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Published: 2023-11-17 00:00:00 ET

nfg-20230930

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, 2023


			☐			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. ☑

If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐

Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐

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 $5,187,493,000 as of March 31, 2023.

Common Stock, par value $1.00 per share, outstanding as of October 31, 2023: 91,829,588 shares.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the registrant’s definitive Proxy Statement for its 2024 Annual Meeting of Stockholders, to be filed with the Securities and Exchange Commission within 120 days of September 30, 2023, 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

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.

EAP Energy Affordability Program; a program that provides bill discounts to gas customers who receive benefits under qualifying public assistance programs.

ESG Environmental, social and governance

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 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.

Impact Fee An annual fee imposed on unconventional wells spud in Pennsylvania. The fee is administered by the PaPUC and fees are distributed to counties and municipalities where the well is located.

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

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)

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

MDth Thousand decatherms (of natural gas)

Methane The primary component of natural gas. It is a compound made up of one carbon atom and four hydrogen atoms (CH4).

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

MMcf Million cubic feet (of natural gas)

MMcfe Million cubic feet equivalent

Natural Gas A naturally occurring mixture of gaseous hydrocarbons consisting primarily of methane and found in underground rock formations.

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.

NOAA National Oceanic and Atmospheric Administration

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.

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.

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.

SOFR Secured Overnight Financing Rate

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/adjustment 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, 2023


CONTENTS
		Page
Part I
ITEM 1	BUSINESS	6
	THE COMPANY AND ITS SUBSIDIARIES	6
	RATES AND REGULATION	7
	THE EXPLORATION AND PRODUCTION SEGMENT	7
	THE PIPELINE AND STORAGE SEGMENT	7
	THE GATHERING SEGMENT	8
	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	11
	EXECUTIVE OFFICERS OF THE COMPANY	13
ITEM 1A	RISK FACTORS	14
ITEM 1B	UNRESOLVED STAFF COMMENTS	25
ITEM 1C	CYBERSECURITY	25
ITEM 2	PROPERTIES	25
	GENERAL INFORMATION ON FACILITIES	25
	EXPLORATION AND PRODUCTION ACTIVITIES	26
ITEM 3	LEGAL PROCEEDINGS	30
ITEM 4	MINE SAFETY DISCLOSURES	30
Part II
ITEM 5	MARKET FOR THE REGISTRANT’S COMMON EQUITY, RELATED STOCKHOLDER MATTERS AND ISSUER PURCHASES OF EQUITY SECURITIES	31
ITEM 6	[RESERVED]	32
ITEM 7	MANAGEMENT’S DISCUSSION AND ANALYSIS OF FINANCIAL CONDITION AND RESULTS OF OPERATIONS	33
ITEM 7A	QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK	61
ITEM 8	FINANCIAL STATEMENTS AND SUPPLEMENTARY DATA	62
ITEM 9	CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS ON ACCOUNTING AND FINANCIAL DISCLOSURE	125
ITEM 9A	CONTROLS AND PROCEDURES	125
ITEM 9B	OTHER INFORMATION	125
ITEM 9C	DISCLOSURE REGARDING FOREIGN JURISDICTIONS THAT PREVENT INSPECTIONS	125

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Part III
ITEM 10	DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE	126
ITEM 11	EXECUTIVE COMPENSATION	126
ITEM 12	SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS AND MANAGEMENT AND RELATED STOCKHOLDER MATTERS	126
ITEM 13	CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS, AND DIRECTOR INDEPENDENCE	126
ITEM 14	PRINCIPAL ACCOUNTANT FEES AND SERVICES	127
Part IV
ITEM 15	EXHIBITS AND FINANCIAL STATEMENT SCHEDULES	127
ITEM 16	FORM 10-K SUMMARY	131
SIGNATURES		132

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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, storage 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 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 both existing and new 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 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, primarily natural gas in the Appalachian region of the United States. At September 30, 2023, Seneca had proved developed and undeveloped reserves of 4,535,084 MMcf of natural gas and 216 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 natural gas pipeline systems in Pennsylvania and New York. Supply Corporation also provides storage services through its underground natural gas storage fields, and Empire provides storage service (via lease with Supply Corporation) to a nonaffiliated company.

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 754,000 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.

Revenue from one customer of the Company's Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $208 million, or 9.6%, of the Company's consolidated revenue for the year ended September 30, 2023. This one customer was also a customer of the Company's Pipeline and Storage segment, accounting for an additional $14 million, or 0.6%, of the Company's consolidated revenue for the year ended September 30, 2023.

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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, and other regulators, 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.”

The Exploration and Production Segment

The Exploration and Production segment contributed net income of $232.3 million in 2023.

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 $100.5 million in 2023.

The Pipeline and Storage segment generated approximately 32% of its revenues in 2023 from services provided to the Utility segment or Exploration and Production segment.

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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 $99.7 million in 2023.

The Gathering segment generated approximately 94% of its revenues in 2023 from services provided to the Exploration and Production segment.

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.

The Utility Segment

The Utility segment contributed net income of $48.4 million in 2023.

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 incurred a net loss of $4.0 million in 2023.

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 (primarily natural gas) 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.

Natural gas is the principal raw material for the Utility segment. In 2023, the Utility segment purchased 73.1 Bcf of gas (including 71.3 Bcf for delivery to retail customers and 1.8 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 50% of these purchases. Purchases of gas in the spot market (contracts of one month or less) accounted for 50% of the Utility segment’s 2023 purchases. Purchases from DTE Energy Trading, Inc. (24%), Vitol, Inc. (14%), Shell Energy North America US (9%), EQT Energy, LLC (9%), Emera Energy Services, Inc. (8%), J. Aron & Company (7%), Tenaska Marketing Ventures (5%), Chevron Natural Gas (5%), and NRG Business Marketing Inc. (5%), accounted for nearly 86% of the Utility segment's 2023 gas purchases. No other producer or supplier provided the Utility segment with more than 5% of its gas requirements in 2023. 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, geothermal, solar and wind. Management believes that the reliability and affordability of natural gas support its competitive position relative to other fuels.

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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 natural gas producers and marketers with respect to sales of natural gas. The Exploration and Production segment also competes, by competitive bidding and otherwise, with other 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, maintains a portfolio of firm transportation and sales contracts in order to compete in higher priced markets, seeks to minimize the risk of exploratory efforts through partnership-type arrangements, utilizes technology for both 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 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, Mid-Atlantic 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. Various expansion projects on Empire have expanded it'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 natural gas to key markets within New York State, the northeastern United States and Canada.

Competition: The Gathering Segment

The Gathering segment provides gathering services for Seneca and, to a lesser extent, other producers. It 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 8% 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

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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 continues to exist and competition with electrification alternatives is growing, particularly in New York State, natural gas retains its competitive position from a reliability and affordability standpoint.

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. In addition to the federal Inflation Reduction Act, New York, for example, adopted the Climate Leadership & Community Protection Act (CLCPA) in July 2019, which could 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 and/or business impacts 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 is largely mitigated by a weather normalization clause (WNC). Prior to October 2023, the weather impact on cash flow in the Utility segment was mitigated by a WNC solely in its New York rate jurisdiction. However, effective October 2023, the weather impact on cash flow in the Utility segment will also be mitigated by a WNC in its Pennsylvania rate jurisdiction. Refer to Item 8, Note A – Summary of Significant Accounting Policies under the heading “Regulatory Mechanisms” for additional discussion. Under the WNC, 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 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.

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.nationalfuel.com, as soon as reasonably practicable after they are electronically filed with or furnished to

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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 total rewards, 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 total rewards, 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.nationalfuel.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.

Employees and Collective Bargaining Agreements

The Company and its wholly-owned subsidiaries had a total of 2,240 full-time employees at September 30, 2023.

As of September 30, 2023, 47% 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 collective bargaining units in Pennsylvania into April 2026.

Safety

Safety is one of the Company’s guiding principles. In managing the business, the Company focuses on the safety of its employees, contractors and communities 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 and applicable contractors. The Company also ties executive compensation to safety related goals to emphasize the importance of and focus on safety at the Company.

Voluntary Attrition Rate

The Company measures the voluntary attrition rate of its employees in assessing the Company’s overall human capital. The Company's voluntary attrition rate was 8.7% (not including retirements), which is comparable to last year’s voluntary attrition rate of 8%. The Company continues to actively monitor employee metrics, including attrition rate, to ensure proper management of and responsiveness to human capital matters.

No Work Stoppages

During fiscal 2023, the Company did not incur any work stoppages (strikes or lockouts) and therefore experienced zero idle days for the fiscal year.

Total Rewards

To attract employees and meet the needs of the Company’s workforce, the Company offers market-competitive 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, and periodically conducts employee surveys to provide additional insight into employee perspectives and interest in desired benefits.

The Company's compensation program for salaried employees is intended to align employee compensation with the market while providing greater incentive to the Company’s employees to work toward the achievement of Company goals. These goals include the coordinated business goals and ESG objectives of the Company's business segments as a whole. This meaningful investment illustrates the Company’s view that attracting, retaining and motivating our employees is integral to the Company’s success.

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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 subsidiaries to discuss career pathing and employee development.

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. The Company’s focus on building a diverse and inclusive culture is reflected in the Company's approach to Board diversity, its adoption of specific diversity and inclusion performance goals as part of the Company’s executive compensation program, and policies and training that reinforce the Company’s commitment to diversity and inclusion in the workplace. The Company’s policies prohibit discrimination or harassment against any employee or applicant on the basis of sex, race/ethnicity, and other protected categories. The Company communicates to employees its commitment to a harassment free workplace through the onboarding process, annual distribution and acknowledgement of the Company’s Non-Discrimination and Anti-Harassment Policy, and training for all employees including management. Additionally, to ensure transparency over time, the Company publicly discloses gender, racial and ethnic minority representation, and multi-generational workforce metrics in the Company’s Corporate Responsibility Report.

The Company's Diversity and Inclusion team continues to spearhead diversity and inclusion initiatives to help attract candidates within diverse communities, encourage partnerships with diverse vendors and suppliers and provide tools and trainings designed to promote equity and inclusion within employment teams. The Company also supports multiple active Employee Resource Groups for women, ethnically diverse employees, veterans and employees who identify as LGBTQ+, where employees can network, build community and seek support. Each group is voluntary, employee-led, open to allies, and has an executive sponsor to help facilitate communication directly to senior management.

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Executive Officers of the Company as of November 15, 2023(1)


Name and Age (as of November 15, 2023)						Current Company Positions and Other Material Business Experience During Past Five Years
David P. Bauer (54)						Chief Executive Officer of the Company since July 2019. Mr. Bauer previously served as 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 and Empire from June 2007 through June 2019.
Donna L. DeCarolis (64)						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.
Ronald C. Kraemer (67)						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.
Timothy J. Silverstein (40)						Treasurer and Principal Financial Officer of the Company since May 2023. Treasurer of Seneca Resources Company since May 2023. Treasurer of Distribution Corporation, Supply Corporation, Empire and Midstream Company since July 2021. Mr. Silverstein previously served as Assistant Treasurer of Distribution Corporation, Supply Corporation and Empire from April 2020 through June 2021. General Manager of Finance from April 2019 through March 2020. Manager of Finance from April 2017 through March 2019.
Elena G. Mendel (57)						Controller and Principal Accounting Officer of the Company since July 2019. Controller of Distribution Corporation, Supply Corporation, Empire, and Midstream Company since July 2019. Ms. Mendel previously served as Assistant Controller of Distribution Corporation, Supply Corporation and Empire from February 2017 through June 2019.
Martin A. Krebs (53)						Chief Information Officer of the Company since December 2018 and Senior Vice President of Distribution Corporation since May 2023. 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.
Michael W. Reville (64)						General Counsel and Secretary of the Company since April 2023 and Senior Vice President of Distribution Corporation since May 2020. Mr. Reville previously served as General Counsel of Distribution Corporation from April 2015 through March 2023. Secretary of Distribution Corporation from May 2020 through March 2023. Vice President of Distribution Corporation from April 2015 through April 2020.
Justin I. Loweth (45)						President of Midstream Company since April 2022 and 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.

