nfg-20210930

UNITED STATES SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K


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

For the Fiscal Year Ended September 30, 2021


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

For the Transition Period from to

Commission File Number 1-3880

National Fuel Gas Company

(Exact name of registrant as specified in its charter)


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)		(Zip Code)

(716) 857-7000

(Registrant’s telephone number, including area code)


Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
Common Stock, par value $1.00 per share	NFG	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15 (d) of the Act. Yes ☐ No ☑

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


Large accelerated filer	☑	Accelerated filer	☐
Non-accelerated filer	☐	Smaller reporting company	☐
		Emerging growth company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Act). Yes ☐ No ☑

The aggregate market value of the voting stock held by nonaffiliates of the registrant amounted to $4,487,649,000 as of March 31, 2021.

Common Stock, par value $1.00 per share, outstanding as of October 31, 2021: 91,190,074 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement for its 2022 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days of September 30, 2021, are incorporated by reference into Part III of this report.

Glossary of Terms

Frequently used abbreviations, acronyms, or terms used in this report:

National Fuel Gas Companies

Company The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure

Distribution Corporation National Fuel Gas Distribution Corporation

Empire Empire Pipeline, Inc.

Midstream Company National Fuel Gas Midstream Company, LLC

National Fuel National Fuel Gas Company

NFR National Fuel Resources, Inc.

Registrant National Fuel Gas Company

Seneca Seneca Resources Company, LLC

Supply Corporation National Fuel Gas Supply Corporation

Regulatory Agencies

CFTC Commodity Futures Trading Commission

EPA United States Environmental Protection Agency

FASB Financial Accounting Standards Board

FERC Federal Energy Regulatory Commission

IRS Internal Revenue Service

NYDEC New York State Department of Environmental Conservation

NYPSC State of New York Public Service Commission

PaDEP Pennsylvania Department of Environmental Protection

PaPUC Pennsylvania Public Utility Commission

PHMSA Pipeline and Hazardous Materials Safety Administration

SEC Securities and Exchange Commission

Other

2017 Tax Reform Act Tax legislation referred to as the "Tax Cuts and Jobs Act," enacted December 22, 2017.

Bbl Barrel (of oil)

Bcf Billion cubic feet (of natural gas)

Bcfe (or Mcfe) — represents Bcf (or Mcf) Equivalent The total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. The Company uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas.

Btu British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit.

Capital expenditure Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.

Cashout revenues A cash resolution of a gas imbalance whereby a customer pays Supply Corporation and/or Empire for gas the customer receives in excess of amounts delivered into Supply Corporation’s and Empire’s systems by the customer’s shipper.

CLCPA Legislation referred to as the "Climate Leadership & Community Protection Act," enacted by the State of New York on July 18, 2019.

Degree day A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.

Derivative A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial

instrument or contract. Examples include futures contracts, options, no cost collars and swaps.

Development costs Costs incurred to obtain access to proved oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas.

Development well A well drilled to a known producing formation in a previously discovered field.

Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act.

Dth Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.

Exchange Act Securities Exchange Act of 1934, as amended

Expenditures for long-lived assets Includes capital expenditures, stock acquisitions and/or investments in partnerships.

Exploitation Development of a field, including the location, drilling, completion and equipment of wells necessary to produce the commercially recoverable oil and gas in the field.

Exploration costs Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.

Exploratory well A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.

FERC 7(c) application An application to the FERC under Section 7(c) of the federal Natural Gas Act for authority to construct, operate (and provide services through) facilities to transport or store natural gas in interstate commerce.

Firm transportation and/or storage The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.

GAAP Accounting principles generally accepted in the United States of America

Goodwill An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.

Hedging A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.

Hub Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.

ICE Intercontinental Exchange. An exchange which maintains a futures market for crude oil and natural gas.

Interruptible transportation and/or storage The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.

LDC Local distribution company

LIBOR London Interbank Offered Rate

LIFO Last-in, first-out

Marcellus Shale A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.

Mbbl Thousand barrels (of oil)

Mcf Thousand cubic feet (of natural gas)

MD&A Management’s Discussion and Analysis of Financial Condition and Results of Operations

MDth Thousand decatherms (of natural gas)

MMBtu Million British thermal units (heating value of one decatherm of natural gas)

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MMcf Million cubic feet (of natural gas)

MMcfe Million cubic feet equivalent

NGA The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.

NYMEX New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.

OPEB Other Post-Employment Benefit

Open Season A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.

PCB Polychlorinated Biphenyl

Precedent Agreement An agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called “conditions precedent”) happen, usually within a specified time.

Proved developed reserves Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.

Proved undeveloped (PUD) reserves Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make those reserves productive.

PRP Potentially responsible party

Reliable technology Technology that a company may use to establish reserves estimates and categories that has been proven empirically to lead to correct conclusions.

Reserves The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.

Restructuring Generally referring to partial “deregulation” of the pipeline and/or utility industry by statutory or regulatory process. Restructuring of federally regulated natural gas pipelines resulted in the separation (or “unbundling”) of gas commodity service from transportation service for wholesale and large-volume retail markets. State restructuring programs attempt to extend the same process to retail mass markets.

Revenue decoupling mechanism A rate mechanism which adjusts customer rates to render a utility financially indifferent to throughput decreases resulting from conservation.

S&P Standard & Poor’s Ratings Service

SAR Stock appreciation right

Service Agreement The binding agreement by which the pipeline company agrees to provide service and the shipper agrees to pay for the service.

Spot gas purchases The purchase of natural gas on a short-term basis.

Stock acquisitions Investments in corporations.

Unbundled service A service that has been separated from other services, with rates charged that reflect only the cost of the separated service.

Utica Shale A Middle Ordovician-age geological formation lying several thousand feet below the Marcellus Shale in the Appalachian region of the United States, including much of Ohio, Pennsylvania, West Virginia and southern New York.

VEBA Voluntary Employees’ Beneficiary Association

WNC Weather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.

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For the Fiscal Year Ended September 30, 2021


CONTENTS
		Page
Part I
ITEM 1	BUSINESS	5
	THE COMPANY AND ITS SUBSIDIARIES	5
	RATES AND REGULATION	6
	THE EXPLORATION AND PRODUCTION SEGMENT	7
	THE PIPELINE AND STORAGE SEGMENT	7
	THE GATHERING SEGMENT	7
	THE UTILITY SEGMENT	8
	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	13
ITEM 1A	RISK FACTORS	14
ITEM 1B	UNRESOLVED STAFF COMMENTS	24
ITEM 2	PROPERTIES	24
	GENERAL INFORMATION ON FACILITIES	24
	EXPLORATION AND PRODUCTION ACTIVITIES	25
ITEM 3	LEGAL PROCEEDINGS	29
ITEM 4	MINE SAFETY DISCLOSURES	29
Part II
ITEM 5	MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	30
ITEM 6	[RESERVED]	32
ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	32
ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	60
ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	61
ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	123
ITEM 9A	CONTROLS AND PROCEDURES	123
ITEM 9B	OTHER INFORMATION	123


Part III
ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	123
ITEM 11	EXECUTIVE COMPENSATION	124
ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	124
ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	124
ITEM 14	PRINCIPAL ACCOUNTANT FEES AND SERVICES	125
Part IV
ITEM 15	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	125
SIGNATURES		130

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PART I


Item 1			Business

The Company and its Subsidiaries

National Fuel Gas Company (the Registrant), incorporated in 1902, is a holding company organized under the laws of the State of New Jersey. The Registrant owns directly or indirectly all of the outstanding securities of its subsidiaries. Reference to “the Company” in this report means the Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure. Also, all references to a certain year in this report relate to the Company’s fiscal year ended September 30 of that year unless otherwise noted.

The Company is a diversified energy company engaged principally in the production, gathering, transportation and distribution of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being used for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current natural gas production development activities are focused in the Marcellus and Utica shales, geological shale formations that are present nearly a mile or more below the surface in the Appalachian region of the United States. Pipeline development activities are designed to transport natural gas production to new and growing markets. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian basin to markets in the eastern United States and Canada. The Company also develops and produces oil reserves, primarily in California. The Company reports financial results for four business segments: Exploration and Production, Pipeline and Storage, Gathering, and Utility.

1. The Exploration and Production segment operations are carried out by Seneca Resources Company, LLC (Seneca), a Pennsylvania limited liability company. Seneca is engaged in the exploration for, and the development and production of, natural gas and oil reserves in the Appalachian region of the United States and in California. At September 30, 2021, Seneca had proved developed and undeveloped reserves of 3,723,433 MMcf of natural gas and 21,537 Mbbl of oil.

2. The Pipeline and Storage segment operations are carried out by National Fuel Gas Supply Corporation (Supply Corporation), a Pennsylvania corporation, and Empire Pipeline, Inc. (Empire), a New York corporation. Supply Corporation and Empire provide interstate natural gas transportation services for affiliated and nonaffiliated companies through integrated gas pipeline systems in Pennsylvania and New York. Supply Corporation also provides storage services through its underground natural gas storage fields.

3. The Gathering segment operations are carried out by wholly-owned subsidiaries of National Fuel Gas Midstream Company, LLC (Midstream Company), a Pennsylvania limited liability company. Through these subsidiaries, Midstream Company builds, owns and operates natural gas processing and pipeline gathering facilities in the Appalachian region.

4. The Utility segment operations are carried out by National Fuel Gas Distribution Corporation (Distribution Corporation), a New York corporation. Distribution Corporation provides natural gas utility services to approximately 753,000 customers through a local distribution system located in western New York and northwestern Pennsylvania. The principal metropolitan areas served by Distribution Corporation include Buffalo, Niagara Falls and Jamestown, New York and Erie and Sharon, Pennsylvania.

Financial information about each of the Company’s business segments can be found in Item 7, MD&A and also in Item 8 at Note M — Business Segment Information.

Seneca’s Northeast Division is included in the Company's All Other category. This division marketed timber from Appalachian land holdings. On August 5, 2020, the Company entered into a purchase and sale agreement to sell substantially all timber and other assets, which at September 30, 2020, accounted for the Company's ownership of approximately 95,000 acres of timber property and management of approximately 2,500 additional acres of timber cutting rights. The transaction closed on December 10, 2020. For additional

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discussion of the purchase and sale agreement to sell these assets, see Item 8 at Note B — Asset Acquisitions and Divestitures.

National Fuel Resources, Inc. (NFR) is included in the Company’s All Other category. NFR marketed gas to industrial, wholesale, commercial, public authority and residential customers in western and central New York and northwestern Pennsylvania. On August 1, 2020, NFR completed the sale of its commercial and industrial contracts and certain other assets. This sale, in conjunction with the turn back of NFR's residential customers to Distribution Corporation, effectively ended NFR's operations. For additional discussion of this sale, see Item 8 at Note B — Asset Acquisitions and Divestitures.

No single customer, or group of customers under common control, accounted for more than 10% of the Company’s consolidated revenues in 2021.

Rates and Regulation

The Company’s businesses are subject to regulation under a wide variety of federal, state and local laws, regulations and policies. This includes federal and state agency regulations with respect to rate proceedings, project permitting and environmental requirements.

The Company is subject to the jurisdiction of the FERC with respect to 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 operations. 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 Supply Corporation, Empire or Distribution Corporation are unable to obtain approval from these regulators for the rates they are requesting to charge customers, particularly when necessary to cover increased costs, earnings may decrease. For additional discussion of the Pipeline and Storage and Utility segments’ rates, see Item 7, MD&A under the heading “Rate Matters” and Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) and Note F — Regulatory Matters.

The discussion under Item 8 at Note F — Regulatory Matters includes a description of the regulatory assets and liabilities reflected on the Company’s Consolidated Balance Sheets in accordance with applicable accounting standards. To the extent that the criteria set forth in such accounting standards are not met by the operations of the Utility segment or the Pipeline and Storage segment, as the case may be, the related regulatory assets and liabilities would be eliminated from the Company’s Consolidated Balance Sheets and such accounting treatment would be discontinued.

The FERC also exercises jurisdiction over the construction and operation of interstate gas transmission and storage facilities and possesses significant penalty authority with respect to violations of the laws and regulations it administers. The Company is also subject to the jurisdiction of the Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA issues regulations and conducts evaluations, among other things, that set safety standards for pipelines and underground storage facilities. PHMSA may delegate this authority to a state, as it has in New York and Pennsylvania, and that state may choose to institute more stringent safety regulations for the construction, operation and maintenance of intrastate facilities. In addition to this state safety authority program, the NYPSC imposes additional requirements on the construction of certain utility facilities. Increased regulation by these agencies, or requested changes to construction projects, could lead to operational delays or restrictions and increase compliance costs that the Company may not be able to recover fully through rates or otherwise offset.

For additional discussion of the material effects of compliance with government environmental regulation, see Item 7, MD&A under the heading “Environmental Matters.”

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The Exploration and Production Segment

The Exploration and Production segment contributed net income of $101.9 million in 2021.

Additional discussion of the Exploration and Production segment appears below in this Item 1 under the headings “Sources and Availability of Raw Materials” and “Competition: The Exploration and Production Segment,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

The Pipeline and Storage Segment

The Pipeline and Storage segment contributed net income of $92.5 million in 2021.

Supply Corporation’s firm transportation capacity is subject to change as the market identifies different transportation paths and receipt/delivery point combinations. At the end of fiscal year 2021, Supply Corporation had firm transportation service agreements and lease agreements (Contracted Firm Transportation Capacity) for approximately 3,284 MDth per day. The Utility segment accounts for approximately 1,191 MDth per day or 36% of Contracted Firm Transportation Capacity, and the Exploration and Production segment represents another 44 MDth per day or 1%. Additionally, Supply Corporation leases 55 MDth per day or 2% of its Contracted Firm Transportation Capacity to Empire. The remaining 1,994 MDth or 61% is subject to firm transportation service agreements or leases with nonaffiliated customers. The amount of Contracted Firm Transportation Capacity with nonaffiliated parties will increase materially in fiscal 2022, largely due to the new 330 MDth capacity lease associated with Supply Corporation's FM100 Project. The contracted firm transportation capacity held by affiliated shippers is expected to remain constant in fiscal 2022.

Supply Corporation had service agreements and leases for all of its firm storage capacity, totaling 70,693 MDth, at the end of 2021. The Utility segment has contracted for 30,064 MDth or 43% of the total firm storage capacity. Additionally, Supply Corporation leases 3,753 MDth or 5% of its firm storage capacity to Empire. Nonaffiliated customers have contracted for the remaining 36,876 MDth or 52%. Supply Corporation expects contracted storage services totaling approximately 899 MDth to terminate and be remarketed in fiscal 2022.

At the end of fiscal 2021, Empire had service agreements in place for firm transportation capacity totaling approximately 964 MDth per day, with 100% of that capacity contracted as long-term, full-year deals. The Utility segment and the Exploration and Production segment account for 7% and 21%, respectively, of Empire’s firm contracted capacity, with the remaining 72% subject to contracts with nonaffiliated customers. Contracted transportation capacity with both affiliated and nonaffiliated shippers is expected to remain relatively constant in fiscal 2022.

Empire’s firm storage capacity, totaling 3,753 MDth, was fully contracted at the end of fiscal 2021. The total storage capacity is contracted on a long-term basis, with a nonaffiliated customer. The contract will not expire or terminate in fiscal 2022.

The majority of Supply Corporation’s and Empire's transportation and storage contracts allow either party to terminate the contract upon six or twelve months’ notice effective at the end of the primary term, and include “evergreen” language that allows for annual term extension(s).

Additional discussion of the Pipeline and Storage segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Pipeline and Storage Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

The Gathering Segment

The Gathering segment contributed net income of $80.3 million in 2021.

Additional discussion of the Gathering segment appears below under the headings “Sources and Availability of Raw Materials” and “Competition: The Gathering Segment,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

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The Utility Segment

The Utility segment contributed net income of $54.3 million in 2021.

Additional discussion of the Utility segment appears below under the headings “Sources and Availability of Raw Materials,” “Competition: The Utility Segment” and “Seasonality,” in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

All Other Category and Corporate Operations

The All Other category and Corporate operations contributed net income of $34.6 million in 2021.

Additional discussion of the All Other category and Corporate operations appears below in Item 7, MD&A and in Item 8, Financial Statements and Supplementary Data.

Sources and Availability of Raw Materials

The Exploration and Production segment seeks to discover and produce raw materials (natural gas, oil and hydrocarbon liquids) as further described in this report in Item 7, MD&A and Item 8 at Note M — Business Segment Information and Note N — Supplementary Information for Oil and Gas Producing Activities.

The Pipeline and Storage segment transports and stores natural gas owned by its customers, whose gas primarily originates in the Appalachian region of the United States, as well as other gas supply regions in the United States and Canada. Additional discussion of proposed pipeline projects appears below under “Competition: The Pipeline and Storage Segment” and in Item 7, MD&A.

The Gathering segment gathers, processes and transports natural gas that is, in large part, produced by Seneca in the Appalachian region of the United States. Additional discussion of proposed gathering projects appears below in Item 7, MD&A.

Natural gas is the principal raw material for the Utility segment. In 2021, the Utility segment purchased 73.2 Bcf of gas (including 70.3 Bcf for delivery to retail customers and 2.9 Bcf used in operations) pursuant to its purchase contracts with firm delivery requirements. Gas purchased from producers and suppliers in the United States under multi-month contracts accounted for 46% of these purchases. Purchases of gas in the spot market (contracts of one month or less) accounted for 54% of the Utility segment’s 2021 purchases. Purchases from DTE Energy Trading, Inc. (37%), Emera Energy Services, Inc. (14%), Tenaska Marketing Ventures (9%), Shell Energy North America US (7%), and Repsol Energy North America (6%) accounted for nearly 73% of the Utility segment's 2021 gas purchases. No other producer or supplier provided the Utility segment with more than 5% of its gas requirements in 2021. The Utility segment does not directly purchase gas from affiliates.

Competition

Competition in the natural gas industry exists among providers of natural gas, as well as between natural gas and other sources of energy, such as fuel oil and electricity. Management believes that the environmental advantages of natural gas have enhanced its competitive position relative to other fuels.

The Company competes on the basis of price, service and reliability, product performance and other factors. Sources and providers of energy, other than those described under this “Competition” heading, do not compete with the Company to any significant extent.

Competition: The Exploration and Production Segment

The Exploration and Production segment competes with other oil and natural gas producers and marketers with respect to sales of oil and natural gas. The Exploration and Production segment also competes, by competitive bidding and otherwise, with other oil and natural gas producers with respect to exploration and development prospects and mineral leaseholds.

To compete in this environment, Seneca originates and acts primarily as operator on its prospects, seeks to minimize the risk of exploratory efforts through partnership-type arrangements, utilizes technology for both

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exploratory studies and drilling operations, and seeks prospect and partnership opportunities based on size, operating expertise and financial criteria.

Competition: The Pipeline and Storage Segment

Supply Corporation competes for market growth in the natural gas market with other pipeline companies transporting gas in the northeast United States and with other companies providing gas storage services. Supply Corporation has some unique characteristics which enhance its competitive position. Most of Supply Corporation’s facilities are in or near areas overlying the Marcellus and Utica shale production areas in Pennsylvania, and it has established interconnections with producers and other pipelines that provide access to these supplies and to premium off-system markets. Its facilities are also located adjacent to the Canadian border at the Niagara River providing access to markets in Canada and the northeastern and midwestern United States via the TC Energy pipeline system. Supply Corporation has developed and placed into service a number of pipeline expansion projects designed to transport natural gas to key markets in New York, Pennsylvania, the northeastern United States, Canada, and to long-haul pipelines with access to the U.S. Midwest and the gulf coast. For further discussion of Pipeline and Storage projects, refer to Item 7, MD&A under the heading “Investing Cash Flow.”

Empire competes for natural gas market growth with other pipeline companies transporting gas in the northeast United States and upstate New York in particular. Empire is well situated to provide transportation of Appalachian shale gas as well as gas supplies available at Empire’s interconnect with TC Energy at Chippawa. Empire’s geographic location provides it the opportunity to compete for service to its on-system LDC markets, as well as for a share of the gas transportation markets into Canada (via Chippawa) and into the northeastern United States. The Empire Connector, along with other subsequent projects, has expanded Empire’s footprint and capability, allowing Empire to serve new markets in New York and elsewhere in the Northeast, and to attach to prolific Marcellus and Utica supplies principally from Tioga and Bradford Counties in Pennsylvania. Like Supply Corporation, Empire’s expanded system facilitates transportation of shale gas to key markets within New York State, the northeastern United States and Canada.

Competition: The Gathering Segment

The Gathering segment principally provides gathering services for Seneca’s production and competes with other companies that gather and process natural gas in the Appalachian region.

Competition: The Utility Segment

With respect to gas commodity service, in New York and Pennsylvania, both of which have implemented “unbundling” policies that allow customers to choose their gas commodity supplier, Distribution Corporation has retained a substantial majority of small sales customers. In both New York and Pennsylvania, approximately 9% of Distribution Corporation’s small-volume residential and commercial customers purchase their supplies from unregulated marketers. In contrast, almost all large-volume load is served by unregulated retail marketers. However, retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation, because in both jurisdictions, utility cost of service is recovered through rates and charges for gas delivery service, not gas commodity service.

Competition for transportation service to large-volume customers continues with local producers or pipeline companies attempting to sell or transport gas directly to end-users located within the Utility segment’s service territories without use of the utility’s facilities (i.e., bypass). In addition, while competition with fuel oil suppliers exists, natural gas retains its competitive position despite recent commodity pricing.

The Utility segment competes in its most vulnerable markets (the large commercial and industrial markets) by offering unbundled, flexible, high quality services. The Utility segment continues to advance programs promoting the efficient use of natural gas.

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in jurisdictions that impact the Utility segment. New York, for example, adopted the Climate Leadership & Community Protection Act (CLCPA) in July 2019, which could

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ultimately result in increased competition from electric and geothermal forms of energy. However, given the extended time frames associated with the CLCPA's emission reduction mandates as discussed in Item 7, MD&A under the heading “Environmental Matters” and subheading “Environmental Regulation,” any meaningful competition resulting from the CLCPA cannot be determined.

Seasonality

Variations in weather conditions can materially affect the volume of natural gas delivered by the Utility segment, as virtually all of its residential and commercial customers use natural gas for space heating. The effect that this has on Utility segment margins in New York is largely mitigated by a weather normalization clause (WNC), which covers the eight-month period from October through May. Weather that is warmer than normal results in an upward adjustment to customers’ current bills, while weather that is colder than normal results in a downward adjustment, so that in either case projected delivery revenues calculated at normal temperatures will be largely recovered.

Volumes transported and stored by Supply Corporation and by Empire may vary significantly depending on weather, without materially affecting the revenues of those companies. Supply Corporation’s and Empire’s allowed rates are based on a straight fixed-variable rate design which allows recovery of fixed costs in fixed monthly reservation charges. Variable charges based on volumes are designed to recover only the variable costs associated with actual transportation or storage of gas.

Capital Expenditures

A discussion of capital expenditures by business segment is included in Item 7, MD&A under the heading “Investing Cash Flow.”

Environmental Matters

A discussion of material environmental matters involving the Company is included in Item 7, MD&A under the heading “Environmental Matters” and in Item 8, Note L — Commitments and Contingencies.

Miscellaneous

The Utility segment has numerous municipal franchises under which it uses public roads and certain other rights-of-way and public property for the location of facilities. When necessary, the Utility segment renews such franchises.

The Company makes its annual report on Form 10-K, quarterly reports on Form 10-Q, current reports on Form 8-K, and any amendments to those reports, available free of charge on the Company’s website, www.nationalfuelgas.com, as soon as reasonably practicable after they are electronically filed with or furnished to the SEC. The information available at the Company’s website is not part of this Form 10-K or any other report filed with or furnished to the SEC.

Human Capital

The Company aims to attract the best employees, to retain those employees through offering competitive benefits, career development and training opportunities while also prioritizing their safety and wellness, and to create a safe, inclusive and productive work environment for everyone. Human capital measures and objectives that the Company focuses on in managing its business include the safety of its employees, its voluntary attrition rate, the number of work stoppages, its employee benefits, employee development, and diversity and inclusion. Additional information regarding the Company’s human capital measures and objectives is contained in the Company’s recently published Corporate Responsibility Report, which is available on the Company’s website, www.nationalfuelgas.com. The information on the Company’s website is not, and will not be deemed to be, a part of this annual report on Form 10-K or incorporated into any of the Company’s other filings with the SEC.

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Employees and Collective Bargaining Agreements

The Company and its wholly-owned subsidiaries had a total of 2,188 full-time employees at September 30, 2021.

As of September 30, 2021, 48% of the Company’s active workforce was covered under collective bargaining agreements. The Company has agreements in place with collective bargaining units in New York into February 2025, as well as with one collective bargaining unit in Pennsylvania into May 2026. One agreement covering employees in a collective bargaining unit in Pennsylvania is scheduled to expire in April 2022 and negotiations with respect to renewing that agreement are likely to start in early 2022.

Safety

Safety is one of the Company’s guiding principles. In managing the business, the Company focuses on the safety of its employees and contractors and has implemented safety programs and management practices to promote a culture of safety. This includes required trainings for both field and office employees, as well as specific qualifications and certifications for field employees. The Company also ties executive compensation to safety related goals to emphasize the importance of and focus on safety at the Company.

The Company has continued to monitor and respond to developments related to the coronavirus (COVID-19) pandemic and limit exposure for our workforce. In response to the COVID-19 pandemic, the Company’s Pandemic Response Team has implemented workforce and facility changes designed to protect the health and safety of the Company’s employees. These efforts continue to include: remote and flexible work arrangements where possible, facility cleaning and sanitation protocols, policies on the use of personal protective equipment and employee health screening protocols.

Voluntary Attrition Rate

The Company measures the voluntary attrition rate of its employees in assessing the Company’s overall human capital. The Company has maintained a relatively low voluntary attrition rate (not including retirements) of 5.1%. Additionally, throughout the COVID-19 pandemic, the Company has not instituted any furloughs or workforce reductions.

No Work Stoppages

During the Company’s fiscal year, the Company did not incur any work stoppages (strikes or lockouts) and therefore experienced zero idle days for the fiscal year.

Employee Benefits

To attract employees and meet the needs of the Company’s workforce, the Company offers benefits packages to employees of its subsidiaries. The Company’s benefits package options may vary depending on type of employee and date of hire. Additionally, the Company continuously looks for ways to improve employee work-life balance and well-being.

Employee Development

The Company provides its employees with tools and development resources to enhance their skills and careers at the Company, including: (i) encouraging employees to discuss their professional development and identify interests or possible cross-training areas during annual performance reviews with their supervisors; (ii) offering corporate and technical training programs based on position, regulatory environment, and employee needs; (iii) providing a tuition aid program for educational pursuits related to present work or possible future positions; (iv) providing talent review and succession planning; (v) providing opportunities for on-the-job growth, through stretch assignments or temporary projects outside of an employee’s typical responsibilities; and (vi) offering one-on-one meetings for supervisory employees at the Company’s regulated subsidiaries to discuss career pathing and employee development.

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Diversity, Equity and Inclusion

The Company recognizes that a diverse talent pool provides the opportunity to gain a diversity of perspectives, ideas and solutions to help the Company succeed. As such, the Company approaches diversity from the top-down, which is reflected in the makeup of our Board of Directors and senior leadership team: three out of eleven directors are diverse, and four of the Company’s ten designated executive officers are women. The Company's Corporate Governance Guidelines incorporate the “Rooney Rule.” As a result, when identifying independent director candidates for nomination to the Board, the Nominating/Corporate Governance Committee is committed to including in any initial candidate pool qualified racially, ethnically and/or gender diverse candidates. Beginning in fiscal year 2021, the Compensation Committee adopted specific diversity and inclusion performance goals as part of the Company's Annual at Risk Compensation Incentive Plan and Executive Annual Compensation Incentive Program to link executive compensation to the Company's focus on diversity.

During fiscal year 2021, the Company furthered numerous initiatives to increase the diversity of our workforce and create a more inclusive environment. The Company created the new role of Director of Diversity and Inclusion (“D&I Director”) to spearhead diversity and inclusion initiatives across the organization. Part of that initiative is to focus on diversity when making hiring and promotional decisions. To attract diverse candidates, the Company works with community groups and organizations to help promote awareness of our job opportunities within diverse communities. The D&I Director maintains close partnerships with the employment teams, cultivates the Company’s relationships with community organizations, and focuses on initiatives to attract diverse candidates, vendors and suppliers. The executive team receives a monthly report about the composition of the Company’s salaried applicant pools to encourage the recruiting team to focus recruiting in diverse communities and identify resources needed to do so. The Company has also focused on encouraging diverse suppliers to receive the necessary certifications to participate in the industry and has added new diverse suppliers to its list of vendors in an effort to promote diversity.

The D&I Director also spearheads inclusion initiatives throughout the organization. To promote a more inclusive work environment, the Company has provided training opportunities available to employees relating to Unconscious Bias Training, Building an Inclusive Culture with Intention, and Micro-aggressions. In addition, the Company has several policies that reinforce its commitment to diversity and inclusion within the workplace. The Company’s Employee Handbook Policy includes equal employment opportunity commitments and nondiscrimination and anti-harassment disclosures, which communicate the Company’s expectations with respect to maintaining a professional workplace free of harassment. The Company prohibits discrimination or harassment against any employee or applicant on the basis of sex, race/ethnicity, or the other protected categories listed within the Company’s Non-Discrimination and Anti-Harassment Policy. This policy is mailed to employees annually with an employee survey, and employees must acknowledge that they have received the policy. The Company reiterates its commitment to a harassment free workplace through this process, as well as through prevention training for employees. Annually, the Company’s Chief Executive Officer reinforces the Company’s commitment to equal employment opportunity by signing a corporate Equal Employment Opportunity policy statement. This statement is then displayed at Company locations, included in employee handbooks, and discussed with new hires during their onboarding process.

