressed in U.S. dollars.

-121-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Capitalized Costs Relating to Oil and Gas Producing Activities

At September 30
2018 2017
(Thousands)
Proved Properties(1) $ 5,114,753
$ 4,832,301
Unproved Properties 62,234
80,932
5,176,987
4,913,233
Less — Accumulated Depreciation, Depletion and Amortization 3,862,687
3,765,710
$ 1,314,300
$ 1,147,523


	At September 30
	2020		2019
	(Thousands)
Proved Properties(1)	$	6,238,830	$	5,623,623
Unproved Properties	148,075		53,498
	6,386,905		5,677,121
Less — Accumulated Depreciation, Depletion and Amortization	4,628,765		4,012,568
	$	1,758,140	$	1,664,553


~~(1)~~	~~Includes asset retirement costs of $44.3 million and $54.4 million at September 30, 2018 and 2017, respectively.~~

(1)Includes asset retirement costs of $132.6 million and $70.5 million at September 30, 2020 and 2019, respectively.

Costs related to unproved properties are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized. Although the timing of the ultimate evaluation or disposition of the unproved properties cannot be determined, the Company expects the majority of its acquisition costs associated with unproved properties to be transferred into the amortization base by ~~2023.~~2025. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by ~~2020.~~2023. Following is a summary of costs excluded from amortization at September 30, ~~2018:~~2020:


	Total as of September 30, 2020		Year Costs Incurred
			2020		2019		2018		Prior
	(Thousands)
Acquisition Costs	$	64,218	$	39,953	$	0	$	0	$	24,265
Development Costs	75,138		54,761		17,326		403		2,648
Exploration Costs	7,606		0		0		0		7,606
Capitalized Interest	1,113		969		41		0		103
	$	148,075	$	95,683	$	17,367	$	403	$	34,622

-122-

Total as of
September 30,
2018
Year Costs Incurred
2018 2017 2016 Prior
(Thousands)
Acquisition Costs $ 39,681
$ —
$ —
$ —
$ 39,681
Development Costs 14,824
11,115
236
2,886
587
Exploration Costs 7,606
—
32
7,574
—
Capitalized Interest 123
20
—
103
—
$ 62,234
$ 11,135
$ 268
$ 10,563
$ 40,268

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Costs Incurred in Oil and Gas Property Acquisition, Exploration and Development Activities

Year Ended September 30
2018 2017 2016
(Thousands)
United States
Property Acquisition Costs:
Proved $ 1,544
$ 8,908
$ 1,342
Unproved 4,286
262
2,165
Exploration Costs(1) 29,365
40,975
27,561
Development Costs(2) 332,496
200,639
219,386
Asset Retirement Costs (10,107 ) (9,175 ) (49,653 )
$ 357,584
$ 241,609
$ 200,801


	Year Ended September 30
	2020		2019		2018
	(Thousands)
United States
Property Acquisition Costs:
Proved	$	245,976	$	3,136	$	1,544
Unproved	42,922		3,679		4,286
Exploration Costs	3,891		2,060		29,365
Development Costs(1)	355,742		468,498		332,496
Asset Retirement Costs	62,080		26,192		(10,107)
	$	710,611	$	503,565	$	357,584


~~(1)~~	~~Amounts for 2018, 2017 and 2016 include capitalized interest of zero, $0.3 million and $0.3 million, respectively.~~


~~(2)~~	~~Amounts for 2018, 2017 and 2016 include capitalized interest of $0.3 million, $0.2 million and $0.2 million, respectively.~~

(1)Amounts for 2020, 2019 and 2018 include capitalized interest of $1.0 million, $0.2 million and $0.3 million, respectively.

For the years ended September 30, ~~2018, 2017~~2020, 2019 and ~~2016,~~2018, the Company spent ~~$182.3~~$219.9 million, ~~$101.1~~$246.0 million and ~~$92.8~~$182.3 million, respectively, developing proved undeveloped reserves.

Results of Operations for Producing Activities

Year Ended September 30
2018 2017 2016
United States (Thousands, except per Mcfe amounts)
Operating Revenues:
Natural Gas (includes transfers to operations of $2,134, $2,357 and $1,765, respectively)(1) $ 390,642
$ 399,975
$ 282,619
Oil, Condensate and Other Liquids 168,254
126,517
103,533
Total Operating Revenues(2) 558,896
526,492
386,152
Production/Lifting Costs 162,721
165,991
153,914
Franchise/Ad Valorem Taxes 14,355
15,372
13,794
Purchased Emission Allowance Expense 1,883
1,391
700
Accretion Expense 4,266
4,896
6,663
Depreciation, Depletion and Amortization ($0.67, $0.63 and $0.85 per Mcfe of production, respectively) 119,946
108,471
136,579
Impairment of Oil and Gas Producing Properties —
—
948,307
Income Tax Expense (Benefit) 72,723
86,657
(368,940 )
Results of Operations for Producing Activities (excluding corporate overheads and interest charges) $ 183,002
$ 143,714
$ (504,865 )


	Year Ended September 30
	2020		2019		2018
United States	(Thousands, except per Mcfe amounts)
Operating Revenues:
Gas (includes transfers to operations of 1,921, 2,532 and 2,134, respectively)(1)	$	402,447	$	481,048	$	390,642
Oil, Condensate and Other Liquids	107,844		149,078		168,254
Total Operating Revenues(2)	510,291		630,126		558,896
Production/Lifting Costs	203,670		186,626		162,721
Franchise/Ad Valorem Taxes	15,582		17,673		14,355
Purchased Emission Allowance Expense	2,930		2,527		1,883
Accretion Expense	5,237		3,723		4,266
Depreciation, Depletion and Amortization ($0.69, $0.71 and $0.67 per Mcfe of production, respectively)	166,759		149,881		119,946
Impairment of Oil and Gas Producing Properties	449,438		0		0
Income Tax Expense	(92,820)		64,652		72,723
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)	$	(240,505)	$	205,044	$	183,002


~~(1)~~	~~There were no revenues from sales to affiliates for all years presented.~~


~~(2)~~	~~Exclusive of hedging gains and losses. See further discussion in Note G — Financial Instruments.~~

(1)There were 0 revenues from sales to affiliates for all years presented.

(2)Exclusive of hedging gains and losses. See further discussion in Note J — Financial Instruments.

-123-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Reserve Quantity Information

The Company's proved oil and gas reserve estimates are prepared by the Company's reservoir engineers who meet the qualifications of Reserve Estimator per the "Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserve Information" promulgated by the Society of Petroleum Engineers as of February 19, 2007. The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance.

The Company's Vice President of Reservoir Engineering is the primary technical person responsible for overseeing the Company's reserve estimation process and engaging and overseeing the third party reserve audit. His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 30 years of Petroleum Engineering experience with both major and independent oil and gas companies. He has maintained oversight of the Company's reserve estimation process since 2003. He is a member of the Society of Petroleum Evaluation Engineers and a Registered Professional Engineer in the State of Texas.