(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 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 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, $1.4 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 $1.4 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. Executive orders from the federal administration, in

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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 natural gas, 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.

Federal and state legislatures have from time to time considered bills that would establish a cap-and-trade program, cap-and-invest program, methane fee or carbon tax to incent the reduction of greenhouse gas emissions. For example, in August 2022, the federal Inflation Reduction Act was signed into law, which includes a methane charge that is expected to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, starting in calendar year 2024.

A number of states have also 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 natural gas industry which has resulted in permitting changes with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. Furthermore, in 2019, the New York State legislature passed the CLCPA, which created emission reduction and electrification mandates, and could ultimately impact the Utility segment’s customer base and business. Pursuant to the CLCPA, New York's Climate Action Council (“CAC”) approved a final scoping plan that includes recommendations to strategically downsize and decarbonize the natural gas system and curtail use of natural gas and natural gas appliances. The final scoping plan was approved on December 19, 2022 and includes detailed recommendations to meet the CLCPA’s emissions reduction targets in the transportation, buildings, electricity, industry, agriculture & forestry and waste sectors. The final scoping plan also recommends statewide and cross-sector policies relevant to gas system transition, economywide strategies, land use, local government and adaptation and resilience. Additionally, the scoping plan recommends the implementation of a cap-and-invest program in New York. In January 2023, New York’s Governor directed the NYDEC and the New York State Energy Research and Development Authority to advance an economywide cap-and-invest program that establishes a declining cap on greenhouse gas emissions, and invests in programs to drive emissions reductions. If this proposed program or a similar program becomes effective and the Company becomes subject to new or revised cap-and-trade programs, cap-and-invest programs, methane charges, fees for carbon-based fuels or other similar costs or charges, the Company may experience additional costs and incremental operating expenses, which would impact our future earnings and cash flows, and may also experience decreased revenue in the event that implementation of these policies leads to reduced demand for natural gas.

In addition to the scoping plan, legislation or regulation that aims to reduce greenhouse gas emissions could also include natural gas bans, 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. For example, in May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to various exemptions. While the Company does not currently expect that this legislation will have a substantial impact on its financial results or operations, future legislation or regulation that aims to reduce natural gas demand or to impose additional operations requirements or restrictions on natural gas facilities, if effectuated, could impact our future earnings and cash flows.

Additionally, the trend toward increased energy conservation, change in consumer behaviors, competition from renewable energy sources, and technological advances to address climate change may reduce the demand for natural gas, which could impact our future earnings and cash flows. For further discussion of the risks associated with environmental regulation to address climate change, refer to Item 2, MD&A under the heading “Environmental Matters.”

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

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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 natural gas industry could have an adverse effect on Company operations.

Organized opposition to the natural gas industry, including exploration and production activity, pipeline expansion and replacement projects, and the extension and continued operation of natural gas distribution systems, may continue to increase as a result of, among other things, safety incidents involving natural gas facilities, and concerns raised by policymakers, 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 natural gas, 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.

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, as well as the renewal or modification of key permits for ongoing operations, and may result in asset write-offs and reduced earnings.

Construction of planned distribution, gathering, and transmission pipeline and storage facilities, as well as the expansion and replacement of existing facilities, and the development of new natural gas wells, 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 as well as the renewal or modification of key permits for ongoing operations. In addition, third parties could impede the Company’s acquisition, expansion or renewal of rights-of-way or land rights on a timely basis and on acceptable terms. Any delay in project development or 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 increased project costs due to extended construction timeframes, asset write-offs and materially impact operating results or anticipated results. Additionally, delays in pipeline construction projects or gathering facility completion 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 dividends to the Company 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 could adversely affect the Company’s revenues and cash flows or restrict its future growth. Additionally, supply chain disruptions, and the associated costs and inflation related thereto, could have an impact on the Company's operations. Economic conditions in the Company’s utility service

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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, high inflation, or high commodity prices, potentially resulting in increased bad debt expense and reduced earnings. 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, 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. Certain customers of the Company's Exploration and Production segment can represent a concentrated risk during times of high commodity prices and high hedging losses. Any of these events or circumstances could have or contribute to a material adverse effect on the Company’s results of operations, financial condition and cash flows.

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 may increase the rates at which the Company can refinance maturing debt. In addition, the Company’s authorized rate of return in its regulated businesses is based upon certain assumptions regarding interest rates. If interest rates are lower than assumed rates, the Company’s authorized rate of return could be reduced. If interest rates are higher than assumed rates, the Company’s ability to earn its authorized rate of return may be adversely impacted.

Fluctuations in natural 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 natural gas production. Both short-term and long-term price trends affect the economics of exploring for, developing, producing, and gathering natural gas. Natural gas prices can be volatile and can be affected by various factors, including weather conditions, natural disasters, consumer demand, national and worldwide economic conditions, economic disruptions caused by terrorist activities, acts of war or major accidents, domestic and foreign political conditions and events, the price and availability of alternative fuels, the proximity to, and availability of, sufficient capacity on transportation and liquefaction facilities, regional and global levels of supply and demand, energy conservation measures, and government regulations. The Company sells the natural gas that it produces at a combination of current market prices, indexed prices or through fixed-price contracts. The Company hedges a significant portion of future sales that are based on indexed prices utilizing the physical sale counter-party 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. Any prolonged reduction in natural gas prices could result in the Company reducing the level of exploration and production activity the Company otherwise would pursue, which could have a material adverse effect on its future revenues, cash flows and results of operations.

In the Company’s Pipeline and Storage segment, significant changes in the price differential between equivalent quantities of natural gas at different geographic locations could adversely impact the Company. For example, if the price of natural gas at a particular receipt point on the Company’s pipeline system increases relative to the price of natural gas at other locations, then the volume of natural gas received by the Company at the relatively more expensive receipt point may decrease, or the Company may need to discount the approved tariff rate for that transportation path in the future in order to maintain the existing volumes on its system. Changes in price differentials can cause shippers to seek alternative lower priced natural 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 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 natural gas futures contracts for winter deliveries to locations served by the Pipeline and Storage segment decline relative to the prices of such contracts for summer

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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 natural gas storage services driven by that price differential could decrease. These changes could adversely affect future 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, customer demand could be reduced, thereby decreasing revenue. Customers may also have trouble paying the resulting higher bills when gas prices are higher or in periods of economic uncertainty, which could increase bad debt expenses and could 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 natural gas production as well as its fixed price sale commitments.

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

The nature of these hedging contracts could lead to potential liquidity impacts in scenarios of significantly increased natural gas prices if the Company has hedged its current production at prices below the current market price. Hedging collateral deposits represent the cash, letters of credit, or other eligible instruments 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 collateral could be in excess of the Company’s available short-term liquidity under its committed credit facility and other uncommitted sources of capital, leading to potential default under certain of its hedging arrangements. 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, under the Company’s hedging guidelines, 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 natural gas falls short of hedged volumes, the Company may incur substantial losses to cover its hedges to the extent the hedges are in a loss position.

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.”

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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 natural 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 natural gas reserves and future net cash flows. These factors include: historical production from the area compared with production from other producing areas; the assumed effect of governmental regulation; and assumptions concerning natural gas prices, production and development costs, severance and excise taxes, and capital expenditures. Changes in natural gas prices impact the quantity of economic natural gas reserves. 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 natural gas reserves and future net cash flows. If conditions change in the future, then subsequent reserve estimates may be revised accordingly. You should not assume that the present value of future net cash flows from the Company’s proved reserves is the current market value of the Company’s estimated natural gas reserves. In accordance with SEC requirements, the Company bases the estimated discounted future net cash flows from its proved reserves on a 12-month average of historical prices for natural 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 natural gas and other hydrocarbons that cannot be measured in an exact manner. The process of estimating natural 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 natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including historical production from the area compared with production from other comparable producing areas, and the assumed effects of regulations by governmental agencies. Because all reserve estimates are to some degree subjective, each of the following items may differ materially from those assumed in estimating reserves: the quantities of natural gas that are ultimately recovered, the timing of the recovery of natural 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 natural 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 natural 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

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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 committed credit facility. The Company last recognized non-cash, pre-tax impairment charges on its oil and natural gas properties in fiscal years 2020 and 2021, in the amounts of $449.4 million and $76.2 million, respectively.

OPERATIONAL RISKS

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, equipment, and technology/software systems 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.

Our businesses depend on natural gas gathering, storage, and transmission facilities, which, if unavailable, could adversely affect the Company’s results of operations, financial condition, and cash flows.

Our businesses depend on natural gas gathering, storage, and transmission facilities, including third-party midstream facilities that are not within our control. Our Exploration and Production and Utility segments have entered into long-term agreements with midstream providers for natural gas gathering, storage, and/or transportation services. The disruption or unavailability of the midstream facilities required to provide these services, due to maintenance, mechanical failures, accidents, weather, regulatory requirements and/or other operational hazards, could negatively impact our ability to market and/or deliver our products, especially if such disruption were to last for an extended period of time. In addition, any substantial disruptions to the services provided by our midstream providers could cause us to curtail a significant amount of our production or could impair our ability to deliver natural gas to our utility customers and could have a material adverse effect on the Company’s results of operations, financial condition, and cash flows. Furthermore, as substantially all of our production is transported from the well pad to interconnections with various FERC-regulated pipelines through our affiliated gathering facilities, such a production curtailment could result in significantly reduced throughput on those facilities, adversely affecting revenues and cash flows of our Gathering segment.

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The disruption of the Company's information technology and operational technology systems, including third party attempts to breach the Company’s network security, could adversely affect the Company's financial results.

The Company relies on information technology and operational technology systems to process, transmit, and store information, to manage and support a variety of business processes and activities, and to comply with regulatory, legal, and tax requirements. The Company's information technology and operational technology systems, some of which are dependent on services provided by third parties, may be vulnerable to damage, interruption, or shutdown due to any number of causes outside of our control such as catastrophic events, natural disasters, fires, power outages, systems failures, telecommunications failures, and employee error or malfeasance. In addition, 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 maintain and protect its information technology and operational technology systems, the Company may be vulnerable to material disruptions, material security breaches, lost or corrupted data, programming errors and employee errors and/or malfeasance that could lead to interruptions to the Company's business operations or the unauthorized access, use, disclosure, modification or destruction of 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 system disruptions or breaches, including restoration of customer service and enhancement of information technology and operational technology systems.

The Company seeks to prevent, detect and investigate 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 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 disruptions to services or 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 a material disruption or breach were to occur, the Company’s operations, earnings, cash flows and financial condition could be adversely affected to the extent not fully covered by such insurance.

The amount and timing of actual future natural gas production and the costs of our natural gas production operations are difficult to predict and may vary significantly from estimates, which may reduce the Company’s earnings.

There are many risks in developing natural gas, including numerous uncertainties inherent in estimating quantities of proved natural gas reserves and in projecting future rates of production and timing of development expenditures. The future success of the Company’s Exploration and Production and Gathering segments depends on its ability to develop additional natural gas reserves that are economically recoverable, and its failure to do so may negatively impact the Company’s financial outlook for these businesses. 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, completion crew and related equipment availability, geology, and other factors. Drilling for natural gas can be unprofitable, not only from non-productive wells, but from productive wells that do not produce sufficient revenues to return a profit. Also, title problems, competition and cost to acquire mineral rights, 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

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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.

The Company's ability to access water and opportunities for disposal or recycling produced water can impact drilling and completion operations.