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Executive Officers of the Company as of November 15, 2021(1)


Name and Age (as of November 15, 2021)						Current Company Positions and Other Material Business Experience During Past Five Years
David P. Bauer (52)						Chief Executive Officer of the Company since July 2019. President of Supply Corporation from February 2016 through June 2019. Treasurer and Principal Financial Officer of the Company from July 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.
Donna L. DeCarolis (62)						President of Distribution Corporation since February 2019. Ms. DeCarolis previously served as Vice President of Business Development of the Company from October 2007 through January 2019.
Michael P. Kasprzak (63)						President of Midstream Company since August 2018. Vice President of Midstream Company from July 2017 through July 2018. Mr. Kasprzak previously served as Assistant Vice President of Supply Corporation from March 2009 until July 2017.
Ronald C. Kraemer (65)						Chief Operating Officer of the Company since March 2021, President of Supply Corporation since July 2019 and President of Empire since August 2008. Mr. Kraemer previously served as Senior Vice President of Supply Corporation from June 2016 through June 2019.
Karen M. Camiolo (62)						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 (55)						Controller and Principal Accounting Officer of the Company since July 2019. Controller of Distribution Corporation, Supply Corporation, Empire, and Midstream Company since 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 from July 2012 through January 2017.
Martin A. Krebs (51)						Chief Information Officer of the Company since 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. Krebs' prior employers are not subsidiaries or affiliates of the Company.
Sarah J. Mugel (57)						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 Assistant Secretary of the Company from June 2016 through June 2018.
Justin I. Loweth (43)						President of Seneca Resources Company since May 2021. Mr. Loweth previously served as Senior Vice President of Seneca Resources Company from October 2017 through April 2021 and as Vice President of Seneca Resources Company from September 2012 through September 2017.

(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.

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Item 1A			Risk Factors

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 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 existing 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, taking into account the incremental issuance, and using a pro forma balance sheet as of the last day of the 12-month period used in the interest coverage test, the Company must maintain a ratio of long-term debt to consolidated assets (as defined under the 1974 indenture) of not more than 60%. The 1974 indenture defines consolidated assets as total assets less a number of items, including current and accrued liabilities. Depending on their magnitude, factors that reduce the Company’s operating income and/or total assets, including impairments (i.e., write-downs) of the Company’s oil and natural gas properties, or that increase current and accrued liabilities, like short-term borrowings and "out of the money" derivative financial instruments, could contribute to the Company’s inability to meet the interest coverage test or debt-to-assets ratio.

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 credit ratings published by S&P, Moody's Investors Service, Inc. and Fitch Ratings, Inc. A downgrade in the Company's credit ratings could increase borrowing costs, restrict or eliminate access to commercial paper markets, negatively impact the availability of capital from uncommitted sources, and require the Company’s subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. Additionally, $1.1 billion 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 a credit rating assigned to the notes below investment grade. In addition to the $1.1 billion, 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.

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

Climate change, and the laws, regulations and other initiatives to address climate change, may impact the Company’s financial results. In early 2021, the U.S. rejoined the Paris Agreement, the international effort to establish emissions reduction goals for signatory countries. Under the Paris Agreement, signatory countries are expected to submit their nationally determined contributions to curb greenhouse gas emissions and meet the agreed temperature objectives every five years. On April 22, 2021, the federal administration announced the U.S. nationally determined contribution to achieve a fifty to fifty-two percent reduction from 2005 levels in economy-wide net greenhouse gas pollution by 2030. In addition to the recent federal reentry into the Paris

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Agreement, 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. Recent executive orders from the new federal administration, in addition to federal, state and local legislative and regulatory initiatives proposed or adopted 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 and/or production of gas and oil, establishment of a carbon tax and/or methane fee, lack of support for system modernization, 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, methane fee or carbon tax 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 in 2019, the New York State legislature passed the CLCPA, which created emission reduction and electric generation mandates, and could ultimately impact the Utility segment’s customer base and business. The New York State legislature, in early 2021, proposed a bill known as the Climate and Community Investment Act, which proposed an escalating fee starting at $55 per short ton of carbon dioxide equivalent on any carbon-based fuels sold, used or brought into the state. That bill did not pass, but it, or something similar to it, may be proposed in the future. Legislation or regulation that aims to reduce greenhouse gas emissions could also include greenhouse gas emissions limits and reporting requirements, carbon taxes and/or similar fees on carbon dioxide, methane or equivalent emissions, restrictive permitting, increased efficiency standards requiring system remediation and/or changes in operating practices, and incentives or mandates to conserve energy or use renewable energy sources. Additionally, the trend toward increased conservation, change in consumer behaviors, 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 technology. There are also increasing litigation risks associated with climate change concerns and related disclosures. Increased litigation 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.

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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 planned distribution and transmission pipeline 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. Additionally, supply chain disruptions resulting from the COVID-19 pandemic, and the associated costs and inflation related thereto, could have an impact on the Company's operations. 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 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 regulatory prohibitions and/or limitations on terminations of service, also impact its collections of accounts receivable. Customers of the Company’s Utility segment may have 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. 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 COVID-19 related expenses incurred above those embedded in rates resulting from directives contained in certain PaPUC orders, 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, for example during periods of reduced production. Any of these events could have a material adverse effect on the Company’s results of operations, financial condition and cash flows.

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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.

Loans to the Company under its credit facility may be base rate loans or LIBOR loans. LIBOR is the subject of national, international and other regulatory guidance and proposals for reform. For example, the U.K.’s Financial Conduct Authority, which regulates LIBOR, has announced that it intends to phase out LIBOR as a benchmark. The Federal Reserve Bank of New York publishes a Secured Overnight Funding Rate (“SOFR”), which the Alternative Reference Rates Committee recommended as an alternative reference rate to U.S. Dollar LIBOR. It is not possible to predict what effect the phase out of LIBOR, or a change to SOFR or other alternative rates may have on financial markets for LIBOR-linked financial instruments.

The Company’s current committed credit facilities provide a mechanism for determining an alternative benchmark rate of interest to U.S. Dollar LIBOR. One of those facilities, the Company’s 364-Day Credit Agreement, matures at the end of calendar year 2022, and the Company’s uncommitted lines of credit are reviewed on an annual basis. The phase out of LIBOR, or a change to SOFR or other alternative rates, whether in connection with borrowings under the current committed credit facilities, or borrowings under replacement facilities or lines of credit, could expose the Company’s future borrowings to less favorable rates. If the phase out of LIBOR, or a change to SOFR or other alternative rates, results in increased alternative interest rates or if the Company's lenders have increased costs due to such phase out or changes, then the Company's debt that uses benchmark rates could be affected and, in turn, the Company's cash flows and interest expense could be adversely impacted.

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

Financial results 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 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 and global 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 and/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 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.

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 pipeline system increases relative to the 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 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

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

In the Company’s Utility segment, during periods when natural gas prices are significantly higher than historical levels, customers may have trouble paying the resulting higher bills, which could increase bad debt expenses and ultimately reduce earnings. Additionally, increases in the cost of purchased gas affect cash flows and can therefore impact the amount or availability of the Company’s capital resources.

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 a substantial majority of the Company’s expected energy production over the course of the 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.

The nature of these hedging contracts could lead to potential liquidity impacts in scenarios of significant increases in natural gas or crude oil prices if the Company has hedged its current production at prices below the current market price. Hedging collateral deposits represent the cash held in Company funded margin accounts to serve as collateral for hedging positions used in the Company’s Exploration and Production segment. A significant increase in natural gas prices may cause the Company’s outstanding derivative instrument contracts to be in a liability position creating margin calls on the Company’s hedging arrangements, which could require the Company to temporarily post significant amounts of cash collateral with our hedge counterparties. That interest-bearing cash collateral is returned to us in whole or in part upon a reduction in forward market prices, depending on the amount of such reduction, or in whole upon settlement of the related derivative contract.

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.

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

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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 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 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 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 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 present value of the 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 gas (based on first day of the month prices and 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 authoritative accounting and reporting guidance require that the investment must be written down to the 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 the fourth calendar month following the impairment. In addition, because an impairment results in a charge to retained earnings, it lowers the Company's total capitalization, all other things being equal, and increases the Company's debt to capitalization ratio. As a result, an impairment can impact the Company's ability to maintain compliance with the debt to capitalization covenant set forth in its credit facilities. For the fiscal year ended September 30, 2020 and the quarter ended

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December 31, 2020, the Company recognized non-cash, pre-tax impairment charges on its oil and natural gas properties of $449.4 million and $76.2 million, respectively.

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 or variants thereof, 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 the COVID-19 pandemic, the situation continues to 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.

Significant changes in legislation or regulatory policy to address the COVID-19 pandemic could adversely impact the Company. Although it is not possible to predict the ultimate impact of the COVID-19 pandemic, including on the Company’s business, results of operations, cash flows or financial positions, such impacts that may be material include, but are not limited to: (i) a significant reduction in near-term demand for natural gas and/or oil; (ii) increased late or uncollectible customer payments; (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 work-from-home arrangements, the potential impact of vaccine mandates, and increased purchases of personal protective equipment as the Company assesses and implements its return-to-work plan; (v) difficulties in obtaining financing on acceptable terms or at all for working capital, capital expenditures and other investments, or 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; 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. These events, in turn, could 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. The Company also seeks, but may be unable, to secure written indemnification agreements with contractors that 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.

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

The Company’s information technology and operational technology systems are subject to attempts by others to gain unauthorized access, 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, regulations and directives. 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 and operational 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 has 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 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.

The amount and timing of actual future oil and 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 gas, including numerous uncertainties inherent in estimating quantities of proved oil and gas reserves and in projecting future rates of production and timing of development expenditures. The future success of the Company’s Exploration and Production and Gathering segments depends on its ability to develop additional oil and 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 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.

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The physical risks associated with climate change may adversely affect the Company’s operations and financial results.

Climate change could create acute and/or chronic physical risks to the Company’s operations, which may adversely affect financial results. Acute physical risks include more frequent and severe weather events, which may result in adverse physical effects on portions of the country’s gas infrastructure, and could disrupt the Company’s supply chain and ultimately its operations. Disruption of production activities, as well as transportation and distribution systems, could result in reduced operational efficiency, and customer service interruption. Severe weather events could also cause physical damage to facilities, all of which could lead to reduced revenues, increased insurance premiums or increased operational costs. To the extent the Company’s regulated businesses are unable to recover those costs, or if the recovery of those costs results in higher rates and reduced demand for Company services, the Company’s future financial results could be adversely impacted. Chronic physical risks include long-term shifts in climate patterns resulting in new storm patterns or chronic increased temperatures, which could cause demand for gas to increase or decrease as a result of warmer weather and less degree days, and adversely impact the Company's future financial results.

REGULATORY RISKS

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.

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 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 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 pipelines and underground storage facilities. If as a result of these or similar new laws or regulations the Company incurs material compliance costs that it is unable to recover fully through rates or otherwise offset, the Company's financial condition, 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. 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 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 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 addition, the FERC exercises jurisdiction over the construction and operation of interstate gas transmission facilities and also possesses significant penalty authority with respect to violations of the laws and regulations it administers.

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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 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 and/or cash flows may decrease.

Environmental regulation significantly affects the Company’s business.

The Company’s business operations are subject to federal, state, and local laws, regulations and agency policies relating to environmental protection including obtaining and complying with permits, leases, approvals, consents and certifications from various governmental and permit authorities. These laws, regulations and policies 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.

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 gas drilling activities. Because the costs of such compliance are significant, additional regulation could negatively affect the Company’s business.

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

Due to the Marcellus and Utica Shale 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 of potentially hazardous materials, and environmental and safety issues regarding 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, which could lead to increased operating costs and increased risks of litigation for the Company.

The Company could be adversely affected by the delayed recovery or 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

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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. Extreme weather events, variations in seasonal weather, and other events disrupting supply and/or demand could cause the Company to experience unforeseeable and unprecedented increases in the costs of purchased gas. Any prudently incurred gas costs could be subject to deferred recovery if regulators determine such costs are detrimental to customers in the short-term. Furthermore, 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 delayed recovery or disallowance of purchased gas costs could have a material adverse effect on cash flow and earnings.

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.


Item 2			Properties

General Information on Facilities

The net investment of the Company in property, plant and equipment was $6.4 billion at September 30, 2021. The Exploration and Production segment constitutes 31.0% of this investment, and is primarily located in the Appalachian region of the United States and in California. Approximately 56.4% 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 western Pennsylvania. The Gathering

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segment constitutes 12.6% of the Company’s investment in net property, plant and equipment, and is located in northwestern and central Pennsylvania. 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 customers in New York and Pennsylvania. Net property, plant and equipment has increased $1.9 billion, or 43.3%, since September 30, 2016. The five year increase is net of impairments of oil and gas producing properties recorded in 2020 and 2021 ($449 million and $76 million, respectively).

The Exploration and Production segment had a net investment in property, plant and equipment of $2.0 billion at September 30, 2021.

The Pipeline and Storage segment had a net investment of $2.0 billion in property, plant and equipment at September 30, 2021. Transmission pipeline represents 32% of this segment’s total net investment and includes 2,264 miles of pipeline utilized to move large volumes of gas throughout its service area. Storage facilities represent 13% of this segment’s total net investment and consist of 30 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 388 miles of pipeline. Net investment in storage facilities includes $81.1 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 32 compressor stations with 226,316 installed horsepower that represent 28% 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 2021 peak day sendout for transportation service of 2,133 MMcf, which occurred on February 7, 2021. Withdrawals from storage of 606.3 MMcf provided approximately 28% of the requirements on that day.

The Gathering segment had a net investment of $0.8 billion in property, plant and equipment at September 30, 2021. Gathering lines and related compressor stations represent substantially all of this segment’s total net investment, including 355 miles of pipelines utilized to move Appalachian production (including Marcellus and Utica shales) to various transmission pipeline receipt points. The Gathering segment has 23 compressor stations with 121,300 installed horsepower.

The Utility segment had a net investment in property, plant and equipment of $1.6 billion at September 30, 2021. The net investment in its gas distribution network (including 15,008 miles of distribution pipeline) and its service connections to customers represent approximately 49% and 32%, respectively, of the Utility segment’s net investment in property, plant and equipment at September 30, 2021.

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 the Appalachian region of the United States and in California. The Company's development activities in the Appalachian region are focused primarily in the Marcellus and Utica shales. Further discussion of oil and gas producing activities is included in Item 8, Note N — Supplementary Information for Oil and Gas Producing Activities. Note N sets forth proved developed and undeveloped reserve information for Seneca. The September 30, 2021, 2020 and 2019 reserves shown in Note N are valued 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. The reserves were estimated by Seneca’s petroleum engineers and were audited by independent petroleum engineers from Netherland, Sewell & Associates, Inc. Note N discusses the qualifications of the Company's petroleum 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 proved developed and undeveloped natural gas reserves increased from 3,325 Bcf at September 30, 2020 to 3,723 Bcf at September 30, 2021. This increase is attributed to extensions and discoveries of 689 Bcf and revisions of previous estimates of 23 Bcf, partially offset by production of 314 Bcf. Upward revisions

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included 74 Bcf of price-related revisions and 29 Bcf of revisions related to positive performance improvements including reduced operating expenses. Downward revisions of 80 Bcf from the removal of 8 PUD locations were due to continued integration of the recently acquired Tioga assets, as well as other operational optimizations that resulted in pad layout and development schedule changes.

Seneca’s proved developed and undeveloped oil reserves decreased from 22,100 Mbbl at September 30, 2020 to 21,537 Mbbl at September 30, 2021. The decrease of 563 Mbbl is attributed to production of 2,235 Mbbl and downward revisions of previous estimates of 579 Mbbl, partially offset by positive price-related revisions of 1,210 Mbbl and extensions and discoveries of 1,041 Mbbl, primarily occurring in the West Coast region.

On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 3,458 Bcfe at September 30, 2020 to 3,853 Bcfe at September 30, 2021. This increase is attributed to extensions and discoveries of 696 Bcfe and upward revisions of previous estimates of 26 Bcfe, partially offset by production of 327 Bcfe.

Seneca's proved developed and undeveloped natural gas reserves increased from 2,950 Bcf at September 30, 2019 to 3,325 Bcf at September 30, 2020. This increase was attributed to extensions and discoveries of 7 Bcf and acquisitions of 684 Bcf partially offset by downward revisions of 88 Bcf and production of 227 Bcf. Of the total net downward gas revisions of 88 Bcf, 8 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 were 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 on producing wells combined with longer laterals on certain wells.

Seneca’s proved developed and undeveloped oil reserves decreased from 24,873 Mbbl at September 30, 2019 to 22,100 Mbbl at September 30, 2020. The decrease of 2,773 Mbbl was attributed to production of 2,348 Mbbl and downward revisions of previous estimates of 713 Mbbl, partially offset by extensions and discoveries of 288 Mbbl, primarily occurring in the West Coast region. Downward revisions were mainly a result of lower oil prices of 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 417 Mbbl due to field performance.

On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 3,099 Bcfe at September 30, 2019 to 3,458 Bcfe at September 30, 2020. This increase was attributed to acquisitions of 684 Bcfe and extensions and discoveries of 9 Bcfe, partially offset by production of 241 Bcfe and downward revisions of previous estimates of 93 Bcfe.

At September 30, 2021, the Company’s Exploration and Production segment had delivery commitments for production of 2,170 Bcfe (mostly natural gas as commitments for crude oil were insignificant). The Company expects to meet those commitments through the future production of reserves that are currently classified as proved reserves and future extensions and discoveries.

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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
	2021			2020			2019
United States
Appalachian Region
Average Sales Price per Mcf of Gas	$	2.46	(1)	$	1.75	(1)	$	2.40	(1)
Average Sales Price per Barrel of Oil	$	48.02		$	45.69		$	57.14
Average Sales Price per Mcf of Gas (after hedging)	$	2.22		$	2.05		$	2.41
Average Sales Price per Barrel of Oil (after hedging)	$	48.02		$	45.69		$	57.14
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	$	0.67	(1)	$	0.68	(1)	$	0.67	(1)
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	856		(1)	616		(1)	537		(1)
West Coast Region
Average Sales Price per Mcf of Gas	$	6.34		$	3.82		$	5.15
Average Sales Price per Barrel of Oil	$	60.50		$	45.94		$	64.18
Average Sales Price per Mcf of Gas (after hedging)	$	6.34		$	3.82		$	5.15
Average Sales Price per Barrel of Oil (after hedging)	$	56.55		$	56.97		$	61.66
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	$	3.74		$	3.14		$	3.47
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	41			44			43
Total Company
Average Sales Price per Mcf of Gas	$	2.49		$	1.77		$	2.43
Average Sales Price per Barrel of Oil	$	60.49		$	45.94		$	64.17
Average Sales Price per Mcf of Gas (after hedging)	$	2.25		$	2.07		$	2.44
Average Sales Price per Barrel of Oil (after hedging)	$	56.54		$	56.96		$	61.65
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	$	0.82		$	0.84		$	0.88
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	897			660			580

(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, 2021, 2020 and 2019) contributed 597 MMcfe, 463 MMcfe and 447 MMcfe of daily production in 2021, 2020 and 2019, respectively. The average lifting costs (per Mcfe) were $0.70 in 2021, $0.70 in 2020 and $0.68 in 2019. The Utica Shale fields (which exceed 15% of total reserves at September 30, 2021, 2020 and 2019) contributed 255 MMcfe, 151 MMcfe and 88 MMcfe of daily production in 2021, 2020 and 2019, respectively. The average lifting costs (per Mcfe) were $0.62 in 2021, $0.62 in 2020 and $0.63 in 2019.

Productive Wells


	Appalachian Region		West Coast Region		Total Company
At September 30, 2021	Gas	Oil	Gas	Oil	Gas	Oil
Productive Wells — Gross	947	—	—	1,811	947	1,811
Productive Wells — Net	822	—	—	1,777	822	1,777

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Developed and Undeveloped Acreage


At September 30, 2021	Appalachian Region		West Coast Region	Total Company
Developed Acreage
— Gross	660,951		17,322	678,273
— Net	651,354		15,689	667,043
Undeveloped Acreage
— Gross	687,546		—	687,546
— Net	647,652		—	647,652
Total Developed and Undeveloped Acreage
— Gross	1,348,497		17,322	1,365,819
— Net	1,299,006	(1)	15,689	1,314,695

(1)Of the 1,299,006 Total Developed and Undeveloped Net Acreage in the Appalachian region as of September 30, 2021, there are a total of 1,228,819 net acres in Pennsylvania. Of the 1,228,819 total net acres in Pennsylvania, shale development in the Marcellus, Utica or Geneseo shales has occurred on approximately 113,249 net acres, or 9.2% 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, 2021, the aggregate amount of gross undeveloped acreage expiring in the next three years and thereafter are as follows: 5,879 acres in 2022 (4,717 net acres), 2,569 acres in 2023 (2,368 net acres), 15,203 acres in 2024 (14,310 net acres) and 198,751 acres thereafter (194,794 net acres). The remaining 465,144 gross acres (431,463 net acres) represent non-expiring oil and gas rights owned by the Company. Of the acreage that is currently scheduled to expire in 2022, 2023 and 2024, Seneca has 12.9 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	2021	2020	2019	2021	2020	2019
United States
Appalachian Region
Net Wells Completed
— Exploratory	—	—	—	—	1.00	—
— Development(1)	47.83	39.84	40.00	2.00	6.50	7.00
West Coast Region
Net Wells Completed
— Exploratory	—	—	—	—	—	—
— Development	10.00	34.00	44.00	—	—	1.00
Total Company
Net Wells Completed
— Exploratory	—	—	—	—	1.00	—
— Development	57.83	73.84	84.00	2.00	6.50	8.00

(1)Fiscal 2021, 2020 and 2019 Appalachian region dry wells include 2, 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 2021, 2020 and 2019 after the Company determined it would not continue development

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activities. The remaining 2 dry wells in fiscal 2020 and 4 dry wells in 2019 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, 2021	Appalachian Region	West Coast Region	Total Company
Wells in Process of Drilling(1)
— Gross	64.00	—	64.00
— Net	59.00	—	59.00

(1)Includes wells awaiting completion.


Item 3			Legal Proceedings

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


Item 4			Mine Safety Disclosures

Not Applicable.

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PART II


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

At September 30, 2021, there were 9,567 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 H — Capitalization and Short-Term Borrowings.

On July 1, 2021, the Company issued a total of 8,290 unregistered shares of Company common stock to the ten non-employee directors of the Company then serving on the Board of Directors of the Company, consisting of 829 shares to each such 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, 2021. The Company issued an additional 163 unregistered shares in the aggregate on July 15, 2021, pursuant to the dividend reinvestment feature of the Company's Deferred Compensation Plan for Directors and Officers, to the six non-employee directors who elected to defer the shares issued for the quarter ended September 30, 2021. 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, 2021	11,620	$	52.17	—	6,971,019
Aug. 1-31, 2021	13,423	$	52.80	—	6,971,019
Sept. 1-30, 2021	11,545	$	51.87	—	6,971,019
Total	36,588	$	52.31	—	6,971,019

(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, 2021, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 36,588 shares purchased other than through a publicly announced share repurchase program, 36,283 were purchased for the Company’s 401(k) plans and 305 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 Company has not repurchased any shares since September 17, 2008. The repurchase program has no expiration date and management would discuss with the Company's Board of Directors any future repurchases under this program.

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Performance Graph

The following graph compares the Company’s common stock performance with the performance of the S&P 500 Index, the S&P Mid Cap 400 Gas Utility Index and the S&P 1500 Oil & Gas Exploration & Production Index for the period September 30, 2016 through September 30, 2021. The graph assumes that the value of the investment in the Company’s common stock and in each index was $100 on September 30, 2016 and that all dividends were reinvested.


	2016	2017	2018	2019	2020	2021
National Fuel	$100	$108	$110	$95	$86	$115
S&P 500 Index	$100	$119	$140	$146	$168	$218
S&P Mid Cap 400 Gas Utility Index (S4GASU)	$100	$116	$131	$136	$96	$117
S&P 1500 Oil & Gas Exp & Prod Index (S15OILP)	$100	$88	$111	$72	$40	$93

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.

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Item 6			(Reserved)


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

OVERVIEW

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

Corporate Responsibility

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

Part of the Board and management’s strategic and capital spending decision process includes identifying and assessing climate-related risks and opportunities. Management reports quarterly to the Board on critical and potentially emerging risks, including climate-related risks, as part of the Enterprise Risk Management process. Since the Company operates an integrated business with assets being utilized for, and benefiting from, the production, transportation and consumption of natural gas, the Board and management consider physical and transitional climate risks, including policy and legal risks, technological developments, shifts in market conditions, including future natural gas usage, and reputational risks, and the impact of those risks on the Company’s business. The Company reviews and considers adjustments to its approach to capital investment in response to these transitional developments, with its long-term, returns-focused approach, along with its integrated and diversified business model positioning it to take advantage of potential opportunities to participate in the ongoing efforts to decarbonize our economy.

The Company recognizes the important role of ongoing system modernization and efficiency in reducing greenhouse gas emissions and remains focused on reducing the Company’s carbon footprint, with these efforts positioning natural gas, and the Company’s related infrastructure, to remain an important part of the energy complex. In March 2021, the Company set greenhouse gas reduction targets associated with the Company's utility delivery system. To further our ongoing efforts to lower the Company's emissions profile, in September 2021 the Company also established methane intensity reduction targets at each of its businesses, as well as an absolute greenhouse gas emissions reduction target for the consolidated Company. The Company's ability to estimate accurately the time, costs and resources necessary to meet these emissions reduction targets may change as environmental exposures and opportunities change, technology advances and regulatory updates are issued. In addition to these targets, the Company understands the importance of scenario analysis to our stakeholders and plans to publish further analysis of the resilience of the Company’s businesses to a lower carbon economy, in line with the Task Force on Climate Related Financial Disclosures framework.

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Fiscal 2021 Highlights

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

1.The critical accounting estimates of the Company;

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

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

4.Other Matters, including: (a) 2021 and projected 2022 funding for the Company’s pension and other post-retirement benefits; (b) disclosures and tables concerning market risk sensitive instruments; (c) rate matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions; (d) environmental matters; and (e) new authoritative accounting and financial reporting guidance.

The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report, which includes a comparison of our Results of Operations and Capital Resources and Liquidity for fiscal 2021 and fiscal 2020. For a discussion of the Company's earnings, refer to the Results of Operations section below. A discussion of changes in the Company’s results of operations from fiscal 2019 to fiscal 2020 has been omitted from this Form 10-K, but may be found in Item 7, MD&A, of the Company’s Form 10-K for the fiscal year ended September 30, 2020, filed with the SEC on November 20, 2020.

The Company is closely monitoring and responding to developments related to the novel coronavirus (COVID-19) and is taking steps to limit operational impacts and the potential exposure for our workforce and customers. Refer to Risk Factors in Part I, Item 1A, Risk Factors, under Operational Risks in this Form 10-K for a more complete discussion of the risks to the Company associated with the COVID-19 pandemic.

The Company continues to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation's system, referred to as the FM100 Project, will upgrade a 1950’s era pipeline in northwestern Pennsylvania and create approximately 330,000 Dth per day of additional transportation capacity in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County, Pennsylvania to the Transcontinental Gas Pipe Line Company, LLC system at Leidy, Pennsylvania. Construction activities for the FM100 Project are fully in progress. The FM100 Project has an expected target in-service date of December 1, 2021 and a preliminary cost estimate of approximately $240 million. This project is expected to provide incremental annual transportation revenues of approximately $50 million. The FM100 Project is discussed in more detail in the Capital Resources and Liquidity section that follows. Another project on Empire’s system, referred to as the Empire North Project, which allows for the transportation of 205,000 Dth per day of additional supplies from interconnections in Tioga County, Pennsylvania, to the TC Energy pipeline, and the Tennessee Gas Pipeline L.L.C. (TGP) 200 Line, was placed in-service during the fourth quarter of fiscal 2020. The Empire North project provided incremental transportation revenues in the Pipeline and Storage segment of $26.9 million in fiscal 2021. For further discussion of the Pipeline and Storage segment's revenues and earnings, refer to the Results of Operations section below.

In advance of the expected late calendar 2021 online date for Seneca’s 330,000 Dth per day of incremental capacity on the Leidy South Project, which is the companion project to the Company's FM100 Project, the Company's Exploration and Production segment added a second horizontal drilling rig in the Appalachian region in January 2021. Production from the first pad that was drilled in connection with this additional activity is expected in early fiscal 2022, with this incremental production reaching Transco Zone 6 markets during the winter heating season. Seneca anticipates an increase in natural gas production in fiscal 2022 as a result of this incremental pipeline capacity. The Company's Exploration and Production segment continues to grow, as evidenced by an 11% growth in proved reserves from the prior year to a total of 3,853 Bcfe at September 30, 2021.

The Company uses the full cost method of accounting for determining the book value of its oil and natural gas properties in the Exploration and Production segment and that book value is subject to a quarterly ceiling test. This is discussed in more detail in the Critical Accounting Estimates section that follows. In addition to the significant non-cash impairment charges under the ceiling test that the Company recorded during fiscal 2020,

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the Company recorded a non-cash impairment charge under the ceiling test for the year ended September 30, 2021 of $76.2 million ($55.2 million after-tax), which was recorded during the quarter ended December 31, 2020. Please refer to the Critical Accounting Estimates section below for a sensitivity analysis concerning commodity price changes.

From a financing perspective, on February 24, 2021, the Company issued $500.0 million of 2.95% notes due March 1, 2031. The proceeds of the debt issuance were used for general corporate purposes, including the redemption of $500.0 million of the Company's 4.90% notes on March 11, 2021 that were scheduled to mature in December 2021. The Company redeemed those notes for $515.7 million, plus accrued interest.

On February 3, 2021, the Company amended its existing 364-day credit facility agreement. The amendment extends the maturity date of the facility from May 3, 2021 to December 30, 2022, and increases the commitment provided under the facility from $200.0 million to $250.0 million of unsecured committed revolving credit access. The Company entered into the amendment with a syndicate of twelve banks, all of which are also lenders under the Company's existing $750.0 million multi-year credit facility.

The Company expects to use cash on hand and cash from operations, as well as short-term borrowings, to meet its financing needs for fiscal 2022.

CRITICAL ACCOUNTING ESTIMATES

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

Oil and Gas Exploration and Development Costs. In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this accounting methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center.