The Company maintains a system of internal controls over the reserve estimation process. Management reviews the price, heat content, lease operating cost and future investment assumptions used in the economic model to determine the reserves. The Vice President of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions. Access to the reserve database is restricted. Significant changes to the reserve report are reviewed by senior management on a quarterly basis. Periodically, the Company's internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls.

All of the Company's reserve estimates are audited annually by Netherland, Sewell and Associates, Inc. (NSAI). Since 1961, NSAI has evaluated gas and oil properties and independently certified petroleum reserve quantities in the United States and internationally under the Texas Board of Professional Engineers Registration No. F-002699. The primary technical persons (employed by NSAI) that are responsible for leading the audit include a professional engineer registered with the State of Texas (consulting at NSAI since ~~2004~~2011 and with over 54 years of prior industry experience in petroleum engineering) and a professional geoscientist registered in the State of Texas (consulting at NSAI since 2008 and with over 11 years of prior industry experience in petroleum geosciences). NSAI was satisfied with the methods and procedures used by the Company to prepare its reserve estimates at September 30, ~~2018~~2020 and did not identify any problems which would cause it to take exception to those estimates.

The reliable technologies that were utilized in estimating the reserves include wire line open-hole log data, performance data, log cross sections, core data, 2D and 3D seismic data and statistical analysis. The statistical method utilized production performance from both the Company's and competitors’ wells. Geophysical data includes data from the Company's wells, third-party wells, published documents and state data-sites, and 2D and 3D seismic data. These were used to confirm continuity of the formation.

-124-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Gas MMcf
U.S.

Appalachian
Region

West Coast
Region

Total
Company
Proved Developed and Undeveloped Reserves:
September 30, 2015 2,092,782
   49,346
2,142,128
Extensions and Discoveries 185,347
(1) —
185,347
Revisions of Previous Estimates (245,029 )    (3,132 ) (248,161 )
Production (140,457 ) (2) (3,090 ) (143,547 )
Sale of Minerals in Place (261,192 ) —
(261,192 )
September 30, 2016 1,631,451
   43,124
1,674,575
Extensions and Discoveries 386,649
(1) 8
386,657
Revisions of Previous Estimates 84,480
   6,369
90,849
Production (154,093 ) (2) (2,995 ) (157,088 )
Sale of Minerals in Place (21,873 ) —
(21,873 )
September 30, 2017 1,926,614
   46,506
1,973,120
Extensions and Discoveries 521,694
(1) —
521,694
Revisions of Previous Estimates 90,113
   3,322
93,435
Production (160,499 ) (2) (2,407 ) (162,906 )
Sale of Minerals in Place (57,420 ) (10,581 ) (68,001 )
September 30, 2018 2,320,502
   36,840
2,357,342
Proved Developed Reserves:

September 30, 2015 1,267,498
   49,346
1,316,844
September 30, 2016 1,089,492
   43,124
1,132,616
September 30, 2017 1,316,596
   46,506
1,363,102
September 30, 2018 1,569,692
   36,840
1,606,532
Proved Undeveloped Reserves:

September 30, 2015 825,284
   —
825,284
September 30, 2016 541,959
   —
541,959
September 30, 2017 610,018
   —
610,018
September 30, 2018 750,810
   —
750,810


	Gas MMcf
	U.S.
	Appalachian Region		West Coast Region	Total Company
Proved Developed and Undeveloped Reserves:
September 30, 2017	1,926,614		46,506	1,973,120
Extensions and Discoveries	521,694	(1)	0	521,694
Revisions of Previous Estimates	90,113		3,322	93,435
Production	(160,499)	(2)	(2,407)	(162,906)

Sale of Minerals in Place	(57,420)		(10,581)	(68,001)
September 30, 2018	2,320,502		36,840	2,357,342
Extensions and Discoveries	686,549	(1)	0	686,549
Revisions of Previous Estimates	104,741		(1,233)	103,508
Production	(195,906)	(2)	(1,974)	(197,880)


September 30, 2019	2,915,886		33,633	2,949,519
Extensions and Discoveries	7,246	(1)	0	7,246
Revisions of Previous Estimates	(85,647)		(2,772)	(88,419)
Production	(225,513)	(2)	(1,889)	(227,402)
Purchases of Minerals in Place	684,141		0	684,141

September 30, 2020	3,296,113		28,972	3,325,085
Proved Developed Reserves:
September 30, 2017	1,316,596		46,506	1,363,102
September 30, 2018	1,569,692		36,840	1,606,532
September 30, 2019	1,901,162		33,633	1,934,795
September 30, 2020	2,744,851		28,972	2,773,823
Proved Undeveloped Reserves:
September 30, 2017	610,018		0	610,018
September 30, 2018	750,810		0	750,810
September 30, 2019	1,014,724		0	1,014,724
September 30, 2020	551,262		0	551,262


~~(1)~~	Extensions and discoveries include 179 Bcf (during 2016), 181 Bcf (during 2017) and 274 Bcf (during 2018), of Marcellus Shale gas in the Appalachian region. Extensions and discoveries include 6 Bcf (during 2016), 205 Bcf (during 2017) and 248 Bcf (during 2018), of Utica Shale gas in the Appalachian region.


~~(2)~~	Production includes 135,598 MMcf (during 2016), 145,452 MMcf (during 2017) and 150,196 MMcf (during 2018), from Marcellus Shale fields (which exceed 15% of total reserves). Production includes 9,409 MMcf (during 2018), from Utica Shale fields (which exceed 15% of total reserves).

(1)Extensions and discoveries include 274 Bcf (during 2018), 175 Bcf (during 2019) and 7 Bcf (during 2020), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 248 Bcf (during 2018), 512 Bcf (during 2019) and 0 Bcf (during 2020), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.

(2)Production includes 150,196 MMcf (during 2018), 163,015 MMcf (during 2019) and 169,453 MMcf (during 2020), from Marcellus Shale fields. Production includes 9,409 MMcf (during 2018), 32,095 MMcf (during 2019) and 55,392 MMcf (during 2020), from Utica Shale fields.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	Oil Mbbl							Oil Mbbl
	U.S.							U.S.
	Appalachian Region		West Coast Region		Total Company			Appalachian Region	West Coast Region	Total Company
Proved Developed and Undeveloped Reserves:							Proved Developed and Undeveloped Reserves:
September 30, 2015	220		33,502		33,722
Extensions and Discoveries	—		530		530
Revisions of Previous Estimates	(46	)	(2,201	)	(2,247	)
Production	(28	)	(2,895	)	(2,923	)
Sales of Minerals in Place	(73	)	—		(73	)
September 30, 2016	73		28,936		29,009
Extensions and Discoveries	—		674		674
Revisions of Previous Estimates	(12	)	3,305		3,293
Production	(4	)	(2,736	)	(2,740	)
Sales of Minerals in Place	(29	)	—		(29	)
September 30, 2017	28		30,179		30,207		September 30, 2017	28	30,179	30,207
Extensions and Discoveries	—		2,301		2,301		Extensions and Discoveries	0	2,301	2,301
Revisions of Previous Estimates	(10	)	2,487		2,477		Revisions of Previous Estimates	(10)	2,487	2,477
Production	(4	)	(2,531	)	(2,535	)	Production	(4)	(2,531)	(2,535)
Sales of Minerals in Place	—		(4,787	)	(4,787	)	Sales of Minerals in Place	0	(4,787)	(4,787)