The drilling and hydraulic fracturing process requires significant volumes of water and an ability to recycle or dispose of water produced as a by-product of gas production. Limitations or restrictions on the Company's ability to secure sufficient amounts of water, including disruptions from natural causes (such as drought) or issues with transportation availability and costs, could impact its operations. If the Company is unable to secure adequate water volumes, drilling and completions can be delayed, or it would have to obtain new sources of water at increased costs. Similarly, if the Company experiences limitations or restrictions on its ability to recycle or dispose of its produced water, whether due to environmental regulations, permit requirements, transportation issues or other factors, producing wells may need to be shut-in and new wells may be delayed until such time as adequate recycling or disposal capacity is obtained, which can require significant lead times for permitting and could result in increased costs, delays in the Company's operations and adverse impacts on its cash flow and results of operations.

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 natural gas infrastructure, and could disrupt the Company’s supply chain and ultimately its operations. Disruption of production activities, as well as natural gas 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 impact natural gas demand, and adversely impact the Company's future financial results.

Disputes with collective bargaining units representing the Company’s workforce, and work stoppage (e.g. strike or lockout), could adversely affect the Company’s operations as well as its financial results.

Approximately half of the Company’s active workforce is represented by collective bargaining units in New York and Pennsylvania. These labor agreements are negotiated periodically, and therefore, the Company is subject to the risk that such agreements may not be able to be renewed on reasonably satisfactory terms, on anticipated timelines, or at all. In connection with the negotiation of such collective bargaining agreements, or in future matters involving collective bargaining units representing the Company’s workforce, the Company could experience, among other things, strikes, work stoppages, slowdowns or lockouts, which could cause a disruption of the Company's operations and have a material adverse effect on the Company's results of operations and financial condition.

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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 and state prevailing wage rate schedules, may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company or its contractors, 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 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 natural gas transmission and storage facilities and also possesses significant penalty authority with respect to violations of the laws and regulations it administers.

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

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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 natural 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.

Various state legislative and regulatory initiatives regarding the exploration and production business have been proposed or adopted in the northeast United States affecting the Marcellus and Utica Shale gas plays. These initiatives include potential new or updated statutes and regulations governing the drilling, casing, cementing, testing, monitoring and abandonment of wells, the protection of water supplies and restrictions on water use and water rights, hydraulic fracturing operations, increased setback requirements, surface owners’ rights and damage compensation, the spacing of wells, use and disposal of potentially hazardous materials, and environmental and safety issues regarding natural gas pipelines. New permitting fees and/or severance taxes for natural gas production are also possible. Additionally, legislative initiatives in the U.S. Congress and environmental and health 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 natural gas adjustment clauses which permit Distribution Corporation to file with state regulators for rate adjustments to recover increases in the cost of purchased natural gas. Assuming those rate adjustments are granted, increases in the cost of purchased natural 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 natural 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 natural gas. Prudently incurred natural 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 natural gas purchases. Any material delayed recovery or disallowance of purchased natural 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

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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, and the regulatory treatment of certain benefit plan activity, 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. The Company’s earnings and cash flows may also be impacted by the rate treatment of certain income and expense activity and regulatory asset and liability balances that would be determined in a future rate proceeding.

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, and/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 1C			Cybersecurity

Not applicable.


Item 2			Properties

General Information on Facilities

The net investment of the Company in property, plant and equipment was $7.3 billion at September 30, 2023. The Exploration and Production segment constitutes 35.0% of this investment, and is primarily located in the Appalachian region of the United States. Approximately 52.8% 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 segment constitutes 12.2% 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 modernize transmission, storage, and distribution facilities for customers in New York and Pennsylvania. Net property, plant and equipment has increased $2.3 billion, or 46.7%, since September 30, 2018. 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 $2.6 billion at September 30, 2023 consisting primarily of capitalized costs relating to oil and gas producing

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activities, the components of which are disclosed in Item 8, Note N — Supplementary Information for Oil and Gas Producing Activities.

The Pipeline and Storage segment had a net investment of $2.1 billion in property, plant and equipment at September 30, 2023. Transmission pipeline represents 35% of this segment’s total net investment and includes 2,246 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 385 miles of pipeline, as well as 29 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. Net investment in storage facilities includes $82.2 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 31 compressor stations with 260,008 installed horsepower that represent 31% of this segment’s total net investment in property, plant and equipment.

The Pipeline and Storage segment's facilities provided the capacity to meet Supply Corporation’s 2023 peak day sendout for transportation service of 2,360 MMcf, which occurred on February 3, 2023. Withdrawals from storage of 505 MMcf provided approximately 21% of the requirements on that day.

The Gathering segment had a net investment of $0.9 billion in property, plant and equipment at September 30, 2023. Gathering lines and related compressor stations represent substantially all of this segment’s total net investment, including 376 miles of pipelines utilized to move Appalachian production (including Marcellus and Utica shales) to various transmission pipeline receipt points. The Gathering segment has 24 compressor stations with 124,256 installed horsepower.

The Utility segment had a net investment in property, plant and equipment of $1.7 billion at September 30, 2023. The net investment in its gas distribution network (including 15,052 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, 2023.

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 reserves in the Appalachian region of the United States. 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, 2023, 2022 and 2021 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 4,171 Bcf at September 30, 2022 to 4,535 Bcf at September 30, 2023. This increase is attributed to extensions and discoveries of 670 Bcf, purchases of minerals in place of 34 Bcf, and revisions of previous estimates of 32 Bcf, partially offset by production of 372 Bcf. Upward revisions of 94 Bcf are mainly attributed to positive performance improvements and adding back one PUD location. The additions and upward revisions were partially offset by downward revisions of 62 Bcf from the removal of seven PUD locations related to pad layout changes and price-related revisions. The Company has no near term plans to develop the reserves at these PUD locations.

Seneca’s proved developed and undeveloped oil reserves decreased from 250 Mbbl at September 30, 2022 to 216 Mbbl at September 30, 2023. The decrease was attributed to current year production of 30 Mbbl and downward revisions of previous estimates of 4 Mbbl.

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On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 4,172 Bcfe at September 30, 2022 to 4,536 Bcfe at September 30, 2023. This increase is attributed to extensions and discoveries of 670 Bcfe, purchases of minerals in place of 34 Bcfe and net upward revisions of previous estimates of 32 Bcfe, partially offset by production of 372 Bcfe.

Seneca's proved developed and undeveloped natural gas reserves increased from 3,723 Bcf at September 30, 2021 to 4,171 Bcf at September 30, 2022. This increase was attributed to extensions and discoveries of 838 Bcf and revisions of previous estimates of 3 Bcf, partially offset by production of 343 Bcf. Upward revisions included 3 Bcf of price-related revisions and 13 Bcf of revisions related to positive performance improvements including reduced operating expenses. The additions and upward revisions were partially offset by divestures of 50 Bcf as well as downward revisions of 13 Bcf from the removal of one PUD location related to pad layout changes. The Company has no near term plans to develop the reserves at this PUD location.

Seneca’s proved developed and undeveloped oil reserves decreased from 21,537 Mbbl at September 30, 2021 to 250 Mbbl at September 30, 2022. The decrease of 21,287 Mbbl was attributed to production of 1,604 Mbbl and the sale of Seneca's West Coast region (i.e., California) assets of 20,766 Mbbl. These decreases were partially offset by positive performance revisions of 787 Mbbl and extensions and discoveries of 296 Mbbl.

On a Bcfe basis, Seneca’s proved developed and undeveloped reserves increased from 3,853 Bcfe at September 30, 2021 to 4,172 Bcfe at September 30, 2022. This increase was attributed to extensions and discoveries of 839 Bcfe and upward revisions of previous estimates of 8 Bcfe, partially offset by production of 353 Bcfe and divestures, primarily from the sale of the West Coast region (i.e., California) assets, of 175 Bcfe.

At September 30, 2023, the Company’s Exploration and Production segment had delivery commitments for natural gas production of 2,147 Bcf. 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.

Production


	For The Year Ended September 30
	2023			2022			2021
United States
Appalachian Region
Average Sales Price per Mcf of Gas	$	2.78	(1)	$	5.03	(1)	$	2.46	(1)
Average Sales Price per Barrel of Oil	$	75.64		$	97.82		$	48.02
Average Sales Price per Mcf of Gas (after hedging)	$	2.55		$	2.69		$	2.22
Average Sales Price per Barrel of Oil (after hedging)	$	75.64		$	97.82		$	48.02
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	$	0.68	(1)	$	0.68	(1)	$	0.67	(1)
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	1,020		(1)	936		(1)	856		(1)
West Coast Region
Average Sales Price per Mcf of Gas	N/A		(2)	$	10.03		$	6.34
Average Sales Price per Barrel of Oil	N/A		(2)	$	94.06		$	60.50
Average Sales Price per Mcf of Gas (after hedging)	N/A		(2)	$	10.03		$	6.34
Average Sales Price per Barrel of Oil (after hedging)	N/A		(2)	$	70.53		$	56.55
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	N/A		(2)	$	4.83		$	3.74
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	N/A		(2)	39		(2)	41
Total Company
Average Sales Price per Mcf of Gas	$	2.78		$	5.05		$	2.49
Average Sales Price per Barrel of Oil	$	75.64		$	94.10		$	60.49
Average Sales Price per Mcf of Gas (after hedging)	$	2.55		$	2.71		$	2.25
Average Sales Price per Barrel of Oil (after hedging)	$	75.64		$	70.80		$	56.54
Average Production (Lifting) Cost per Mcf Equivalent of Gas and Oil Produced	$	0.68		$	0.81		$	0.82
Average Production per Day (in MMcf Equivalent of Gas and Oil Produced)	1,020			966			897

(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, 2023, 2022 and 2021) contributed 521 MMcfe, 574 MMcfe and 597 MMcfe of daily production in 2023, 2022 and 2021, respectively. The average lifting costs (per Mcfe) were $0.73 in 2023, $0.71 in 2022 and $0.70 in 2021. The Utica Shale fields (which exceed 15% of total reserves at September 30, 2023, 2022 and 2021) contributed 495 MMcfe, 357 MMcfe and 255 MMcfe of daily production in 2023, 2022 and 2021, respectively. The average lifting costs (per Mcfe) were $0.62 in 2023, $0.63 in 2022 and $0.62 in 2021.

(2)West Coast region properties were sold at June 30, 2022. Information for the year ended September 30, 2023 is not applicable (N/A) as a result of the sale.

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Productive Wells


	Appalachian Region
At September 30, 2023	Gas	Oil
Productive Wells — Gross	1,006	—
Productive Wells — Net	891	—

Developed and Undeveloped Acreage


At September 30, 2023	Appalachian Region
Developed Acreage
— Gross	661,478
— Net	650,278
Undeveloped Acreage
— Gross	728,389
— Net	671,676
Total Developed and Undeveloped Acreage
— Gross	1,389,867
— Net	1,321,954	(1)

(1)Of the 1,321,954 Total Developed and Undeveloped Net Acreage in the Appalachian region as of September 30, 2023, there are a total of 1,250,077 net acres in Pennsylvania. Of the 1,250,077 total net acres in Pennsylvania, shale development in the Marcellus, Utica or Geneseo shales has occurred on approximately 134,414 net acres, or 11% 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, 2023, the aggregate amounts of gross undeveloped acreage expiring under lease in the next three years and thereafter are as follows: 20,858 acres in 2024 (19,108 net acres), 11,176 acres in 2025 (10,180 net acres), 15,389 acres in 2026 (14,219 net acres) and 211,719 acres thereafter (193,090 net acres). The remaining 469,247 gross acres (435,079 net acres) represent non-expiring oil and gas rights owned by the Company. Of the acreage that is currently scheduled to expire in 2024, 2025 and 2026, Seneca has 352.2 Bcf of associated proved undeveloped gas reserves. As a part of its management approved development plan, Seneca generally commences development of these reserves prior to the expiration of the leases and/or proactively extends/renews these leases.