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

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determined that the unproved properties are impaired. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.

In addition to depletion under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. The full cost ceiling test is an impairment test prescribed by SEC Regulation S-X Rule 4-10. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The estimates of future production and future expenditures are based on internal budgets that reflect planned production from current wells and expenditures necessary to sustain such future production. The amount of the ceiling can fluctuate significantly from period to period because of additions to or subtractions from proved reserves and significant fluctuations in oil and gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment charge must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. At September 30, 2021, the ceiling exceeded the book value of the oil and gas properties by approximately $842.1 million. The 12-month average of the first day of the month price for crude oil for each month during 2021, based on posted Midway Sunset prices, was $56.66 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during 2021, based on the quoted Henry Hub spot price for natural gas, was $2.94 per MMBtu. (Note — because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for 2021. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the amounts the ceiling would have exceeded the book value of the Company's oil and gas properties at September 30, 2021 if natural gas prices were $0.25 per MMBtu lower than the average prices used at September 30, 2021, if crude oil prices were $5 per Bbl lower than the average prices used at September 30, 2021, and if both natural gas prices and crude oil prices were $0.25 per MMBtu and $5 per Bbl lower than the average prices used at September 30, 2021 (all amounts are presented after-tax). In all cases, these price decreases would not have resulted in an impairment charge. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

Ceiling Testing Sensitivity to Commodity Price Changes


(Millions)	$0.25/MMBtu Decrease in Natural Gas Prices		$5.00/Bbl Decrease in Crude Oil Prices		$0.25/MMBtu Decrease in Natural Gas Prices and $5.00/Bbl Decrease in Crude Oil Prices
Excess of Ceiling over Book Value under Sensitivity Analysis	$	567.0	$	806.8	$	531.7

It is difficult to predict what factors could lead to future impairments under the SEC’s full cost ceiling test. As discussed above, fluctuations in or subtractions from proved reserves, increases in development costs

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for undeveloped reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time.

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

Regulation. The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to the FASB authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting principles for certain types of rate-regulated activities provide that certain actual or anticipated costs that would otherwise be charged to expense can be deferred as regulatory assets, based on the expected recovery from customers in future rates. Likewise, certain actual or anticipated credits that would otherwise reduce expense can be deferred as regulatory liabilities, based on the expected flowback to customers in future rates. Management’s assessment of the probability of recovery or pass through of regulatory assets and liabilities requires judgment and interpretation of laws and regulatory commission orders. If, for any reason, the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the balance sheet and included in the income statement for the period in which the discontinuance of regulatory accounting treatment occurs. Such amounts would be classified as an extraordinary item. For further discussion of the Company’s regulatory assets and liabilities, refer to Item 8 at Note F — Regulatory Matters.

RESULTS OF OPERATIONS

EARNINGS

2021 Compared with 2020

The Company's earnings were $363.6 million in 2021 compared to a loss of $123.8 million in 2020. The increase in earnings of $487.4 million was primarily a result of higher earnings in the Exploration and Production segment, Pipeline and Storage segment, Gathering segment and All Other category. Lower earnings in the Utility segment, as well as a loss in the Corporate category, partially offset these increases. In the discussion that follows, all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings were impacted by the following events in 2021 and 2020:

2021 Events

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

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

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

2020 Events

•Non-cash impairment charges of $449.4 million ($326.3 million after-tax) recorded during 2020 for the Exploration and Production segment's oil and gas producing properties.

•A deferred tax valuation allowance of $56.8 million established during the quarter ended March 31, 2020, primarily in the Exploration and Production and Gathering segments.

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Earnings (Loss) by Segment


	Year Ended September 30
	2021		2020		2019
	(Thousands)
Exploration and Production	$	101,916	$	(326,904)	$	111,807
Pipeline and Storage	92,542		78,860		74,011
Gathering	80,274		68,631		58,413
Utility	54,335		57,366		60,871
Total Reported Segments	329,067		(122,047)		305,102
All Other	37,645		(269)		(1,811)
Corporate	(3,065)		(1,456)		999
Total Consolidated	$	363,647	$	(123,772)	$	304,290

EXPLORATION AND PRODUCTION

Revenues

Exploration and Production Operating Revenues


	Year Ended September 30
	2021		2020
	(Thousands)
Gas (after Hedging)	$	705,326	$	470,270
Oil (after Hedging)	126,369		133,712
Gas Processing Plant	2,960		2,374
Other	2,042		1,097
Operating Revenues	$	836,697	$	607,453

Production


	Year Ended September 30
	2021	2020
Gas Production (MMcf)
Appalachia	312,300	225,513
West Coast	1,720	1,889
Total Production	314,020	227,402
Oil Production (Mbbl)
Appalachia	2	3
West Coast	2,233	2,345
Total Production	2,235	2,348

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Average Prices


	Year Ended September 30
	2021		2020
Average Gas Price/Mcf
Appalachia	$	2.46	$	1.75
West Coast	$	6.34	$	3.82
Weighted Average	$	2.49	$	1.77
Weighted Average After Hedging(1)	$	2.25	$	2.07
Average Oil Price/Barrel (Bbl)
Appalachia	$	48.02	$	45.69
West Coast	$	60.50	$	45.94
Weighted Average	$	60.49	$	45.94
Weighted Average After Hedging(1)	$	56.54	$	56.96

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

2021 Compared with 2020

Operating revenues for the Exploration and Production segment increased $229.2 million in 2021 as compared with 2020. Gas production revenue after hedging increased $235.1 million primarily due to an $0.18 per Mcf increase in the weighted average price of gas after hedging coupled with an 86.6 Bcf increase in gas production. The increase in gas production was largely due to additional production from the acquisition of Appalachian upstream assets from SWEPI LP, a subsidiary of Royal Dutch Shell plc ("Shell") on July 31, 2020 combined with new Marcellus and Utica wells in the Appalachian region. This production increase occurred despite 4.0 Bcf of price-related curtailments in 2021, the majority of which occurred in the first quarter of the year. Oil production revenue after hedging decreased $7.3 million primarily due to a $0.42 per Bbl decrease in the weighted average price of oil after hedging combined with a 113 Mbbl decrease in crude oil production. In addition, other revenue increased $0.9 million and gas processing plant revenue increased $0.6 million.

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

Earnings

2021 Compared with 2020

The Exploration and Production segment’s earnings for 2021 were $101.9 million, an increase of $428.8 million when compared with a loss of $326.9 million for 2020. The increase in earnings was primarily attributable to a decrease in impairments of oil and gas properties ($326.3 million during 2020 compared to $55.2 million during 2021), higher natural gas production ($141.5 million) and higher natural gas prices after hedging ($44.2 million).

The establishment of a deferred tax valuation allowance in the quarter ended March 2020, as discussed more completely in Item 8 at Note G — Income Taxes, reduced earnings in 2020. The non-recurrence of this initial valuation allowance created an earnings increase in 2021 ($60.5 million). Partially offsetting this impact, the Exploration and Production segment experienced a higher effective tax rate during 2021 compared to 2020 ($6.7 million). The increase in the effective tax rate was primarily driven by a higher effective state income tax rate as a result of the Company's asset acquisition from Shell that caused a change in the mix of earnings between state jurisdictions, partially offset by a partial reversal of the valuation allowance that was established in the quarter ended March 2020.

The Exploration and Production segment’s earnings were also impacted by the recognition of a loss in March 2021 ($10.7 million) for this segment’s share of the premium paid by the Company to redeem $500 million of the Company’s 4.90% notes that were scheduled to mature in December 2021. Partially offsetting

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this impact, the Exploration and Production segment experienced lower interest expense ($2.5 million) due to lower weighted average interest rates resulting from the Company's issuance of a 2.95% coupon note in February 2021 as replacement debt for the 4.9% coupon note that was retired in March 2021.

In addition to the factors discussed above, the Exploration and Production segment's earnings were negatively impacted by lower crude oil production ($5.1 million), lower crude oil prices after hedging ($0.7 million), higher lease operating and transportation expenses ($50.3 million), higher depletion expense ($8.2 million), higher other operating expenses ($5.3 million) and higher other taxes ($5.2 million). The increase in lease operating and transportation expenses was primarily due to increased gathering and transportation costs in the Appalachian region and costs to operate the acquired Shell assets for the entire 2021 year. In addition, the West Coast region had higher steam fuel and well workover costs. The increase in depletion expense was primarily due to the increase in production, partially offset by a $0.15 decrease in the depletion rate as a result of the asset acquisition from Shell coupled with prior period non-cash ceiling test impairments. The increase in other operating expenses was largely due to an increase in accretion costs associated with asset retirement obligations, as well as higher personnel costs. The increase in accretion costs stemmed from the asset acquisition from Shell. The increase in other taxes was mainly attributed to increased impact fees in the Appalachian region due to added wells from the Shell acquisition combined with NYMEX gas price increases, shifting fees into a higher per well tier.

PIPELINE AND STORAGE

Revenues

Pipeline and Storage Operating Revenues


	Year Ended September 30
	2021		2020
	(Thousands)
Firm Transportation	$	254,853	$	228,457
Interruptible Transportation	996		934
	255,849		229,391
Firm Storage Service	83,032		79,031
Interruptible Storage Service	48		42
	83,080		79,073
Other	4,628		1,140
	$	343,557	$	309,604

Pipeline and Storage Throughput — (MMcf)


	Year Ended September 30
	2021	2020
Firm Transportation	770,284	752,773
Interruptible Transportation	1,460	2,859
	771,744	755,632

2021 Compared with 2020

Operating revenues for the Pipeline and Storage segment increased $34.0 million in 2021 as compared with 2020. The increase in operating revenues was primarily due to an increase in transportation revenues of $26.5 million, an increase in storage revenues of $4.0 million and an increase in other revenues of $3.5 million. The increase in transportation revenues was primarily attributable to new demand charges for transportation service from the Empire North Project, which was placed into service during the fourth quarter of fiscal 2020. Transportation revenue also increased due to an increase in Supply Corporation's transportation rates effective February 1, 2020 in accordance with Supply Corporation's rate case settlement. The settlement was approved by the FERC on June 1, 2020. The increase in transportation revenues was partially offset by the impact of a final

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true-up adjustment to increase revenue in 2020 associated with the Pipeline Safety and Greenhouse Gas (PS/GHG) surcharge that had been in effect under Supply Corporation's last rate case settlement (RP15-1310) but which ended with the effective date of Supply Corporation’s 2020 rate case settlement (February 1, 2020). It was also offset by a decrease in transportation revenues from miscellaneous contract revisions and terminations and a decrease in revenues from short-term seasonal contracts. The increase in storage revenues was largely attributable to an increase in Supply Corporation's storage rates related to its 2020 rate case settlement, combined with a surcharge for PS/GHG regulatory costs that went into effect in November 2020 associated with Supply Corporation’s 2020 rate case settlement. The PS/GHG regulatory costs surcharge is also applicable to transportation revenues, but it did not have a significant impact to the increase in transportation revenues for fiscal 2021. The increase in other revenues was primarily due to proceeds received during the quarter ended December 31, 2020 as a result of a contract buyout.

Transportation volume increased by 16.1 Bcf in 2021 as compared with 2020, primarily due to incremental volume from the Empire North Project, which was brought online on September 15, 2020, partially offset by a decrease in volume from a decline in capacity utilization by certain contract shippers. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

Earnings

2021 Compared with 2020

The Pipeline and Storage segment’s earnings in 2021 were $92.5 million, an increase of $13.6 million when compared with earnings of $78.9 million in 2020. The increase in earnings was primarily due to the impact of higher operating revenues of $26.8 million, as discussed above, combined with lower income tax expense ($2.7 million). The decrease in income tax expense was mainly due to permanent differences related to stock compensation activity as well as the timing of passing back excess deferred taxes to rate payers as a result of the 2017 Tax Reform Act per the Supply Corporation 2020 rate case settlement. These earnings increases were partially offset by an increase in depreciation expense ($6.7 million), higher interest expense ($6.5 million), and an increase in operating expenses ($2.4 million). The increase in depreciation expense was due to an increase in Supply Corporation's depreciation rates associated with its 2020 rate case settlement as well as incremental depreciation from the Empire North Project going into service, both mentioned above. The increase in interest expense was primarily due to interest on additional intercompany long-term borrowings associated with the Company's June 2020 debt issuance. The increase in operating expenses was mainly due to an increase in personnel and technology-related costs, higher vehicle fuel costs and higher power costs related to Empire's electric motor drive compressor station placed into service as part of the Empire North Project mentioned above, partially offset by a decrease in the reserve for preliminary project costs. Power costs related to Empire’s electric motor drive compressor station are offset by an equal amount of revenue due to a surcharge mechanism.

GATHERING

Revenues

Gathering Operating Revenues


	Year Ended September 30
	2021		2020
	(Thousands)
Gathering	$	193,264	$	142,893

Gathering Volume — (MMcf)


	Year Ended September 30
	2021	2020
Gathered Volume	366,033	264,305

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2021 Compared with 2020

Operating revenues for the Gathering segment increased $50.4 million in 2021 as compared with 2020, which was driven primarily by a 101.7 Bcf increase in gathered volume. The July 31, 2020 acquisition of midstream gathering assets from Shell (Tioga gathering system) was the primary driver of this increase. The Tioga gathering system and legacy Covington gathering assets recorded a 62.4 Bcf increase in gathered volume for the year ended September 30, 2021. Other contributors to the increase included the Clermont, Trout Run and Wellsboro gathering systems, which recorded increases of 16.2 Bcf, 11.9 Bcf and 11.2 Bcf, respectively. The increase in gathered volume can be attributed to the increase in Seneca's gross natural gas production in the Appalachian region, as discussed above.

Earnings

2021 Compared with 2020

The Gathering segment’s earnings in 2021 were $80.3 million, an increase of $11.7 million when compared with earnings of $68.6 million in 2020. The increase in earnings was primarily attributable to higher gathering revenues ($39.8 million) driven by the increase in gathered volume (discussed above). In 2020, the Gathering segment recorded an initial income tax benefit as an offset to the valuation allowance established in the Exploration and Production segment, as discussed above. The non-recurrence of this initial income tax benefit reduced earnings in 2021 ($3.8 million). This offset is a result of the Gathering and Exploration and Production segments’ subsidiaries filing a combined state tax return. The increase in earnings was also partially offset by higher operating expenses ($8.9 million), higher depreciation expense ($7.8 million), higher interest expense ($4.5 million) and higher income tax expense ($2.3 million). The increase in operating expenses was largely due to higher lease compression expense associated with the Tioga gathering system and major overhaul maintenance of compressor units at Clermont gathering system compressor stations during fiscal 2021. The increase in depreciation expense was largely due to higher plant balances associated with the Tioga gathering system. The increase in interest expense was primarily driven by additional intercompany long-term borrowings from the Company's long term debt issuances in June 2020 and February 2021. The Gathering segment also recognized a loss in March 2021 ($0.7 million) for its share of the premium paid by the Company to redeem $500 million of the Company's 4.90% notes that were scheduled to mature in December 2021. The increase in income tax expense was primarily driven by a higher effective state income tax rate as a result of the fiscal 2020 acquisition of midstream gathering assets from Shell that caused a change in the mix of earnings between state jurisdictions.

UTILITY

Revenues

Utility Operating Revenues


	Year Ended September 30
	2021		2020
	(Thousands)
Retail Revenues:
Residential	$	497,244	$	478,503
Commercial	63,954		61,643
Industrial	3,089		3,305
	564,287		543,451

Transportation	108,213		114,128
Other	(5,249)		(5,281)
	$	667,251	$	652,298

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Utility Throughput — million cubic feet (MMcf)


	Year Ended September 30
	2021	2020
Retail Sales:
Residential	61,038	60,977
Commercial	8,741	8,798
Industrial	475	537
	70,254	70,312

Transportation	66,012	68,272
	136,266	138,584

Degree Days


				Percent (Warmer) Colder Than
Year Ended September 30		Normal	Actual	Normal(1)		Prior Year(1)
2021	Buffalo, NY	6,617	5,731	(13.4)	%	(6.1)	%
	Erie, PA	6,147	5,221	(15.1)	%	(4.2)	%
2020	Buffalo, NY	6,653	6,103	(8.3)	%	(8.9)	%
	Erie, PA	6,181	5,449	(11.8)	%	(7.8)	%

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

2021 Compared with 2020

Operating revenues for the Utility segment increased $15.0 million in 2021 compared with 2020. The increase largely resulted from a $20.8 million increase in retail gas sales revenues. The increase in retail gas sales revenues was mainly attributable to the migration of residential transportation customers to retail service (which includes a significantly higher charge for purchased gas than transportation service), in addition to a modest increase in the cost of gas sold (per Mcf). This increase was partially offset by a $5.9 million decrease in transportation revenues. The decrease in transportation revenues was primarily due to a 2.3 Bcf decrease in transportation throughput due to the migration of residential transportation customers previously served by marketers to retail service provided by the Utility segment and warmer weather.

Purchased Gas

The cost of purchased gas is one of the Company’s largest operating expenses. Annual variations in purchased gas costs are attributed directly to changes in gas sales volume, the price of gas purchased and the operation of purchased gas adjustment clauses. Distribution Corporation recorded $274.8 million and $263.1 million of Purchased Gas expense during 2021 and 2020, respectively. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is not allowed to profit from fluctuations in gas costs. Purchased Gas expense recorded on the consolidated income statement matches the revenues collected from customers, a component of Operating Revenues on the consolidated income statement. Under mechanisms approved by the NYPSC in New York and the PaPUC in Pennsylvania, any difference between actual purchased gas costs and what has been collected from the customer is deferred on the consolidated balance sheet as either an asset, Unrecovered Purchased Gas Costs, or a liability, Amounts Payable to Customers. These deferrals are subsequently collected from the customer or passed back to the customer, subject to review by the NYPSC and the PaPUC. Absent disallowance of full recovery of Distribution Corporation’s purchased gas costs, such costs do not impact the profitability of the Company. Purchased gas costs impact cash flow from operations due to the timing of recovery of such costs versus the actual purchased gas costs incurred during a particular period. Distribution Corporation’s purchased gas adjustment clauses seek to mitigate this impact by adjusting revenues on either a quarterly or monthly basis.

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

Earnings

2021 Compared with 2020

The Utility segment’s earnings in 2021 were $54.3 million, a decrease of $3.1 million when compared with earnings of $57.4 million in 2020. The decrease in earnings was primarily attributable to higher operating expenses ($2.6 million), which were largely a result of higher personnel costs and an increase to the allowance for uncollectible accounts, higher depreciation expense ($1.7 million) primarily due to higher plant balances, higher income tax expense ($1.2 million), and the impacts of lower usage and weather on customer margins ($1.1 million). The increase to the allowance for uncollectible accounts is related to the COVID-19 pandemic as the Company recorded incremental expense due to the potential for future customer non-payment, given the current economic environment. These decreases were partially offset by the positive earnings impact related to the system modernization tracker ($3.7 million). The system modernization tracker is a rate mechanism in the Utility segment's New York jurisdiction that provides recovery of qualified leak prone pipe replacement costs.

The impact of weather variations on earnings in the Utility segment's New York rate jurisdiction is largely mitigated by that jurisdiction's weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility segment's New York customers. For 2021, the WNC contributed approximately $4.5 million to earnings, as the weather was warmer than normal. In 2020, the WNC contributed approximately $3.5 million to earnings, as the weather was warmer than normal.

ALL OTHER AND CORPORATE OPERATIONS

All Other and Corporate operations primarily includes the operations of NFR, the operations of Seneca’s Northeast Division and corporate operations. NFR previously marketed natural gas to industrial, wholesale, commercial, public authority and residential customers primarily in western and central New York and northwestern Pennsylvania. NFR completed the sale of its commercial and industrial contracts and certain other assets on August 1, 2020. This sale, in conjunction with the turn back of NFR's residential customers to Distribution Corporation, effectively ended NFR's operations. Seneca’s Northeast Division previously marketed timber from its New York and Pennsylvania land holdings. On December 10, 2020, the Company completed the sale of substantially all timber properties. Please refer to Item 8 at Note B — Asset Acquisitions and Divestitures for further discussion of the sale of timber properties.

Earnings

2021 Compared with 2020

All Other and Corporate operations had earnings of $34.6 million in 2021, an increase of $36.3 million when compared with a loss of $1.7 million in 2020. The increase in earnings was primarily attributable to the gain recognized on the sale of timber properties by Seneca's Northeast Division for $51.1 million ($37.0 million after-tax). This gain was offset by changes in unrealized gains on investments in equity securities. In 2021, the Company recorded unrealized gains of $0.1 million, while in 2020, the Company recorded unrealized gains of $1.3 million.

INTEREST CHARGES

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

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Interest on long-term debt increased $31.4 million in 2021 as compared to 2020. The Company redeemed $500.0 million of 4.90% notes in March 2021 and paid an early redemption premium of $15.7 million that was recorded as interest expense on long-term debt. The remaining increase is due largely to the higher average long-term debt balance stemming from the issuance of $500.0 million of 5.50% notes in June 2020. This increase was partially offset by a lower weighted average interest rate on long-term debt, stemming from the Company's issuance of $500.0 million of 2.95% notes in February 2021, which replaced $500.0 million of 4.90% notes that were retired in March 2021.

Other interest expense decreased $2.2 million in 2021 as compared to 2020. The decrease was primarily due to lower average short-term debt balances in 2021 compared to 2020 combined with lower average interest rates for 2021.

CAPITAL RESOURCES AND LIQUIDITY

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


	Year Ended September 30
	2021		2020
	(Millions)
Provided by Operating Activities	$	791.6	$	740.8
Capital Expenditures	(751.7)		(716.2)
Acquisition of Upstream Assets and Midstream Gathering Assets	—		(506.3)
Net Proceeds from Sale of Timber Properties	104.6		—
Other Investing Activities	13.8		(1.1)
Reduction of Long-Term Debt	(515.7)		—
Change in Notes Payable to Banks and Commercial Paper	128.5		(25.2)
Net Proceeds from Issuance of Long-Term Debt	495.3		493.0
Net Proceeds from Issuance (Repurchase) of Common Stock	(3.7)		161.6
Dividends Paid on Common Stock	(163.1)		(153.3)

Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	$	99.6	$	(6.7)

The Company expects to have adequate amounts of cash to meet both its short-term and long-term cash requirements. During 2022, cash provided by operating activities is expected to increase over the amount of cash provided by operating activities during 2021 and will be used to meet the Company's dividend requirements and reduce short-term borrowings. Capital expenditures in 2022 are expected to decrease as shown in the Estimated Capital Expenditures table shown below. There are no scheduled repayments of long-term debt in 2022. Looking at 2023 through 2024, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures in each of those years, which could lead to further capital investments in the business or reductions in short-term borrowings and a net reduction in long-term debt in 2023 while still allowing the Company to meet its dividend requirements. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.

OPERATING CASH FLOW

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

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

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of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.

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

The Company, in its Utility segment and Exploration and Production segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. Refer to Item 8 at Note L — Commitments and Contingencies under the heading “Other” for additional discussion concerning these contractual commitments as well as the amounts of future gas purchase, transportation and storage contract commitments expected to be incurred during the next five years and thereafter. Also refer to Item 8 at Note D – Leases for a discussion of the Company’s operating lease arrangements and a schedule of lease payments during the next five years and thereafter.

Net cash provided by operating activities totaled $791.6 million in 2021, an increase of $50.8 million compared with the $740.8 million provided by operating activities in 2020. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Pipeline and Storage segment, the Exploration and Production segment and the Gathering segment, partially offset by lower cash provided by operating activities in the Utility segment. The increase in the Pipeline and Storage segment was primarily due to higher cash receipts from transportation and storage service, which largely reflects an increase in Supply Corporation's transportation and storage rates effective February 1, 2020 and an increase in demand charges for transportation services from the Empire North Project that was placed in service during September 2020. The increase in the Exploration and Production segment and the Gathering segment was primarily due to higher cash receipts from natural gas production and gathering services in the Appalachian region, largely stemming from the July 31, 2020 acquisition of upstream assets and midstream gathering assets from Shell. The decrease in Utility segment is primarily due to the timing of gas cost recovery and the timing of receivable collections.

INVESTING CASH FLOW

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets, including non-cash capital expenditures, totaled $769.9 million and $1.2 billion in 2021 and 2020, respectively. The table below presents these expenditures:


	Year Ended September 30
	2021			2020
	(Millions)
Exploration and Production:
Capital Expenditures(3)	$	381.4	(1)	$	670.4	(2)
Pipeline and Storage:
Capital Expenditures	$	252.3	(1)	$	166.7	(2)
Gathering:
Capital Expenditures(4)	$	34.7	(1)	$	297.8	(2)
Utility:
Capital Expenditures	$	100.8	(1)	$	94.3	(2)
All Other and Corporate:
Capital Expenditures	$	0.5		$	0.5
Eliminations	$	0.2		$	(1.1)
Total Expenditures	$	769.9		$	1,228.6

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(1)2021 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $47.9 million, $39.4 million, $4.8 million and $10.6 million, respectively, of non-cash capital expenditures.

(2)2020 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $45.8 million, $17.3 million, $13.5 million and $10.7 million, respectively, of non-cash capital expenditures.

(3)2020 includes $282.8 million related to the acquisition of upstream assets acquired from Shell, of which $281.7 million is included in Property, Plant and Equipment and $1.1 million is included in Materials, Supplies and Emission Allowances. The acquisition cost is reported as a component of Acquisition of Upstream Assets and Midstream Gathering Assets on the Consolidated Statement of Cash Flows.

(4)2020 includes $223.5 million related to the acquisition of midstream gathering assets acquired from Shell, of which $223.4 million is included in Property, Plant and Equipment and $0.1 million is included in Materials, Supplies and Emission Allowances. The acquisition cost is reported as a component of Acquisition of Upstream Assets and Midstream Gathering Assets on the Consolidated Statement of Cash Flows.

Exploration and Production

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

In 2020, the majority of the Exploration and Production segment capital expenditures were well drilling and completion expenditures, and also included $282.8 million of expenditures related to the acquisition of upstream assets acquired from Shell on July 31, 2020. The acquisition included over 400,000 net acres in Appalachia, with approximately 200,000 net acres in Tioga County. The proved developed and undeveloped natural gas reserves associated with this acquisition amounted to 684,141 MMcf in 2020. Capital expenditures were approximately $639.7 million for the Appalachian region (including $412.0 million in the Marcellus Shale area and $204.6 million in the Utica Shale area) and $30.7 million for the West Coast region. These amounts included approximately $219.9 million spent to develop proved undeveloped reserves.

Pipeline and Storage

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

The majority of the Pipeline and Storage segment’s capital expenditures for 2020 were related to additions, improvements and replacements to this segment's transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for 2020 included expenditures related to the Empire North Project ($68.9 million), Supply Corporation's Line N to Monaca Project ($4.1 million) and Supply Corporation's FM100 Project ($3.7 million).

Gathering

The majority of the Gathering segment's capital expenditures for 2021 included expenditures related to the continued expansion of Midstream Company's Clermont, Covington and Wellsboro gathering systems, as discussed below. Midstream Company spent $23.1 million, $4.4 million and $3.7 million, respectively, in 2021 on the development of the Clermont, Covington and Wellsboro gathering systems. These expenditures were largely attributable to new Clermont gathering pipelines, a new tie-in between the legacy Covington gathering system and the midstream gathering assets acquired from Shell (now referred to as the Tioga gathering system), as well as the continued development of centralized station facilities, including increased compression

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horsepower at the Clermont and Wellsboro gathering systems and additional dehydration on the Clermont gathering system.

The majority of the Gathering segment's capital expenditures for 2020 were for the acquisition of midstream gathering assets from Shell in the amount of $223.5 million. These gathering assets, including approximately 238 miles of gathering pipeline, support the upstream assets in Tioga County that the Exploration and Production segment acquired from Shell, as discussed above, and are interconnected with various interstate pipelines, including the Company's Empire pipeline systems. In addition, the Gathering segment's capital expenditures included expenditures related to the continued expansion of Midstream Company's Trout Run, Clermont, and Wellsboro gathering systems. Midstream Company spent $36.5 million, $19.7 million and $17.3 million, respectively, in 2020 on the development of the Trout Run, Clermont and Wellsboro gathering systems. These expenditures were largely attributable to the continued development of centralized station facilities, including increased compression horsepower at the Trout Run and Wellsboro gathering systems and additional dehydration on the Clermont gathering system. The Trout Run expenditures also included costs to construct new pipeline and station facilities to bring a third party producer online.

Utility

The majority of the Utility segment’s capital expenditures for 2021 and 2020 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions.

Other Investing Activities

On December 10, 2020, the Company completed the sale of substantially all timber properties in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme Allegheny Land Company II LLC for net proceeds of $104.6 million. After purchase price adjustments and transaction costs, a gain of $51.1 million was recognized on the sale of these assets ($37.0 million after-tax). The sale of the timber properties completed a reverse like-kind exchange pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchange”). On July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from Shell for total consideration of $506.3 million. The purchase and sale agreement with Shell was structured, in part, as a Reverse 1031 Exchange. Refer to Item 8 at Note B — Asset Acquisitions and Divestitures for additional information concerning the Company’s acquisition of certain upstream assets and midstream gathering assets from Shell.

Estimated Capital Expenditures

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


	Year Ended September 30
	2022		2023		2024
	(Millions)
Exploration and Production(1)	$	425	$	415	$	400
Pipeline and Storage	125		90		85
Gathering	55		65		80
Utility(2)	95		105		105
All Other	—		—		—
	$	700	$	675	$	670

(1)Includes estimated expenditures for the years ended September 30, 2022, 2023 and 2024 of approximately $161 million, $128 million and $56 million, respectively, to develop proved undeveloped reserves. The Company is committed to developing its proved undeveloped reserves within five years as required by the SEC’s final rule on Modernization of Oil and Gas Reporting.

(2)Includes estimated expenditures for the years ended September 30, 2022, 2023 and 2024 of approximately $70 million, $75 million and $75 million, respectively, for system modernization and safety to enhance the reliability and safety of the system and reduce emissions.