September 30, 2018	14		27,649		27,663		September 30, 2018	14	27,649	27,663
Extensions and Discoveries							Extensions and Discoveries	0	787	787
Revisions of Previous Estimates							Revisions of Previous Estimates	2	(1,256)	(1,254)
Production							Production	(3)	(2,320)	(2,323)

September 30, 2019							September 30, 2019	13	24,860	24,873
Extensions and Discoveries							Extensions and Discoveries	0	288	288
Revisions of Previous Estimates							Revisions of Previous Estimates	2	(715)	(713)
Production							Production	(3)	(2,345)	(2,348)

September 30, 2020							September 30, 2020	12	22,088	22,100
Proved Developed Reserves:							Proved Developed Reserves:
September 30, 2015	220		33,150		33,370
September 30, 2016	73		28,698		28,771
September 30, 2017	28		29,771		29,799		September 30, 2017	28	29,771	29,799
September 30, 2018	14		26,689		26,703		September 30, 2018	14	26,689	26,703
September 30, 2019							September 30, 2019	13	24,246	24,259
September 30, 2020							September 30, 2020	12	22,088	22,100
Proved Undeveloped Reserves:							Proved Undeveloped Reserves:
September 30, 2015	—		352		352
September 30, 2016	—		238		238
September 30, 2017	—		408		408		September 30, 2017	0	408	408
September 30, 2018	—		960		960		September 30, 2018	0	960	960
September 30, 2019							September 30, 2019	0	614	614
September 30, 2020							September 30, 2020	0	0	0

The Company’s proved undeveloped (PUD) reserves ~~increased~~decreased from ~~612~~1,018 Bcfe at September 30, ~~2017~~2019 to ~~757~~551 Bcfe at September 30, ~~2018.~~2020. PUD reserves in the Marcellus Shale decreased from ~~456~~383 Bcfe at September 30, ~~2017~~2019 to 287 Bcfe at September 30, 2020. PUD reserves in the Utica Shale decreased from 632 Bcfe at September 30, 2019 to 265 Bcfe at September 30, 2020. The Company’s total PUD reserves were 16% of total proved reserves at September 30, 2020, down from 33% of total proved reserves at September 30, 2019.

The Company’s PUD reserves increased from 757 Bcfe at September 30, 2018 to 1,018 Bcfe at September 30, 2019. PUD reserves in the Marcellus Shale decreased slightly from 394 Bcfe at September 30, ~~2018.~~2018 to 383 Bcfe at September 30, 2019. PUD reserves in the Utica Shale increased from ~~154 Bcfe at September 30, 2017 to~~ 357 Bcfe at September 30, ~~2018.~~2018 to 632 Bcfe at September 30, 2019. The Company’s total PUD reserves were 33% of total proved reserves at September 30, 2019, up from 30% of total proved reserves at September 30, ~~2018, up from 28% of total proved reserves at September 30, 2017.~~2018.

The Company’s PUD reserves increased from 543 Bcfe at September 30, 2016 to 612 Bcfe at September 30, 2017. PUD reserves in the Marcellus Shale decreased from 542 Bcfe at September 30, 2016 to 456 Bcfe at September 30, 2017. The Company’s total PUD reserves were 28% of total proved reserves at September 30, 2017, down from 29% of total proved reserves at September 30, 2016.

~~The increase~~decrease in PUD reserves in ~~2018~~2020 of ~~145~~467 Bcfe is a result of 431 Bcfe in new PUD reserve additions (229 Bcfe from the Marcellus Shale, 197 Bcfe from the Utica Shale and 5 Bcfe from the West Coast region) and 60 Bcfe in upward revisions to remaining PUD reserves, partially offset by 284363 Bcfe in PUD conversions to developed reserves ~~(264~~(146 Bcfe from the Marcellus Shale, 18214 Bcfe from the Utica Shale and 23 Bcfe from the West Coast region),

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)~~

5 and 179 Bcfe in PUD reserves removed for ~~one Marcellus~~17 PUD ~~and sales of 57 Bcfe~~locations, all in ~~PUD working interest reserves sold as part of~~ the ~~joint development agreement, previously discussed.~~

The increase in PUD reserves in 2017 of 69 Bcfe was a result of 269 Bcfe in new PUD reserve additions (113 Bcfe from the Marcellus Shale, 154 Bcfe from the Utica Shale and 2 Bcfe from the West Coast region) and 13 Bcfe in upward revisions to remaining PUD reserves, partially offset by 159 Bcfe in PUD conversions to developed reserves (158 Bcfe from the Marcellus Shale and 1 Bcfe from the West Coast region) and 54 Bcfe in PUD reserves removed. In the EasternWestern Development Area, ~~Marcellus Shale PUD reserves of 36 Bcfe were removed~~ due to development timing no longer scheduled to meet the five year requirement for proved reserves. ~~Seneca successfully leased an adjacent tract to~~NaN of these wells removed were in the Marcellus Shale (14 Bcfe) and 15 were in the Utica Shale (165 Bcfe). These decreases were offset by 7 Bcfe in new PUD reserve additions, 20 Bcfe in

-126-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

upward revisions to remaining PUD reserves and 48 Bcfe in revisions for 5 PUD locations added back in 2020 (after removing 1 in 2016 and 4 in 2017 ~~and intends~~due to ~~develop the wells now with longer laterals drilled into this adjacent tract. These development plans are not expected to commence within~~scheduling delays beyond the five year ~~time horizon~~requirement).

The increase in PUD reserves in 2019 of 261 Bcfe is a result of 575 Bcfe in new PUD reserve additions (175 Bcfe from ~~original booking.~~the Marcellus Shale, 398 Bcfe from the Utica Shale and 2 Bcfe from the West Coast region) and 38 Bcfe in upward revisions to remaining PUD reserves, partially offset by 297 Bcfe in PUD conversions to developed reserves (186 Bcfe from the Marcellus Shale, 106 Bcfe from the Utica Shale and 5 Bcfe from the West Coast region), and 55 Bcfe in PUD reserves removed for 6 PUD locations, 2 of ~~18 Bcfe were~~these wells removed ~~as part of Seneca’s transition toward a Utica focused development program~~are in the ~~Western Development Area, where certain~~ Marcellus ~~well locations were replaced with Utica well locations~~(13 Bcfe) and 4 are in the ~~Company's development plan.~~Utica (42 Bcfe).

The Company invested ~~$182~~$220 million during the year ended September 30, ~~2018~~2020 to convert ~~284~~363 Bcfe (393 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents ~~46%~~36% of the net PUD reserves ~~booked~~recorded at September 30, ~~2017 (or 51%~~2019. The 30 Bcfe in upward revisions to PUD reserves converted to developed reserves in 2020 were primarily a result of ~~remaining~~longer completed laterals. In the Appalachian region, 35 of 99 PUD locations were developed and in the West Coast region, all 14 PUD locations were developed.