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Drilling Activity


	Productive			Dry
For the Year Ended September 30	2023	2022	2021	2023	2022	2021
United States
Appalachian Region
Net Wells Completed
— Exploratory	—	—	—	—	—	—
— Development(1)	34.25	43.00	47.83	0.50	2.50	2.00
West Coast Region
Net Wells Completed
— Exploratory	—	—	—	—	—	—
— Development	—	23.00	10.00	—	—	—
Total Company
Net Wells Completed
— Exploratory	—	—	—	—	—	—
— Development	34.25	66.00	57.83	0.50	2.50	2.00

(1)Fiscal 2023, 2022 and 2021 Appalachian region dry wells include 0.5, 2.5 and 2 net wells, respectively, drilled prior to 2013 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 2023, 2022 and 2021 after the Company determined it would not continue development activities.

Present Activities


At September 30, 2023			Appalachian Region
Wells in Process of Drilling(1)
— Gross			54.00
— Net			52.00

(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, 2023, there were 8,751 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 3, 2023, the Company issued a total of 8,490 unregistered shares of Company common stock to non-employee directors of the Company then serving on the Board of Directors of the Company (or, in the case of non-employee directors who elected to defer receipt of such shares pursuant to the Company's Deferred Compensation Plan for Directors and Officers (the “DCP”), to the DCP trustee), consisting of 849 shares per 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, 2023. The Company issued an additional 540 unregistered shares in the aggregate on July 14, 2023 pursuant to the dividend reinvestment feature of the DCP, to the six non-employee directors who participate in the DCP. 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, 2023	14,954	$	51.00	—	6,971,019
Aug. 1-31, 2023	12,495	$	53.88	—	6,971,019
Sept. 1-30, 2023	13,493	$	51.42	—	6,971,019
Total	40,942	$	52.10	—	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, if any, tendered to the Company by holders of stock-based compensation awards for the payment of applicable withholding taxes. During the quarter ended September 30, 2023, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 40,942 shares purchased other than through a publicly announced share repurchase program, 40,679 were purchased for the Company’s 401(k) plans and 263 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, 2018 through September 30, 2023. The graph assumes that the value of the investment in the Company’s common stock and in each index was $100 on September 30, 2018 and that all dividends were reinvested.


	2018	2019	2020	2021	2022	2023
National Fuel	$100	$86	$78	$105	$126	$110
S&P 500 Index	$100	$104	$120	$155	$131	$160
S&P Mid Cap 400 Gas Utility Index (S4GASU)	$100	$105	$74	$91	$93	$84
S&P 1500 Oil & Gas Exp & Prod Index (S15OILP)	$100	$64	$35	$82	$122	$144

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.


Item 6			(Reserved)

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

OVERVIEW

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

Corporate Responsibility

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

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

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

Fiscal 2023 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;”

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

4.Other Matters, including: (a) 2023 and projected 2024 funding for the Company’s pension and other post-retirement benefits; (b) disclosures and tables concerning market risk sensitive instruments; (c) rate matters in the Company’s New York, Pennsylvania and FERC-regulated jurisdictions; (d) environmental matters; and (e) effects of inflation.

The information in MD&A should be read in conjunction with the Company’s financial statements in Item 8 of this report, which includes a comparison of our Results of Operations and Capital Resources and Liquidity for fiscal 2023 and fiscal 2022. 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 2021 to fiscal 2022 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, 2022, filed with the SEC on November 18, 2022.

The Company's Exploration and Production segment continues to grow, as evidenced by a 9% growth in proved reserves from the prior year to a total of 4,536 Bcfe at September 30, 2023. Production increased 19.9 Bcfe during the fiscal year ended September 30, 2023 to a total of 372.5 Bcfe, and is expected to increase again in fiscal 2024.

On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN Production Company, LLC ("SWN") for total consideration of $124.8 million. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment.

The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation's system, referred to as the Tioga Pathway Project, would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC’s (“Transco”) capacity lease, providing access to Mid-Atlantic markets. The Tioga Pathway Project has a target in-service date in late calendar 2026 and a preliminary cost estimate of approximately $90 million. The Tioga Pathway Project is discussed in more detail in the Capital Resources and Liquidity section that follows.

From a rate perspective, Distribution Corporation, in its Pennsylvania jurisdiction, reached a settlement with the parties to its rate case proceeding. On June 15, 2023, the PaPUC issued an order adopting the settlement in full. The settlement authorized an increase in Distribution Corporation's annual base rate operating revenues of $23 million that became effective August 1, 2023. Distribution Corporation also filed a rate case proceeding with the NYPSC in its New York jurisdiction on October 31, 2023 seeking an increase of $88.8 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024. In addition, Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023. For further discussion of Distribution Corporation and Supply Corporation rate matters, refer to the Rate Matters section below.

From a financing perspective, on June 30, 2022, the Company entered into a 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under a Credit Agreement (as amended from time to time, the "Credit Agreement"). The 364-Day Credit Agreement provided an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company used the proceeds for general corporate purposes, which included using $150.0 million for the November 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date in March 2023. In March 2023, the Company utilized short-term borrowings and cash on hand to redeem the remaining long-term debt that had maturity dates in March 2023, which included $350.0 million of 3.75% notes and $49.0 million of 7.395% notes.

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On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. The proceeds of this debt issuance were used for general corporate purposes, including to repay all indebtedness under the $250.0 million unsecured committed delayed draw term loan under the 364-Day Credit Agreement mentioned above.

The Company expects to use cash on hand, cash from operations, and short-term and long-term borrowings, as needed, to meet its financing needs for fiscal 2024. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures and rising interest rates, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs as discussed above.

In early 2023, turmoil with certain financial institutions created uncertainty in the economy. While the Company was not directly impacted, it continues to closely monitor any potential future impacts on the business. The Company has a diverse group of twelve banks that participate in its multi-year credit facility. All of these banks have solid investment grade credit ratings. Additionally, the Company regularly reviews the credit quality of its hedging counterparties, those that provide credit support for customers, and any other material counterparties, and has not identified any material risks as a result of the current economic uncertainty.

CRITICAL ACCOUNTING ESTIMATES

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

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

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

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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 natural gas prices. The ceiling is then compared to the capitalized cost of oil and gas properties less accumulated depletion and related deferred income taxes. If the capitalized costs of oil and gas properties less accumulated depletion and related deferred taxes exceeds the ceiling at the end of any fiscal quarter, a non-cash impairment charge must be recorded to write down the book value of the reserves to their present value. This non-cash impairment cannot be reversed at a later date if the ceiling increases. It should also be noted that a non-cash impairment to write down the book value of the reserves to their present value in any given period causes a reduction in future depletion expense. At September 30, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $794.7 million. The 12-month average of the first day of the month price for natural gas for each month during 2023, based on the quoted Henry Hub spot price for natural gas, was $3.42 per MMBtu. (Note — because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for 2023. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices used at September 30, 2023 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's oil and gas properties by approximately $442.9 million (after-tax), which would not have resulted in an impairment charge. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

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

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

Regulation. The Company is subject to regulation by certain state and federal authorities. The Company, in its Utility and Pipeline and Storage segments, has accounting policies which conform to the FASB authoritative guidance regarding accounting for certain types of regulations, and which are in accordance with the accounting requirements and ratemaking practices of the regulatory authorities. The application of these accounting principles for certain types of rate-regulated activities provides 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

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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 Consolidated Statement of Income 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

2023 Compared with 2022

The Company's earnings were $476.9 million in 2023 compared with earnings of $566.0 million in 2022. The decrease in earnings of $89.1 million was a result of lower earnings in all reportable segments, as well as losses in the Corporate and All Other categories. In the discussion that follows, all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted. Earnings were impacted by the following events in 2022:

2022 Events

•The reversal of a deferred tax valuation allowance of $24.9 million recorded in the Exploration and Production and Gathering segments, which increased earnings in 2022.

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

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

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

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

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

Earnings (Loss) by Segment


	Year Ended September 30
	2023		2022		2021
	(Thousands)
Exploration and Production	$	232,275	$	306,064	$	101,916
Pipeline and Storage	100,501		102,557		92,542
Gathering	99,724		101,111		80,274
Utility	48,395		68,948		54,335
Total Reported Segments	480,895		578,680		329,067
All Other	(531)		(9)		37,645
Corporate	(3,498)		(12,650)		(3,065)
Total Consolidated	$	476,866	$	566,021	$	363,647

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EXPLORATION AND PRODUCTION

Revenues

Exploration and Production Operating Revenues


	Year Ended September 30
	2023		2022
	(Thousands)
Gas (after Hedging)	$	948,484	$	930,130
Oil (after Hedging)(1)	2,261		113,588
Gas Processing Plant	1,203		3,511
Other	6,507		(36,765)
Operating Revenues	$	958,455	$	1,010,464

Production


	Year Ended September 30
	2023	2022
Gas Production (MMcf)
Appalachia	372,271	341,700
West Coast	—	1,211
Total Production	372,271	342,911
Oil Production (Mbbl)
Appalachia	30	16
West Coast	—	1,588
Total Production	30	1,604

Average Prices


	Year Ended September 30
	2023		2022
Average Gas Price/Mcf
Appalachia	$	2.78	$	5.03
West Coast(2)	N/A		$	10.03
Weighted Average Before Hedging	$	2.78	$	5.05
Weighted Average After Hedging(3)	$	2.55	$	2.71
Average Oil Price/Barrel (Bbl)
Appalachia	$	75.64	$	97.82
West Coast(2)	N/A		$	94.06
Weighted Average Before Hedging	$	75.64	$	94.10
Weighted Average After Hedging(1)(3)	$	75.64	$	70.80

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

(2)Prices for the year ended September 30, 2023 are not applicable (N/A) as a result of the sale of Seneca's West Coast assets in June 2022.

(3)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.

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2023 Compared with 2022

Operating revenues for the Exploration and Production segment decreased $52.0 million in 2023 as compared with 2022. Gas production revenue after hedging increased $18.4 million primarily due to a 29.4 Bcf increase in gas production offset by a $0.16 per Mcf decrease in the weighted average realized price of gas after hedging. The increase in gas production was largely due to new Marcellus and Utica wells in the Appalachian region. Oil production revenue after hedging decreased $111.3 million mainly attributable to the sale of California assets at June 30, 2022. In addition, other revenue increased $43.3 million and plant revenue decreased $2.3 million. The increase in other revenue was primarily attributable to the non-recurrence of a loss on the discontinuance of crude oil cash flow hedges as a result of the sale of California assets combined with the non-recurrence of royalty shut-in payments made in 2022 in accordance with lease agreements. These increases to other revenue were partially offset by decreases to temporary capacity release revenue and a decrease in operating revenue from this segment's water treatment plants. Finally, the decrease in gas processing plant revenues was mainly attributable to the sale of California assets combined with declining gas pricing.