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Exploration and Production

Estimated capital expenditures in 2022 for the Exploration and Production segment include approximately $410 million for the Appalachian region and $15 million for the West Coast region.

Estimated capital expenditures in 2023 for the Exploration and Production segment include approximately $400 million for the Appalachian region and $15 million for the West Coast region.

Estimated capital expenditures in 2024 for the Exploration and Production segment include approximately $385 million for the Appalachian region and $15 million for the West Coast region.

Pipeline and Storage

Capital expenditures for the Pipeline and Storage segment in 2022 through 2024 are expected to include: construction of new pipeline and compressor stations to support expansion projects, the replacement of transmission and storage lines, the reconditioning of storage wells and improvements of compressor stations. Expansion projects where the Company has begun to make significant investments of preliminary survey and investigation costs and/or where shipper agreements have been executed are described below.

In light of the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia — specifically in the Marcellus and Utica Shale producing areas — Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica gas production to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems.

Supply Corporation has developed its FM100 Project, which will upgrade a 1950's era pipeline in northwestern Pennsylvania and create approximately 330,000 Dth per day of additional transportation capacity in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County to the Transcontinental Gas Pipe Line Company, LLC (“Transco”) system at Leidy, Pennsylvania. A precedent agreement has been executed by Supply Corporation and Transco whereby this additional capacity is expected to be leased by Transco ("Lease") and become part of a Transco expansion project ("Leidy South") that will create incremental transportation capacity to Transco Zone 6 markets. Seneca is an anchor shipper on Leidy South, which provides it with an outlet to premium markets from both its Eastern and Western development areas. FERC issued the Section 7(c) certificate on July 17, 2020 and Supply Corporation accepted it on August 14, 2020. FERC issued a Notice to Proceed on February 22, 2021, and the Lease was fully executed on that date. Construction activities are fully in progress. The FM100 Project has an expected target in-service date of December 1, 2021 and a preliminary cost estimate of approximately $240 million. As of September 30, 2021, approximately $186.2 million has been capitalized as Construction Work in Progress for this project. The remaining expenditures expected to be spent on the project are included in Pipeline and Storage estimated capital expenditures in the table above.

Supply Corporation and Empire have developed a project which would move significant prospective Marcellus and Utica production from Seneca's Western Development Area at Clermont to an Empire interconnection with the TC Energy pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York (the “Northern Access project”). The Northern Access project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. On February 3, 2017, the Company received FERC approval of the project. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order, and FERC's decisions were appealed. The Second Circuit Court of Appeals

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issued an order upholding the FERC waiver orders. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project. The Company will update the $500 million preliminary cost estimate and expected in-service date for the project when there is further clarity on the timing of receipt of necessary regulatory approvals. As of September 30, 2021, approximately $55.7 million has been spent on the Northern Access project, including $24.1 million that has been spent to study the project. The remaining $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2021. Because it is difficult to predict the timing of the resolution of the litigation process, no estimated capital expenditures for the Northern Access project are included in the table above.

Gathering

The majority of the Gathering segment capital expenditures in 2022 through 2024, included in the table above, are expected to be for construction and expansion of gathering systems, as discussed below.

NFG Midstream Clermont, LLC, a wholly-owned subsidiary of Midstream Company, continues to develop an extensive gathering system with compression in the Pennsylvania counties of McKean, Elk and Cameron. The Clermont gathering system was initially placed in service in July 2014. The current system consists of three compressor stations and backbone and in-field gathering pipelines. The total cost estimate for the continued buildout will be dependent on the nature and timing of Seneca's long-term plans. Estimated capital expenditures in 2022 through 2024 include anticipated expenditures in the range of $80 million to $100 million for the continued expansion of the Clermont gathering system.

NFG Midstream Covington, LLC, a wholly-owned subsidiary of Midstream Company, operates its Covington gathering system as well as the Tioga gathering system acquired from Shell on July 31, 2020, both in Tioga County, Pennsylvania. The current Covington gathering system consists of two compressor stations and backbone and in-field gathering pipelines. The Tioga gathering system consists of 13 compressor stations and backbone and in-field gathering pipelines. Estimated capital expenditures in 2022 through 2024 include anticipated expenditures in the range of $90 million to $110 million for continued expansion of the Tioga gathering system.

NFG Midstream Wellsboro, LLC, a wholly-owned subsidiary of Midstream Company, continues to develop its Wellsboro gathering system in Tioga County, Pennsylvania. The current system consists of one compressor station and backbone and in-field gathering pipelines. Estimated capital expenditures in 2022 through 2024 include anticipated expenditures of less than $10 million for the continued expansion of the Wellsboro gathering system.

NFG Midstream Trout Run, LLC, a wholly-owned subsidiary of Midstream Company, continues to develop its Trout Run gathering system in Lycoming County, Pennsylvania. The Trout Run gathering system was initially placed in service in May 2012. The current system consists of three compressor stations and backbone and in-field gathering pipelines. Estimated capital expenditures in 2022 through 2024 include anticipated expenditures of less than $10 million for the continued expansion of the Trout Run gathering system.

Utility

Capital expenditures for the Utility segment in 2022 through 2024 are expected to be concentrated in the areas of main and service line improvements and replacements and, to a lesser extent, the purchase of new equipment.

Project Funding

Over the past two years, the Company has been financing capital expenditures with cash from operations, short-term and long-term debt, common stock, and proceeds from the sale of timber properties. During fiscal 2021, capital expenditures were funded with cash from operations and short-term debt. The Company issued long-term debt and common stock in June 2020 to help finance the acquisition of upstream assets and midstream gathering assets from Shell. The financing of the asset acquisition from Shell was completed in

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December 2020 when the Company completed the sale of substantially all of its timber properties, through the completion of the Reverse 1031 Exchange discussed above. Going forward, the Company expects to use cash on hand, cash from operations and short-term borrowings to finance capital expenditures. The level of short-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas and crude oil production and the associated commodity price realizations.

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

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

The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, quicker development of existing oil and gas properties, natural gas storage and transmission facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market and regulatory conditions.

FINANCING CASH FLOW

Consolidated short-term debt increased $128.5 million when comparing the balance sheet at September 30, 2021 to the balance sheet at September 30, 2020. The maximum amount of short-term debt outstanding during the year ended September 30, 2021 was $182.3 million. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. Given the significant rise in gas prices toward the end of the fiscal year, the Company was required to post margin on some of its outstanding derivative financial instruments. As a result, the Company accessed the commercial paper markets to meet its short-term borrowing needs. The Company’s margin deposits are reflected on the balance sheet as a current asset titled Hedging Collateral Deposits. The Company expects its outstanding Credit Agreements (as defined below) to provide ample liquidity should gas prices continue to increase and additional margin calls be required by our counterparties. At September 30, 2021, the Company had outstanding commercial paper of $158.5 million. The Company did not have any outstanding short-term notes payable to banks at September 30, 2021.

The Company maintains $1.0 billion of unsecured committed revolving credit access across two facilities. On October 25, 2018, the Company entered into a Fourth Amended and Restated Credit Agreement ("Credit Agreement") with a syndicate of twelve banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through October 25, 2023. In addition to the Credit Agreement, on February 3, 2021, the Company amended its existing 364-Day Credit Agreement to extend the maturity date

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thereof from May 3, 2021 to December 30, 2022, and to increase the lenders' commitments thereunder from $200.0 million to $250.0 million, among other changes (as amended, the "Amended 364-Day Credit Agreement"). Twelve banks are parties to the Amended 364-Day Credit Agreement, all of which are also lenders under the Credit Agreement. The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future.

The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $250 million. This provision also applies to the Amended 364-Day Credit Agreement. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at September 30, 2021, $190.7 million was added back to the Company's total capitalization for purposes of the facility, and the Company’s debt to capitalization ratio, as calculated under the facility, was .59. The constraints specified in both the Credit Agreement and Amended 364-Day Credit Agreement would have permitted an additional $884.2 million in short-term and/or long-term debt to be outstanding at September 30, 2021 before the Company’s debt to capitalization ratio exceeded .65.

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

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

On February 24, 2021, the Company issued $500.0 million of 2.95% notes due March 1, 2031. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.3 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 4.95%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded. The proceeds of this debt issuance were used for general corporate purposes, including the redemption of $500.0 million of the Company's 4.90% notes on March 11, 2021 that were scheduled to mature in December 2021. The Company redeemed those notes for $515.7 million, plus accrued interest.

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amounted to $493.0 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50%, if there is a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded. The proceeds of this debt issuance were used for general corporate purposes, which included the payment of a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020 and the repayment and refinancing of short-term debt.

None of the Company’s long-term debt at September 30, 2021 and September 30, 2020 had a maturity date within the next twelve months. As of September 30, 2021, the future contractual obligations related to aggregate principal amounts of long-term debt, including interest expense, maturing during the next five years and thereafter are as follows: $117.8 million in 2022, $654.1 million in 2023, $95.4 million in 2024, $589.4 million in 2025, $548.9 million in 2026, and $1,203.9 million thereafter. Refer to Item 8 at Note H — Capitalization and Short-Term Borrowings, as well as the table under Interest Rate Risk in the Market Risk Sensitive Instruments section below, for the amounts excluding interest expense. Principal payments of long-term debt are a component of cash used in financing activities while interest payments on long-term debt are a component of cash used in operating activities.

The Company’s embedded cost of long-term debt was 4.48% and 4.85% at September 30, 2021 and September 30, 2020, respectively. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.

On June 2, 2020, the Company completed a public offering and sale of 4,370,000 shares of the Company's common stock, par value $1.00 per share, at a price of $39.50 per share. After deducting fees, commissions and other issuance costs, the net proceeds to the Company amounted to $165.8 million. The proceeds of this issuance were used to fund a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020.

Under the Company's existing indenture covenants at September 30, 2021, the Company would have been permitted to issue up to a maximum of approximately $1.6 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by debt to capitalization ratio constraints under the Company’s Credit Agreement and Amended 364-Day Credit Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

The Company’s 1974 indenture pursuant to which $99.0 million (or 3.7%) of the Company’s long-term debt (as of September 30, 2021) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

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OTHER MATTERS

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

The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan). The Company has been making contributions to the Retirement Plan over the last several years and anticipates that it will continue making contributions to the Retirement Plan. During 2021, the Company contributed $20.0 million to the Retirement Plan. The Company anticipates that the annual contribution to the Retirement Plan in 2022 will be in the range of $20.0 million to $25.0 million. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments or through cash on hand, cash from operations or short-term borrowings. For further discussion of the Company’s Retirement Plan, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the Retirement Plan has been closed to new participants since 2003. In that regard, the average remaining service life of active participants in the Retirement Plan is approximately 6 years.

The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits. The Company has been making contributions to its VEBA trusts and/or 401(h) accounts over the last several years and anticipates that it will continue making contributions to the VEBA trusts and/or 401(h) accounts. During 2021, the Company contributed $2.8 million to its VEBA trusts. In addition, the Company made direct payments of $0.3 million to retirees not covered by the VEBA trusts and 401(h) accounts during 2021. The Company anticipates that the annual contribution to its VEBA trusts in 2022 will be in the range of $2.5 million to $3.0 million. The funding of such contributions will come from amounts collected in rates in the Utility and Pipeline and Storage segments. For further discussion of the Company’s other post-retirement benefits, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the other post-retirement benefits provided by the Company have been closed to new participants since 2003. In that regard, the average remaining service life of active participants is approximately 5 years for those eligible for other post-retirement benefits.

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

MARKET RISK SENSITIVE INSTRUMENTS

Energy Commodity Price Risk

The Company uses various derivative financial instruments (derivatives), including price swap agreements and no cost collars, as part of the Company’s overall energy commodity price risk management strategy in its Exploration and Production segment. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas and crude oil, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the Company would receive from, or pay to, the respective counterparties at September 30, 2021 to

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terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas and crude oil transactions that are related to the financial instruments.

On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act required the CFTC, SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation, and includes provisions related to the swaps and over-the-counter derivatives markets that are designed to promote transparency, mitigate systemic risk and protect against market abuse. Although regulators have issued certain regulations, other rules that may impact the Company have yet to be finalized. Rules developed by the CFTC and other regulators could impact the Company. While many of those rules place specific conditions on the operations of swap dealers and major swap participants, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs. Additionally, given the enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business. Should the Company violate any laws or regulations applicable to our hedging activities, it could be subject to CFTC enforcement action and material penalties and sanctions. The Company continues to monitor these enforcement and other regulatory developments, but cannot predict the impact that evolving application of the Dodd-Frank Act may have on its operations.

The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At September 30, 2021, the Company determined that nonperformance risk would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

The following tables disclose natural gas and crude oil price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2021. At September 30, 2021, the Company had not entered into any natural gas or crude oil price swap agreements extending beyond 2026.

Natural Gas Price Swap Agreements


	Expected Maturity Dates
	2022		2023		2024		2025		2026		Total
Notional Quantities (Equivalent Bcf)	202.3		112.7		59.2		22.9		1.7		398.8
Weighted Average Fixed Rate (per Mcf)	$	2.84	$	2.88	$	2.81	$	2.83	$	2.83	$	2.84
Weighted Average Variable Rate (per Mcf)	$	4.99	$	3.74	$	3.31	$	3.12	$	2.99	$	4.27

At September 30, 2021, the Company would have paid its respective counterparties an aggregate of approximately $569.8 million to terminate the natural gas price swap agreements outstanding at that date.

At September 30, 2020, the Company had natural gas price swap agreements covering 259.4 Bcf at a weighted average fixed rate of $2.69 per Mcf.

Crude Oil Price Swap Agreements


	Expected Maturity Dates
	2022		2023		2024		2025		Total
Notional Quantities (Equivalent Bbls)	1,296,000		480,000		120,000		120,000		2,016,000
Weighted Average Fixed Rate (per Bbl)	$	57.40	$	58.48	$	50.30	$	50.32	$	56.81
Weighted Average Variable Rate (per Bbl)	$	74.26	$	68.96	$	64.61	$	61.51	$	71.66

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At September 30, 2021, the Company would have paid its respective counterparties an aggregate of approximately $29.9 million to terminate the crude oil price swap agreements outstanding at that date.

At September 30, 2020, the Company had crude oil price swap agreements covering 1,548,000 Bbls at a weighted average fixed rate of $57.87 per Bbl.

No Cost Collars

The following table discloses the notional quantities, the weighted average ceiling price and the weighted average floor price for the no cost collars used by the Company to manage natural gas price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). At September 30, 2021, the Company had not entered into any natural gas no cost collars extending beyond 2024.


	Expected Maturity Dates
	2022		2023		2024		Total
Natural Gas
Notional Quantities (Equivalent Bcf)	2.3		17.1		1.5		20.9
Weighted Average Ceiling Price (per Mcf)	$	2.86	$	3.29	$	3.29	$	3.25
Weighted Average Floor Price (per Mcf)	$	2.35	$	2.87	$	2.87	$	2.81

At September 30, 2021, the Company would have had to pay an aggregate of approximately $17.4 million to terminate the natural gas no cost collars outstanding at that date.

At September 30, 2020, the Company had no cost collars agreements covering 27.3 Bcf at a weighted average ceiling price of $2.87 per Mcf and a weighted average floor price of $2.35 per Mcf.

Foreign Exchange Risk

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

The following table discloses foreign exchange contract information by expected maturity dates. The Company receives a fixed price in exchange for paying a variable price as noted in the Canadian to U.S. dollar forward exchange rates. Notional amounts (Canadian dollars) are used to calculate the contractual payments to be exchanged under contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2021. At September 30, 2021, the Company had not entered into any foreign currency exchange contracts extending beyond 2030.


	Expected Maturity Dates
	2022		2023		2024		2025		2026		Thereafter		Total
Notional Quantities (Canadian Dollar in millions)	$	16.1	$	14.7	$	12.9	$	10.9	$	1.9	$	4.2	$	60.7
Weighted Average Fixed Rate ($Cdn/$US)	$	1.29	$	1.29	$	1.29	$	1.28	$	1.35	$	1.40	$	1.30
Weighted Average Variable Rate ($Cdn/$US)	$	1.28	$	1.28	$	1.28	$	1.28	$	1.31	$	1.35	$	1.28

At September 30, 2021, absent other positions with the same counterparties, the Company would have received from its respective counterparties an aggregate of $0.7 million to terminate these foreign exchange contracts.

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

Interest Rate Risk

The fair value of long-term fixed rate debt is $2.9 billion at September 30, 2021. This fair value amount is not intended to reflect principal amounts that the Company will ultimately be required to pay. The following table presents the principal cash repayments and related weighted average interest rates by expected maturity date for the Company’s long-term fixed rate debt:

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	Principal Amounts by Expected Maturity Dates
	2022		2023		2024		2025		2026		Thereafter		Total
	(Dollars in millions)
Long-Term Fixed Rate Debt	$	—	$	549.0	$	—	$	500.0	$	500.0	$	1,100.0	$	2,649.0
Weighted Average Interest Rate Paid	—		4.1%		—		5.4%		5.5%		3.7%		4.5%

RATE MATTERS

Utility Operation

Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” Neither the New York or Pennsylvania divisions currently have a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.

New York Jurisdiction

Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017. The order directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018.

On August 13, 2021, the NYPSC issued an order extending the date through which qualified leak prone pipe replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (until March 31, 2023). The extension is contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to April 1, 2023.

In New York, on March 13, 2020, in response to the COVID-19 pandemic, the Company agreed to NYPSC Staff’s request that the Company suspend service terminations and disconnections. Thereafter, on June 17, 2020, New York enacted a law that prohibits utilities from terminating or disconnecting services to any residential customer for non-payment for the duration of the state disaster emergency. While that legislation expired on March 31, 2021, new legislation was enacted in May 2021 that prohibits utility terminations for non-payment for residential and small commercial customers who experienced a change in financial circumstances due to the COVID-19 state of emergency, with such prohibition running for a period of one hundred eighty days after either the New York State COVID-19 state of emergency is lifted or expires or December 31, 2021, whichever is earlier. On June 24, 2021, the New York State COVID-19 state of emergency expired. Updated guidance issued by the NYPSC on July 6, 2021 confirmed that qualified customers are protected from termination through December 21, 2021 and are eligible for a deferred payment agreement without the requirement of a down payment, late fees, penalties or interest on arrears incurred during the COVID-19 state of emergency. It is uncertain at this point as to whether there would be any regulatory relief for utilities with regard to an increase in costs associated with the COVID-19 pandemic, but it is one of many issues currently being considered in a generic NYPSC proceeding entitled “Proceeding on Motion of the Commission Regarding the Effects of COVID-19 on Utility Service” (Case No. 20-M-0266). Correspondence from NYPSC Staff has recommended that utilities rely on existing avenues of relief for these costs, and has identified additional, more stringent requirements that must be met to achieve relief.

Pennsylvania Jurisdiction

Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007. The rate settlement does not specify any requirement to file a future rate case.

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Corporation’s regulatory liability associated with OPEB expenses. The PaPUC issued an order approving this tariff supplement on September 15, 2021 and new rates went into effect on October 1, 2021. On September 21, 2021, a complaint was filed in this proceeding. While new rates, including associated refunds, went into effect on October 1, 2021, certain other adjustments called for by the tariff supplement that allow Distribution Corporation to reduce its regulatory liability and its OPEB expenses will not be recorded in the Company’s consolidated financial statements until the complaint is resolved. The PaPUC has assigned the matter to the Office of Administrative Law Judge. The refunds specified in the tariff supplement will be funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company’s Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation will no longer fund the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.

On March 26, 2020, the PaPUC ratified an Emergency Order that established a Service Termination Moratorium intended to continue during the pendency of Governor Wolf’s March 6, 2020 Proclamation of Disaster Emergency associated with the COVID-19 pandemic. On May 13, 2020, the Company (and other Pennsylvania local distribution companies) received a Secretarial Letter from the PaPUC regarding COVID-19 pandemic cost tracking and regulatory assets. The Secretarial Letter directs utilities to track “extraordinary, nonrecurring incremental COVID-19 related expenses” so the Commission can understand the impact of these expenses on the utilities’ finances. It also authorizes the creation of a utility regulatory asset, but only for incremental uncollectible expenses incurred above those embedded in rates (and incurred since the issuance of the Emergency Order). On October 8, 2020, the Commission issued an order ending the Service Termination Moratorium effective November 9, 2020, imposing a list of enhanced customer protections that expired on March 31, 2021 ("Modified Termination Moratorium"). On March 11, 2021, the Commission adopted an order lifting the Modified Termination Moratorium effective April 1, 2021, and authorizing utilities to return to the regular collections process with certain modifications to customer payment arrangements. On July 15, 2021, the Commission issued an order indicating that after September 30, 2021, customer payment arrangements will adhere to the traditional provisions of the Public Utility Code and Commission regulations. The October and March orders expanded the aforementioned potential utility regulatory asset to include all incremental COVID-19 related expenses incurred above those embedded in rates resulting from directives contained in the orders. The Company continues to monitor this item for potential deferral opportunity.

Pipeline and Storage

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

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

ENVIRONMENTAL MATTERS

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

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

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

Environmental Regulation

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in the United States. These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions. The U.S. Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented by EPA impose more stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. The Company must continue to comply with all applicable regulations. Additionally, other federal regulatory agencies are beginning to address greenhouse gas emissions through changes in their regulatory oversight approach and policies. A number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines and is in the process of evaluating cap-and-trade programs (e.g., Regional Greenhouse Gas Initiative). In California, the Company currently complies with California cap-and-trade rules, which increases the Company's cost of environmental compliance in its Exploration and Production segment. On April 23, 2021, California's Governor issued an executive order directing California Geologic Energy Management Division to stop issuing hydraulic fracturing permits by 2024, which does not have a direct impact on the plans of the Exploration and Production segment as those plans do not involve fracking. The executive order also directed the California Air Resources Board to investigate phasing out oil extraction by 2045, which may result in permitting delays and new legislative action in support of the directive. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The NYPSC, for example, initiated a proceeding to consider climate-related financial disclosures at the utility operating company level, and the New York State legislature passed the CLCPA that mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on the promulgation of final regulations and on regulatory treatment afforded in the process. Thus far, the only regulations promulgated in connection with the CLCPA are greenhouse gas emissions limits established by the NYDEC in 6 NYCRR Part 496, effective December 30, 2020. The NYDEC has until January 1, 2024 to issue further rules and regulations implementing the statute. The above-enumerated initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.

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NEW AUTHORITATIVE ACCOUNTING AND FINANCIAL REPORTING GUIDANCE

For discussion of the recently issued authoritative accounting and financial reporting guidance, refer to Item 8 at Note A — Summary of Significant Accounting Policies under the heading “New Authoritative Accounting and Financial Reporting Guidance.”

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

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

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

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

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

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

5.The length and severity of the ongoing COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity;

6.Changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services;

7.Changes in the price of natural gas or oil;

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

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

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

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11.Delays or changes in costs or plans with respect to Company projects or related projects of other companies, including disruptions due to the COVID-19 pandemic, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators;

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

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

14.Changes in price differentials between similar quantities of natural gas or oil at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations;

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

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

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

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

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

20.Uncertainty of oil and gas reserve estimates;

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

22.Changes in demographic patterns and weather conditions;

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

24.Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;

25.Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war;

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

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

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

INDUSTRY AND MARKET DATA DISCLOSURE

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


Item 7A			Quantitative and Qualitative Disclosures About Market Risk

Refer to the “Market Risk Sensitive Instruments” section in Item 7, MD&A.

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Item 8			Financial Statements and Supplementary Data

Index to Financial Statements


			Page
Financial Statements:

Report of Independent Registered Public Accounting Firm			62
Consolidated Statement of Income and Earnings Reinvested in the Business for the years ended September 30, 2021, 2020 and 2019			65
Consolidated Statement of Comprehensive Income for the years ended September 30, 2021, 2020 and 2019			66
Consolidated Balance Sheet at September 30, 2021 and 2020			67
Consolidated Statement of Cash Flows for the years ended September 30, 2021, 2020 and 2019			68
Notes to Consolidated Financial Statements			69

All schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes thereto.

Supplementary Data

Supplementary data that is included in Note N — Supplementary Information for Oil and Gas Producing Activities (unaudited), appears under this Item, and reference is made thereto.

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Report of Independent Registered Public Accounting Firm

To the Board of Directors and Shareholders of National Fuel Gas Company

Opinions on the Financial Statements and Internal Control over Financial Reporting

We have audited the consolidated financial statements, including the related notes, of National Fuel Gas Company and its subsidiaries (the “Company”) as listed in the accompanying index (collectively referred to as the “consolidated financial statements”). We also have audited the Company's internal control over financial reporting as of September 30, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of September 30, 2021 and 2020, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2021 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of September 30, 2021, based on criteria established in Internal Control - Integrated Framework (2013) issued by the COSO.

Basis for Opinions

The Company's management is responsible for these consolidated financial statements, for maintaining effective internal control over financial reporting, and for its assessment of the effectiveness of internal control over financial reporting, included in Management's Annual Report on Internal Control over Financial Reporting appearing under Item 9A. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company's internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects.

Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions.

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Definition and Limitations of Internal Control over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

Critical Audit Matters

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of Proved Oil and Gas Reserves on Oil and Gas Properties, Net

As described in Note A to the consolidated financial statements, the Exploration and Production segment includes capitalized costs relating to oil and gas producing activities, net of depreciation, depletion, and amortization (DD&A) of $1.9 billion as of September 30, 2021, and related DD&A expense of $177.1 million for the year then ended. The Exploration and Production segment follows the full cost method of accounting. Under this method, all costs associated with property acquisition, exploration and development activities are capitalized and DD&A is computed based on quantities produced in relation to proved reserves using the units of production method. Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. If capitalized costs, net of accumulated DD&A and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. For the first quarter ended December 31, 2020, a pre-tax impairment charge of $76.2 million was recognized. No additional ceiling test impairment charges were recorded during the year ended September 30, 2021. As of September 30, 2021, the ceiling exceeded the book value of the oil and gas properties by approximately $842.1 million. As disclosed by management, in addition to DD&A under the units-of-production method, proved reserves are a major component in the SEC full cost ceiling test. Estimates of the Company’s proved oil and gas reserves and the future net cash flows from those reserves were prepared by the Company’s petroleum engineers and audited by independent petroleum engineers (together referred to as “management’s specialists”). Petroleum engineering involves significant assumptions in the evaluation of available geological, geophysical, engineering and economic data for each reservoir. Estimates of economically recoverable oil and gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including 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.

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The principal considerations for our determination that performing procedures relating to the impact of proved oil and gas reserves on oil and gas properties, net is a critical audit matter are the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved oil and gas reserves, which in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of quantities of proved oil and gas that are ultimately recovered.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved oil and gas reserves that are utilized in the ceiling test and DD&A expense calculations. These procedures also included, among others, evaluating the reasonableness of the significant assumptions used by management related to the quantities of oil and gas that are ultimately recovered. Evaluating the reasonableness of the significant assumptions included evaluating information on additional development activity, production history, if the assumptions used were reasonable considering the past performance of the Company, and whether they were consistent with evidence obtained in other areas of the audit. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the estimates of proved oil and gas reserves. As a basis for using this work, the specialists’ qualifications and objectivity were understood and the Company’s relationship with the specialists assessed. The procedures performed also included evaluation of the methods and assumptions used by the specialists, tests of the data used by the specialists and an evaluation of the specialists’ findings.

/s/ PRICEWATERHOUSECOOPERS LLP

Buffalo, New York

November 19, 2021

We have served as the Company’s auditor since 1941.