The Company invested $246 million during the year ended September 30, 2019 to convert 297 Bcfe (380 Bcfe after positive revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 39% of the net PUD reserves ~~after 57 Bcfe in PUD working interest reserves were sold as part of the joint development agreement, as previously discussed).~~recorded at September 30, 2018. In fiscal ~~2018,~~2019, the Company developed 5356 (or ~~62%~~50%) of its well locations with net PUD reserves recorded at September 30, ~~2017.~~2018. The ~~vast~~ majority of these wells were in the Appalachian region.

The ~~Company invested $101 million during the year ended September 30, 2017~~83 Bcfe in upward revisions to ~~convert 147 Bcfe of Marcellus Shale~~ PUD reserves converted to developed ~~reserves. This represents 27%~~reserves in 2019 were a result of ~~the net~~longer completed laterals and improved well performance at PUD ~~reserves booked at September 30, 2016. In fiscal 2017, the Company developed 37 (or 41%) of its well~~ locations ~~with net PUD reserves~~that were recorded at September 30, ~~2016. The vast majority of these wells were in the Appalachian region.~~2019.

In ~~2019,~~2021, the Company estimates that it will invest approximately ~~$210~~$134 million to develop its PUD reserves. The Company is committed to developing its PUD reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting. Since that rule, and over the last five years, the Company developed ~~51% of its beginning year PUD reserves in fiscal 2014, 33% of its beginning year PUD reserves in fiscal 2015,~~ 25% of its beginning year PUD reserves in fiscal 2016, 27% of its beginning year PUD reserves in fiscal 2017, ~~and~~ 51% of its beginning year PUD reserves in fiscal ~~2018.~~2018, 39% of its beginning year PUD reserves in fiscal 2019 and 36% of its beginning year PUD reserves in fiscal 2020.

At September 30, ~~2018,~~2020, the Company does not have ~~a material concentration of~~any proved undeveloped reserves that have been on the books for more than five years at the corporate level, country level or field level. All of the Company’s proved reserves are in the United States.

Standardized Measure of Discounted Future Net Cash Flows Relating to Proved Oil and Gas Reserves

The Company cautions that the following presentation of the standardized measure of discounted future net cash flows is intended to be neither a measure of the fair market value of the Company’s oil and gas properties, nor an estimate of the present value of actual future cash flows to be obtained as a result of their development and production. It is based upon subjective estimates of proved reserves only and attributes no value to categories of reserves other than proved reserves, such as probable or possible reserves, or to unproved acreage. Furthermore, in accordance with the SEC’s final rule on Modernization of Oil and Gas Reporting, it is based on the 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 and costs adjusted only for existing contractual changes. It assumes an arbitrary discount rate of 10%. Thus, it gives no effect to future price and cost changes certain to occur under widely fluctuating political and economic conditions.

~~NATIONAL FUEL GAS COMPANY~~

~~NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)~~

The standardized measure is intended instead to provide a means for comparing the value of the Company’s proved reserves at a given time with those of other oil- and gas-producing companies than is provided by a simple comparison of raw proved reserve quantities.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	Year Ended September 30							Year Ended September 30
	2018		2017		2016			2020		2019		2018
	(Thousands)							(Thousands)
United States							United States
Future Cash Inflows	$	7,822,855	$	6,144,317	$	3,768,463	Future Cash Inflows	$	6,493,362	$	8,738,182	$	7,822,855
Less:							Less:
Future Production Costs	2,606,411		2,378,262		1,994,916		Future Production Costs	3,149,857		2,989,518		2,606,411
Future Development Costs	559,707		411,578		375,152		Future Development Costs	501,678		797,640		559,707
Future Income Tax Expense at Applicable Statutory Rate	1,125,910		1,160,469		303,397		Future Income Tax Expense at Applicable Statutory Rate	454,553		1,159,882		1,125,910
Future Net Cash Flows	3,530,827		2,194,008		1,094,998		Future Net Cash Flows	2,387,274		3,791,142		3,530,827
Less:							Less:
10% Annual Discount for Estimated Timing of Cash Flows	1,810,522		1,080,962		452,470		10% Annual Discount for Estimated Timing of Cash Flows	1,164,804		2,054,823		1,810,522
Standardized Measure of Discounted Future Net Cash Flows	$	1,720,305	$	1,113,046	$	642,528	Standardized Measure of Discounted Future Net Cash Flows	$	1,222,470	$	1,736,319	$	1,720,305

Schedule II — Valuation and Qualifying Accounts

Description Balance at Beginning of Period Additions Charged to Costs and Expenses Additions Charged to Other Accounts(1) Deductions (2) Balance at End of Period
Year Ended September 30, 2018
Allowance for Uncollectible Accounts $ 22,526
$ 10,905
$ 1,967
$ 10,861
$ 24,537
Valuation Allowance for Deferred Tax Assets (3) $ —
$ 5,000
$ —
$ —
$ 5,000
Year Ended September 30, 2017
Allowance for Uncollectible Accounts $ 21,109
$ 6,301
$ 1,774
$ 6,658
$ 22,526
Year Ended September 30, 2016
Allowance for Uncollectible Accounts $ 29,029
$ 6,819
$ 1,521
$ 16,260
$ 21,109


Description	Balance at Beginning of Period		Additions Charged to Costs and Expenses		Additions Charged to Other Accounts(1)		Deductions (2)		Balance at End of Period
Year Ended September 30, 2020
Allowance for Uncollectible Accounts	$	25,788	$	12,339	$	1,353	$	16,670	$	22,810
Valuation Allowance for Deferred Tax Assets (3)	$	0	$	63,205	$	0	$	0	$	63,205
Year Ended September 30, 2019
Allowance for Uncollectible Accounts	$	24,537	$	10,184	$	1,707	$	10,640	$	25,788
Valuation Allowance for Deferred Tax Assets (3)	$	5,000	$	0	$	0	$	5,000	$	0
Year Ended September 30, 2018
Allowance for Uncollectible Accounts	$	22,526	$	10,905	$	1,967	$	10,861	$	24,537
Valuation Allowance for Deferred Tax Assets (3)	$	0	$	5,000	$	0	$	0	$	5,000

(1)Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate agreement.

(2)Amounts represent net accounts receivable written-off, as well as a reversal of a valuation allowance, as discussed in footnote (3) below.

(3)During fiscal 2020, a valuation allowance was recorded against certain state deferred tax assets. During fiscal 2019, there was a $5.0 million benefit recorded to reverse the valuation allowance established at September 30, 2018 related to the potential sequestration of estimated alternative minimum tax credit refunds as a result of the 2017 Tax Reform Act.


~~(1)~~			~~Represents the discount on accounts receivable purchased in accordance with the Utility segment’s 2005 New York rate agreement.~~


~~(2)~~	~~Amounts represent net accounts receivable written-off.~~


~~(3)~~	~~Valuation allowance recorded to reflect the potential sequestration of estimated alternative minimum tax credit refunds as a result of the 2017 Tax Reform Act.~~



Item 9	Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

None.



Item 9A			Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of September 30, ~~2018.~~2020.

Management’s Annual Report on Internal Control over Financial Reporting

The management of the Company is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. The Company’s internal control over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and preparation of financial statements for external purposes in accordance with

-129-

GAAP. Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements.