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

2023 Compared with 2022

The Exploration and Production segment’s earnings for 2023 were $232.3 million, a decrease of $73.8 million when compared with earnings of $306.1 million for 2022. The sale of California assets on June 30, 2022 was a large factor in the earnings variance year over year. As a result of the sale, 2023 earnings decreased due to lower oil production ($88.1 million) and the non-recurrence of a gain that was recognized on the sale of Seneca’s California non-full cost pool assets ($9.5 million). However, these factors were partially offset by the non-recurrence of a 2022 loss related to the discontinuance of its crude oil cash flow hedges ($33.3 million) and 2022 transaction and severance costs associated with the sale ($7.2 million). There was also a lower unrealized loss recognized in 2023 ($0.7 million) on contingent consideration received as part of the California asset sale as compared to the unrealized loss that was recognized in 2022 ($3.2 million) on that contingent consideration. Other factors impacted by the sale included lower lease operating and transportation expenses ($24.0 million), lower other operating expenses ($11.1 million), and lower other taxes ($6.0 million). Excluding the impact of the California sale, lease operating and transportation costs in the Appalachian region increased year over year. Other operating costs were also impacted by the non-recurrence of abandonment costs recognized in 2022 for certain offshore Gulf of Mexico wells that were formerly owned by Seneca, and other taxes was also impacted by lower Impact Fees in the Appalachain region. Aside from the earnings impact of these items, the earnings decrease reflected lower natural gas prices after hedging ($48.4 million), lower other revenue ($1.1 million) and lower gas processing plant revenue ($1.8 million), all of which are discussed above. Other factors that decreased earnings included higher depletion expense ($26.1 million), higher interest expense ($0.7 million) and higher income tax expense ($3.4 million). In 2022, the Exploration and Production segment reversed a valuation allowance ($28.6 million) on deferred tax assets related to certain state net operating loss and credit carryforwards as these deferred tax assets are now expected to be realized in the future. The Exploration and Production segment also recorded an income tax benefit ($16.2 million) in 2022 from the remeasurement of deferred income taxes related to a state corporate income tax rate reduction in Pennsylvania that was signed into law in July 2022. The law reduces the Pennsylvania corporate income tax rate to 8.99% for fiscal 2024, and starting with fiscal 2025, the rate is further reduced by 0.5% annually until it reaches 4.99% for fiscal 2032. Partially offsetting these items, the Exploration and Production segment had higher natural gas production ($62.9 million), and higher other income ($2.7 million).

The increase in depletion expense was primarily due to the increase in production, combined with a $0.06 per Mcfe increase in the depletion rate. The year over year increase in the depletion rate was mainly driven by higher capitalized costs and an increase in future development costs related to proved undeveloped wells. The increase in interest expense can largely be attributed to higher average interest rates on short-term and long-term borrowings offset partially by lower intercompany long-term debt balances. The increase in income tax expense was primarily driven by a prior-year benefit realized from the Enhanced Oil Recovery tax credit, which

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did not recur in the current year as a result of the sale of the California assets. The increase in other income was attributable to higher interest income, as well as non-service pension and post-retirement income in 2023 compared to non-service pension and post-retirement benefit costs in 2022.

PIPELINE AND STORAGE

Revenues

Pipeline and Storage Operating Revenues


	Year Ended September 30
	2023		2022
	(Thousands)
Firm Transportation	$	289,935	$	287,486
Interruptible Transportation	1,290		2,481
	291,225		289,967
Firm Storage Service	84,960		84,565
Interruptible Storage Service	2		—
	84,962		84,565
Other	3,004		2,512
	$	379,191	$	377,044

Pipeline and Storage Throughput — (MMcf)


	Year Ended September 30
	2023	2022
Firm Transportation	816,484	790,417
Interruptible Transportation	2,192	5,612
	818,676	796,029

2023 Compared with 2022

Operating revenues for the Pipeline and Storage segment increased $2.1 million in 2023 as compared with 2022. The increase in operating revenues was primarily due to an increase in transportation revenues of $1.3 million, an increase in storage revenues of $0.4 million and an increase in other revenues of $0.5 million. The increase in transportation revenues was primarily attributable to new demand charges for transportation service from Supply Corporation's FM100 Project, which was placed into service in December 2021. The increase from the FM100 Project includes the impact of a negotiated revenue step-up to Period 2 Rates that went into effect April 1, 2022, as specified in Supply Corporation's 2020 rate case settlement. An increase in short-term contracts also contributed to the increase in transportation revenues. These increases were partially offset by a decline in revenues associated with miscellaneous contract expirations and revisions. The increase in other revenues primarily reflects proceeds received during the quarter ended September 30, 2023 as a result of a contract buyout.

Transportation volume increased by 22.6 Bcf in 2023 as compared with 2022, primarily due to an increase in short-term contracts, as well as an increase in volume from the FM100 Project. These increases were partially offset by certain contract expirations during fiscal 2023. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

The majority of Supply Corporation's and Empire's transportation and storage contracts allow either party to terminate the contract upon six or twelve months' notice effective at the end of the primary term and include "evergreen" language that allows for annual term extension(s). The Pipeline and Storage segment's contracted transportation and storage capacity with both affiliated and unaffiliated shippers is expected to remain relatively constant in fiscal 2024.

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Earnings

2023 Compared with 2022

The Pipeline and Storage segment’s earnings in 2023 were $100.5 million, a decrease of $2.1 million when compared with earnings of $102.6 million in 2022. The decrease in earnings was primarily due to an increase in operating expenses ($5.2 million) and an increase in depreciation expense ($2.5 million). The increase in operating expenses was primarily due to higher personnel costs, higher pipeline integrity costs and an increase in compressor maintenance costs. The increase in depreciation expense was primarily due to incremental depreciation from the FM100 Project. These earnings decreases were partially offset by the impact of higher operating revenues ($1.7 million), as discussed above, combined with higher other income ($3.6 million). The increase in other income is primarily due to a higher weighted average interest rate on intercompany short-term notes receivables along with higher non-service pension and post-retirement benefit income. This was partially offset by a decrease in allowance for funds used during construction (equity component) related to the construction of the FM100 Project along with an annual adjustment that was recorded during the current fiscal year.

GATHERING

Revenues

Gathering Operating Revenues


	Year Ended September 30
	2023		2022
	(Thousands)
Gathering	$	230,317	$	214,843

Gathering Volume — (MMcf)


	Year Ended September 30
	2023	2022
Gathered Volume	453,338	419,332

2023 Compared with 2022

Operating revenues for the Gathering segment increased $15.5 million in 2023 as compared with 2022, which was driven primarily by a 34.0 Bcf increase in gathered volume. Gathered volume on the Tioga and Clermont gathering systems increased 36.3 Bcf and 7.1 Bcf, respectively, partially offset by a decrease of 9.4 Bcf on the Trout Run gathering system. The net increase in gathered volume can be attributed to the increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems. All references to the Tioga gathering system in this operating revenues discussion and the earnings discussion that follows include the revenues, volume and earnings of the gathering system owned by NFG Midstream Covington, LLC (Covington), which includes the gathering system previously owned by NFG Midstream Wellsboro, LLC (Wellsboro). Wellsboro was merged into Covington effective August 31, 2023. The merger of Wellsboro into Covington reflects the completion of a pipeline that connects the two systems.

Earnings

2023 Compared with 2022

The Gathering segment’s earnings in 2023 were $99.7 million, a decrease of $1.4 million when compared with earnings of $101.1 million in 2022. Income taxes were a significant factor in the year over year variation. First, earnings were negatively impacted by the non-recurrence of an income tax benefit ($11.9 million) during the quarter ended September 30, 2022 from the remeasurement of deferred income taxes related to a state corporate income tax rate reduction in Pennsylvania that was signed into law in July 2022 (as discussed above, in the Exploration and Production segment). This segment also experienced an increase in income tax expense ($1.0 million) due to higher state income tax expense. Partially offsetting these factors, earnings benefited from the non-recurrence of deferred income tax expense ($3.7 million) recognized during the quarter ended

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September 30, 2022 as an offset to the Exploration and Production segment's reversal of the deferred tax asset valuation allowance. This offset is a result of the Gathering and Exploration and Production segments' subsidiaries filing a combined state tax return. In addition to these income tax variations, earnings decreased due to higher operating expenses ($4.9 million) and higher depreciation expense ($1.4 million). The increase in operating expenses was largely attributable to higher outside service costs associated with preventative maintenance overhauls on the Clermont, Tioga and Trout Run gathering systems, higher leased compression expense on the Trout Run and Tioga gathering systems and higher labor-related costs across all of the gathering systems. The increase in depreciation expense was largely due to higher plant balances associated with the Tioga and Clermont gathering systems. These earnings decreases were partially offset by the impact of higher gathering revenues ($12.2 million) driven by the increase in gathered volume (discussed above). Additionally, earnings increased due to lower interest expense ($1.2 million) and higher other income ($0.6 million). The decrease in interest expense was primarily due to higher capitalized interest and lower interest on intercompany long-term borrowings associated with the Company's redemption of $500.0 million of 3.75% notes during 2023. The increase in other income is primarily due to lower non-service pension and post-retirement benefit expenses.

UTILITY

Revenues

Utility Operating Revenues


	Year Ended September 30
	2023		2022
	(Thousands)
Retail Revenues:
Residential	$	729,715	$	691,034
Commercial	103,150		95,120
Industrial	5,682		4,913
	838,547		791,067

Transportation	103,305		111,072
Other	508		(3,918)
	$	942,360	$	898,221

Utility Throughput — million cubic feet (MMcf)


	Year Ended September 30
	2023	2022
Retail Sales:
Residential	61,401	64,011
Commercial	9,342	9,621
Industrial	548	541
	71,291	74,173

Transportation	62,986	65,993
	134,277	140,166

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Degree Days


				Percent (Warmer) Colder Than
Year Ended September 30		Normal	Actual	Normal(1)		Prior Year(1)
2023	Buffalo, NY	6,617	5,717	(13.6)	%	(0.9)	%
	Erie, PA(2)	6,104	5,493	(10.0)	%	2.3	%
2022	Buffalo, NY	6,617	5,769	(12.8)	%	0.7	%
	Erie, PA	6,147	5,368	(12.7)	%	2.8	%

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

(2)Normal degree days changed from the NOAA 30-year degree days to NOAA 15-year degree days with the implementation of new base rates in Pennsylvania in August 2023.

2023 Compared with 2022

Operating revenues for the Utility segment increased $44.1 million in 2023 compared with 2022. The increase resulted from a $47.5 million increase in retail gas sales revenue and a $4.4 million increase in other revenues, which were partially offset by a $7.8 million decrease in transportation revenue. The increase in retail gas sales revenue was primarily due to an increase in the cost of gas sold (per Mcf), partially offset by a 2.9 Bcf decrease in throughput due to warmer weather during the winter months and a decrease in base rates. The decrease in base rates is related to a tariff filing approved by the NYPSC, which created a surcredit that temporarily eliminates pension and OPEB cost recovery from base rates effective October 1, 2022. Additional details related to the regulatory proceeding are discussed in Item 8 at Note F — Regulatory Matters. The increase in other revenues was due to an increase in capacity release revenues and a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act. The decrease in transportation revenue resulted from a 3.0 Bcf decrease in throughput due to warmer weather and the decrease in base rates, as previously mentioned. The decreases in gas retail sales revenue and transportation revenue were partially offset by an increase in revenues earned under the system modernization and system improvement tracker mechanisms in Distribution Corporation's New York jurisdiction, which allow for the recovery of investments in leak prone pipe replacement.

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 $548.2 million and $498.0 million of Purchased Gas expense during 2023 and 2022, respectively. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation does not profit from fluctuations in gas costs. Purchased Gas expense recorded on the consolidated income statement matches the revenues collected from customers, a component of Operating Revenues on the consolidated income statement. Under mechanisms approved by the NYPSC in New York and the PaPUC in Pennsylvania, any difference between actual purchased gas costs and what has been collected from the customer is deferred on the consolidated balance sheet as either an asset, Unrecovered Purchased Gas Costs, or a liability, Amounts Payable to Customers. These deferrals are subsequently collected from the customer or passed back to the customer, subject to review by the NYPSC and the PaPUC. Absent disallowance of full recovery of Distribution Corporation’s purchased gas costs, such costs do not impact the profitability of the Company. Purchased gas costs impact cash flow from operations due to the timing of recovery of such costs versus the actual purchased gas costs incurred during a particular period. Distribution Corporation’s purchased gas adjustment clauses seek to mitigate this impact by adjusting revenues on either a quarterly or monthly basis.