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NATIONAL FUEL GAS COMPANY

CONSOLIDATED STATEMENTS OF INCOME AND EARNINGS

REINVESTED IN THE BUSINESS


	Year Ended September 30
	2021		2020		2019
	(Thousands of dollars, except per common share amounts)
INCOME
Operating Revenues:
Utility and Energy Marketing Revenues	$	667,549	$	728,336	$	860,985
Exploration and Production and Other Revenues	837,597		611,885		636,528
Pipeline and Storage and Gathering Revenues	237,513		206,070		195,819
	1,742,659		1,546,291		1,693,332
Operating Expenses:
Purchased Gas	171,827		233,890		386,265
Operation and Maintenance:
Utility and Energy Marketing	179,547		181,051		171,472
Exploration and Production and Other	173,041		148,856		147,457
Pipeline and Storage and Gathering	123,218		108,640		111,783
Property, Franchise and Other Taxes	94,713		88,400		88,886
Depreciation, Depletion and Amortization	335,303		306,158		275,660
Impairment of Oil and Gas Producing Properties	76,152		449,438		—
	1,153,801		1,516,433		1,181,523
Gain on Sale of Timber Properties	51,066		—		—
Operating Income	639,924		29,858		511,809
Other Income (Expense):

Other Income (Deductions)	(15,238)		(17,814)		(15,542)
Interest Expense on Long-Term Debt	(141,457)		(110,012)		(101,614)
Other Interest Expense	(4,900)		(7,065)		(5,142)
Income (Loss) Before Income Taxes	478,329		(105,033)		389,511
Income Tax Expense	114,682		18,739		85,221
Net Income (Loss) Available for Common Stock	363,647		(123,772)		304,290
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Year	991,630		1,272,601		1,098,900
	1,355,277		1,148,829		1,403,190
Dividends on Common Stock	(164,102)		(156,249)		(148,432)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	—		(950)		—
Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities	—		—		7,437
Cumulative Effect of Adoption of Authoritative Guidance for Reclassification of Stranded Tax Effects	—		—		10,406

Balance at End of Year	$	1,191,175	$	991,630	$	1,272,601
Earnings (Loss) Per Common Share:
Basic:
Net Income (Loss) Available for Common Stock	$	3.99	$	(1.41)	$	3.53
Diluted:
Net Income (Loss) Available for Common Stock	$	3.97	$	(1.41)	$	3.51
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	91,130,941		87,968,895		86,235,550
Used in Diluted Calculation	91,684,583		87,968,895		86,773,259

See Notes to Consolidated Financial Statements

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NATIONAL FUEL GAS COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Year Ended September 30
	2021		2020		2019
	(Thousands of dollars)
Net Income (Loss) Available for Common Stock	$	363,647	$	(123,772)	$	304,290
Other Comprehensive Income (Loss), Before Tax:
Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	17,862		(19,214)		(44,089)
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans	16,229		15,361		7,332

Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(665,371)		9,862		79,301

Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	83,711		(93,295)		5,464
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	—		1,313		—
Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities to Earnings Reinvested in the Business	—		—		(11,738)
Other Comprehensive Income (Loss), Before Tax	(547,569)		(85,973)		36,270
Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	4,072		(4,357)		(10,473)
Reclassification Adjustment for Income Tax Benefit Related to the Amortization of the Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans	3,762		3,566		1,698

Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(179,028)		2,578		20,619

Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	22,465		(25,521)		2,726
Income Tax Benefit (Expense) on Cumulative Effect of Adoption of Authoritative Guidance for Hedging	—		363		—
Reclassification Adjustment for Income Tax Benefit (Expense) on the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities to Earnings Reinvested in the Business	—		—		(4,301)
Reclassification Adjustment for Stranded Tax Effects Related to the 2017 Tax Reform Act to Earnings Reinvested in the Business	—		—		10,406
Income Taxes — Net	(148,729)		(23,371)		20,675
Other Comprehensive Income (Loss)	(398,840)		(62,602)		15,595
Comprehensive Income (Loss)	$	(35,193)	$	(186,374)	$	319,885

See Notes to Consolidated Financial Statements

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NATIONAL FUEL GAS COMPANY

CONSOLIDATED BALANCE SHEETS


	At September 30
	2021		2020
	(Thousands of dollars)
ASSETS
Property, Plant and Equipment	$	13,103,639	$	12,351,852
Less — Accumulated Depreciation, Depletion and Amortization	6,719,356		6,353,785
	6,384,283		5,998,067
Assets Held for Sale, Net	—		53,424
Current Assets
Cash and Temporary Cash Investments	31,528		20,541
Hedging Collateral Deposits	88,610		—
Receivables — Net of Allowance for Uncollectible Accounts of $31,639 and $22,810, Respectively	205,294		143,583
Unbilled Revenue	17,000		17,302
Gas Stored Underground	33,669		33,338
Materials, Supplies and Emission Allowances	53,560		51,877
Unrecovered Purchased Gas Costs	33,128		—
Other Current Assets	59,660		47,557
	522,449		314,198
Other Assets
Recoverable Future Taxes	121,992		118,310
Unamortized Debt Expense	10,589		12,297
Other Regulatory Assets	60,145		156,106
Deferred Charges	59,939		67,131
Other Investments	149,632		154,502
Goodwill	5,476		5,476
Prepaid Post-Retirement Benefit Costs	149,151		76,035
Fair Value of Derivative Financial Instruments	—		9,308
Other	1,169		81
	558,093		599,246
Total Assets	$	7,464,825	$	6,964,935
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value; Authorized - 200,000,000 Shares; Issued and Outstanding - 91,181,549 Shares and 90,954,696 Shares, Respectively	$	91,182	$	90,955
Paid In Capital	1,017,446		1,004,158
Earnings Reinvested in the Business	1,191,175		991,630
Accumulated Other Comprehensive Loss	(513,597)		(114,757)
Total Comprehensive Shareholders’ Equity	1,786,206		1,971,986
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,628,687		2,629,576
Total Capitalization	4,414,893		4,601,562
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	158,500		30,000
Current Portion of Long-Term Debt	—		—
Accounts Payable	171,655		134,126
Amounts Payable to Customers	21		10,788
Dividends Payable	41,487		40,475
Interest Payable on Long-Term Debt	17,376		27,521
Customer Advances	17,223		15,319
Customer Security Deposits	19,292		17,199
Other Accruals and Current Liabilities	194,169		140,176
Fair Value of Derivative Financial Instruments	616,410		43,969
	1,236,133		459,573
Other Liabilities
Deferred Income Taxes	660,420		696,054
Taxes Refundable to Customers	354,089		357,508
Cost of Removal Regulatory Liability	245,636		230,079
Other Regulatory Liabilities	200,643		161,573
Pension and Other Post-Retirement Liabilities	7,526		127,181
Asset Retirement Obligations	209,639		192,228
Other Liabilities	135,846		139,177
	1,813,799		1,903,800
Commitments and Contingencies (Note L)	—		—
Total Capitalization and Liabilities	$	7,464,825	$	6,964,935

See Notes to Consolidated Financial Statements

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NATIONAL FUEL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended September 30
	2021		2020		2019
	(Thousands of dollars)
Operating Activities
Net Income (Loss) Available for Common Stock	$	363,647	$	(123,772)	$	304,290
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Gain on Sale of Timber Properties	(51,066)		—		—
Impairment of Oil and Gas Producing Properties	76,152		449,438		—
Depreciation, Depletion and Amortization	335,303		306,158		275,660
Deferred Income Taxes	105,993		54,313		122,265
Premium Paid on Early Redemption of Debt	15,715		—		—


Stock-Based Compensation	17,065		14,931		21,186
Other	10,896		6,527		8,608
Change in:

Receivables and Unbilled Revenue	(61,413)		(2,578)		6,379
Gas Stored Underground and Materials, Supplies and Emission Allowances	(2,014)		(6,625)		(3,713)
Unrecovered Purchased Gas Costs	(33,128)		2,246		1,958
Other Current Assets	(11,972)		49,367		(29,030)
Accounts Payable	31,352		(4,657)		(24,770)
Amounts Payable to Customers	(10,767)		6,771		623
Customer Advances	1,904		2,275		(565)
Customer Security Deposits	2,093		989		(9,493)
Other Accruals and Current Liabilities	34,314		5,001		10,992
Other Assets	1,250		(24,203)		5,115
Other Liabilities	(33,771)		4,628		4,978
Net Cash Provided by Operating Activities	791,553		740,809		694,483
Investing Activities
Capital Expenditures	(751,734)		(716,153)		(788,938)
Net Proceeds from Sale of Timber Properties	104,582		—		—
Acquisition of Upstream Assets and Midstream Gathering Assets	—		(506,258)		—

Other	13,935		(1,205)		(10,237)
Net Cash Used in Investing Activities	(633,217)		(1,223,616)		(799,175)
Financing Activities
Change in Notes Payable to Banks and Commercial Paper	128,500		(25,200)		55,200

Net Proceeds from Issuance of Long-Term Debt	495,267		493,007		—
Reduction of Long-Term Debt	(515,715)		—		—
Net Proceeds from Issuance (Repurchase) of Common Stock	(3,702)		161,603		(8,877)
Dividends Paid on Common Stock	(163,089)		(153,322)		(147,418)
Net Cash Provided by (Used in) Financing Activities	(58,739)		476,088		(101,095)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	99,597		(6,719)		(205,787)
Cash, Cash Equivalents and Restricted Cash At Beginning of Year	20,541		27,260		233,047
Cash, Cash Equivalents and Restricted Cash At End of Year	$	120,138	$	20,541	$	27,260
Supplemental Disclosure of Cash Flow Information
Cash Paid (Refunded) For:
Interest	$	135,136	$	103,479	$	102,920
Income Taxes	$	6,374	$	(82,876)	$	(17,342)
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$	102,700	$	87,328	$	81,121

See Notes to Consolidated Financial Statements

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS

Note A — Summary of Significant Accounting Policies

Principles of Consolidation

The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

Regulation

The Company is subject to regulation by certain state and federal authorities. The Company has accounting policies which conform to GAAP, as applied to regulated enterprises, and are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. Reference is made to Note F — Regulatory Matters for further discussion.

Allowance for Uncollectible Accounts

The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic environment. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered. As a result of the COVID-19 pandemic and the expected increase in customer non-payment, the Company has increased the bad debt reserve to account for the modestly higher receivable balances in the Utility segment.

Activity in the allowance for uncollectible accounts are as follows:


	Year Ended September 30
	2021		2020		2019
	(Thousands)
Balance at Beginning of Year	$	22,810	$	25,788	$	24,537
Additions Charged to Costs and Expenses	14,940		12,339		10,184
Add: Discounts on Purchased Receivables	1,168		1,353		1,707
Deduct: Net Accounts Receivable Written-Off	7,279		16,670		10,640
Balance at End of Year	$	31,639	$	22,810	$	25,788

Regulatory Mechanisms

The Company’s rate schedules in the Utility segment contain clauses that permit adjustment of revenues to reflect price changes from the cost of purchased gas included in base rates. Differences between amounts currently recoverable and actual adjustment clause revenues, as well as other price changes and pipeline and storage company refunds not yet includable in adjustment clause rates, are deferred and accounted for as either unrecovered purchased gas costs or amounts payable to customers. Such amounts are generally recovered from (or passed back to) customers during the following fiscal year.

Estimated refund liabilities to ratepayers represent management’s current estimate of such refunds. Reference is made to Note F — Regulatory Matters for further discussion.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The impact of weather on revenues in the Utility segment’s New York rate jurisdiction is tempered by a WNC, which covers the eight-month period from October through May. The WNC is designed to adjust the rates of retail customers to reflect the impact of deviations from normal weather. Weather that is warmer than normal results in a surcharge being added to customers’ current bills, while weather that is colder than normal results in a refund being credited to customers’ current bills. Since the Utility segment’s Pennsylvania rate jurisdiction does not have a WNC, weather variations have a direct impact on the Pennsylvania rate jurisdiction’s revenues.

The impact of weather normalized usage per customer account in the Utility segment’s New York rate jurisdiction is tempered by a revenue decoupling mechanism. The effect of the revenue decoupling mechanism is to render the Company financially indifferent to throughput decreases resulting from conservation. Weather normalized usage per account that exceeds the average weather normalized usage per customer account results in a refund being credited to customers’ bills. Weather normalized usage per account that is below the average weather normalized usage per account results in a surcharge being added to customers’ bills. The surcharge or credit is calculated over a twelve-month period ending March 31st, and applied to customer bills annually, beginning July 1st.

In the Pipeline and Storage segment, the allowed rates that Supply Corporation and Empire bill their customers are based on a straight fixed-variable rate design, which allows recovery of all fixed costs, including return on equity and income taxes, through fixed monthly reservation charges. Because of this rate design, changes in throughput due to weather variations do not have a significant impact on the revenues of Supply Corporation or Empire.

Asset Acquisition and Business Combination Accounting

In accordance with authoritative guidance issued by the FASB that clarifies the definition of a business, when the Company executes an acquisition, it will perform an initial screening test as of the acquisition date that, if met, results in the conclusion that the set of activities and assets is not a business. If the initial screening test is not met, the Company evaluates whether the set is a business based on whether there are inputs and a substantive process in place. The definition of a business impacts whether the Company consolidates an acquisition under business combination guidance or asset acquisition guidance.

When the Company acquires assets and liabilities deemed to be an asset acquisition, the fair value of the purchase consideration, including the transaction costs of the asset acquisition, is assumed to be equal to the fair value of the net assets acquired. The purchase consideration, including the transaction costs, is allocated to the individual assets and liabilities assumed based on their relative fair values. Transaction costs associated with asset acquisitions are capitalized as part of the costs of the group of assets acquired.

When the Company acquires assets and liabilities deemed to be a business combination, the acquisition method is applied. Goodwill is measured as the fair value of the consideration transferred less the net recognized fair value of the identifiable assets acquired and the liabilities assumed, all measured at the acquisition date. Transaction costs that the Company incurs in connection with a business combination, such as finders’ fees, legal fees, due diligence fees and other professional and consulting fees are expensed as incurred.

Property, Plant and Equipment

In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Company's capitalized costs relating to oil and gas producing activities,

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

net of accumulated depreciation, depletion and amortization, were $1.9 billion and $1.8 billion at September 30, 2021 and 2020, respectively. For further discussion of capitalized costs, refer to Note N — Supplementary Information for Oil and Gas Producing Activities.

Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter. For the first quarter ended December 31, 2020, a pre-tax impairment charge of $76.2 million was recognized. A deferred income tax benefit of $21.0 million related to the non-cash impairment charge was also recognized during the quarter ended December 31, 2020. No additional ceiling test impairment charges were recorded during the year ended September 30, 2021. As of September 30, 2021, the ceiling exceeded the book value of the oil and gas properties by approximately $842.1 million. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2021, 2020 and 2019, estimated future net cash flows were decreased by $76.1 million, increased by $180.0 million and decreased by $17.7 million, respectively.

The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. Despite the economic conditions arising from the COVID-19 pandemic, there were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at September 30, 2021. Management will continue to monitor the situation on a quarterly basis.

Maintenance and repairs of property and replacements of minor items of property are charged directly to maintenance expense. The original cost of the regulated subsidiaries’ property, plant and equipment retired, and the cost of removal less salvage, are charged to accumulated depreciation.

Depreciation, Depletion and Amortization

For oil and gas properties, depreciation, depletion and amortization is computed based on quantities produced in relation to proved reserves using the units of production method. The cost of unproved oil and gas properties is excluded from this computation. Depreciation, depletion and amortization expense for oil and gas properties was $177.1 million, $166.8 million and $149.9 million for the years ended September 30, 2021, 2020 and 2019, respectively. For all other property, plant and equipment, depreciation and amortization is computed using the straight-line method in amounts sufficient to recover costs over the estimated service lives of property in service. The following is a summary of depreciable plant by segment:

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	As of September 30
	2021		2020
	(Thousands)
Exploration and Production	$	6,827,122	$	6,384,086
Pipeline and Storage	2,467,891		2,418,265
Gathering	932,583		849,204
Utility	2,306,603		2,234,433

All Other and Corporate	13,585		20,372
	$	12,547,784	$	11,906,360

Average depreciation, depletion and amortization rates are as follows:


	Year Ended September 30
	2021			2020			2019
Exploration and Production, per Mcfe(1)	$	0.56		$	0.71		$	0.73
Pipeline and Storage	2.6		%	2.4		%	2.2		%
Gathering	3.6		%	3.2		%	3.6		%
Utility	2.7		%	2.7		%	2.7		%

All Other and Corporate	3.4		%	3.6		%	1.8		%

(1)Amounts include depletion of oil and gas producing properties as well as depreciation of fixed assets. As disclosed in Note N — Supplementary Information for Oil and Gas Producing Activities, depletion of oil and gas producing properties amounted to $0.54, $0.69 and $0.71 per Mcfe of production in 2021, 2020 and 2019, respectively.

Goodwill

The Company has recognized goodwill of $5.5 million as of September 30, 2021 and 2020 on its Consolidated Balance Sheets related to the Company’s acquisition of Empire in 2003. The Company accounts for goodwill in accordance with the current authoritative guidance, which requires the Company to test goodwill for impairment annually. At September 30, 2021, 2020 and 2019, the fair value of Empire was greater than its book value. As such, the goodwill was not considered impaired at those dates. Going back to the origination of the goodwill in 2003, the Company has never recorded an impairment of its goodwill balance.

Financial Instruments

The Company uses a variety of derivative financial instruments to manage a portion of the market risk associated with fluctuations in the price of gas and oil and to manage a portion of the risk of currency fluctuations associated with transportation costs denominated in Canadian currency. These instruments include natural gas price swap agreements and no cost collars, crude oil price swap agreements, and foreign currency forward contracts. The Company accounts for these instruments as cash flow hedges for which the fair value of the instrument is recognized on the Consolidated Balance Sheets as either an asset or a liability labeled Fair Value of Derivative Financial Instruments. Reference is made to Note I — Fair Value Measurements for further discussion concerning the fair value of derivative financial instruments.

For cash flow hedges, the offset to the asset or liability that is recorded is a gain or loss recorded in accumulated other comprehensive income (loss) on the Consolidated Balance Sheets. The gain or loss recorded in accumulated other comprehensive income (loss) remains there until the hedged transaction occurs, at which point the gains or losses are reclassified to operating revenues or purchased gas expense on the Consolidated Statements of Income. Reference is made to Note J — Financial Instruments for further discussion concerning cash flow hedges.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Accumulated Other Comprehensive Income (Loss)

The components of Accumulated Other Comprehensive Income (Loss) and changes for the years ended September 30, 2021 and 2020, net of related tax effects, are as follows (amounts in parentheses indicate debits) (in thousands):


	Gains and Losses on Derivative Financial Instruments		Funded Status of the Pension and Other Post-Retirement Benefit Plans		Total
Year Ended September 30, 2021
Balance at October 1, 2020	$	(24,865)	$	(89,892)	$	(114,757)
Other Comprehensive Gains and Losses Before Reclassifications	(486,343)		13,790		(472,553)
Amounts Reclassified From Other Comprehensive Income (Loss)	61,246		12,467		73,713

Balance at September 30, 2021	$	(449,962)	$	(63,635)	$	(513,597)
Year Ended September 30, 2020
Balance at October 1, 2019	$	34,675	$	(86,830)	$	(52,155)
Other Comprehensive Gains and Losses Before Reclassifications	7,284		(14,857)		(7,573)
Amounts Reclassified From Other Comprehensive Income (Loss)	(67,774)		11,795		(55,979)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	950		—		950


Balance at September 30, 2020	$	(24,865)	$	(89,892)	$	(114,757)

The amounts included in accumulated other comprehensive income (loss) related to the funded status of the Company’s pension and other post-retirement benefit plans consist of prior service costs and accumulated losses. The total amount for prior service cost was $0.7 million and $0.9 million at September 30, 2021 and 2020, respectively. The total amount for accumulated losses was $62.9 million and $89.0 million at September 30, 2021 and 2020, respectively.

In August 2017, the FASB issued authoritative guidance which changes the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities and to simplify the application of hedge accounting. The Company adopted this authoritative guidance effective October 1, 2019, recognizing a cumulative effect adjustment that decreased retained earnings by $1.0 million and increased accumulated other comprehensive income by the same amount.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Reclassifications Out of Accumulated Other Comprehensive Income (Loss)

The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the years ended September 30, 2021 and 2020 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):


Details About Accumulated Other Comprehensive Income (Loss) Components	Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) for the Year Ended September 30,		Affected Line Item in the Statement Where Net Income is Presented
	2021	2020
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts	($83,973)	$93,691	Operating Revenues
Commodity Contracts	—	661	Purchased Gas
Foreign Currency Contracts	262	(1,057)	Operating Revenues
Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans:
Prior Service Cost	(208)	(237)	(1)
Net Actuarial Loss	(16,021)	(15,124)	(1)
	(99,940)	77,934	Total Before Income Tax
	26,227	(21,955)	Income Tax Expense
	($73,713)	$55,979	Net of Tax

(1)These accumulated other comprehensive income (loss) components are included in the computation of net periodic benefit cost. Refer to Note K — Retirement Plan and Other Post-Retirement Benefits for additional details.

Gas Stored Underground

In the Utility segment, gas stored underground in the amount of $33.7 million is carried at lower of cost or net realizable value, on a LIFO method. Based upon the average price of spot market gas purchased in September 2021, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $74.1 million at September 30, 2021.

Materials, Supplies and Emission Allowances

The components of the Company's materials, supplies and emission allowances are as follows:


	Year Ended September 30
	2021		2020
	(Thousands)
Materials and Supplies — at average cost	$	34,880	$	33,859
Emission Allowances	18,680		18,018
	$	53,560	$	51,877

Unamortized Debt Expense

Costs associated with the reacquisition of debt related to rate-regulated subsidiaries are deferred and amortized over the remaining life of the issue or the life of the replacement debt in order to match regulatory

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

treatment. At September 30, 2021, the remaining weighted average amortization period for such costs was approximately 6 years.

Income Taxes

The Company and its subsidiaries file a consolidated federal income tax return. State tax returns are filed on a combined or separate basis depending on the applicable laws in the jurisdictions where tax returns are filed.

The Company follows the asset and liability approach in accounting for income taxes, which requires the recognition of deferred income taxes for the expected future tax consequences of net operating losses, credits and temporary differences between the financial statement carrying amounts and the tax basis of assets and liabilities. A valuation allowance is provided on deferred tax assets if it is determined, within each taxing jurisdiction, that it is more likely than not that the asset will not be realized.

The Company reports a liability or a reduction of deferred tax assets for unrecognized tax benefits resulting from uncertain tax positions taken or expected to be taken in a tax return. When applicable, the Company recognizes interest relating to uncertain tax positions in Other Interest Expense and penalties in Other Income (Deductions).

Consolidated Statement of Cash Flows

The components, as reported on the Company's Consolidated Balance Sheets, of the total cash, cash equivalents, and restricted cash presented on the Statement of Cash Flows are as follows (in thousands):


	Year Ended September 30
	2021		2020		2019		2018

Cash and Temporary Cash Investments	$	31,528	$	20,541	$	20,428	$	229,606
Hedging Collateral Deposits	88,610		—		6,832		3,441
Cash, Cash Equivalents, and Restricted Cash	$	120,138	$	20,541	$	27,260	$	233,047

The Company considers all highly liquid debt instruments purchased with a maturity date of generally three months or less to be cash equivalents. The Company’s restricted cash is composed entirely of amounts reported as Hedging Collateral Deposits on the Consolidated Balance Sheets. Hedging Collateral Deposits is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instruments liability or asset balances.

Other Current Assets

The components of the Company’s Other Current Assets are as follows:


	Year Ended September 30
	2021		2020
	(Thousands)
Prepayments	$	14,164	$	12,851
Prepaid Property and Other Taxes	14,788		14,269

State Income Taxes Receivable	1,502		3,828

Regulatory Assets	29,206		16,609
	$	59,660	$	47,557

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Other Accruals and Current Liabilities

The components of the Company’s Other Accruals and Current Liabilities are as follows:


	Year Ended September 30
	2021		2020
	(Thousands)
Accrued Capital Expenditures	$	42,541	$	33,344
Regulatory Liabilities	60,860		44,890

Federal Income Taxes Payable	154		163

Liability for Royalty and Working Interests	31,483		15,665
Non-Qualified Benefit Plan Liability	15,408		14,460
Other	43,723		31,654
	$	194,169	$	140,176

Customer Advances

The Company, primarily in its Utility segment, has balanced billing programs whereby customers pay their estimated annual usage in equal installments over a twelve-month period. Monthly payments under the balanced billing programs are typically higher than current month usage during the summer months. During the winter months, monthly payments under the balanced billing programs are typically lower than current month usage. At September 30, 2021 and 2020, customers in the balanced billing programs had advanced excess funds of $17.2 million and $15.3 million, respectively.

Customer Security Deposits

The Company, primarily in its Utility and Pipeline and Storage segments, oftentimes requires security deposits from marketers, producers, pipeline companies, and commercial and industrial customers before providing services to such customers. At September 30, 2021 and 2020, the Company had received customer security deposits amounting to $19.3 million and $17.2 million, respectively.

Earnings Per Common Share

Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding were SARs, restricted stock units and performance shares. For the years ended September 30, 2021 and September 30, 2019, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 320,222 securities excluded as being antidilutive for the year ended September 30, 2021 and 242,302 securities excluded as being antidilutive for the year ended September 30, 2019. As the Company recognized a net loss for the year ended September 30, 2020, the aforementioned potentially dilutive securities, amounting to 411,890 securities, were not recognized in the diluted earnings per share calculation for 2020.

Stock-Based Compensation

The Company has various stock award plans which provide or provided for the issuance of one or more of the following to key employees: SARs, incentive stock options, nonqualified stock options, restricted stock, restricted stock units, performance units or performance shares. The Company follows authoritative guidance which requires the measurement and recognition of compensation cost at fair value for all share-based payments. SARs and stock options under all plans have exercise prices equal to the average market price of

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Company common stock on the date of grant, and generally no SAR or stock option is exercisable less than one year or more than ten years after the date of each grant. The Company has chosen the Black-Scholes-Merton closed form model to calculate the compensation expense associated with SARs and stock options. For all Company stock awards, forfeitures are recognized as they occur.

Restricted stock is subject to restrictions on vesting and transferability. Restricted stock awards entitle the participants to full dividend and voting rights. The market value of restricted stock on the date of the award is recorded as compensation expense over the vesting period. Certificates for shares of restricted stock awarded under the Company’s stock award plans are held by the Company during the periods in which the restrictions on vesting are effective. Restrictions on restricted stock awards generally lapse ratably over a period of not more than ten years after the date of each grant.

Restricted stock units also are subject to restrictions on vesting and transferability. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. The restricted stock units do not entitle the participants to dividend and voting rights. The accounting for restricted stock units is the same as the accounting for restricted stock awards, except that the fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.

Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period. For performance shares based on a return on capital goal, the fair value at the date of grant of the performance shares is determined by multiplying the expected number of performance shares to be issued by the market value of Company common stock on the date of grant reduced by the present value of forgone dividends. For performance shares based on a total shareholder return goal, the Company uses the Monte Carlo simulation technique to estimate the fair value price at the date of grant.

Refer to Note H — Capitalization and Short-Term Borrowings under the heading “Stock Award Plans” for additional disclosures related to stock-based compensation awards for all plans.

New Authoritative Accounting and Financial Reporting Guidance

On October 1, 2020, the Company adopted authoritative guidance regarding the measurement of credit losses on financial assets measured at amortized cost. The new guidance requires financial assets measured at amortized cost to be presented at the net amount expected to be collected, which means that companies are required to recognize an allowance for credit losses for the difference between the amortized cost basis of the financial asset and the amount expected to be collected over the contractual life of the asset. Prior to adoption, the Company analyzed its financial assets measured at amortized cost, primarily trade receivables. The adoption of this guidance did not have a material impact to the Company’s financial statements.

Note B — Asset Acquisitions and Divestitures

On July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from SWEPI LP, a subsidiary of Royal Dutch Shell plc (“Shell”) for total consideration of $506.3 million. The purchase price, which reflected an effective date of January 1, 2020, was reduced for production revenues less expenses that were retained by Shell from the effective date to the closing date. As part of the transaction, the Company acquired over 400,000 net acres in Appalachia, including approximately 200,000 net acres in Tioga County, Pennsylvania. The proved developed and undeveloped

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

natural gas reserves associated with this acquisition amounted to 684,141 MMcf. In addition, the Company acquired gathering pipelines and related compression, water pipelines, and associated water handling infrastructure, all of which support the acquired Tioga County production operations. These gathering facilities are interconnected with various interstate pipelines, including the Company’s Empire pipeline system, with the potential to tie into the Company’s existing Covington gathering system. Post-closing, the Company has integrated the assets into its existing operations in Tioga County, which has resulted in cost synergies. This transaction was accounted for as an asset acquisition as substantially all the fair value of the gross assets acquired is concentrated in a single asset under the screen test comprised of Proved Developed Producing Reserves and the attached Gathering Property, Plant and Equipment. The purchase consideration, including the transaction costs, has been allocated to the individual assets acquired based on their relative fair values. The following is a summary of the asset acquisition (in thousands):


Purchase Price						$	503,908
Transaction Costs						2,350
Total Consideration						$	506,258

	Allocation of Cost of Asset Acquisition:
	Exploration and Production Reporting Segment			Gathering Reporting Segment				Total
Property, Plant and Equipment	$	281,648	(1)(2)	$	223,369	(2)		$	505,017
Inventory	1,132			109				1,241
Total Accounting	$	282,780		$	223,478			$	506,258

(1)Includes $241,134 in Proved Developed Producing Properties and $277,832 capitalized in the full cost pool.

(2)The Company utilized an income approach and market based approach to determine the fair value of the acquired property, plant and equipment in the Exploration and Production reporting segment. The Company utilized a cost approach and an income approach to determine the fair value of the acquired property, plant and equipment in the Gathering reporting segment.

The acquisition of the upstream assets and midstream gathering assets from Shell was financed with a combination of debt and equity, as discussed in Note H — Capitalization and Short-Term Borrowings. The purchase and sale agreement with Shell was structured, in part, as a reverse like-kind exchange pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchange”).

On December 10, 2020, the Company completed the sale of substantially all timber and other assets in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme Allegheny Land Company II LLC for net proceeds of $104.6 million. At September 30, 2020, these assets, amounting to $53.4 million, which previously were recorded as Net Property, Plant and Equipment, were presented as Assets Held for Sale, Net on the Consolidated Balance Sheet. These assets were a component of the Company’s All Other category and did not have a major impact on the Company’s operations or financial results. After purchase price adjustments and transaction costs, a gain of $51.1 million was recognized on the sale of these assets. Since the sale did not represent a strategic shift in focus for the Company, the financial results associated with operating these assets as well as the gain on sale have not been reported as discontinued operations.

The sale of the timber properties completed the Reverse 1031 Exchange related to the Company’s acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from Shell, as discussed above. In connection with the Reverse 1031 Exchange, the Company, through a subsidiary, assigned the rights

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

to acquire legal title to certain oil and natural gas properties to a Variable Interest Entity ("VIE") formed by an exchange accommodation titleholder. The Company evaluated the VIE to determine whether the Company should be considered as the primary beneficiary having a controlling financial interest. It was determined that the Company had the power to direct the activities of the VIE and the obligation to absorb significant losses of that entity or the right to receive significant benefits from that entity. Therefore, the Company was considered to be the primary beneficiary. From July 31, 2020 to December 10, 2020, a subsidiary of the Company operated the properties pursuant to a lease agreement with the VIE. As the Company was deemed to be the primary beneficiary of the VIE, the VIE was included in the consolidated financial statements of the Company. Upon completion of the sale of the timber properties on December 10, 2020, the affected properties were conveyed to the Company and the VIE structure was terminated.

On August 1, 2020, the Company completed the sale of NFR’s commercial and industrial gas contracts in New York and Pennsylvania and certain other assets to Marathon Power LLC. This sale, in conjunction with the turn back of NFR's residential customers to Distribution Corporation, effectively ended NFR's operations. The sale did not have a material impact to the Company’s financial statements. The divestiture reflects the Company’s decision to focus on other strategic areas of the energy market.

Note C — Revenue from Contracts with Customers

The following tables provide a disaggregation of the Company's revenues for the years ended September 30, 2021 and 2020, presented by type of service from each reportable segment.