The Company’s management assessed the effectiveness of the Company’s internal control over financial reporting as of September 30, ~~2018.~~2020. In making this assessment, management used the framework and criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (COSO) in Internal Control — Integrated Framework, published in 2013. Based on this assessment, management concluded that the Company maintained effective internal control over financial reporting as of September 30, ~~2018.~~

2020.

PricewaterhouseCoopers LLP, the independent registered public accounting firm that audited the Company’s consolidated financial statements included in this Annual Report on Form 10-K, has issued an attestation report on the effectiveness of the Company’s internal control over financial reporting as of September 30, ~~2018.~~2020. The report appears in Part II, Item 8 of this Annual Report on Form 10-K.

Changes in Internal Control over Financial Reporting

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended September 30, ~~2018~~2020 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.



Item 9B			Other Information

None.

PART III



Item 10			Directors, Executive Officers and Corporate Governance

The Company will file the definitive Proxy Statement with the SEC no later than 120 days after September 30, 2020. The information concerning directors will be set forth in the definitive Proxy Statement under the headings entitled “Nominees for Election as Directors for Three-Year Terms to Expire in ~~2022,~~2024,” ~~“Directors~~“Continuing Directors Whose Terms Expire in ~~2021,~~2023,” ~~“Directors~~and “Continuing Directors Whose Terms Expire in ~~2020,~~2022,” ~~and “Section 16(a) Beneficial Ownership Reporting Compliance”~~ and is incorporated herein by reference. The information concerning corporate governance will be set forth in the definitive Proxy Statement under the heading entitled “Meetings of the Board of Directors and Standing Committees” and is incorporated herein by reference. Information concerning the Company’s executive officers can be found in Part I, Item 1, of this report.

The Company has adopted a Code of Business Conduct and Ethics that applies to the Company’s directors, officers and employees and has posted such Code of Business Conduct and Ethics on the Company’s website, www.nationalfuelgas.com, together with certain other corporate governance documents. Copies of the Company’s Code of Business Conduct and Ethics, charters of important committees, and Corporate Governance Guidelines will be made available free of charge upon written request to Investor Relations, National Fuel Gas Company, 6363 Main Street, Williamsville, New York 14221.

The Company intends to satisfy the disclosure requirement under Item 5.05 of Form 8-K regarding an amendment to, or a waiver from, a provision of its code of ethics that applies to the Company’s principal executive officer, principal financial officer, principal accounting officer or controller, or persons performing similar functions, and that relates to any element of the code of ethics definition enumerated in paragraph (b) of Item 406 of the SEC’s Regulation S-K, by posting such information on its website, www.nationalfuelgas.com.



Item 11			Executive Compensation

The information concerning executive compensation will be set forth in the definitive Proxy Statement under the headings “Executive Compensation” and “Compensation Committee Interlocks and Insider Participation” and, excepting the “Report of the Compensation Committee,” is incorporated herein by reference.

-130-



~~Item��~~Item 12			Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

Equity Compensation Plan Information

The equity compensation plan information will be set forth in the definitive Proxy Statement under the heading “Equity Compensation Plan Information” and is incorporated herein by reference.

Security Ownership and Changes in Control

(a) Security Ownership of Certain Beneficial Owners

The information concerning security ownership of certain beneficial owners will be set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.

(b) Security Ownership of Management

The information concerning security ownership of management will be set forth in the definitive Proxy Statement under the heading “Security Ownership of Certain Beneficial Owners and Management” and is incorporated herein by reference.

None.



Item 13			Certain Relationships and Related Transactions, and Director Independence

The information regarding certain relationships and related transactions will be set forth in the definitive Proxy Statement under the headings “Compensation Committee Interlocks and Insider Participation” and “Related Person Transactions” and is incorporated herein by reference. The information regarding director independence is set forth in the definitive Proxy Statement under the heading “Director Independence” and is incorporated herein by reference.



Item 14			Principal Accountant Fees and Services

The information concerning principal accountant fees and services will be set forth in the definitive Proxy Statement under the heading “Audit Fees” and is incorporated herein by reference.

PART IV



Item 15			Exhibits and Financial Statement Schedules



(a)1.			Financial Statements

Financial statements filed as part of this report are listed in the index included in Item 8 of this Form 10-K, and reference is made thereto.



(a)2.			Financial Statement Schedules

Financial statement schedules filed as part of this report are listed in the index included in Item 8 of this Form 10-K, and reference is made thereto.



(a)3.			Exhibits

All documents referenced below were filed pursuant to the Securities Exchange Act of 1934 by National Fuel Gas Company (File No. 1-3880), unless otherwise noted.



Exhibit Number			Description of Exhibits

3(i)			Articles of Incorporation:

-131-


• Exhibit Number			Description of Exhibits
•			Restated Certificate of Incorporation of National Fuel Gas Company dated September 21, 1998; Certificate of Amendment of Restated Certificate of Incorporation dated March 14, 2005 (Exhibit 3.1, Form 10-K for fiscal year ended September 30, 2012)



~~Exhibit~~ ~~Number~~ 3(ii)		~~Description of~~ ~~Exhibits~~ By-Laws:
~~3(ii)~~		~~By-Laws:~~

•	National Fuel Gas Company By-Laws as amended March 10, 2016 (Exhibit 3.1, Form 8-K dated March 16, 2016)

4		Instruments Defining the Rights of Security Holders, Including Indentures:

•		Description of Securities (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 2019)

•		Indenture, dated as of October 15, 1974, between the Company and The Bank of New York Mellon (formerly Irving Trust Company) (Exhibit 2(b) in File No. 2-51796)

•		Third Supplemental Indenture, dated as of December 1, 1982, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York Mellon (formerly Irving Trust Company) (Exhibit 4(a)(4) in File No. 33-49401)

•		Eleventh Supplemental Indenture, dated as of May 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York Mellon (formerly Irving Trust Company) (Exhibit 4(b), Form 8-K dated February 14, 1992)

•		Twelfth Supplemental Indenture, dated as of June 1, 1992, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York Mellon (formerly Irving Trust Company) (Exhibit 4(c), Form 8-K dated June 18, 1992)

•		Thirteenth Supplemental Indenture, dated as of March 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York Mellon (formerly Irving Trust Company) (Exhibit 4(a)(14) in File No. 33-49401)

•		Fourteenth Supplemental Indenture, dated as of July 1, 1993, to Indenture dated as of October 15, 1974, between the Company and The Bank of New York Mellon (formerly Irving Trust Company) (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 1993)

•		Indenture dated as of October 1, 1999, between the Company and The Bank of New York Mellon (formerly The Bank of New York) (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 1999)

•		~~Officer’s Certificate establishing 8.75% Notes due 2019, dated April 6, 2009 (Exhibit 4.4, Form 8-K dated April 6, 2009)~~

•	Officer’s Certificate establishing 4.90% Notes due 2021, dated December 1, 2011 (Exhibit 4.4, Form 8-K dated December 1, 2011)

•		Officers Certificate establishing 3.75% Notes due 2023, dated February 15, 2023 (Exhibit 4.1.1, Form 8-K dated February 15, 2013)