Distribution Corporation contracts for firm long-term transportation and storage capacity services with rights-of-first-refusal from ten upstream pipeline companies including Supply Corporation for transportation and storage services and Empire, for transportation services. Distribution Corporation contracts for firm spot

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and term gas supplies 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

2023 Compared with 2022

The Utility segment’s earnings in 2023 were $48.4 million, a decrease of $20.5 million when compared with earnings of $68.9 million in 2022. The decrease in earnings was due in part to the impact of a proceeding in the Utility's Pennsylvania service territory during the quarter ended March 31, 2022 that allowed for a favorable one-time adjustment of $14.6 million to recognize the cumulative amount of OPEB income, previously deferred as a regulatory liability in that jurisdiction, which did not recur in 2023. In addition to the non-recurrence of this transaction, there was a decrease in OPEB income ($2.4 million) in the Utility's Pennsylvania service territory.

The earnings impact of the reduction in the New York jurisdiction's base rates in 2023 resulting from the NYPSC tariff filing related to pension and OPEB costs discussed above ($12.0 million), combined with an increase in operating costs ($2.0 million) associated with the elimination of fringe benefit credits being applied to service and non-service pension and OPEB costs, was offset by a decrease in other deductions associated with non-service pension and OPEB costs ($14.0 million). With the elimination of pension and OPEB expenses in customer rates, Distribution Corporation’s New York service territory did not recognize any pension and OPEB expenses during 2023 compared to the prior year when it recognized pension and OPEB expenses to match against the pension and OPEB amounts collected in base rates.

Other factors that contributed to the earnings decrease in the Utility segment included higher operating expenses ($6.8 million) and higher interest expense ($8.6 million). The increase in operating expenses was mainly due to higher personnel costs and outside services. The increase in interest expense was largely the result of a higher weighted average interest rate on intercompany short-term borrowings combined with higher average short-term debt balances. There were also several factors that helped to reduce the earnings decrease year over year. The Utility segment's earnings benefited from the impact of the system modernization and system improvement trackers in New York ($3.8 million), lower income tax expense ($3.5 million) in New York and Pennsylvania, of which $1.7 million relates to a methodology change for the repair and maintenance tax deduction in Pennsylvania, higher capacity release revenues ($1.6 million), and a regulatory adjustment ($1.5 million). The Utility's Pennsylvania service territory also benefited from new rates that went into effect August 1, 2023 ($0.8 million).

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 both 2023 and 2022, the WNC contributed approximately $4.8 million to earnings, as the weather was warmer than normal. Effective October 2023, the weather impact on cash flow in the Utility segment will also be mitigated by a WNC in its Pennsylvania rate jurisdiction.

ALL OTHER AND CORPORATE OPERATIONS

Earnings

2023 Compared with 2022

All Other and Corporate operations had a net loss of $4.0 million in 2023, an improvement of $8.7 million when compared with a net loss of $12.7 million in 2022. The improvement was primarily attributable to changes in unrealized gains and losses on investments in equity securities. In 2023, the Company recorded unrealized gains of $0.7 million, while in 2022, the Company recorded unrealized losses of $9.2 million. Other contributing factors include an increase in the cash surrender value of life insurance policies ($1.3 million), an increase in interest income on temporary cash investments ($1.3 million) and lower non-service pension and post-retirement benefit costs ($2.1 million). These changes were partially offset by a decrease in realized gains

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from sales of investments in equity securities ($2.9 million), as well as an increase in operating expenses as a result of an increase in professional services ($2.7 million).

OTHER INCOME (DEDUCTIONS)

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

Net other income on the Consolidated Statements of Income was $18.1 million in 2023 compared to net other deductions of $1.5 million in 2022, for a net increase of $19.6 million. This was mostly due to changes in unrealized and realized gains and losses on investments in equity securities of $10.4 million, along with an increase in the cash surrender value of life insurance policies of $1.3 million. Higher interest income of $5.0 million also contributed to the increase, which resulted from an increase in interest on temporary cash investments, an increase in interest on a larger undercollection of gas costs over the prior year in Distribution Corporation and an increase in interest income earned on investments. The mark-to-market valuation adjustment for the contingent consideration received from the sale of Seneca's California assets in June 2022 was a loss of $0.9 million during 2023 as compared to a loss of $4.4 million during 2022. There was also a $1.9 million increase in non-service pension and post-retirement benefit income year over year. Offsetting these increases was a $2.3 million reduction in allowance for funds used during construction.

INTEREST CHARGES

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

Interest on long-term debt decreased $8.6 million in 2023 as compared to 2022. The Company redeemed $150.0 million of the $500.0 million 3.75% notes in November 2022. In addition, $350.0 million of $500.0 million 3.75% notes and $49.0 million of 7.395% notes were redeemed in March 2023. These redemptions were partially offset by the issuance of $300.0 million of 5.50% notes in May 2023.

Other interest expense increased $10.1 million in 2023 as compared to 2022. The increase was primarily due to higher weighted average interest rates for 2023 partially offset by lower average short-term debt balances in 2023 compared to 2022.

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
	2023		2022
	(Millions)
Provided by Operating Activities	$	1,237.1	$	812.5
Capital Expenditures	(1,009.9)		(811.8)
Net Proceeds from Sale of Oil and Gas Producing Properties	—		254.4
Acquisition of Upstream Assets	(124.8)		—
Sale of Fixed Income Mutual Fund Shares in Grantor Trust	10.0		30.0
Other Investing Activities	12.3		8.7
Reduction of Long-Term Debt	(549.0)		—
Net Proceeds from Issuance of Long-Term Debt	297.3		—
Proceeds from Issuance of Short-Term Note Payable to Bank	250.0		—
Repayments of Short-Term Note Payable to Bank	(250.0)		—
Net Change in Other Short-Term Notes Payable to Banks and Commercial Paper	227.5		(98.5)
Net Repurchases of Common Stock	(6.7)		(9.6)
Dividends Paid on Common Stock	(176.1)		(168.1)

Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	$	(82.3)	$	17.6

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The Company expects to have adequate amounts of cash available to meet both its short-term and long-term cash requirements for at least the next twelve months and for the foreseeable future thereafter. During 2024, cash provided by operating activities is forecasted to be lower than 2023 largely due to a decrease in working capital sources, but is expected to be more than enough to fund the Company's capital expenditures. Looking forward to 2025, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures. The Company also has two long-term debt maturities in 2025, totaling $500.0 million, which the Company anticipates funding with cash on hand and short-term and long-term borrowings. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.

OPERATING CASH FLOW

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

Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from year to year because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire. Prior to October 2023, the weather impact on cash flow in the Utility segment was mitigated by a WNC solely in its New York rate jurisdiction. However, effective October 2023, the weather impact on cash flow in the Utility segment will also be mitigated by a WNC in its Pennsylvania rate jurisdiction. Refer to Item 8 at Note A — Summary of Significant Accounting Policies (Regulatory Mechanisms) for additional discussion.

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

The Company, in its Utility segment and Exploration and Production segment, has entered into contractual commitments in the ordinary course of business, including commitments to purchase gas, transportation, and storage service to meet customer gas supply needs. Refer to Item 8 at Note L — 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 $1,237.1 million in 2023, an increase of $424.6 million compared with the $812.5 million provided by operating activities in 2022. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Exploration and Production segment and Utility segment. The increase in the Exploration and Production segment is primarily due to higher cash receipts from natural gas production, net of royalty and working interests. The increase in the Utility segment is primarily due to the timing of gas cost recovery and the timing of customer receivable balance collections.

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INVESTING CASH FLOW

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets, including non-cash capital expenditures, totaled $1.12 billion and $829.4 million in 2023 and 2022, respectively. The table below presents these expenditures:


	Year Ended September 30
	2023			2022
	(Millions)
Exploration and Production:
Capital Expenditures (1)	$	737.7	(2)	$	565.8	(3)
Pipeline and Storage:
Capital Expenditures	141.9		(2)	95.8		(3)
Gathering:
Capital Expenditures	103.3		(2)	55.5		(3)
Utility:
Capital Expenditures	139.9		(2)	111.0		(3)
All Other and Corporate:
Capital Expenditures	0.8			1.3

Total Expenditures	$	1,123.6		$	829.4

(1)The year ended September 30, 2023 includes $124.8 million related to the acquisition of upstream assets acquired from SWN. The acquisition cost is reported as a component of Acquisition of Upstream Assets on the Consolidated Statement of Cash Flows.

(2)2023 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $43.2 million, $31.8 million, $20.6 million and $13.6 million, respectively, of non-cash capital expenditures.

(3)2022 capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $83.0 million, $15.2 million, $10.7 million and $11.4 million, respectively, of non-cash capital expenditures.

Exploration and Production

In 2023, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures in the Appalachian region and included $292.6 million in the Marcellus Shale area and $430.7 million in the Utica Shale area. These amounts included approximately $342.0 million spent to develop proved undeveloped reserves.

On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN for total consideration of $124.8 million. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment.

Other 2023 acquisitions included the acquisition of certain upstream assets located in Lycoming County in Northeast Pennsylvania for total consideration of $11.5 million as well as the acquisition of undeveloped acreage in Tioga County, Pennsylvania for $13.6 million. The acquisition in Lycoming County included 1,145 net acres and the acquisition in Tioga County included 4,222 net acres. Both transactions were accounted for as asset acquisitions and, as such, the purchase price for each transaction was allocated to property, plant and equipment. The cost of these acquisitions is reported as a component of Capital Expenditures on the Consolidated Statement of Cash Flows.

In 2022, the Exploration and Production segment capital expenditures were primarily well drilling and completion expenditures and included approximately $547.1 million for the Appalachian region (including $161.4 million in the Marcellus Shale area and $370.6 million in the Utica Shale area) and $18.7 million for the

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West Coast region. These amounts included approximately $154.3 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment’s capital expenditures for 2023 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions.

The Pipeline and Storage segment’s capital expenditures for 2022 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions. In addition, the Pipeline and Storage segment capital expenditures for 2022 include expenditures related to Supply Corporation's FM100 Project ($25.2 million).

Gathering

The majority of the Gathering segment's capital expenditures for 2023 included expenditures related to the continued expansion of Midstream Company's Clermont, Tioga and Trout Run gathering systems, as discussed below. The Tioga gathering system refers to the gathering system owned by NFG Midstream Covington, LLC (Covington), which includes the gathering system previously owned by NFG Midstream Wellsboro, LLC (Wellsboro). Wellsboro was merged into Covington effective August 31, 2023. The merger of Wellsboro into Covington reflects the completion of a pipeline that connects the two systems. Midstream Company spent $20.7 million, $71.2 million and $10.8 million, respectively, in 2023 on the development of the Clermont, Tioga and Trout Run gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

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

Utility

The majority of the Utility segment’s capital expenditures for 2023 and 2022 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

In October 2021, the Company sold $30 million of fixed income mutual fund shares held in a grantor trust that was established for the benefit of Pennsylvania ratepayers. The proceeds were used in the Utility segment’s Pennsylvania service territory to fund a one-time customer bill credit of $25 million in October 2021 for previously overcollected OPEB expenses and the first year installment of a 5-year pass back of an additional $29 million in previously overcollected OPEB expenses in accordance with new rates that went into effect on October 1, 2021. In October 2022, the Company sold an additional $10 million of fixed income mutual fund shares held in the grantor trust. The proceeds from this sale were used to fund the second year installment of the 5-year pass back of overcollected OPEB expenses, as well as to diversify a portion of grantor trust investments into lower risk money market mutual fund shares. Please refer to the Rate Matters section that follows for additional discussion of this matter.

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In March 2022, the Company completed the sale of certain oil and gas assets located in Tioga County, Pennsylvania effective as of October 1, 2021. The Company received net proceeds of $13.5 million from this sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.

On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which were in the Exploration and Production segment, to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing. The fair value of the contingent consideration was $7.3 million at September 30, 2023. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances.

Estimated Capital Expenditures

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


	Year Ended September 30
	2024		2025		2026
	(Millions)
Exploration and Production(1)	$	550	$	520	$	510
Pipeline and Storage	130		135		180
Gathering	100		110		95
Utility(2)	140		150		150
All Other	—		—		—
	$	920	$	915	$	935

(1)Includes estimated expenditures for the years ended September 30, 2024, 2025 and 2026 of approximately $315 million, $225 million and $120 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, 2024, 2025, and 2026 of approximately $115 million, $115 million and $120 million, respectively, for system modernization and safety to enhance the reliability and safety of the system and reduce emissions.