	Year Ended September 30, 2021
Revenues by Type of Service	Exploration and Production		Pipeline and Storage		Gathering		Utility		Total Reportable Segments		All Other		Corporate and Intersegment Eliminations		Total Consolidated
	(Thousands)
Production of Natural Gas	$	780,477	$	—	$	—	$	—	$	780,477	$	—	$	—	$	780,477
Production of Crude Oil	135,191		—		—		—		135,191		—		—		135,191
Natural Gas Processing	2,960		—		—		—		2,960		—		—		2,960
Natural Gas Gathering Service	—		—		193,264		—		193,264		—		(190,148)		3,116
Natural Gas Transportation Service	—		255,849		—		103,141		358,990		—		(72,920)		286,070
Natural Gas Storage Service	—		83,080		—		—		83,080		—		(35,841)		47,239
Natural Gas Residential Sales	—		—		—		492,567		492,567		—		—		492,567
Natural Gas Commercial Sales	—		—		—		62,634		62,634		—		—		62,634
Natural Gas Industrial Sales	—		—		—		3,071		3,071		—		—		3,071
Natural Gas Marketing	—		—		—		—		—		678		(49)		629
Other	2,042		4,628		—		(5,249)		1,421		544		(374)		1,591
Total Revenues from Contracts with Customers	920,670		343,557		193,264		656,164		2,113,655		1,222		(299,332)		1,815,545
Alternative Revenue Programs	—		—		—		11,087		11,087		—		—		11,087
Derivative Financial Instruments	(83,973)		—		—		—		(83,973)		—		—		(83,973)
Total Revenues	$	836,697	$	343,557	$	193,264	$	667,251	$	2,040,769	$	1,222	$	(299,332)	$	1,742,659

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	Year Ended September 30, 2020
Revenues by Type of Service	Exploration and Production		Pipeline and Storage		Gathering		Utility		Total Reportable Segments		All Other		Corporate and Intersegment Eliminations		Total Consolidated
	(Thousands)
Production of Natural Gas	$	402,447	$	—	$	—	$	—	$	402,447	$	—	$	—	$	402,447
Production of Crude Oil	107,844		—		—		—		107,844		—		—		107,844
Natural Gas Processing	2,374		—		—		—		2,374		—		—		2,374
Natural Gas Gathering Service	—		—		142,893		—		142,893		—		(142,821)		72
Natural Gas Transportation Service	—		229,391		—		109,214		338,605		—		(77,699)		260,906
Natural Gas Storage Service	—		79,073		—		—		79,073		—		(34,579)		44,494
Natural Gas Residential Sales	—		—		—		475,846		475,846		—		—		475,846
Natural Gas Commercial Sales	—		—		—		61,239		61,239		—		—		61,239
Natural Gas Industrial Sales	—		—		—		3,291		3,291		—		—		3,291
Natural Gas Marketing	—		—		—		—		—		95,727		(835)		94,892
Other	1,097		1,140		—		(5,281)		(3,044)		5,174		(294)		1,836
Total Revenues from Contracts with Customers	513,762		309,604		142,893		644,309		1,610,568		100,901		(256,228)		1,455,241
Alternative Revenue Programs	—		—		—		7,989		7,989		—		—		7,989
Derivative Financial Instruments	93,691		—		—		—		93,691		(10,630)		—		83,061
Total Revenues	$	607,453	$	309,604	$	142,893	$	652,298	$	1,712,248	$	90,271	$	(256,228)	$	1,546,291

The Company records revenue related to its derivative financial instruments in the Exploration and Production segment and previously recorded revenue related to its derivative financial instruments in its NFR operations (included in the All Other category) until NFR completed the sale of its commercial and industrial contracts and certain other assets on August 1, 2020. The Company also records revenue related to alternative revenue programs in its Utility segment. Revenue related to derivative financial instruments and alternative revenue programs are excluded from the scope of the authoritative guidance regarding revenue recognition since they are accounted for under other existing accounting guidance.

Exploration and Production Segment Revenue

The Company’s Exploration and Production segment records revenue from the sale of the natural gas and oil that it produces and natural gas liquids (NGLs) processed based on entitlement, which means that revenue is recorded based on the actual amount of natural gas or oil that is delivered to a pipeline, or upon pick-up in the case of NGLs, and the Company’s ownership interest. Natural gas production occurs primarily in the Appalachian region of the United States and crude oil production occurs primarily in the West Coast region of the United States. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance. The sales contracts generally require the Company to deliver a specific quantity of a commodity per day for a specific number of days at a price that is either fixed or variable and considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery.

The transaction price for the sale of natural gas, oil and NGLs is contractually agreed upon based on prevailing market pricing (primarily tied to a market index with certain adjustments based on factors such as delivery location and prevailing supply and demand conditions) or fixed pricing. The Company allocates the transaction price to each performance obligation on the basis of the relative standalone selling price of each distinct unit sold. Revenue is recognized at a point in time when the transfer of the commodity occurs at the delivery point per the contract. The amount billable, as determined by the contracted quantity and price, indicates the value to the customer, and is used for revenue recognition purposes by the Exploration and Production segment as specified by the “invoice practical expedient” (the amount that the Exploration and

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Production segment has the right to invoice) under the authoritative guidance for revenue recognition. The contracts typically require payment within 30 days of the end of the calendar month in which the natural gas and oil is delivered, or picked up in the case of NGLs.

The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment related to sales of the natural gas and oil that it produces. Gains or losses on such derivative financial instruments are recorded as adjustments to revenue; however, they are not considered to be revenue from contracts with customers.

Pipeline and Storage Segment Revenue

The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services in New York and Pennsylvania at tariff-based rates regulated by the FERC. Customers secure their own gas supply and the Pipeline and Storage segment provides transportation and/or storage services to move the customer-supplied gas to the intended location, including injections into or withdrawals from the storage field. This performance obligation is satisfied over time. The rate design for the Pipeline and Storage segment’s customers generally includes a combination of volumetric or commodity charges as well as monthly “fixed” charges (including charges commonly referred to as capacity charges, demand charges, or reservation charges). These types of fixed charges represent compensation for standing ready over the period of the month to deliver quantities of gas, regardless of whether the customer takes delivery of any quantity of gas. The performance obligation under these circumstances is satisfied based on the passage of time and meter reads, if applicable, which correlates to the period for which the charges are eligible to be invoiced. The amount billable, as determined by the meter read and the “fixed” monthly charge, indicates the value to the customer, and is used for revenue recognition purposes by the Pipeline and Storage segment as specified by the “invoice practical expedient” (the amount that the Pipeline and Storage segment has the right to invoice) under the authoritative guidance for revenue recognition. Customers are billed after the end of each calendar month, with payment typically due by the 25th day of the month in which the invoice is received.

The Company’s Pipeline and Storage segment expects to recognize the following revenue amounts in future periods related to “fixed” charges associated with remaining performance obligations for transportation and storage contracts: $185.6 million for fiscal 2022; $147.7 million for fiscal 2023; $125.8 million for fiscal 2024; $118.5 million for fiscal 2025; $98.5 million for fiscal 2026; and $429.3 million thereafter.

Gathering Segment Revenue

The Company’s Gathering segment provides gathering and processing services in the Appalachian region of Pennsylvania, primarily for Seneca. The Gathering segment’s primary performance obligation is to deliver gathered natural gas volumes from Seneca’s wells into interstate pipelines at contractually agreed upon per unit rates. This obligation is satisfied over time. The performance obligation is satisfied based on the passage of time and meter reads, which correlates to the period for which the charges are eligible to be invoiced. The amount billable, as determined by the meter read and the contracted volumetric rate, indicates the value to the customer, and is used for revenue recognition purposes by the Gathering segment as specified by the “invoice practical expedient” (the amount that the Gathering segment has the right to invoice) under the authoritative guidance for revenue recognition. Customers are billed after the end of each calendar month, with payment typically due by the 10th day after the invoice is received.

Utility Segment Revenue

The Company’s Utility segment records revenue for natural gas sales and natural gas transportation services in western New York and northwestern Pennsylvania at tariff-based rates regulated by the NYPSC and the PaPUC. Natural gas sales and transportation services are provided largely to residential, commercial and industrial customers. The Utility segment’s performance obligation to its customers is to deliver natural gas, an obligation which is satisfied over time. This obligation generally remains in effect as long as the customer

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consumes the natural gas provided by the Utility segment. The Utility segment recognizes revenue when it satisfies its performance obligation by delivering natural gas to the customer. Natural gas is delivered and consumed by the customer simultaneously. The satisfaction of the performance obligation is measured by the turn of the meter dial. The amount billable, as determined by the meter read and the tariff-based rate, indicates the value to the customer, and is used for revenue recognition purposes by the Utility segment as specified by the “invoice practical expedient” (the amount that the Utility segment has the right to invoice) under the authoritative guidance for revenue recognition. Since the Utility segment bills its customers in cycles having billing dates that do not generally coincide with the end of a calendar month, a receivable is recorded for natural gas delivered but not yet billed to customers based on an estimate of the amount of natural gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets. The Utility segment’s tariffs allow customers to utilize budget billing. In this situation, since the amount billed may differ from the amount of natural gas delivered to the customer in any given month, revenue is recognized monthly based on the amount of natural gas consumed. The differential between the amount billed and the amount consumed is recorded as a component of Receivables or Customer Advances on the Consolidated Balance Sheets. All receivables or advances related to budget billing are settled within one year.

Utility Segment Alternative Revenue Programs

As indicated in the revenue table shown above, the Company’s Utility segment has alternative revenue programs that are excluded from the scope of the new authoritative guidance regarding revenue recognition. The NYPSC has authorized alternative revenue programs that are designed to mitigate the impact that weather and conservation have on margin. The NYPSC has also authorized additional alternative revenue programs that adjust billings for the effects of broad external factors or to compensate the Company for demand-side management initiatives. These alternative revenue programs primarily allow the Company and customer to share in variances from imputed margins due to migration of transportation customers, allow for adjustments to the gas cost recovery mechanism for fluctuations in uncollectible expenses associated with gas costs, and allow the Company to pass on to customers costs associated with customer energy efficiency programs. In general, revenue is adjusted monthly for these programs and is collected from or passed back to customers within 24 months of the annual reconciliation period.

Energy Marketing Revenue

The Company’s energy marketing subsidiary, NFR (included in the All Other category), completed the sale of its commercial and industrial contracts and certain other assets on August 1, 2020. This sale, in conjunction with the turn back of NFR's residential customers to Distribution Corporation, effectively ended NFR's operations. The sale did not have a material impact to the Company’s financial statements. NFR recorded revenue from natural gas sales to industrial, wholesale, commercial, public authority and residential customers in western and central New York and northwestern Pennsylvania.

Note D — Leases

On October 1, 2019, the Company adopted authoritative guidance regarding lease accounting, which requires entities that lease the use of property, plant and equipment to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, including leases classified as operating leases. The Company implemented the new standard using the optional transition method and elected to apply the following practical expedients provided in the authoritative guidance:

1.For contracts that commenced prior to and existed as of October 1, 2019, a package of practical expedients to not reassess whether a contract is or contains a lease, lease classification, and initial direct costs under the new authoritative guidance;

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2.An election not to apply the recognition requirements in the new authoritative guidance to short-term leases (a lease that at commencement date has a lease term of one year or less);

3.A practical expedient to not reassess certain land easements that existed prior to October 1, 2019 and were not previously accounted for as leases under the prior authoritative guidance; and

4.A practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a lease (elected by asset-class).

Upon adoption, the Company increased assets and liabilities on its Consolidated Balance Sheet by $19.7 million. The adoption did not result in a cumulative effect adjustment to earnings reinvested in the business or have a material impact on the Company’s Consolidated Statement of Income or Consolidated Statement of Cash Flows. Comparative periods, including disclosures relating to those periods, were not restated.

Nature of Leases

The Company primarily leases building space and drilling rigs, and on a limited basis compressor equipment and other miscellaneous assets. The Company determines if an arrangement is a lease at the inception of the arrangement. To the extent that an arrangement represents a lease, the Company classifies that lease as an operating or a finance lease in accordance with the authoritative guidance. The Company did not have any material finance leases as of September 30, 2021 or September 30, 2020. Aside from a sublease of office space at the Company’s corporate headquarters, the Company does not have any material arrangements where the Company is the lessor.

Buildings and Property

The Company enters into building and property rental agreements with third parties for office space, certain field locations and other properties used in the Company’s operations. Building and property leases include the Company’s corporate headquarters in Williamsville, New York, and Exploration and Production segment offices in Houston, Texas, and Pittsburgh, Pennsylvania. The primary non-cancelable terms of the Company’s building and property leases range from three months to ten years. Most building leases include one or more options to renew, generally at the Company’s sole discretion, with renewal terms that can extend the lease terms from one year to eighteen years. Renewal options are included in the lease term if they are reasonably certain to be exercised. The agreements do not contain any material restrictive covenants.

Drilling Rigs

The Company enters into contracts for drilling rig services with third party contractors to support Seneca’s development activities in Pennsylvania and California. Seneca’s drilling rig arrangements are structured with a non-cancelable primary term of one year or less. Upon mutual agreement with the contractor, Seneca has the option to extend the contract with amended terms and conditions, including a renegotiated day rate fee.

The Company has strategically entered into shorter-term drilling rig arrangements to allow for operational and financial flexibility to respond to changes in its operating and economic environment. The Company uses discretion in choosing to extend or not extend drilling rig contracts on a rig by rig basis depending on market and operating conditions present at the time the contract expires, including prices for natural gas and oil and other performance indicators.

Due to these considerations, the Company concluded that it is not reasonably certain that it will elect to extend any of its drilling rig arrangements beyond their primary non-cancelable terms of one year or less. Consequently, the Company’s drilling rig leases are deemed to be short-term leases subject to the exemption for balance sheet recognition. These costs are capitalized as part of oil and natural gas properties on the Consolidated Balance Sheet when incurred.

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Significant Judgments

Lease Identification

The Company uses judgment when determining whether or not an arrangement is or contains a lease. A contract is or contains a lease if the contract conveys the right to use an explicitly or implicitly identified asset that is physically distinct and the Company has the right to control the use of the identified asset for a period of time. When determining right of control, the Company evaluates whether it directs the use of the asset and obtains substantially all of the economic benefits from the use of the asset.

Discount Rate

The Company uses a discount rate to calculate the present value of lease payments in order to determine lease classification and measurement of the lease asset and liability. In the absence of a rate of interest that is readily determinable in the contract, the Company estimates the incremental borrowing rate (IBR) for each lease. The IBR reflects the rate of interest that the Company would pay on the lease commencement date to borrow an amount equal to the lease payments on a collateralized basis over a similar term in similar economic environments.

Firm Transportation and Storage Contracts

The Company’s subsidiaries enter into long-term arrangements to both reserve firm transportation capacity on third party pipelines and provide firm transportation and storage services to third party shippers. The Company’s firm capacity contracts with non-affiliated entities do not provide rights to use substantially all of the underlying pipeline or storage asset. As such, the Company has concluded that these arrangements are not leases under the authoritative guidance.

Oil and Gas Leases

The authoritative guidance does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. As such, the Company has concluded that its oil and gas exploration and production leases and gas storage leases are not leases under the authoritative guidance.

Amounts Recognized in the Financial Statements

Operating lease costs, excluding those relating to short-term drilling rig leases that are capitalized as part of oil and natural gas properties under full cost pool accounting, are presented in Operations and Maintenance expense on the Consolidated Statement of Income. The following table summarizes the components of the Company’s total operating lease costs (in thousands):


	Year Ended September 30
	2021		2020
Operating Lease Expense	$	5,268	$	4,129
Variable Lease Expense(1)	537		525
Short-Term Lease Expense(2)	1,279		918
Sublease Income	(356)		(297)
Total Lease Expense	$	6,728	$	5,275

Short-Term Lease Costs Recorded to Property, Plant and Equipment(3)	$	14,188	$	19,232

(1)Variable lease payments that are not dependent on an index or rate are not included in the lease liability.

(2)Short-term lease costs exclude expenses related to leases with a lease term of one month or less.

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(3)Short-term lease costs relating to drilling rig leases that are capitalized as part of oil and natural gas properties under full cost pool accounting.

Right-of-use assets and lease liabilities are recognized at the commencement date of a leasing arrangement based on the present value of lease payments over the lease term. The weighted average remaining lease term was 8.8 years and 7.4 years as of September 30, 2021 and 2020, respectively. The weighted average discount rate was 4.24% and 3.39% as of September 30, 2021 and 2020, respectively.

The Company’s right-of-use operating lease assets are reflected as Deferred Charges on the Consolidated Balance Sheet. The corresponding operating lease liabilities are reflected in Other Accruals and Current Liabilities (current) and Other Liabilities (noncurrent). Short-term leases that have a lease term of one year or less are not recorded on the Consolidated Balance Sheet.

The following amounts related to operating leases were recorded on the Company’s Consolidated Balance Sheet (in thousands):


	Year Ended September 30
	2021		2020
Assets:
Deferred Charges	$	23,601	$	19,850

Liabilities:
Other Accruals and Current Liabilities	$	3,963	$	4,943
Other Liabilities	$	19,638	$	14,777

Cash paid for lease liabilities, and reported in cash provided by operating activities on the Company’s Consolidated Statement of Cash Flows, was $6.7 million and $5.3 million for the years ended September 30, 2021 and 2020, respectively. The Company did not record any right-of-use assets in exchange for new lease liabilities during the years ended September 30, 2021 or 2020.

The following schedule of operating lease liability maturities summarizes the undiscounted lease payments owed by the Company to lessors pursuant to contractual agreements in effect as of September 30, 2021 (in thousands):


	At September 30, 2021
2022	$	4,040
2023	3,526
2024	3,261
2025	3,049
2026	2,634
Thereafter	11,911
Total Lease Payments	28,421
Less: Interest	(4,820)
Total Lease Liability	$	23,601

Note E — Asset Retirement Obligations

The Company accounts for asset retirement obligations in accordance with the authoritative guidance that requires entities to record the fair value of a liability for an asset retirement obligation in the period in which it is incurred. An asset retirement obligation is defined as a legal obligation associated with the retirement of a tangible long-lived asset in which the timing and/or method of settlement may or may not be conditional on a

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future event that may or may not be within the control of the Company. When the liability is initially recorded, the entity capitalizes the estimated cost of retiring the asset as part of the carrying amount of the related long-lived asset. Over time, the liability is adjusted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. The Company estimates the fair value of its asset retirement obligations based on the discounting of expected cash flows using various estimates, assumptions and judgments regarding certain factors such as the existence of a legal obligation for an asset retirement obligation; estimated amounts and timing of settlements; the credit-adjusted risk-free rate to be used; and inflation rates. Asset retirement obligations incurred in the current period were Level 3 fair value measurements as the inputs used to measure the fair value are unobservable.

The Company has recorded an asset retirement obligation representing plugging and abandonment costs associated with the Exploration and Production segment’s crude oil and natural gas wells and has capitalized such costs in property, plant and equipment (i.e. the full cost pool). During fiscal 2021, this segment’s Appalachian operations were required to implement additional water testing on a portion of its assets, which contributed to an increase in the asset retirement obligation. This increase is the primary component of the Revisions of Estimates amount for fiscal 2021 shown in the table below.

In addition to the asset retirement obligation recorded in the Exploration and Production segment, the Company has recorded future asset retirement obligations associated with the plugging and abandonment of natural gas storage wells in the Pipeline and Storage segment and the removal of asbestos and asbestos-containing material in various facilities in the Utility and Pipeline and Storage segments. The Company has also recorded asset retirement obligations for certain costs connected with the retirement of the distribution mains, services and other components of the pipeline system in the Utility segment, the transmission mains and other components in the pipeline system in the Pipeline and Storage segment, and the gathering lines and other components in the Gathering segment. The retirement costs within the distribution, transmission and gathering systems are primarily for the capping and purging of pipe, which are generally abandoned in place when retired, as well as for the clean-up of PCB contamination associated with the removal of certain pipe.

As discussed in Note B — Asset Acquisitions and Divestitures, on July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from Shell. With the acquisition of these assets, the Company recorded an additional $57.2 million to its Asset Retirement Obligation at September 30, 2020, which is reflected in Liabilities Incurred in the table below. The following is a reconciliation of the change in the Company’s asset retirement obligations:


	Year Ended September 30
	2021		2020		2019
	(Thousands)
Balance at Beginning of Year	$	192,228	$	127,458	$	108,235
Liabilities Incurred	7,035		61,246		4,122
Revisions of Estimates	14,509		3,267		16,693
Liabilities Settled	(14,270)		(7,268)		(7,670)
Accretion Expense	10,137		7,525		6,078
Balance at End of Year	$	209,639	$	192,228	$	127,458

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Note F — Regulatory Matters

Regulatory Assets and Liabilities

The Company has recorded the following regulatory assets and liabilities:


	At September 30
	2021		2020
	(Thousands)
Regulatory Assets(1):
Pension Costs(2) (Note K)	$	21,655	$	107,010
Post-Retirement Benefit Costs(2) (Note K)	10,075		18,863
Recoverable Future Taxes (Note G)	121,992		118,310
Environmental Site Remediation Costs(2) (Note L)	7,256		10,479
Asset Retirement Obligations(2) (Note E)	16,799		16,245
Unamortized Debt Expense (Note A)	10,589		12,297
Other(3)	33,566		20,118
Total Regulatory Assets	221,932		303,322
Less: Amounts Included in Other Current Assets	(29,206)		(16,609)
Total Long-Term Regulatory Assets	$	192,726	$	286,713


	At September 30
	2021		2020
	(Thousands)
Regulatory Liabilities:
Cost of Removal Regulatory Liability	$	245,636	$	230,079
Taxes Refundable to Customers (Note G)	354,089		357,508
Post-Retirement Benefit Costs(4) (Note K)	213,112		146,474
Amounts Payable to Customers (See Regulatory Mechanisms in Note A)	21		10,788
Other(5)	48,391		59,989
Total Regulatory Liabilities	861,249		804,838
Less: Amounts included in Current and Accrued Liabilities	(60,881)		(55,678)
Total Long-Term Regulatory Liabilities	$	800,368	$	749,160

(1)The Company recovers the cost of its regulatory assets but generally does not earn a return on them. There are a few exceptions to this rule. For example, the Company does earn a return on Unrecovered Purchased Gas Costs and, in the New York jurisdiction of its Utility segment, earns a return, within certain parameters, on the excess of cumulative funding to the pension plan over the cumulative amount collected in rates.

(2)Included in Other Regulatory Assets on the Consolidated Balance Sheets.

(3)$29,206 and $16,609 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2021 and 2020, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $4,360 and $3,509 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2021 and 2020, respectively.

(4)$30,000 is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheet at September 30, 2021, since that amount is expected to be passed back to ratepayers in the next 12 months. $183,112 is included in Other Regulatory Liabilities on the Consolidated Balance Sheet at September 30, 2021.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(5)$30,860 and $44,890 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2021 and 2020, respectively, since such amounts are expected to be passed back to ratepayers in the next 12 months. $17,531 and $15,099 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2021 and 2020, respectively.

If for any reason the Company ceases to meet the criteria for application of regulatory accounting treatment for all or part of its operations, the regulatory assets and liabilities related to those portions ceasing to meet such criteria would be eliminated from the Consolidated Balance Sheets and included in income of the period in which the discontinuance of regulatory accounting treatment occurs.

Cost of Removal Regulatory Liability

In the Company’s Utility and Pipeline and Storage segments, costs of removing assets (i.e. asset retirement costs) are collected from customers through depreciation expense. These amounts are not a legal retirement obligation as discussed in Note E — Asset Retirement Obligations. Rather, they are classified as a regulatory liability in recognition of the fact that the Company has collected dollars from customers that will be used in the future to fund asset retirement costs.

New York Jurisdiction

Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017. The order provided for a return on equity of 8.7%. The order also directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018.

Pennsylvania Jurisdiction

On July 22, 2021, Distribution Corporation filed a supplement to its current Pennsylvania tariff proposing to reduce base rates effective October 1, 2021 by $7.7 million in order to stop collecting other post-employment benefit (“OPEB”) expenses from customers at this time, to begin to refund to customers overcollected OPEB expenses in the amount of $50.0 million, and to make certain other adjustments to further reduce Distribution Corporation’s regulatory liability associated with OPEB expenses. The PaPUC issued an order approving this tariff supplement on September 15, 2021 and new rates went into effect on October 1, 2021. On September 21, 2021, a complaint was filed in this proceeding. While new rates, including associated refunds, went into effect on October 1, 2021, certain other adjustments called for by the tariff supplement that allow Distribution Corporation to reduce its regulatory liability and its OPEB expenses will not be recorded in the Company’s consolidated financial statements until the complaint is resolved. The PaPUC has assigned the matter to the Office of Administrative Law Judge. The refunds specified in the tariff supplement will be funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company’s Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation will no longer fund the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.

FERC Jurisdiction

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

Note G — Income Taxes

The components of federal and state income taxes included in the Consolidated Statements of Income are as follows:


	Year Ended September 30
	2021		2020		2019
	(Thousands)
Current Income Taxes —
Federal	$	(10)	$	(42,548)	$	(41,645)
State	8,699		6,974		4,601
Deferred Income Taxes —
Federal	90,970		4,538		98,514
State	15,023		49,775		23,751
Total Income Taxes	$	114,682	$	18,739	$	85,221

On December 22, 2017, federal tax legislation referred to as the “Tax Cuts and Jobs Act” (the 2017 Tax Reform Act) was enacted. The 2017 Tax Reform Act repealed the corporate alternative minimum tax (AMT) and provides that the Company’s existing AMT credit carryovers are refundable, if not utilized to reduce tax, beginning in fiscal 2019. As of September 30, 2018, the Company had $85.0 million of AMT credit carryovers. The Company received the first installment for $42.5 million of AMT credit refunds related to fiscal 2019 in January 2020. On March 27, 2020, the “Coronavirus Aid, Relief and Economic Security (CARES) Act” was signed into law. The CARES Act, among other things, includes provisions relating to AMT credit refunds discussed above, refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, and modifications to the net interest deduction limitation. The Company filed for the acceleration of the remaining AMT credit refunds (under CARES) of $42.5 million, which were received in June 2020.

Total income taxes as reported differ from the amounts that were computed by applying the federal income tax rate to income before income taxes. The following is a reconciliation of this difference:


	Year Ended September 30
	2021		2020		2019
	(Thousands)
U.S. Income (Loss) Before Income Taxes(1)	$	478,327	$	(105,046)	$	389,420
Income Tax Expense (Benefit), Computed at U.S. Federal Statutory Rate of 21%	$	100,449	$	(22,060)	$	81,778
State Valuation Allowance(2)	(5,560)		63,205		—
State Income Taxes (Benefit)(3)	24,300		(18,374)		22,397

Amortization of Excess Deferred Federal Income Taxes(4)	(5,215)		(4,749)		(3,185)
Plant Flow Through Items	(1,503)		(2,848)		(1,544)
Stock Compensation	2,239		3,867		(1,491)
Federal Tax Credits	(310)		(217)		(7,361)
Impact of 2017 Tax Reform Act(5)	—		—		(5,000)
Miscellaneous	282		(85)		(373)
Total Income Taxes	$	114,682	$	18,739	$	85,221

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(1)Amounts include the impact of deferred investment tax credits reported in Other Income (Deductions) on the Consolidated Statements of Income.

(2)During fiscal 2020, a valuation allowance was recorded against certain state deferred tax assets, as discussed below.

(3)The state income tax expense (benefit) shown above includes adjustments to the estimated state effective tax rates utilized in the calculation of deferred income taxes and the impact of state enhanced oil recovery tax credits.

(4)Represents amortization of net excess deferred federal income taxes under the 2017 Tax Reform Act.

(5)The $5.0 million benefit in fiscal 2019 represents the reversal of the estimated sequestration of AMT credit refunds.

Significant components of the Company’s deferred tax liabilities and assets were as follows:


	At September 30
	2021		2020
	(Thousands)
Deferred Tax Liabilities:
Property, Plant and Equipment	$	920,692	$	874,607
Pension and Other Post-Retirement Benefit Costs	23,240		54,066
Other	35,081		23,377
Total Deferred Tax Liabilities	979,013		952,050
Deferred Tax Assets:
OCI Hedging	(170,155)		(9,546)
Tax Loss and Credit Carryforwards	(120,725)		(179,363)
Pension and Other Post-Retirement Benefit Costs	(53,765)		(95,599)
Other	(31,593)		(34,693)
Total Gross Deferred Tax Assets	(376,238)		(319,201)
Valuation Allowance	57,645		63,205
Total Deferred Tax Assets	(318,593)		(255,996)
Total Net Deferred Income Taxes	$	660,420	$	696,054

The following is a summary of changes in valuation allowances for deferred tax assets:


	Year Ended September 30
	2021		2020		2019
	(Thousands)
Balance at Beginning of Year	$	63,205	$	—	$	5,000
Additions	—		63,205		—
Deductions	5,560		—		5,000
Balance at End of Year	$	57,645	$	63,205	$	—

A valuation allowance for deferred tax assets, including net operating losses and tax credits, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. The Company continually assesses the realizability of its deferred tax assets, including factors such as future taxable income, reversal of existing temporary differences, and tax planning strategies. The Company considers both positive and negative evidence related to the likelihood of the realization of the 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

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

a result of the 2017 Tax Reform Act. As of September 30, 2020, the Company recorded a valuation allowance against certain state deferred tax assets in the amount of $63.2 million based on its conclusion, considering all available objective evidence and the Company’s history of subsidiary state tax losses, that it was more likely than not that the deferred tax assets would not be realized. The valuation allowance decreased to $57.6 million as of September 30, 2021 as a result of certain state net operating loss and tax credit activity. Changes in judgment regarding future realization of these deferred tax assets may result in a reversal of all or a portion of the valuation allowance. The Company will continue to re-assess this position each quarter.

Regulatory liabilities representing the reduction of previously recorded deferred income taxes associated with rate-regulated activities that are expected to be refundable to customers amounted to $354.1 million and $357.5 million at September 30, 2021 and 2020, respectively. Also, regulatory assets representing future amounts collectible from customers, corresponding to additional deferred income taxes not previously recorded because of ratemaking practices, amounted to $122.0 million and $118.3 million at September 30, 2021 and 2020, respectively.