•		Officers Certificate establishing 5.20% Notes due 2025, dated June 25, 2015 (Exhibit 4.1.1, Form 8-K dated June 25, 2015)

•		Officers Certificate establishing 3.95% Notes due 2027, dated September 27, 2017 (Exhibit 4.1.1, Form 8-K dated September 27, 2017)

•		Officers Certificate establishing 4.75% Notes due 2028, dated August 17, 2018 (Exhibit 4.1.1, Form 8-K dated August 17, 2018)

•	Amended and Restated Rights Agreement, dated as of December 4, 2008, between the Company and The Bank of New York Mellon (formerly The Bank of New York), as rights agent (Exhibit 4.1, Form 8-K dated December 4, 2008)

•	~~Letter of Appointment of Wells Fargo Bank, National Association, as Successor Rights Agent, dated July 18, 2012 (Exhibit 4.1, Form 10-K for fiscal year ended September 30, 2012)~~



~~Exhibit~~ ~~Number~~ •		~~Description of~~ ~~Exhibits~~
•	~~Amendment No. 1,~~Officers Certificate establishing 5.50% Notes due 2026, dated as of January 11, 2018, to the Amended and Restated Rights Agreement, dated as of December 4, 2008, between National Fuel Gas Company and Wells Fargo Bank, National Association, as successor rights agentJune 3, 2020 (Exhibit ~~4.1,~~4.1.1, Form 8-K dated ~~January 12, 2018)~~June 3, 2020)

10		Material Contracts:

•		Fourth Amended and Restated Credit Agreement, dated as of October 25, 2018, among the Company, the Lenders Party Thereto, and JP Morgan Chase Bank, National Association, as Administrative Agent (Exhibit 10.1, Form 8-K dated October 31, 2018)

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• Exhibit Number		~~Third Amended and Restated Credit Agreement, dated as~~Description of September 9, 2016, among the Company, the Lenders Party Thereto, and JP Morgan Chase Bank, National Association, as Administrative Agent (Exhibit 10.1, Form 10-K for the fiscal year ended September 30, 2016) Exhibits

•	Form of Indemnification Agreement, dated September 2006, between the Company and each Director (Exhibit 10.1, Form 8-K dated September 18, 2006)

•		Purchase and Sale Agreement, dated as of May 4, 2020, by and among SWEPI LP, Seneca Resources Company, LLC, NFG Midstream Covington, LLC, National Fuel Gas Midstream Company, LLC and National Fuel Gas Company (Exhibit 10.1, Form 8-K dated May 4, 2020)

•		364-Day Credit Agreement, dated as of May 4, 2020, among the Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (Exhibit 10.2, Form 8-K dated May 4, 2020)

		Management Contracts and Compensatory Plans and Arrangements:

•		Standard Form of Amended and Restated Employment Continuation and Noncompetition Agreement among the Company, a subsidiary of the Company and executive officers (Exhibit 10.1, Form 10-K for the fiscal year ended September 30, 2008)

•		Form of Amended and Restated Employment Continuation and Noncompetition Agreement between Seneca Resources Company, LLC and John P. McGinnis (Exhibit 10.1, Form 10-K for the fiscal year ended September 30, 2017)

•		National Fuel Gas Company 1997 Award and Option Plan, as amended and restated as of July 23, 2007 (Exhibit 10.4, Form 10-Q for the quarterly period ended March 31, 2008)

•		~~Form of Stock Appreciation Right Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2, Form 10-Q for the quarterly period ended December 31, 2008)~~

•	Form of Stock Appreciation Right Award Notice under National Fuel Gas Company 1997 Award and Option Plan (Exhibit 10.2, Form 10-Q for the quarterly period ended December 31, 2011)

•		National Fuel Gas Company 2010 Equity Compensation Plan, as amended and restated December 5, 2018 (Exhibit ~~10.2,~~10.1, Form 8-K dated March ~~16, 2015)~~11, 2019)

•		~~Form of Stock Appreciation Right Award Notice under the National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 2010)~~

•	Form of Stock Appreciation Right Award Notice under the National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.4, Form 10-Q for the quarterly period ended December 31, 2010)

•		National Fuel Gas Company 2012 Annual At Risk Compensation Incentive Plan (Exhibit 10.2, Form 10-Q for the quarterly period ended March 31, 2012)

•		National Fuel Gas Company Executive Annual Cash Incentive Program (Exhibit 10.3, Form 10-Q for the quarterly period ended December 31, 2009)

•		Administrative Rules of the Compensation Committee of the Board of Directors of National Fuel Gas Company, as amended and restated effective June 9, 2016 (Exhibit 10.1, Form 10-Q for the quarterly period ended June 30, 2016)

•		National Fuel Gas Company Deferred Compensation Plan, as amended and restated through March 20, 1997 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 1997)



~~Exhibit~~ ~~Number~~ •		~~Description of~~ ~~Exhibits~~
•	Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 16, 1997 (Exhibit 10.4, Form 10-K for fiscal year ended September 30, 1997)

•		Amendment No. 2 to the National Fuel Gas Company Deferred Compensation Plan, dated March 13, 1998 (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 1998)

•		Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated February 18, 1999 (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 1999)

•		Amendment to National Fuel Gas Company Deferred Compensation Plan, dated June 15, 2001 (Exhibit 10.3, Form 10-K for fiscal year ended September 30, 2001)

•		Amendment to the National Fuel Gas Company Deferred Compensation Plan, dated October 21, 2005 (Exhibit 10.5, Form 10-K for fiscal year ended September 30, 2005)

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• Exhibit Number			Description of Exhibits
•			Form of Letter Regarding Tophat Plan and Internal Revenue Code Section 409A, dated July 12, 2005 (Exhibit 10.7, Form 10-K for fiscal year ended September 30, 2005)

•			National Fuel Gas Company Tophat Plan, as amended September 20, 2007 (Exhibit 10.3, Form 10-K for the fiscal year ended September 30, 2007)

•			Split Dollar Insurance and Death Benefit Agreement, dated September 15, 1997, between the Company and David F. Smith (Exhibit 10.13, Form 10-K for fiscal year ended September 30, 1999)

•			Amendment Number 1 to Split Dollar Insurance and Death Benefit Agreement by and between the Company and David F. Smith, dated March 29, 1999 (Exhibit 10.14, Form 10-K for fiscal year ended September 30, 1999)

•			National Fuel Gas Company Parameters for Executive Life Insurance Plan (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 2004)

•			National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, Amended and Restated as of September 24, 2008 (Exhibit 10.5, Form 10-K for the fiscal year ended September 30, 2008)

•			Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated June 1, 2010 (Exhibit 10.1, Form 10-Q for the quarterly period ended June 30, 2010)

•			Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated August 13, 2015 (Exhibit 10.2, Form 10-K for the fiscal year ended September 30, 2015)

•			National Fuel Gas Company 2009 Non-Employee Director Equity Compensation Plan, as amended and ~~reapproved~~restated March ~~10, 2016~~11, 2020 (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 2020)

•			Form of Award Notice for Return on Capital Performance Shares under the National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.1, Form 10-Q for the quarterly period ended December 31, 2019)