Exploration and Production

Capital expenditures for the Exploration and Production segment in 2024 through 2026 are expected to be primarily well drilling and completion expenditures in the Appalachian region.

Pipeline and Storage

Capital expenditures for the Pipeline and Storage segment in 2024 through 2026 are expected to include: the replacement and modernization of transmission and storage facilities, the reconditioning of storage wells, improvements of compressor stations and emissions reduction initiatives, as well as capital expenditures related to system expansion.

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In addition, due to the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, specifically in the Marcellus and Utica Shale producing areas, Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems. An expansion and modernization project where the Company has forecasted a significant amount of investment in preliminary survey and investigation costs and/or capital expenditures in 2024 through 2026, and where a precedent agreement has been executed, is discussed below.

Supply Corporation concluded an Open Season on August 25, 2023, and based on post-open season discussions, has designed a project that would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC’s (“Transco”) capacity lease, providing access to Mid-Atlantic markets (“Tioga Pathway Project”). The Tioga Pathway Project involves the construction of approximately 19 miles of new pipeline and the replacement of approximately four miles of existing pipeline on the Supply Corporation system. Supply Corporation has executed a Precedent Agreement with Seneca for 190,000 Dth per day of transportation capacity. Supply Corporation expects to file a Section 7(c) application with the FERC in the second half of calendar 2024. The Tioga Pathway project has a projected in-service date of late calendar year 2026 and an estimated capital cost of approximately $90 million. The majority of these expenditures are included as Pipeline and Storage segment estimated capital expenditures in the table above. As of September 30, 2023, less than $0.1 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at September 30, 2023.

Gathering

The majority of the Gathering segment capital expenditures in 2024 through 2026, included in the table above, are expected to be for construction and expansion of gathering systems, as discussed below. The Gathering segment primarily invests capital to support Seneca's drilling and completion activity in their long-term development plan. Seneca has shifted a larger share of its forward-looking activity from its Western Development Area to Tioga County, Pennsylvania. As a result, the Gathering segment is expecting to see near-term increases in capital expenditures as it constructs the necessary infrastructure to support Seneca's activity in the region.

Utility

Capital expenditures for the Utility segment in 2024 through 2026 are expected to be concentrated in the areas of main and service line improvements and replacements that will enhance the reliability and safety of the system, emission reduction initiatives and, to a lesser extent, the purchase of new equipment.

Project Funding

During fiscal 2023 and 2022, capital expenditures were funded with cash from operations and short-term debt. Capital expenditures in fiscal 2022 were also funded with proceeds from the sale of the Company's California assets. Going forward, the Company expects to use cash on hand, cash from operations and short-term or long-term borrowings, as needed, to finance capital expenditures. The level of short-term and/or long-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production and the associated commodity price realizations in the Exploration and Production segment. It will also likely depend on the timing of gas cost recovery in the Utility segment.

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

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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 natural gas properties, accelerated development of existing natural gas properties, natural gas storage and transmission facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. The amounts are also subject to modification for opportunities involving emission reductions and/or energy transition including investments directly related to low- and no-carbon fuels. 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 business segments depends, to a large degree, upon market and regulatory conditions as well as legislative actions.

FINANCING CASH FLOW

Consolidated short-term debt increased $227.5 million, to a total of $287.5 million, when comparing the balance sheet at September 30, 2023 to the balance sheet at September 30, 2022. The maximum amount of short-term debt outstanding during the year ended September 30, 2023 was $422.3 million. In addition to cash provided by operating activities, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, asset purchases, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. During fiscal 2023, the Company repaid $549.0 million of long-term debt with maturity dates in March 2023 and issued $300.0 million of additional long-term debt in May 2023. The net reduction in long-term debt resulted in an increase in the short-term debt balance. As of September 30, 2023, the Company had outstanding commercial paper of $287.5 million. The Company did not have any short-term notes payable to banks as of September 30, 2023.

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

On June 30, 2022, the Company entered into a 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provided an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company used the proceeds for general corporate purposes, which included using $150.0 million for the November 25, 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date of March 1, 2023. All indebtedness under the 364-Day Credit Agreement was repaid on May 18, 2023.

The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future.

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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 0.65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at September 30, 2023, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement. On May 3, 2022, the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modified the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ended June 30, 2022, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet. Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. At September 30, 2023, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement was 0.46. The constraints specified in the Credit Agreement would have permitted an additional $3.17 billion in short-term and/or long-term debt to be outstanding at September 30, 2023 before the Company’s debt to capitalization ratio exceeded 0.65.

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

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

On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $297.3 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 7.50%, 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 to repay all indebtedness under the $250.0 million unsecured committed delayed draw term loan under the 364-Day Credit Agreement.

None of the Company's long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period. The Current Portion of Long-Term Debt at September 30, 2022 consisted of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes, that each had maturity dates in March 2023. The Company utilized short-term borrowings and cash on hand to repay $150.0 million of these maturities in November 2022 and the remaining $399.0 million in March 2023. As of September 30, 2023, the future

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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: $111.9 million in 2024, $605.9 million in 2025, $565.4 million in 2026, $640.4 million in 2027, $327.9 million in 2028, and $535.7 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 4.69% at September 30, 2023 and 4.48% at September 30, 2022. Refer to “Interest Rate Risk” in this Item for a more detailed breakdown of the Company’s embedded cost of long-term debt.

Under the Company's existing indenture covenants at September 30, 2023, the Company would have been permitted to issue up to a maximum of approximately $3.43 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 the debt to capitalization ratio constraint under the Company's Credit Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

The Company’s 1974 indenture pursuant to which $50.0 million (or 2.1%) of the Company’s long-term debt (as of September 30, 2023) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement, or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

OTHER MATTERS

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

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

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Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project, which is the subject of an ongoing appeal at the U.S. Court of Appeals for the D.C. Circuit. 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, including the completion of ongoing litigation. As of September 30, 2023, approximately $55.9 million has been spent on the Northern Access project, including $24.3 million that has been spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet. The remaining $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at September 30, 2023.

The Company has a tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan). During 2023, the Company did not make any contributions to the Retirement Plan. Estimated contributions to the Retirement Plan in 2024 will be in the range of zero to $5.0 million. For further discussion of the Company’s Retirement Plan, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the Retirement Plan has been closed to new participants since 2003. In that regard, the average remaining service life of active participants in the Retirement Plan is approximately 6 years.

The Company provides health care and life insurance benefits (other post-retirement benefits) for a majority of its retired employees. The Company has established VEBA trusts and 401(h) accounts for its other post-retirement benefits. The Company has been making contributions to its VEBA trusts and/or 401(h) accounts over the last several years and does not anticipate making contributions to the VEBA trusts and/or 401(h) accounts in the near term. However, this will be subject to future review. During 2023, the Company did not make any contributions to its VEBA trusts. However, the Company made direct payments of $0.2 million to retirees not covered by the VEBA trusts and 401(h) accounts during 2023. The Company does not expect to make any contributions to its VEBA trusts in 2024. For further discussion of the Company’s other post-retirement benefits, including actuarial assumptions, refer to Item 8 at Note K — Retirement Plan and Other Post-Retirement Benefits. As noted in that footnote, the other post-retirement benefits provided by the Company have been closed to new participants since 2003. In that regard, the average remaining service life of active participants is approximately 4 years for those eligible for other post-retirement benefits.

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

MARKET RISK SENSITIVE INSTRUMENTS

Energy Commodity Price Risk

The Company uses various derivative financial instruments (derivatives), including price swap agreements and no cost collars, as part of the Company’s overall energy commodity price risk management strategy in its Exploration and Production segment. Under this strategy, the Company manages a portion of the market risk associated with fluctuations in the price of natural gas, thereby attempting to provide more stability to operating results. The Company has operating procedures in place that are administered by experienced management to monitor compliance with the Company’s risk management policies. The derivatives are not held for trading purposes. The fair value of these derivatives, as shown below, represents the amount that the Company would receive from, or pay to, the respective counterparties at September 30, 2023 to terminate the derivatives. However, the tables below and the fair value that is disclosed do not consider the physical side of the natural gas transactions that are related to the financial instruments.

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

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several final regulations, other rules that may impact the Company have yet to be finalized. Rules adopted by the CFTC and other regulators could adversely impact the Company. While many of those rules place specific conditions on the operations of swap dealers rather than directly on the Company, concern remains that swap dealers with whom the Company may transact will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs. Some of those rules also may apply directly to the Company and adversely impact its ability to trade swaps and over-the-counter derivatives, whether due to increased costs, limitations on trading capacity or for other reasons. Additionally, given the enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and anti-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 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 requires 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, 2023, the Company determined that nonperformance risk associated with its natural gas price swap agreements, natural gas no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

The following tables disclose natural gas price swap information by expected maturity dates for agreements in which the Company receives a fixed price in exchange for paying a variable price as quoted in various national natural gas publications or on the NYMEX. Notional amounts (quantities) are used to calculate the contractual payments to be exchanged under the contract. The weighted average variable prices represent the weighted average settlement prices by expected maturity date as of September 30, 2023. At September 30, 2023, the Company had not entered into any natural gas price swap agreements extending beyond 2028.

Natural Gas Price Swap Agreements


	Expected Maturity Dates
	2024		2025		2026		2027		2028		Total
Notional Quantities (Equivalent Bcf)	131.3		78.4		36.2		13.1		1.0		260.0
Weighted Average Fixed Rate (per Mcf)	$	3.43	$	3.59	$	4.10	$	4.37	$	4.40	$	3.62
Weighted Average Variable Rate (per Mcf)	$	3.29	$	3.88	$	4.16	$	4.12	$	3.95	$	3.63

At September 30, 2023, the Company would have paid its respective counterparties an aggregate of approximately $2.5 million to terminate the natural gas price swap agreements outstanding at that date.

At September 30, 2022, the Company had natural gas price swap agreements covering 207.3 Bcf at a weighted average fixed rate of $2.98 per Mcf.

No Cost Collars

The following table discloses the notional quantities, the weighted average ceiling price and the weighted average floor price for the no cost collars used by the Company to manage natural gas price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). At September 30, 2023, the Company had not entered into any natural gas no cost collars extending beyond 2027.

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	Expected Maturity Dates
	2024		2025		2026		2027		Total
Natural Gas
Notional Quantities (Equivalent Bcf)	63.5		42.8		41.5		3.5		151.3
Weighted Average Ceiling Price (per Mcf)	$	4.29	$	4.78	$	4.89	$	4.89	$	4.61
Weighted Average Floor Price (per Mcf)	$	3.42	$	3.59	$	3.62	$	3.62	$	3.53

At September 30, 2023, the Company would have received an aggregate of approximately $16.0 million to terminate the natural gas no cost collars outstanding at that date.

At September 30, 2022, the Company had no cost collars agreements covering 213.5 Bcf at a weighted average ceiling price of $4.24 per Mcf and a weighted average floor price of $3.40 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, 2023. At September 30, 2023, the Company had not entered into any foreign currency exchange contracts extending beyond 2030.