The Company is in the Bridge Phase of the IRS Compliance Assurance Process (“CAP”) for fiscal 2021. The Bridge Phase is intended for taxpayers with a low risk of non-compliance who are cooperative and transparent with few, if any, material issues that require resolution. The IRS will not accept any disclosures, conduct any reviews or provide any letters of assurance for the Bridge year. The federal statute of limitations remains open for fiscal 2018 and later years. The Company is also subject to various routine state income tax examinations. The Company’s principal subsidiaries operate mainly in four states which have statutes of limitations that generally expire between three to four years from the date of filing of the income tax return. Net operating losses being carried forward from prior years remain subject to examination on a future return until they are utilized, upon which time the statute of limitation begins. The Company has no unrecognized tax benefits as of September 30, 2021, 2020, or 2019.

During fiscal 2009, preliminary consent was received from the IRS National Office approving the Company’s application to change its tax method of accounting for certain capitalized costs relating to its utility property, subject to final guidance. The Company is awaiting the issuance of IRS guidance addressing the issue for natural gas utilities.

Tax carryforwards available, prior to valuation allowance, at September 30, 2021, were as follows:


Jurisdiction	Tax Attribute	Amount (Thousands)		Expires
Federal Pre-Fiscal 2019	Net Operating Loss	$	55,832	2033-2038
Federal Post-Fiscal 2018	Net Operating Loss	83,356		Unlimited
Pennsylvania	Net Operating Loss	385,093		2030-2041
California	Net Operating Loss	201,997		2030-2039


Federal	Enhanced Oil Recovery Credit	26,790		2029-2039
California	Enhanced Oil Recovery Credit	7,903		2031-2039
California	Alternative Minimum Tax Credit	8,737		Unlimited
Federal	R&D Tax Credit	6,919		2031-2041

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Note H — Capitalization and Short-Term Borrowings

Summary of Changes in Common Stock Equity


	Common Stock			Paid In Capital		Earnings Reinvested in the Business			Accumulated Other Comprehensive Income (Loss)
	Shares	Amount
	(Thousands, except per share amounts)
Balance at September 30, 2018	85,957	$	85,957	$	820,223	$	1,098,900		$	(67,750)
Net Income Available for Common Stock						304,290
Dividends Declared on Common Stock ($1.72 Per Share)						(148,432)
Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities						7,437
Cumulative Effect of Adoption of Authoritative Guidance for Reclassification of Stranded Tax Effects						10,406
Other Comprehensive Income, Net of Tax									15,595
Share-Based Payment Expense(1)				19,613
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	358	358		(7,572)
Balance at September 30, 2019	86,315	86,315		832,264		1,272,601			(52,155)
Net Loss Available for Common Stock						(123,772)
Dividends Declared on Common Stock ($1.76 Per Share)						(156,249)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging						(950)
Other Comprehensive Loss, Net of Tax									(62,602)
Share-Based Payment Expense(1)				13,180
Common Stock Issued from Sale of Common Stock	4,370	4,370		161,399
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	270	270		(2,685)
Balance at September 30, 2020	90,955	90,955		1,004,158		991,630			(114,757)
Net Income Available for Common Stock						363,647
Dividends Declared on Common Stock ($1.80 Per Share)						(164,102)
Other Comprehensive Loss, Net of Tax									(398,840)
Share-Based Payment Expense(1)				15,297
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	227	227		(2,009)
Balance at September 30, 2021	91,182	$	91,182	$	1,017,446	$	1,191,175	(2)	$	(513,597)

(1)Paid in Capital includes compensation costs associated with performance shares and/or restricted stock awards. The expense is included within Net Income Available for Common Stock, net of tax benefits.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(2)The availability of consolidated earnings reinvested in the business for dividends payable in cash is limited under terms of the indentures covering long-term debt. At September 30, 2021, $1.0 billion of accumulated earnings was free of such limitations.

Common Stock

The Company has various plans which allow shareholders, employees and others to purchase shares of the Company common stock. The National Fuel Gas Company Direct Stock Purchase and Dividend Reinvestment Plan allows shareholders to reinvest cash dividends and make cash investments in the Company’s common stock and provides investors the opportunity to acquire shares of the Company common stock without the payment of any brokerage commissions in connection with such acquisitions. The 401(k) Plans allow employees the opportunity to invest in the Company common stock, in addition to a variety of other investment alternatives. Generally, at the discretion of the Company, shares purchased under these plans are either original issue shares purchased directly from the Company or shares purchased on the open market by an independent agent. During 2021, the Company did not issue any original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan or the Company's 401(k) plans.

During 2021, the Company issued 106,007 original issue shares of common stock for restricted stock units that vested and 165,161 original issue shares of common stock for performance shares that vested. Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes. During 2021, 83,288 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

The Company also has a director stock program under which it issues shares of Company common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, including the reinvestment of dividends for certain non-employee directors who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's Deferred Compensation Plan for Directors and Officers, as partial consideration for the directors’ services during the fiscal year. Under this program, the Company issued 38,973 original issue shares of common stock during 2021.

Stock Award Plans

Stock-based compensation expense for the years ended September 30, 2021, 2020 and 2019 was approximately $15.2 million, $13.1 million and $19.5 million, respectively. Stock-based compensation expense is included in operation and maintenance expense on the Consolidated Statements of Income. The total income tax benefit related to stock-based compensation expense during the years ended September 30, 2021, 2020 and 2019 was approximately $2.4 million, $2.1 million and $3.8 million, respectively. A portion of stock-based compensation expense is subject to capitalization under IRS uniform capitalization rules. Stock-based compensation of $0.1 million was capitalized under these rules during each of the years ended September 30,

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

2021, 2020 and 2019. The tax expense related to stock-based compensation exercises and vestings was $0.7 million for the year ended September 30, 2021.

Pursuant to registration statements for these plans, there were 2,845,865 shares available for future grant at September 30, 2021. These shares include shares available for future options, SARs, restricted stock and performance share grants.

SARs

Transactions for 2021 involving SARs for all plans are summarized as follows:


	Number of Shares Subject To Option	Weighted Average Exercise Price		Weighted Average Remaining Contractual Life (Years)	Aggregate Intrinsic Value (In thousands)
Outstanding at September 30, 2020	513,180	$	56.07
Granted in 2021	—	$	—
Exercised in 2021	—	$	—
Forfeited in 2021	—	$	—
Expired in 2021	(194,735)	$	60.10

Outstanding at September 30, 2021	318,445	$	53.60	0.90	$	—
SARs exercisable at September 30, 2021	318,445	$	53.60	0.90	$	—

The Company did not grant any SARs during the years ended September 30, 2020 and 2019. The Company’s SARs include both performance based and nonperformance-based SARs, but the performance conditions associated with the performance based SARs at the time of grant have all been subsequently met. The SARs are considered equity awards under the current authoritative guidance for stock-based compensation. The accounting for SARs is the same as the accounting for stock options.

During the year ended September 30, 2020, no SARs were exercised. The total intrinsic value of SARs exercised during the year ended September 30, 2019 totaled approximately $7.2 million. There were no SARs that became fully vested during the years ended September 30, 2021, 2020 and 2019, and all SARs outstanding have been fully vested since fiscal 2017.

Restricted Share Awards

Transactions for 2021 involving restricted share awards for all plans are summarized as follows:


	Number of Restricted Share Awards	Weighted Average Fair Value per Award
Outstanding at September 30, 2020	20,000	$	47.46
Granted in 2021	—	$	—
Vested in 2021	(20,000)	$	47.46
Forfeited in 2021	—	$	—
Outstanding at September 30, 2021	—	$	—

The Company did not grant any restricted share awards (non-vested stock as defined by the current accounting literature) during the years ended September 30, 2020 and 2019.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Restricted Stock Units

Transactions for 2021 involving nonperformance-based restricted stock units for all plans are summarized as follows:


	Number of Restricted Stock Units	Weighted Average Fair Value per Award
Outstanding at September 30, 2020	335,773	$	44.76
Granted in 2021	172,513	$	37.98
Vested in 2021	(106,007)	$	46.35
Forfeited in 2021	(36,798)	$	41.22
Outstanding at September 30, 2021	365,481	$	41.45

The Company also granted 150,839 and 123,939 nonperformance-based restricted stock units during the years ended September 30, 2020 and 2019, respectively. The weighted average fair value of such nonperformance-based restricted stock units granted in 2020 and 2019 was $40.38 per share and $49.40 per share, respectively. As of September 30, 2021, unrecognized compensation expense related to nonperformance-based restricted stock units totaled approximately $6.0 million, which will be recognized over a weighted average period of 2.0 years.

Vesting restrictions for the nonperformance-based restricted stock units outstanding at September 30, 2021 will lapse as follows: 2022 — 119,225 units; 2023 — 108,138 units; 2024 — 83,618 units; 2025 - 35,650 units; and 2026 - 18,850 units.

Performance Shares

Transactions for 2021 involving performance shares for all plans are summarized as follows:


	Number of Performance Shares	Weighted Average Fair Value per Award
Outstanding at September 30, 2020	592,628	$	49.18
Granted in 2021	309,470	$	39.19
Vested in 2021	(165,161)	$	50.99
Forfeited in 2021	(136,303)	$	42.15

Outstanding at September 30, 2021	600,634	$	45.13

The Company also granted 254,608 and 244,734 performance shares during the years ended September 30, 2020 and 2019, respectively. The weighted average grant date fair value of such performance shares granted in 2020 and 2019 was $43.32 per share and $55.67 per share, respectively. As of September 30, 2021, unrecognized compensation expense related to performance shares totaled approximately $8.5 million, which will be recognized over a weighted average period of 1.7 years. Vesting restrictions for the outstanding performance shares at September 30, 2021 will lapse as follows: 2022 — 165,438 shares; 2023 — 203,632 shares; and 2024 — 231,564 shares.

Half of the performance shares granted during the years ended September 30, 2021, 2020 and 2019 must meet a performance goal related to relative return on capital over a three-year performance cycle. The performance goal over the respective performance cycles for the performance shares granted during 2021, 2020 and 2019 is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”). Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

the Report Group companies in the Bloomberg database. The number of these performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value of these performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award.

The other half of the performance shares granted during the years ended September 30, 2021, 2020 and 2019 must meet a performance goal related to relative total shareholder return over a three-year performance cycle. The performance goal over the respective performance cycles for the total shareholder return performance shares ("TSR performance shares") granted during 2021, 2020 and 2019 is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group. Three-year shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these TSR performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value price at the date of grant for the TSR performance shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the present value of forgone dividends over the vesting term of the award. This price is multiplied by the number of TSR performance shares awarded, the result of which is recorded as compensation expense over the vesting term of the award. In calculating the fair value of the award, the risk-free interest rate is based on the yield of a Treasury Note with a term commensurate with the remaining term of the TSR performance shares. The remaining term is based on the remainder of the performance cycle as of the date of grant. The expected volatility is based on historical daily stock price returns. For the TSR performance shares, it was assumed that there would be no forfeitures, based on the vesting term and the number of grantees. The following assumptions were used in estimating the fair value of the TSR performance shares at the date of grant:


	Year Ended September 30
	2021		2020		2019
Risk-Free Interest Rate	0.19	%	1.63	%	2.61	%
Remaining Term at Date of Grant (Years)	2.80		2.81		2.78
Expected Volatility	29.1	%	19.3	%	20.2	%
Expected Dividend Yield (Quarterly)	N/A		N/A		N/A

Redeemable Preferred Stock

As of September 30, 2021, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Long-Term Debt

The outstanding long-term debt is as follows:


	At September 30
	2021		2020
	(Thousands)
Medium-Term Notes(1):
7.4% due March 2023 to June 2025	$	99,000	$	99,000
Notes(1)(2)(3):
2.95% to 5.50% due March 2023 to March 2031	2,550,000		2,550,000
Total Long-Term Debt	2,649,000		2,649,000
Less Unamortized Discount and Debt Issuance Costs	20,313		19,424
Less Current Portion(4)	—		—
	$	2,628,687	$	2,629,576

(1)The Medium-Term Notes and Notes are unsecured.

(2)The holders of these notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade.

(3)The interest rate payable on $300.0 million of 4.75% notes, $300.0 million of 3.95% notes and $500.0 million of 2.95% notes will be subject to adjustment from time to time, with a maximum of 2.00%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The interest rate payable on $500.0 million of 5.50% notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50%, if there is a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded.

(4)None of the Company's long-term debt at September 30, 2021 and 2020 will mature within the following twelve-month period.

On February 24, 2021, the Company issued $500.0 million of 2.95% notes due March 1, 2031. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.3 million. The proceeds of this debt issuance were used for general corporate purposes, including the redemption of $500.0 million of 4.90% notes on March 11, 2021 that were scheduled to mature in December 2021. The Company redeemed those notes for $515.7 million, plus accrued interest. The early redemption premium of $15.7 million was recorded to Interest Expense on Long-Term Debt on the Consolidated Income Statement during the quarter ended March 31, 2021.

On June 3, 2020, the Company issued $500.0 million of 5.50% notes due January 15, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $493.0 million. The proceeds of this debt issuance were used for general corporate purposes, which included the payment of a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020 and the repayment and refinancing of short-term debt.

As of September 30, 2021, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: zero in 2022, $549.0 million in 2023, zero in 2024, $500.0 million in 2025, $500.0 million in 2026, and $1,100.0 million thereafter.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Short-Term Borrowings

The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. On October 25, 2018, the Company entered into a Fourth Amended and Restated Credit Agreement ("Credit Agreement") with a syndicate of twelve banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through October 25, 2023. In addition to the Credit Agreement, on February 3, 2021, the Company amended its existing 364-Day Credit Agreement to extend the maturity date thereof from May 3, 2021 to December 30, 2022, and to increase the lenders' commitments thereunder from $200.0 million to $250.0 million, among other changes (as amended, the "Amended 364-Day Credit Agreement"). Twelve banks are parties to the Amended 364-Day Credit Agreement, all of which are also lenders under the Credit Agreement. The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future. The total amount available to be issued under the Company’s commercial paper program is $500.0 million. At September 30, 2021, the commercial paper program is backed by the Credit Agreement.

At September 30, 2021, the Company had outstanding commercial paper of $158.5 million with a weighted average interest rate on the commercial paper of 0.40%. The Company did not have any outstanding short-term notes payable to banks at September 30, 2021. At September 30, 2020, the Company had outstanding short-term notes payable to banks of $15.0 million, all of which was issued under the Credit Agreement. The Company had outstanding commercial paper of $15.0 million at September 30, 2020. At September 30, 2020, the weighted average interest rate on the short-term notes payable to banks was 1.51% and the weighted average interest rate on the commercial paper was 0.25%.

Debt Restrictions

The Credit Agreement provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $250 million. This provision also applies to the Amended 364-Day Credit Agreement. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at September 30, 2021, $190.7 million was added back to the Company's total capitalization for purposes of the facility, and the Company’s debt to capitalization ratio, as calculated under the facility, was .59. The constraints specified in both the Credit Agreement and Amended 364-Day Credit Agreement would have permitted an additional $884.2 million in short-term and/or long-term debt to be outstanding before the Company’s debt to capitalization ratio exceeded .65.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more, or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.

In order to issue incremental long-term debt, the Company must meet an interest coverage test under its existing indenture covenants. 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, taking into account the incremental issuance, and using a pro forma balance sheet as of the last day of the 12-month period used in the interest coverage test, the Company must maintain a ratio of long-term debt to consolidated assets (as defined under the indenture) of not more than 60%. Under the Company's existing indenture covenants at September 30, 2021, the Company would have been permitted to issue up to a maximum of approximately $1.6 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by debt to capitalization ratio constraints under the Company’s Credit Agreement and Amended 364-Day Credit Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to Part II, Item 7, Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

The Company’s 1974 indenture pursuant to which $99.0 million (or 3.7%) of the Company’s long-term debt (as of September 30, 2021) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

Note I — Fair Value Measurements

The FASB authoritative guidance regarding fair value measurements establishes a fair-value hierarchy and prioritizes the inputs used in valuation techniques that measure fair value. Those inputs are prioritized into three levels. Level 1 inputs are unadjusted quoted prices in active markets for assets or liabilities that the Company can access at the measurement date. Level 2 inputs are inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly or indirectly at the measurement date. Level 3 inputs are unobservable inputs for the asset or liability at the measurement date. The Company’s assessment of the significance of a particular input to the fair value measurement requires judgment, and may affect the valuation of fair value assets and liabilities and their placement within the fair value hierarchy levels.

The following table sets forth, by level within the fair value hierarchy, the Company’s financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of September 30, 2021 and 2020. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over-the-counter swaps combines gas

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company.


	At Fair Value as of September 30, 2021
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Netting Adjustments(1)		Total(1)
	(Dollars in thousands)
Assets:
Cash Equivalents — Money Market Mutual Funds	$	22,269	$	—	$	—	$	—	$	22,269
Hedging Collateral Deposits	88,610		—		—		—		88,610
Derivative Financial Instruments:

Over the Counter Swaps — Gas and Oil	—		1,802		—		(1,802)		—

Foreign Currency Contracts	—		938		—		(938)		—
Other Investments:
Balanced Equity Mutual Fund	34,433		—		—		—		34,433
Fixed Income Mutual Fund	70,639		—		—		—		70,639



Total	$	215,951	$	2,740	$	—	$	(2,740)	$	215,951
Liabilities:
Derivative Financial Instruments:

Over the Counter Swaps — Gas and Oil	$	—	$	601,551	$	—	$	(1,802)	$	599,749
Over the Counter No Cost Collars — Gas	—		17,385		—		—		17,385
Foreign Currency Contracts	—		214		—		(938)		(724)
Total	$	—	$	619,150	$	—	$	(2,740)	$	616,410
Total Net Assets/(Liabilities)	$	215,951	$	(616,410)	$	—	$	—	$	(400,459)


	At Fair Value as of September 30, 2020
Recurring Fair Value Measures	Level 1		Level 2		Level 3		Netting Adjustments(1)		Total(1)
	(Dollars in thousands)
Assets:
Cash Equivalents — Money Market Mutual Funds	$	12,285	$	—	$	—	$	—	$	12,285
Derivative Financial Instruments:
Over the Counter Swaps — Gas and Oil	—		36,418		—		(26,400)		10,018
Over the Counter No Cost Collars — Gas	—		—		—		(720)		(720)
Foreign Currency Contracts	—		259		—		(338)		(79)
Other Investments:
Balanced Equity Mutual Fund	39,618		—		—		—		39,618
Fixed Income Mutual Fund	72,253		—		—		—		72,253
Common Stock — Financial Services Industry	639		—		—		—		639


Total	$	124,795	$	36,677	$	—	$	(27,458)	$	134,014
Liabilities:
Derivative Financial Instruments:
Over the Counter Swaps — Gas and Oil	$	—	$	61,280	$	—	$	(26,400)	$	34,880
Over the Counter No Cost Collars — Gas	—		8,171		—		(720)		7,451
Foreign Currency Contracts	—		1,976		—		(338)		1,638
Total	$	—	$	71,427	$	—	$	(27,458)	$	43,969
Total Net Assets/(Liabilities)	$	124,795	$	(34,750)	$	—	$	—	$	90,045

(1)Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Derivative Financial Instruments

At September 30, 2021, the derivative financial instruments reported in Level 2 consist of natural gas price swap agreements, natural gas no cost collars, crude oil price swap agreements, and foreign currency contracts, all of which are used in the Company's Exploration and Production segment. Hedging collateral deposits of $88.6 million at September 30, 2021, which were associated with the price swap agreements, no cost collars and foreign currency contracts, have been reported in Level 1 at September 30, 2021.

The fair value of the Level 2 price swap agreements and no cost collars is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The fair value of the Level 2 foreign currency contracts at September 30, 2021 and September 30, 2020 are determined using the market approach based on observable market transactions of forward Canadian currency rates.

For the years ended September 30, 2021 and 2020, there were no assets or liabilities measured at fair value and classified as Level 3.

Note J — Financial Instruments

Long-Term Debt

The fair market value of the Company’s debt, as presented in the table below, was determined using a discounted cash flow model, which incorporates the Company’s credit ratings and current market conditions in determining the yield, and subsequently, the fair market value of the debt. Based on these criteria, the fair market value of long-term debt, including current portion, was as follows:


	At September 30
	2021 Carrying Amount		2021 Fair Value		2020 Carrying Amount		2020 Fair Value
	(Thousands)
Long-Term Debt	$	2,628,687	$	2,898,552	$	2,629,576	$	2,778,556

The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value. The fair value of long-term debt was calculated using observable inputs (U.S. Treasuries for the risk-free component and company specific credit spread information — generally obtained from recent trade activity in the debt). As such, the Company considers the debt to be Level 2.

Any temporary cash investments, notes payable to banks and commercial paper are stated at cost. Temporary cash investments are considered Level 1, while notes payable to banks and commercial paper are considered to be Level 2. Given the short-term nature of the notes payable to banks and commercial paper, the Company believes cost is a reasonable approximation of fair value.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Other Investments

The components of the Company's Other Investments are as follows (in thousands):


	At September 30
	2021		2020
	(Thousands)
Life Insurance Contracts	$	44,560	$	41,992
Equity Mutual Fund	34,433		39,618
Fixed Income Mutual Fund	70,639		72,253
Marketable Equity Securities	—		639
	$	149,632	$	154,502

Investments in life insurance contracts are stated at their cash surrender values or net present value. Investments in an equity mutual fund and a fixed income mutual fund are stated at fair value based on quoted market prices with changes in fair value recognized in net income. The insurance contracts and equity mutual fund are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees. The fixed income mutual fund is primarily an informal funding mechanism for certain regulatory obligations that the Company has to Utility segment customers in its Pennsylvania jurisdiction, as discussed in Note F — Regulatory Matters, and for various benefit obligations the Company has to certain employees.

Derivative Financial Instruments

The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment. The Company enters into over-the-counter no cost collars and over-the-counter swap agreements for natural gas and crude oil to manage the price risk associated with forecasted sales of gas and oil. In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. These instruments are accounted for as cash flow hedges. The duration of the Company’s cash flow hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 9 years.

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at September 30, 2021 and September 30, 2020. Substantially all of the derivative financial instruments reported on those line items relate to commodity contracts and a small portion relates to foreign currency forward contracts.

Cash Flow Hedges

For derivative financial instruments that are designated and qualify as a cash flow hedge, the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings.

As of September 30, 2021, the Company had the following commodity derivative contracts (swaps and no cost collars) outstanding:


Commodity	Units
Natural Gas	419.7	Bcf

Crude Oil	2,016,000	Bbls

As of September 30, 2021, the Company was hedging a total of $60.7 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

As of September 30, 2021, the Company had $616.4 million ($450.0 million after-tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that $464.5

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

million ($339.1 million after-tax) of such unrealized losses will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings.


The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Year Ended September 30, 2021 and 2020 (Dollar Amounts in Thousands)
Derivatives in Cash Flow Hedging Relationships	Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) for the Year Ended September 30,				Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Year Ended September 30,
	2021		2020			2021		2020
Commodity Contracts	$	(668,074)	$	9,905	Operating Revenue	$	(83,973)	$	93,691
Commodity Contracts	—		391		Purchased Gas	—		661
Foreign Currency Contracts	2,703		(434)		Operating Revenue	262		(1,057)
Total	$	(665,371)	$	9,862		$	(83,711)	$	93,295

Credit Risk

The Company has over-the-counter swap positions, no cost collars and applicable foreign currency forward contracts with seventeen counterparties. The majority of the Company’s counterparties are financial institutions and energy traders. As of September 30, 2021, fifteen of the seventeen counterparties to the Company’s outstanding derivative financial instrument contracts (specifically the over-the-counter swaps, over-the-counter no cost collars and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to post or increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative financial instrument contracts with a credit-risk contingency feature were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then hedging collateral deposits or an increase to such deposits could be required. At September 30, 2021, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $504.6 million according to the Company's internal model (discussed in Note I — Fair Value Measurements) and the Company posted $88.6 million in hedging collateral deposits. Depending on the movement of commodity prices in the future, it is possible that these liability positions could swing into asset positions, at which point the Company would be exposed to credit risk on its derivative financial instruments. In that case, the Company's counterparties could be required to post hedging collateral deposits.

The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value.

Note K — Retirement Plan and Other Post-Retirement Benefits

The Company has a tax-qualified, noncontributory, defined-benefit retirement plan (Retirement Plan). The Retirement Plan covers certain non-collectively bargained employees hired before July 1, 2003 and certain collectively bargained employees hired before November 1, 2003. Certain non-collectively bargained employees hired after June 30, 2003 and certain collectively bargained employees hired after October 31, 2003

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

are eligible for a Retirement Savings Account benefit provided under the Company’s defined contribution Tax-Deferred Savings Plans. Costs associated with the Retirement Savings Account were $4.8 million, $4.2 million and $3.9 million for the years ended September 30, 2021, 2020 and 2019, respectively. Costs associated with the Company’s contributions to the Tax-Deferred Savings Plans, exclusive of the costs associated with the Retirement Savings Account, were $7.2 million, $6.7 million, and $6.4 million for the years ended September 30, 2021, 2020 and 2019, respectively.

The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The other post-retirement benefits cover certain non-collectively bargained employees hired before January 1, 2003 and certain collectively bargained employees hired before October 31, 2003.

The Company’s policy is to fund the Retirement Plan with at least an amount necessary to satisfy the minimum funding requirements of applicable laws and regulations and not more than the maximum amount deductible for federal income tax purposes. The Company has established VEBA trusts for its other post-retirement benefits. Contributions to the VEBA trusts are tax deductible, subject to limitations contained in the Internal Revenue Code and regulations and are made to fund employees’ other post-retirement benefits, as well as benefits as they are paid to current retirees. In addition, the Company has established 401(h) accounts for its other post-retirement benefits. They are separate accounts within the Retirement Plan trust used to pay retiree medical benefits for the associated participants in the Retirement Plan. Although these accounts are in the Retirement Plan trust, for funding status purposes as shown below, the 401(h) accounts are included in Fair Value of Assets under Other Post-Retirement Benefits. Contributions are tax-deductible when made, subject to limitations contained in the Internal Revenue Code and regulations.

The expected return on Retirement Plan assets, a component of net periodic benefit cost shown in the tables below, is applied to the market-related value of plan assets. The market-related value of plan assets is the market value as of the measurement date adjusted for variances between actual returns and expected returns (from previous years) that have not been reflected in net periodic benefit costs. The expected return on other post-retirement benefit assets (i.e. the VEBA trusts and 401(h) accounts), which is a component of net periodic benefit cost shown in the tables below, is applied to the fair value of assets as of the measurement date.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Reconciliations of the Benefit Obligations, Plan Assets and Funded Status, as well as the components of Net Periodic Benefit Cost and the Weighted Average Assumptions of the Retirement Plan and other post-retirement benefits are shown in the tables below. The components of net periodic benefit cost other than service cost are presented in Other Income (Deductions) on the Consolidated Statements of Income. The date used to measure the Benefit Obligations, Plan Assets and Funded Status is September 30 for fiscal years 2021, 2020 and 2019.


	Retirement Plan									Other Post-Retirement Benefits
	Year Ended September 30									Year Ended September 30
	2021			2020			2019			2021			2020			2019
	(Thousands)
Change in Benefit Obligation
Benefit Obligation at Beginning of Period	$	1,139,105		$	1,097,625		$	985,690		$	476,722		$	468,163		$	435,986
Service Cost	9,865			9,318			8,482			1,602			1,609			1,519
Interest Cost	21,686			29,930			38,378			9,303			12,913			17,145
Plan Participants’ Contributions	—			—			—			3,216			3,058			2,930
Retiree Drug Subsidy Receipts	—			—			—			1,244			1,411			1,855

Actuarial (Gain) Loss	(8,141)			65,908			127,748			(34,729)			16,396			34,401
Benefits Paid	(64,059)			(63,676)			(62,673)			(26,145)			(26,828)			(25,673)
Benefit Obligation at End of Period	$	1,098,456		$	1,139,105		$	1,097,625		$	431,213		$	476,722		$	468,163
Change in Plan Assets
Fair Value of Assets at Beginning of Period	$	1,016,796		$	968,449		$	924,506		$	547,885		$	524,127		$	513,800
Actual Return on Plan Assets	122,992			87,402			77,401			47,541			44,448			30,006
Employer Contributions	20,000			24,621			29,215			3,068			3,080			3,064
Plan Participants’ Contributions	—			—			—			3,216			3,058			2,930
Benefits Paid	(64,059)			(63,676)			(62,673)			(26,145)			(26,828)			(25,673)
Fair Value of Assets at End of Period	$	1,095,729		$	1,016,796		$	968,449		$	575,565		$	547,885		$	524,127
Net Amount Recognized at End of Period (Funded Status)	$	(2,727)		$	(122,309)		$	(129,176)		$	144,352		$	71,163		$	55,964
Amounts Recognized in the Balance Sheets Consist of:
Non-Current Liabilities	$	(2,727)		$	(122,309)		$	(129,176)		$	(4,799)		$	(4,872)		$	(4,553)
Non-Current Assets	—			—			—			149,151			76,035			60,517
Net Amount Recognized at End of Period	$	(2,727)		$	(122,309)		$	(129,176)		$	144,352		$	71,163		$	55,964
Accumulated Benefit Obligation	$	1,060,659		$	1,096,427		$	1,053,914		N/A			N/A			N/A
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30
Discount Rate	2.75		%	2.66		%	3.15		%	2.76		%	2.71		%	3.17		%
Rate of Compensation Increase	4.70		%	4.70		%	4.70		%	4.70		%	4.70		%	4.70		%

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	Retirement Plan									Other Post-Retirement Benefits
	Year Ended September 30									Year Ended September 30
	2021			2020			2019			2021			2020			2019
	(Thousands)
Components of Net Periodic Benefit Cost
Service Cost	$	9,865		$	9,318		$	8,482		$	1,602		$	1,609		$	1,519
Interest Cost	21,686			29,930			38,378			9,303			12,913			17,145
Expected Return on Plan Assets	(58,148)			(60,063)			(62,368)			(28,964)			(29,232)			(30,157)
Amortization of Prior Service Cost (Credit)	631			729			826			(429)			(429)			(429)

Recognition of Actuarial Loss(1)	36,814			39,384			32,096			849			535			5,962
Net Amortization and Deferral for Regulatory Purposes	14,063			5,359			2,493			28,010			25,596			16,481
Net Periodic Benefit Cost	$	24,911		$	24,657		$	19,907		$	10,371		$	10,992		$	10,521
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30
Effective Discount Rate for Benefit Obligations	2.66		%	3.15		%	4.30		%	2.71		%	3.17		%	4.31		%
Effective Rate for Interest on Benefit Obligations	1.96		%	2.81		%	4.03		%	2.01		%	2.84		%	4.05		%
Effective Discount Rate for Service Cost	3.01		%	3.31		%	4.40		%	3.20		%	3.39		%	4.43		%
Effective Rate for Interest on Service Cost	2.60		%	3.12		%	4.29		%	2.98		%	3.30		%	4.39		%
Expected Return on Plan Assets	6.00		%	6.40		%	6.75		%	5.40		%	5.70		%	6.00		%
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.