•			Form of Award Notice for Total Shareholder Return Performance Shares under the National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.2, Form 10-Q for the quarterly period ended ~~March~~December 31, ~~2016)~~2019)

•			Form of Award Notice for Return on Capital Performance Shares under National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.1, Form 10-Q for the quarterly period ended December 31, 2018)

•			Form of Award Notice for Total Shareholder Return Performance Shares under the National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.2, Form 10-Q for the quarterly period ended December 31, 2018)

•			Form of Award Notice for Return on Capital Performance Shares under the National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.1, Form 10-Q for the quarterly period ended December 31, 2017)

•			Form of Award Notice for Total Shareholder Return Performance Shares under the National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.2, Form 10-Q for the quarterly period ended December 31, 2017)

•			Form of Award Notice for Restricted Stock Units under the National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.3, Form 10-Q for the quarterly period ended December 31, 2017)

•
21			~~Form~~Subsidiaries of ~~Award Notice for Return on Capital Performance Shares under~~ the ~~National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.1, Form 10-Q for the quarterly period ended December 31, 2016)~~Registrant

-134-



New Jersey			13-1086010
(State or other jurisdiction of incorporation or organization)			(I.R.S. Employer Identification No.)

6363 Main Street
Williamsville,	New York	14221
(Address of principal executive offices)			~~14221~~ (Zip Code)



Title of Each Class	Trading Symbol		Name of Each Exchange on Which Registered
Common Stock, par value $1.00 per share ~~and~~ ~~Common Stock Purchase Rights~~		NFG		New York Stock Exchange



CONTENTS
				Page
Part I
ITEM 1			BUSINESS	5
			THE COMPANY AND ITS SUBSIDIARIES	5
			RATES AND REGULATION	6
			THE EXPLORATION AND PRODUCTION SEGMENT	67
			THE PIPELINE AND STORAGE SEGMENT	67
			THE GATHERING SEGMENT	7
			THE UTILITY SEGMENT	78
			~~THE ENERGY MARKETING SEGMENT~~	7
	ALL OTHER CATEGORY AND CORPORATE OPERATIONS	8
			SOURCES AND AVAILABILITY OF RAW MATERIALS	8
			COMPETITION	8
			SEASONALITY	10
			CAPITAL EXPENDITURES	10
			ENVIRONMENTAL MATTERS	10
			MISCELLANEOUS	10
			HUMAN CAPITAL	10
			EXECUTIVE OFFICERS OF THE COMPANY	1113
ITEM 1A			RISK FACTORS	1214
ITEM 1B			UNRESOLVED STAFF COMMENTS	2023
ITEM 2			PROPERTIES	2024
			GENERAL INFORMATION ON FACILITIES	2024
			EXPLORATION AND PRODUCTION ACTIVITIES	2124
ITEM 3			LEGAL PROCEEDINGS	2528
ITEM 4			MINE SAFETY DISCLOSURES	2528
Part II
ITEM 5			MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	2629
ITEM 6			SELECTED FINANCIAL DATA	2831
ITEM 7			MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	2932
ITEM 7A			QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	6463
ITEM 8			FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	6564
ITEM 9			CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	~~123~~129
ITEM 9A			CONTROLS AND PROCEDURES	~~123~~129
ITEM 9B			OTHER INFORMATION	~~124~~130



Part III
ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	~~124~~130
ITEM 11	EXECUTIVE COMPENSATION	~~124~~130
ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	~~124~~131
ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	~~125~~131
ITEM 14	PRINCIPAL ACCOUNTANT FEES AND SERVICES	~~125~~131
Part IV
ITEM 15	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	~~125~~131
SIGNATURES		~~130~~136



Name and Age (as of November 15, ~~2018)~~2020)		Current Company Positions and Other Material Business Experience During Past Five Years
~~Ronald J. Tanski~~David P. Bauer ~~(66)~~(51)		Chief Executive Officer of the Company since ~~April 2013~~July 2019. President of Supply Corporation from February 2016 through June 2019. Treasurer and ~~President~~Principal Financial Officer of the Company ~~since~~from July ~~2010.~~2010 through June 2019. Treasurer of Seneca from April 2015 through June 2019. Treasurer of Distribution Corporation from April 2015 through June 2019. Treasurer of Midstream Company from April 2013 through June 2019. Treasurer of Supply Corporation from June 2007 through June 2019. Treasurer of Empire from June 2007 through June 2019.
John R. Pustulka ~~(66)~~(68)		Chief Operating Officer of the Company since February 2016. Mr. Pustulka previously served as President of Supply Corporation from July 2010 through January 2016.
~~David P. Bauer~~Donna L. DeCarolis ~~(49)~~(61)		President of Supply Corporation since February 2016. Treasurer and Principal Financial Officer of the Company since July 2010. Treasurer of Seneca since April 2015; Treasurer of Distribution Corporation since April 2015; Treasurer of Midstream Company since April 2013; Treasurer of Supply Corporation since June 2007; and Treasurer of Empire since June 2007. Mr. Bauer previously served as Assistant Treasurer of Distribution Corporation from April 2004 through March 2015.
~~Carl M. Carlotti~~ ~~(63)~~	President of Distribution Corporation since February ~~2016.~~2019. Ms. DeCarolis previously served as Vice President of Business Development of the Company from October 2007 through January 2019.
Michael P. Kasprzak (62)		President of Midstream Company since August 2018. Vice President of Midstream Company from July 2017 through July 2018. Mr. ~~Carlotti~~Kasprzak previously served as Assistant Vice President of Supply Corporation from March 2009 until July 2017.
Ronald C. Kraemer (64)		President of Supply Corporation since July 2019 and President of Empire since August 2008. Mr. Kraemer previously served as Senior Vice President of ~~Distribution~~Supply Corporation from ~~January 2008~~June 2016 through ~~January 2016.~~
~~Ronald C. Kraemer~~ ~~(62)~~	~~President of Empire since August 2008~~June 2019 and ~~Senior Vice President of Supply Corporation since June 2016. Mr. Kraemer previously served~~ as Vice President of Supply Corporation from August 2008 through May 2016.
John P. McGinnis ~~(58)~~(60)		President of Seneca since May 2016. Mr. McGinnis previously served as Chief Operating Officer of Seneca from October 2015 through April ~~2016 and Senior Vice President of Seneca from March 2007 through September 2015.~~
~~Paula M. Ciprich~~ ~~(58)~~	Senior Vice President of the Company since April 2015; Secretary of the Company from July 2008 through June 2018; General Counsel of the Company since January 2005; Secretary of Distribution Corporation since July 2008.2016.
Karen M. Camiolo ~~(59)~~(61)		Treasurer and Principal Financial Officer of the Company since July 2019. Treasurer of Distribution Corporation, Supply Corporation, Empire, Seneca and Midstream Company since July 2019. Ms. Camiolo previously served as Controller and Principal Accounting Officer of the Company from April 2004 through June 2019. Vice President of Distribution Corporation from April 2015 through June 2019. Controller of Midstream Company from April 2013 through June 2019. Controller of Empire from June 2007 through June 2019. Controller of Distribution Corporation and Supply Corporation from April 2004 through June 2019.
Elena G. Mendel (54)		Controller and Principal Accounting Officer of the Company since ~~April 2004; Vice President of Distribution Corporation since April 2015; Controller of Midstream Company since April 2013; Controller of Empire since June 2007; and~~July 2019. Controller of Distribution Corporation, ~~and~~ Supply Corporation, Empire, and Midstream Company since ~~April 2004.~~
~~Donna L. DeCarolis~~ ~~(59)~~	~~Vice President Business Development~~July 2019. Assistant Controller of Distribution Corporation, Supply Corporation and Empire from February 2017 through June 2019. Ms. Mendel also previously served as Chief Auditor of the Company ~~since October 2007.~~from July 2012 through January 2017.
~~Ann M. Wegrzyn~~ ~~(60)~~ Martin A. Krebs (50)		Chief Information Officer of the Company since ~~February 2017. Mrs. Wegrzyn~~December 2018. Prior to joining the Company, Mr. Krebs served as Chief Information Officer and Chief Information Security Officer of Fidelis Care, a health insurance provider for New York State residents, from January 2012 to June 2018. Centene Corporation acquired Fidelis Care in July 2018, and Mr. Krebs served as the Chief Information Officer of the Fidelis Plan and Senior Vice President of Information Technology and Security from the acquisition to November 2018. Mr. Kreb’s prior employers are not subsidiaries or affiliates of the Company.
Sarah J. Mugel (56)		General Counsel of the Company since May 2020 and Secretary of the Company since July 2018. Ms. Mugel has been Vice President of Supply Corporation since April 2015 and General Counsel and Secretary of Supply Corporation since April 2016. Ms. Mugel has been Secretary of Empire Pipeline and Secretary of Midstream Company, and has served as the General Counsel of both entities, since April 2016. Ms. Mugel previously served as ~~Vice President~~Assistant Secretary of ~~Distribution~~the Company from June 2016 through June 2018 and as Assistant Secretary of Supply Corporation from ~~December 2010~~April 2015 through ~~January 2017.~~March 2016.



			þ☑			ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



			¨☐			TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934



~~(716) 857-7000~~
~~Registrant’s telephone number, including area code~~
Securities registered pursuant to Section 12(b) of the Act:


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;”~~


(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	$	448.7	$	222.9	$	487.8
Actual Impairment Recorded at September 30, 2020	183.7		183.7		183.7
Additional Impairment	$	265.0	$	39.2	$	304.1


~~(1)~~	~~Refer to further discussion of hedging activities below under “Market Risk Sensitive Instruments” and in Note G — Financial Instruments in Item 8 of this report.~~



						Percent (Warmer) Colder Than
Year Ended September 30		Normal			Actual	Normal(1)		Prior Year(1)
2018	Buffalo	6,617			6,391	(3.4	)%	12.0	%
	Erie	6,147			5,976	(2.8	)%	15.4	%
2017	Buffalo	6,617			5,708	(13.7	)%	1.7	%
	Erie	6,147			5,179	(15.7	)%	(0.1	)%
2016	Buffalo	6,653	(2	)	5,611	(15.7	)%	(19.5	)%
	Erie	6,181	(2	)	5,182	(16.2	)%	(21.3	)%


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


~~(2)~~	Normal degree day estimates changed to 6,653 for Buffalo and 6,181 for Erie as a result of updated information from the National Oceanic and Atmospheric Administration. In addition, normal degree days for 2016 reflect the fact that 2016 was a leap year.


~~(1)~~	2018 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $51.3 million, $21.9 million, $6.1 million and $9.5 million, respectively, of non-cash capital expenditures.


~~(2)~~	2017 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $36.5 million, $25.1 million, $3.9 million and $6.7 million, respectively, of non-cash capital expenditures.


~~(3)~~	2016 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $25.2 million, $18.7 million, $5.3 million and $11.2 million, respectively, of non-cash capital expenditures.


~~(4)~~	The capital expenditures for the Exploration and Production segment for 2018, 2017 and 2016 do not include any proceeds received from the sale of oil and gas assets to IOG under the joint development agreement.


~~(1)~~	Includes estimated expenditures for the years ended September 30, 2019, 2020 and 2021 of approximately $210 million, $123 million and $64 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.



	Payments by Expected Maturity Dates
	2019		2020		2021		2022		2023		Thereafter		Total
	(Millions)
Long-Term Debt, including interest expense(1)	$	100.1	$	100.1	$	100.1	$	579.7	$	611.8	$	1,265.1	$	2,756.9
Operating Lease Obligations	$	18.6	$	4.6	$	4.0	$	3.2	$	2.7	$	12.4	$	45.5
Purchase Obligations:
Gas Purchase Contracts(2)	$	220.3	$	20.8	$	5.4	$	0.2	$	—	$	—	$	246.7
Transportation and Storage Contracts(3)	$	77.6	$	82.1	$	81.2	$	152.3	$	162.8	$	1,606.0	$	2,162.0
Hydraulic Fracturing and Fuel Obligations	$	86.2	$	24.8	$	—	$	—	$	—	$	—	$	111.0
Pipeline, Compressor and Gathering Projects	$	105.1	$	6.8	$	6.1	$	5.1	$	3.4	$	13.3	$	139.8
Other	$	45.7	$	23.3	$	16.5	$	10.5	$	8.6	$	27.4	$	132.0


~~(1)~~	Refer to Note E — 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.


~~(2)~~	~~Gas prices are variable based on the NYMEX prices adjusted for basis.~~


~~(3)~~	Transportation service contractual obligations include the following precedent agreements executed by the Exploration and Production segment for transportation of Appalachian gas: $33.1 million for 2019, $35.9 million for 2020, $35.8 million for 2021, $108.2 million for 2022, $119.3 million for 2023 and $1,556.2 million thereafter.


	Expected Maturity Dates
	2021		2022		2023		2024		Total
Notional Quantities (Equivalent Bcf)	145.0		93.6		19.7		1.1		259.4
Weighted Average Fixed Rate (per Mcf)	$	2.72	$	2.68	$	2.58	$	2.53	$	2.69
Weighted Average Variable Rate (per Mcf)	$	2.96	$	2.80	$	2.57	$	2.45	$	2.87


	Principal Amounts by Expected Maturity Dates																			Principal Amounts by Expected Maturity Dates
	2019		2020		2021		2022			2023			Thereafter			Total				2021		2022		2023		2024		2025		Thereafter		Total
	(Dollars in millions)																			(Dollars in millions)
Long-Term Fixed Rate Debt	$	—	$	—	$	—	$	500.0		$	549.0		$	1,100.0		$	2,149.0		Long-Term Fixed Rate Debt	$	—	$	500.0	$	549.0	$	—	$	500.0	$	1,100.0	$	2,649.0
Weighted Average Interest Rate Paid	—		—		—		4.9		%	4.1		%	4.8		%	4.7		%	Weighted Average Interest Rate Paid	—		4.9%		4.1%		—		5.4%		4.9%		4.8%


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


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


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


4.	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;


6.	~~Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;~~


7.	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


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


9.	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;


~~10.~~	~~Other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date;~~