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 $8.3 million, $8.9 million and $7.6 million in 2021, 2020 and 2019, respectively. The components of net periodic benefit cost other than service costs associated with these plans are presented in Other Income (Deductions) on

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

the Consolidated Statements of Income. The accumulated benefit obligations for the plans were $76.9 million, $78.7 million and $79.8 million at September 30, 2021, 2020 and 2019, respectively. The projected benefit obligations for the plans were $95.8 million, $98.1 million and $99.5 million at September 30, 2021, 2020 and 2019, respectively. At September 30, 2021, $15.4 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $80.4 million is recorded in Other Liabilities on the Consolidated Balance Sheets. At September 30, 2020, $14.5 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $83.6 million was recorded in Other Liabilities on the Consolidated Balance Sheets. At September 30, 2019, $13.2 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $86.3 million was recorded in Other Liabilities on the Consolidated Balance Sheets. The weighted average discount rates for these plans were 2.15%, 1.92% and 2.77% as of September 30, 2021, 2020 and 2019, respectively and the weighted average rates of compensation increase for these plans were 8.00%, 8.00% and 8.00% as of September 30, 2021, 2020 and 2019, respectively.

The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2021, as well as the changes in such amounts during 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)	$	(105,532)	$	26,112	$	(33,241)
Prior Service (Cost) Credit	(3,009)		1,972		—
Net Amount Recognized	$	(108,541)	$	28,084	$	(33,241)
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2021(1)
Decrease (Increase) in Actuarial Loss, excluding amortization(2)	$	72,985	$	53,307	$	(5,029)
Change due to Amortization of Actuarial Loss	36,814		849		5,852

Prior Service (Cost) Credit	631		(429)		—
Net Change	$	110,430	$	53,727	$	823

(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, 2021, the Company recorded a $130.9 million decrease to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $34.1 million (pre-tax) increase to Accumulated Other Comprehensive Income.

The effect of the discount rate change for the Retirement Plan in 2021 was to decrease the projected benefit obligation of the Retirement Plan by $11.2 million. The mortality improvement projection scale was updated, which decreased the projected benefit obligation of the Retirement Plan in 2021 by $2.9 million. Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2021 by $5.9 million. The effect of the discount rate change for the Retirement Plan in 2020 was to increase the projected

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

benefit obligation of the Retirement Plan by $61.3 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 Company made cash contributions totaling $20.0 million to the Retirement Plan during the year ended September 30, 2021. The Company expects that the annual contribution to the Retirement Plan in 2022 will be in the range of $20.0 million to $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: $67.0 million in 2022; $67.1 million in 2023; $67.2 million in 2024; $66.9 million in 2025; $66.4 million in 2026; and $320.2 million in the five years thereafter.

The effect of the discount rate change in 2021 was to decrease the other post-retirement benefit obligation by $2.5 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2021 by $2.0 million. The health care cost trend rates were updated, which decreased the other post-retirement benefit obligation in 2021 by $3.7 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2021 by $26.6 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 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 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
2022	$	27,230	$	(1,900)
2023	$	27,442	$	(2,006)
2024	$	27,601	$	(2,111)
2025	$	27,691	$	(2,201)
2026	$	27,643	$	(2,289)
2027 through 2031	$	134,674	$	(12,253)

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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


	2021			2020			2019
Rate of Medical Cost Increase for Pre Age 65 Participants	5.38	%	(1)	5.42	%	(2)	5.50	%	(2)
Rate of Medical Cost Increase for Post Age 65 Participants	4.84	%	(1)	4.75	%	(2)	4.75	%	(2)
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits	6.53	%	(1)	6.80	%	(2)	7.35	%	(2)
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement	4.84	%	(1)	4.75	%	(2)	4.75	%	(2)
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy	6.15	%	(1)	6.20	%	(2)	6.84	%	(2)

(1)It was assumed that this rate would gradually decline to 4% by 2046.

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

The Company made cash contributions totaling $2.8 million to its VEBA trusts during the year ended September 30, 2021. In addition, the Company made direct payments of $0.3 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2021. The Company expects that the annual contribution to its VEBA trusts in 2022 will be in the range of $2.5 million to $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 I — 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, 2021 and 2020, 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):


	At September 30, 2021
	Total Fair Value		Level 1		Level 2		Level 3		Measured at NAV(7)
Retirement Plan Investments
Domestic Equities(1)	$	56,511	$	146	$	—	$	—	$	56,365
International Equities(2)	28,917		—		—		—		28,917
Global Equities(3)	95,865		—		—		—		95,865
Domestic Fixed Income(4)	818,361		1,447		758,417		—		58,497
International Fixed Income(5)	13,773		—		13,773		—		—
Global Fixed Income(6)	42,454		—		—		—		42,454

Real Estate	119,451		—		—		319		119,132
Cash Held in Collective Trust Funds	27,471		—		—		—		27,471
Total Retirement Plan Investments	1,202,803		1,593		772,190		319		428,701
401(h) Investments	(90,429)		(121)		(58,840)		(24)		(31,444)
Total Retirement Plan Investments (excluding 401(h) Investments)	$	1,112,374	$	1,472	$	713,350	$	295	$	397,257
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash	(16,645)
Total Retirement Plan Assets	$	1,095,729

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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	$	—	$	—	$	70,815
International Equities(2)	94,603		—		—		—		94,603
Global Equities(3)	77,736		—		—		—		77,736
Domestic Fixed Income(4)	512,693		2,000		457,381		—		53,312
International Fixed Income(5)	20,201		—		20,201		—		—
Global Fixed Income(6)	79,595		—		—		—		79,595

Real Estate	106,167		—		—		471		105,696
Cash Held in Collective Trust Funds	18,023		—		—		—		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

(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).


	At September 30, 2021
	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	$	165,226	$	—	$	—	$	—	$	165,226


Exchange Traded Funds — Fixed Income	313,392		313,392		—		—		—

Cash Held in Collective Trust Funds	9,700		—		—		—		9,700
Total VEBA Trust Investments	488,318		313,392		—		—		174,926
401(h) Investments	90,429		121		58,840		24		31,444
Total Investments (including 401(h) Investments)	$	578,747	$	313,513	$	58,840	$	24	$	206,370
Miscellaneous Accruals (including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative)	(3,182)
Total Other Post-Retirement Benefit Assets	$	575,565

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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	$	—	$	—	$	—	$	153,923
Exchange Traded Funds — Fixed Income	301,290		301,290		—		—		—

Cash Held in Collective Trust Funds	13,841		—		—		—		13,841
Total VEBA Trust Investments	469,054		301,290		—		—		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

(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, 2021 and September 30, 2020, there were no transfers from Level 1 to Level 2. In addition, as shown in the following tables, there were no transfers in or out of Level 3.


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


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

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

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

Unrealized Gains/(Losses)	(152)		11		(141)

Sales	—		—		—
Balance at September 30, 2021	$	319	$	(24)	$	295

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


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

Balance at September 30, 2019	$	223

Unrealized Gains/(Losses)	(188)

Sales	—
Balance at September 30, 2020	35

Unrealized Gains/(Losses)	(11)
Sales	—
Balance at September 30, 2021	$	24

The Company’s assumption regarding the expected long-term rate of return on plan assets is 5.20% for both the Retirement Plan and other post-retirement benefits, effective for fiscal 2022. 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). Risk tolerance is established through consideration of plan liabilities, plan funded status and corporate financial condition. The assets of the Retirement Plan trust, 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. In fiscal 2021, capital market conditions led to significant improvements in the funded status of the Retirement Plan. As a result, the Company reduced the return seeking portion of its assets, particularly equity securities, held in the Retirement Plan, and increased its allocation to non-return seeking fixed income securities in conjunction with the Company’s liability driven investment strategy. The actual asset allocations as of September 30, 2021 are noted in the table above, and such allocations are subject to change, but the majority of the assets will remain non-return seeking fixed income assets. Similarly, given the level of the VEBA trust and 401(h) assets in relation to the Other Post-Retirement Benefits, the majority of those assets are and will remain in fixed income securities.

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

Note L — Commitments and Contingencies

Environmental Matters

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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, 2021, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.3 million, which includes a $0.2 million estimated minimum liability for post-remediation ongoing monitoring and long-term maintenance of 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. Active remedial work at the site has been completed and restoration is currently underway. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at September 30, 2021. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately one year 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 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. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order and FERC's decisions were appealed. The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project.

Other

The Company, in its Utility segment and Exploration and Production segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. The future gas purchase, transportation and storage contract commitments during the next five years and thereafter are as follows: $319.2 million in 2022, $97.4 million in 2023, $114.0 million in 2024, $129.6 million in 2025, $139.1 million in 2026 and $1,016.0 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 by the unbundling of services in the Utility segment’s service territory, such costs will be recoverable from customers.

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, 2021, the future contractual commitments related to the system modernization and expansion projects are $72.5 million in 2022, $7.1 million in 2023, $6.9 million in 2024, $6.9 million in 2025, $7.0 million in 2026 and $13.6 million thereafter.

The Company, in its Exploration and Production segment, has entered into contractual obligations to support its development activities and operations in Pennsylvania and California, including hydraulic fracturing and other well completion services, well tending services, well workover activities, tubing and casing purchases, production equipment purchases, contracts for drilling rig services and fuel purchases for steam generation. The future contractual commitments are $150.5 million in 2022, $17.3 million in 2023 and $2.4 million in 2024. There are no contractual commitments extending beyond 2024.

-113-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The Company is involved in other litigation arising in the normal course of business. In addition to the regulatory matters discussed in Note F — 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 M — Business Segment Information

The Company reports financial results for four segments: Exploration and Production, Pipeline and Storage, Gathering, and 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 the Appalachian region of the United 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, 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 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 with access to additional markets in the northeastern United States and Canada.

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 primarily 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 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 — 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 (when applicable). When this is not applicable, the Company evaluates performance based on net income.

-114-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	Year Ended September 30, 2021
	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)	$	836,697	$	234,397	$	3,116	$	666,920	$	1,741,130	$	1,173	$	356	$	1,742,659
Intersegment Revenues	$	—	$	109,160	$	190,148	$	331	$	299,639	$	49	$	(299,688)	$	—
Interest Income	$	211	$	1,085	$	259	$	2,117	$	3,672	$	230	$	486	$	4,388
Interest Expense	$	69,662	$	40,976	$	17,493	$	21,795	$	149,926	$	—	$	(3,569)	$	146,357
Depreciation, Depletion and Amortization	$	182,492	$	62,431	$	32,350	$	57,457	$	334,730	$	394	$	179	$	335,303
Income Tax Expense (Benefit)	$	33,370	$	28,812	$	28,876	$	14,007	$	105,065	$	11,438	$	(1,821)	$	114,682
Significant Non-Cash Item: Impairment of Oil and Gas Producing Properties	$	76,152	$	—	$	—	$	—	$	76,152	$	—	$	—	$	76,152
Significant Item: Gain on Sale of Timber Properties	$	—	$	—	$	—	$	—	$	—	$	51,066	$	—	$	51,066
Segment Profit: Net Income (Loss)	$	101,916	$	92,542	$	80,274	$	54,335	$	329,067	$	37,645	$	(3,065)	$	363,647
Expenditures for Additions to Long-Lived Assets	$	381,408	$	252,316	$	34,669	$	100,845	$	769,238	$	—	$	673	$	769,911
	At September 30, 2021
	(Thousands)
Segment Assets	$	2,286,058	$	2,296,030	$	837,729	$	2,148,267	$	7,568,084	$	4,146	$	(107,405)	$	7,464,825


	Year Ended September 30, 2020
	Exploration and Production		Pipeline and Storage		Gathering		Utility		Total Reportable Segments		All Other		Corporate and Intersegment Elimination		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	$	—	$	103,606	$	142,821	$	9,443	$	255,870	$	836	$	(256,706)	$	—
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	$	—	$	—	$	—	$	449,438	$	—	$	—	$	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

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	Year Ended September 30, 2019
	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)	$	632,740	$	195,808	$	11	$	715,813	$	1,544,372	$	148,582	$	378	$	1,693,332
Intersegment Revenues	$	—	$	92,475	$	127,064	$	11,629	$	231,168	$	1,127	$	(232,295)	$	—
Interest Income	$	1,107	$	2,982	$	546	$	1,809	$	6,444	$	1,291	$	(1,670)	$	6,065
Interest Expense	$	54,777	$	29,142	$	9,406	$	23,443	$	116,768	$	21	$	(10,033)	$	106,756
Depreciation, Depletion and Amortization	$	154,784	$	44,947	$	20,038	$	53,832	$	273,601	$	1,291	$	768	$	275,660
Income Tax Expense (Benefit)	$	32,978	$	23,238	$	20,895	$	13,967	$	91,078	$	(955)	$	(4,902)	$	85,221

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	$	491,889	$	143,005	$	49,650	$	95,847	$	780,391	$	128	$	727	$	781,246
	At September 30, 2019
	(Thousands)
Segment Assets	$	1,972,776	$	1,893,514	$	547,995	$	1,991,338	$	6,405,623	$	122,241	$	(65,707)	$	6,462,157

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


Geographic Information	At September 30
	2021		2020		2019
	(Thousands)
Long-Lived Assets:
United States	$	6,942,376	$	6,597,313	$	6,099,534

Note N — 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.

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

Capitalized Costs Relating to Oil and Gas Producing Activities


	At September 30
	2021		2020
	(Thousands)
Proved Properties(1)	$	6,652,341	$	6,238,830
Unproved Properties	103,759		148,075
	6,756,100		6,386,905
Less — Accumulated Depreciation, Depletion and Amortization	4,881,972		4,628,765
	$	1,874,128	$	1,758,140

-116-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(1)Includes asset retirement costs of $152.8 million and $132.6 million at September 30, 2021 and 2020, 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 2026. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2024. Following is a summary of costs excluded from amortization at September 30, 2021:


	Total as of September 30, 2021		Year Costs Incurred
			2021		2020		2019		Prior
	(Thousands)
Acquisition Costs	$	57,027	$	—	$	32,762	$	—	$	24,265
Development Costs	37,574		14,979		2,430		17,114		3,051
Exploration Costs	8,178		572		—		—		7,606
Capitalized Interest	980		340		496		41		103
	$	103,759	$	15,891	$	35,688	$	17,155	$	35,025

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


	Year Ended September 30
	2021		2020		2019
	(Thousands)
United States
Property Acquisition Costs:
Proved	$	1,801	$	245,976	$	3,136
Unproved	5,102		42,922		3,679
Exploration Costs(1)	15,413		3,891		2,060
Development Costs(2)	329,368		355,742		468,498
Asset Retirement Costs	20,194		62,080		26,192
	$	371,878	$	710,611	$	503,565

(1)Amounts for 2021, 2020 and 2019 include capitalized interest of $0.1 million, zero and zero, respectively.

(2)Amounts for 2021, 2020 and 2019 include capitalized interest of $0.4 million, $1.0 million and $0.2 million, respectively.

For the years ended September 30, 2021, 2020 and 2019, the Company spent $81.2 million, $219.9 million and $246.0 million, respectively, developing proved undeveloped reserves.

-117-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Results of Operations for Producing Activities


	Year Ended September 30
	2021		2020		2019
United States	(Thousands, except per Mcfe amounts)
Operating Revenues:
Gas (includes transfers to operations of $3,061, $1,921 and $2,532, respectively)(1)	$	780,477	$	402,447	$	481,048
Oil, Condensate and Other Liquids	135,191		107,844		149,078
Total Operating Revenues(2)	915,668		510,291		630,126
Production/Lifting Costs	267,316		203,670		186,626
Franchise/Ad Valorem Taxes	22,128		15,582		17,673
Purchased Emission Allowance Expense	2,940		2,930		2,527
Accretion Expense	7,743		5,237		3,723
Depreciation, Depletion and Amortization ($0.54, $0.69 and $0.71 per Mcfe of production, respectively)	177,055		166,759		149,881
Impairment of Oil and Gas Producing Properties	76,152		449,438		—
Income Tax Expense	98,593		(92,820)		64,652
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)	$	263,741	$	(240,505)	$	205,044

(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 J — Financial Instruments.

Reserve Quantity Information

The Company's proved oil and gas reserve estimates are prepared by the Company's petroleum 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 Senior Manager 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 12 years of Petroleum Engineering experience with independent oil and gas companies and is a member of the Society of Petroleum Engineers.

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 Senior Manager 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 2011 and with over

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

4 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, 2021 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.


	Gas MMcf
	U.S.
	Appalachian Region		West Coast Region	Total Company
Proved Developed and Undeveloped Reserves:
September 30, 2018	2,320,502		36,840	2,357,342
Extensions and Discoveries	686,549	(1)	—	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)	—	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		—	684,141

September 30, 2020	3,296,113		28,972	3,325,085
Extensions and Discoveries	689,395	(1)	—	689,395
Revisions of Previous Estimates	19,940		3,033	22,973
Production	(312,300)	(2)	(1,720)	(314,020)


September 30, 2021	3,693,148		30,285	3,723,433
Proved Developed Reserves:
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
September 30, 2021	3,061,178		30,285	3,091,463
Proved Undeveloped Reserves:
September 30, 2018	750,810		—	750,810
September 30, 2019	1,014,724		—	1,014,724
September 30, 2020	551,262		—	551,262
September 30, 2021	631,970		—	631,970

(1)Extensions and discoveries include 175 Bcf (during 2019), 7 Bcf (during 2020) and 180 Bcf (during 2021), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 512 Bcf (during 2019), 0 Bcf (during 2020) and 497 Bcf (during 2021), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(2)Production includes 163,015 MMcf (during 2019), 169,453 MMcf (during 2020) and 218,016 MMcf (during 2021), from Marcellus Shale fields. Production includes 32,095 MMcf (during 2019), 55,392 MMcf (during 2020) and 93,253 MMcf (during 2021), from Utica Shale fields.


	Oil Mbbl
	U.S.
	Appalachian Region	West Coast Region	Total Company
Proved Developed and Undeveloped Reserves:
September 30, 2018	14	27,649	27,663
Extensions and Discoveries	—	787	787
Revisions of Previous Estimates	2	(1,256)	(1,254)
Production	(3)	(2,320)	(2,323)



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


September 30, 2020	12	22,088	22,100
Extensions and Discoveries	—	1,041	1,041
Revisions of Previous Estimates	1	630	631
Production	(2)	(2,233)	(2,235)


September 30, 2021	11	21,526	21,537
Proved Developed Reserves:
September 30, 2018	14	26,689	26,703
September 30, 2019	13	24,246	24,259
September 30, 2020	12	22,088	22,100
September 30, 2021	11	20,930	20,941
Proved Undeveloped Reserves:
September 30, 2018	—	960	960
September 30, 2019	—	614	614
September 30, 2020	—	—	—
September 30, 2021	—	596	596

The Company’s proved undeveloped (PUD) reserves increased from 551 Bcfe at September 30, 2020 to 636 Bcfe at September 30, 2021. PUD reserves in the Utica Shale increased from 265 Bcfe at September 30, 2020 to 411 Bcfe at September 30, 2021. PUD reserves in the Marcellus Shale decreased from 287 Bcfe at September 30, 2020 to 220 Bcfe at September 30, 2021. The Company’s total PUD reserves were 16.5% of total proved reserves at September 30, 2021, roughly flat from 16% of total proved reserves at September 30, 2020.

The Company’s PUD reserves decreased from 1,018 Bcfe at September 30, 2019 to 551 Bcfe at September 30, 2020. PUD reserves in the Marcellus Shale decreased from 383 Bcfe at September 30, 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 increase in PUD reserves in 2021 of 85 Bcfe is a result of 344 Bcfe in new PUD reserve additions and 9 Bcfe in upward revisions to remaining PUD reserves, partially offset by 188 Bcfe in PUD conversions to developed reserves (82 Bcfe from the Marcellus Shale and 106 Bcfe from the Utica Shale), and 80 Bcfe in PUD

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

reserves removed for eight PUD locations, half of these due to pad layout changes, and the other half due to schedule changes. Six of these wells removed were in the Marcellus Shale (54 Bcfe) and two were in the Utica Shale (26 Bcfe).

The decrease in PUD reserves in 2020 of 467 Bcfe is a result of 363 Bcfe in PUD conversions to developed reserves (146 Bcfe from the Marcellus Shale, 214 Bcfe from the Utica Shale and 3 Bcfe from the West Coast region), and 179 Bcfe in PUD reserves removed for seventeen PUD locations, all in the Western Development Area, due to development timing no longer scheduled to meet the five year requirement for proved reserves. Two of these wells removed were in the Marcellus Shale (14 Bcfe) and fifteen were in the Utica Shale (165 Bcfe). These decreases were offset by 7 Bcfe in new PUD reserve additions, 20 Bcfe in upward revisions to remaining PUD reserves and 48 Bcfe in revisions for five PUD locations added back in 2020 (after removing one in 2016 and four in 2017 due to scheduling delays beyond the five year requirement).

The Company invested $81 million during the year ended September 30, 2021 to convert 188 Bcfe (198 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 34% of the net PUD reserves recorded at September 30, 2020. In the Appalachian region, 18 of 53 PUD locations were developed. PUD expenditures in 2021 were lower than the 2020 estimate primarily due to changes in the development schedule.

The Company invested $220 million during the year ended September 30, 2020 to convert 363 Bcfe (393 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 36% of the net PUD reserves recorded at September 30, 2019. The 30 Bcfe in upward revisions to PUD reserves converted to developed reserves in 2020 were primarily a result of 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.

In 2022, the Company estimates that it will invest approximately $161 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 27% of its beginning year PUD reserves in fiscal 2017, 51% of its beginning year PUD reserves in fiscal 2018, 39% of its beginning year PUD reserves in fiscal 2019, 36% of its beginning year PUD reserves in fiscal 2020 and 34% of its beginning year PUD reserves in fiscal 2021.

At September 30, 2021, the Company does not have 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.

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
	2021		2020		2019
	(Thousands)
United States
Future Cash Inflows	$	10,175,182	$	6,493,362	$	8,738,182
Less:
Future Production Costs	3,423,629		3,149,857		2,989,518
Future Development Costs	597,662		501,678		797,640
Future Income Tax Expense at Applicable Statutory Rate	1,397,175		454,553		1,159,882
Future Net Cash Flows	4,756,716		2,387,274		3,791,142
Less:
10% Annual Discount for Estimated Timing of Cash Flows	2,403,144		1,164,804		2,054,823
Standardized Measure of Discounted Future Net Cash Flows	$	2,353,572	$	1,222,470	$	1,736,319

The principal sources of change in the standardized measure of discounted future net cash flows were as follows:


	Year Ended September 30
	2021		2020		2019
	(Thousands)
United States
Standardized Measure of Discounted Future
Net Cash Flows at Beginning of Year	$	1,222,470	$	1,736,319	$	1,720,305
Sales, Net of Production Costs	(626,132)		(290,975)		(425,773)
Net Changes in Prices, Net of Production Costs	1,478,995		(1,109,101)		(164,428)
Extensions and Discoveries	462,040		4,236		202,683
Changes in Estimated Future Development Costs	48,247		99,884		(69,254)
Purchases of Minerals in Place	—		170,363		—
Sales of Minerals in Place	—		—		—
Previously Estimated Development Costs Incurred	81,239		219,938		245,964
Net Change in Income Taxes at Applicable Statutory Rate	(415,993)		248,182		21,370
Revisions of Previous Quantity Estimates	(52,383)		(28,337)		53,777
Accretion of Discount and Other	155,089		171,961		151,675
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$	2,353,572	$	1,222,470	$	1,736,319

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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, 2021.

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 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, 2021. 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, 2021.

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, 2021. 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, 2021 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, 2021. The information concerning directors will be set forth in the definitive Proxy Statement under the headings entitled “Nominees for Election as Directors for One-Year Terms to Expire in 2023,” “Continuing Directors Whose Terms Expire in 2024,” and “Continuing Directors Whose Terms Expire in 2023,” 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

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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.


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 will be 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.

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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

All schedules are omitted because they are not applicable or the required information is shown in the Consolidated Financial Statements or Notes 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:

•			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)

•			Certificate of Amendment of Restated Certificate of Incorporation, as amended, of National Fuel Gas Company (Exhibit 3.1, Form 8-K dated March 16, 2021)

3(ii)			By-Laws:

•			By-Laws of National Fuel Gas Company, as amended December 11, 2020 (Exhibit 3.1, Form 8-K dated December 15, 2020)

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)

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Exhibit Number			Description of Exhibits
•			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)

•			Officers Certificate establishing 5.50% Notes due 2026, dated June 3, 2020 (Exhibit 4.1.1, Form 8-K dated June 3, 2020)

•			Officer’s Certificate establishing 2.95% Notes due 2031, dated February 24, 2021 (Exhibit 4.1.1, Form 8-K dated February 24, 2021)

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)

•			Amendment No. 1 to Fourth Amended and Restated Credit Agreement, dated as of February 3, 2021, among the Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (Exhibit 10.2, Form 8-K dated February 4, 2021)

•			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)

•			Amendment No. 1 to 364-Day Credit Agreement, dated as of February 3, 2021, among the Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (Exhibit 10.1, Form 8-K dated February 4, 2021)

			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, 2011)

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

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Exhibit Number			Description of Exhibits
•			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)

•			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)

•			Amendment to National Fuel Gas Company Deferred Compensation Plan, dated December 14, 2020 (Exhibit 10.3, Form 10-Q for the quarterly period ended December 31, 2020)

•			National Fuel Gas Company Deferred Compensation Plan for Directors and Officers (Amended and Restated Effective September 1, 2021) (Exhibit 10.1, Form 8-K dated June 23, 2021)

•			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)

•			Amendment to National Fuel Gas Company Tophat Plan, dated December 14, 2020 (Exhibit 10.5, Form 10-Q for the quarterly period ended December 31, 2020)

•			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)

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Exhibit Number			Description of Exhibits
•			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)

•			Amendment to National Fuel Gas Company and Participating Subsidiaries Executive Retirement Plan, dated December 14, 2020 (Exhibit 10.4, Form 10-Q for the quarterly period ended December 31, 2020)

•			National Fuel Gas Company 2009 Non-Employee Director Equity Compensation Plan, as amended and restated March 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, 2020)

•			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, 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 December 31, 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)

21			Subsidiaries of the Registrant

23			Consents of Experts:

23.1			Consent of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Company, LLC

23.2			Consent of Independent Registered Public Accounting Firm

31			Rule 13a-14(a)/15d-14(a) Certifications:

31.1			Written statements of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act

31.2			Written statements of Principal Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act

32••			Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

99			Additional Exhibits:

99.1			Report of Netherland, Sewell & Associates, Inc. regarding Seneca Resources Company, LLC

99.2			Company Maps

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Exhibit Number			Description of Exhibits
101			Interactive data files submitted pursuant to Regulation S-T, formatted in Inline XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income and Earnings Reinvested in the Business for the years ended September 30, 2021, 2020 and 2019, (ii) the Consolidated Statements of Comprehensive Income for the years ended September 30, 2021, 2020 and 2019 (iii) the Consolidated Balance Sheets at September 30, 2021 and September 30, 2020, (iv) the Consolidated Statements of Cash Flows for the years ended September 30, 2021, 2020 and 2019 and (v) the Notes to Consolidated Financial Statements.

104			Cover Page Interactive Data File (embedded within the Inline XBRL document)

•			Incorporated herein by reference as indicated.

			All other exhibits are omitted because they are not applicable or the required information is shown elsewhere in this Annual Report on Form 10-K.

••			In accordance with Item 601(b)(32)(ii) of Regulation S-K and SEC Release Nos. 33-8238 and 34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference.

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Signatures

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.



National Fuel Gas Company
(Registrant)

By						/s/ D. P. Bauer
						D. P. Bauer
						President and Chief Executive Officer

Date: November 19, 2021

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature

Title

/s/ D. F. Smith

Chairman of the Board and Director

Date: November 19, 2021

D. F. Smith

/s/ D. H. Anderson

Director

Date: November 19, 2021

D. H. Anderson

/s/ B. M. Baumann

Director

Date: November 19, 2021

B. M. Baumann

/s/ D. C. Carroll

Director

Date: November 19, 2021

D. C. Carroll

/s/ S. C. Finch

Director

Date: November 19, 2021

S.C. Finch

/s/ J. N. Jaggers

Director

Date: November 19, 2021

J. N. Jaggers

/s/ R. Ranich

Director

Date: November 19, 2021

R. Ranich

/s/ J. W. Shaw

Director

Date: November 19, 2021

J. W. Shaw

/s/ T. E. Skains

Director

Date: November 19, 2021

T. E. Skains

/s/ R. J. Tanski

Director

Date: November 19, 2021

R. J. Tanski

/s/ D. P. Bauer

President and Chief Executive Officer and Director

Date: November 19, 2021

D. P. Bauer

/s/ K. M. Camiolo

Treasurer and Principal
Financial Officer

Date: November 19, 2021

K. M. Camiolo

/s/ E. G. Mendel

Controller and Principal Accounting Officer

Date: November 19, 2021

E. G. Mendel

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