	Expected Maturity Dates
	2024		2025		2026		2027		2028		Thereafter		Total
Notional Quantities (Canadian Dollar in millions)	$	12.9	$	10.9	$	7.6	$	6.8	$	6.8	$	11.9	$	56.9
Weighted Average Fixed Rate ($Cdn/$US)	$	1.29	$	1.28	$	1.32	$	1.33	$	1.32	$	1.31	$	1.30
Weighted Average Variable Rate ($Cdn/$US)	$	1.32	$	1.32	$	1.34	$	1.34	$	1.33	$	1.33	$	1.33

At September 30, 2023, absent other positions with the same counterparties, the Company would have paid to its respective counterparties an aggregate of $1.3 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 $2.2 billion at September 30, 2023. 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:


	Principal Amounts by Expected Maturity Dates
	2024		2025		2026		2027		2028		Thereafter		Total
	(Dollars in millions)
Long-Term Fixed Rate Debt	$	—	$	500.0	$	500.0	$	600.0	$	300.0	$	500.0	$	2,400.0
Weighted Average Interest Rate Paid	—		5.4%		5.5%		4.7%		4.8%		3.0%		4.7%

RATE MATTERS

Utility Operation

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

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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 ("2017 Rate Order"). The 2017 Rate Order provided for a return on equity of 8.7% and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. On October 31, 2023, Distribution Corporation made a filing with the NYPSC seeking an increase of $88.8 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024 that includes the maximum suspension period permitted under the New York Public Service Law ("2023 Rate Filing"). The Company is also proposing, among other things, to continue its leak prone pipe replacement program and to implement a number of initiatives that will facilitate achievement of the emissions reduction goals of the Climate Leadership and Community Protection Act.

The 2017 Rate Order authorized the Company to recover approximately $15 million annually for pension and OPEB expenses from customers. Because the Company's future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July 2022, Distribution Corporation made a filing with the NYPSC to effectuate a temporary pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022. On September 16, 2022, the NYPSC issued an order approving the filing. With the implementation of this surcredit, Distribution Corporation ceased funding the Retirement Plan and its VEBA trusts in its New York jurisdiction. The 2023 Rate Filing proposes to keep the rate recovery of pension and OPEB costs at zero in the rate year and reflect the $15 million of savings in new base delivery rates.

On August 13, 2021, the NYPSC issued an order extending the date through which qualified pipeline replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (until March 31, 2023). On December 9, 2022, the Company filed a petition with the NYPSC to effectuate a system improvement tracker through which qualified pipeline replacement costs through September 30, 2024 would be tracked and recovered, and to recover certain deferred costs associated with the existing system modernization tracker, effective April 1, 2023. The NYPSC approved the petition by order dated March 17, 2023 contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to October 1, 2024. The 2023 Rate Filing proposes to stop accruing and collecting revenues under its current system modernization and system improvement trackers and shift those revenues into the Company’s new base delivery rates. In the absence of a multi-year rate plan settlement, the Company is requesting that it be allowed to reinstate a tracking mechanism similar to the existing system modernization tracker.

Pennsylvania Jurisdiction

Distribution Corporation’s delivery rates effective through July 31, 2023 in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007. On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $28.1 million. A settlement involving all active parties to the proceeding was reached and filed with the PaPUC on April 13, 2023. The settlement provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million. The PaPUC approved the settlement in full, without modification or correction, on June 15, 2023 and new rates went into effect on August 1, 2023.

Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC, Distribution Corporation reduced base rates by $7.7 million in order to stop collecting OPEB expenses from customers. It also began to refund to customers overcollected OPEB expenses in the amount of $50.0 million. All matters with respect to this tariff supplement were finalized on February 24, 2022 with the PaPUC's approval of an Administrative Law Judge's Recommended Decision. Concurrent with that decision, the Company discontinued regulatory accounting for OPEB expenses and recorded an $18.5 million adjustment during the quarter ended March 31,

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2022 to reduce its regulatory liability for previously deferred OPEB income amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company also increased customer refunds of overcollected OPEB expenses from $50.0 million to $54.0 million. All refunds specified in the tariff supplement are being funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company's Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.

Pipeline and Storage

Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023 proposing rate increases to be effective February 1, 2024. The proposed rates reflect an annual cost of service of $385.4 million, a rate base of $1.32 billion and a proposed cost of equity of 15.12%. If the proposed rate increases finally approved at the end of the proceeding exceed the rates that were in effect at July 31, 2023, but are less than rates put into effect subject to refund on February 1, 2024, Supply Corporation would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2023, such lower rates will become effective prospectively from the effective date provided by the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at July 31, 2023.

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

ENVIRONMENTAL MATTERS

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

The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.

Environmental Regulation

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in the United States. These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. For example, the federal Inflation Reduction Act of 2022 (IRA) legislation was signed into law on August 16, 2022. The IRA includes a methane charge that is expected to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, starting in calendar year 2024. This portion of the IRA is to be administered by the EPA and potential fees will begin with emissions reported for calendar year 2024. The EPA is the lead federal agency that regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented by the EPA impose stringent leak detection and repair requirements and address reporting and control of methane and volatile organic compound emissions. The Company must

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continue to comply with all applicable regulations. Additionally, a number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. 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. In May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to certain exemptions. 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. The NYDEC has until January 1, 2024 to issue further rules and regulations implementing the CLCPA. The NYDEC, in conjunction with the New York State Energy Research and Development Authority, is also in the early phases of developing a cap-and-invest program in the state, which is anticipated to be effective in 2025. The above-enumerated initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.

EFFECTS OF INFLATION

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

SAFE HARBOR FOR FORWARD-LOOKING STATEMENTS

The Company is including the following cautionary statement in this Annual Report on 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

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assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:

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

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

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

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

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

6.Changes in the price of natural gas;

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

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

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

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

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

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

13.Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability and costs, title disputes, weather conditions, water availability and disposal or recycling opportunities of used water, 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;

14.The Company's ability to complete strategic transactions;

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

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

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

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

19.Uncertainty of natural gas reserve estimates;

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

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

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

23.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;

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

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

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

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

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

INDUSTRY AND MARKET DATA DISCLOSURE

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


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 (PCAOB ID 238)			63
Consolidated Statement of Income and Earnings Reinvested in the Business for the years ended September 30, 2023, 2022 and 2021			66
Consolidated Statement of Comprehensive Income for the years ended September 30, 2023, 2022 and 2021			67
Consolidated Balance Sheet at September 30, 2023 and 2022			68
Consolidated Statement of Cash Flows for the years ended September 30, 2023, 2022 and 2021			69
Notes to Consolidated Financial Statements			70

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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended September 30, 2023 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, 2023, 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 Natural Gas Reserves on Natural Gas Properties, Net

As described in Note A to the consolidated financial statements, the Exploration and Production segment includes capitalized costs relating to natural gas producing activities, net of depreciation, depletion, and amortization (DD&A) of $2.4 billion as of September 30, 2023. 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. 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. 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. There were no ceiling test impairment charges for the year ended September 30, 2023. As of September 30, 2023, the ceiling exceeded the book value of the natural gas properties by approximately $794.7 million. Estimates of the Company’s proved natural 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 natural gas reserves and of future net cash flows depend upon a number of variable factors and assumptions, including quantities of natural gas that are ultimately recovered, the timing of the recovery of natural 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 natural gas reserves on natural 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 natural gas reserves, which in turn led to a high degree of auditor judgment, subjectivity and effort in performing procedures and evaluating evidence related to data, methods, and assumptions used by management and its specialists in developing the estimates of proved natural gas reserves and the related assumption of quantities of proved natural 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 natural gas reserves and the related assumption of quantities of proved natural gas that are ultimately recovered which is utilized in the DD&A expense and ceiling test calculations. These procedures also included, among others, evaluating the reasonableness of the significant assumption used by management related to the quantities of proved natural gas that are ultimately recovered which included evaluating information on additional development activity, production history, if the assumption used was reasonable considering the past performance of the Company, and whether it was 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 natural gas reserves and the related assumption of quantities of proved natural gas that are ultimately recovered. As a basis for using this work, the specialists’ qualifications 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 completeness and accuracy of data used by the specialists and an evaluation of the specialists’ findings.

/s/ PRICEWATERHOUSECOOPERS LLP

Buffalo, New York

November 17, 2023

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
	2023		2022		2021
	(Thousands of dollars, except per common share amounts)
INCOME
Operating Revenues:
Utility and Energy Marketing Revenues	$	941,779	$	897,916	$	667,549
Exploration and Production and Other Revenues	958,455		1,010,629		837,597
Pipeline and Storage and Gathering Revenues	273,537		277,501		237,513
	2,173,771		2,186,046		1,742,659
Operating Expenses:
Purchased Gas	437,595		392,093		171,827
Operation and Maintenance:
Utility and Energy Marketing	205,239		193,058		179,547
Exploration and Production and Other	124,270		191,572		173,041
Pipeline and Storage and Gathering	149,247		136,571		123,218
Property, Franchise and Other Taxes	92,700		101,182		94,713
Depreciation, Depletion and Amortization	409,573		369,790		335,303
Impairment of Oil and Gas Producing Properties	—		—		76,152
	1,418,624		1,384,266		1,153,801
Gain on Sale of Assets	—		12,736		51,066
Operating Income	755,147		814,516		639,924
Other Income (Expense):

Other Income (Deductions)	18,138		(1,509)		(15,238)
Interest Expense on Long-Term Debt	(111,948)		(120,507)		(141,457)
Other Interest Expense	(19,938)		(9,850)		(4,900)
Income Before Income Taxes	641,399		682,650		478,329
Income Tax Expense	164,533		116,629		114,682
Net Income Available for Common Stock	476,866		566,021		363,647
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Year	1,587,085		1,191,175		991,630
	2,063,951		1,757,196		1,355,277
Dividends on Common Stock	(178,095)		(170,111)		(164,102)




Balance at End of Year	$	1,885,856	$	1,587,085	$	1,191,175
Earnings Per Common Share:
Basic:
Net Income Available for Common Stock	$	5.20	$	6.19	$	3.99
Diluted:
Net Income Available for Common Stock	$	5.17	$	6.15	$	3.97
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	91,748,890		91,410,625		91,130,941
Used in Diluted Calculation	92,285,918		92,107,066		91,684,583

See Notes to Consolidated Financial Statements

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NATIONAL FUEL GAS COMPANY

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME


	Year Ended September 30
	2023		2022		2021
	(Thousands of dollars)
Net Income Available for Common Stock	$	476,866	$	566,021	$	363,647
Other Comprehensive Income (Loss), Before Tax:
Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	(9,660)		9,561		17,862
Reclassification Adjustment for Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans	1,674		11,054		16,229

Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	708,206		(1,050,831)		(665,371)

Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	88,656		882,581		83,711

Other Post-Retirement Adjustment for Regulatory Proceeding	—		(7,351)		—

Other Comprehensive Income (Loss), Before Tax	788,876		(154,986)		(547,569)
Income Tax Expense (Benefit) Related to the Increase (Decrease) in the Funded Status of the Pension and Other Post-Retirement Benefit Plans	(2,284)		2,169		4,072
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	411		2,574		3,762

Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	214,270		(287,608)		(179,028)

Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	5,806		241,559		22,465

Income Tax Expense (Benefit) Related to Other Post-Retirement Adjustment for Regulatory Proceeding	—		(1,544)		—


Income Taxes — Net	218,203		(42,850)		(148,729)
Other Comprehensive Income (Loss)	570,673		(112,136)		(398,840)
Comprehensive Income (Loss)	$	1,047,539	$	453,885	$	(35,193)

See Notes to Consolidated Financial Statements

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NATIONAL FUEL GAS COMPANY

CONSOLIDATED BALANCE SHEETS


	At September 30
	2023		2022
	(Thousands of dollars)
ASSETS
Property, Plant and Equipment	$	13,635,303	$	12,551,909
Less — Accumulated Depreciation, Depletion and Amortization	6,335,441		5,985,432
	7,299,862		6,566,477

Current Assets
Cash and Temporary Cash Investments	55,447		46,048
Hedging Collateral Deposits	—		91,670
Receivables — Net of Allowance for Uncollectible Accounts of $36,295 and $40,228, Respectively	160,601		361,626
Unbilled Revenue	16,622		30,075
Gas Stored Underground	32,509		32,364
Materials and Supplies - at average cost	48,989		40,637
Unrecovered Purchased Gas Costs	—		99,342
Other Current Assets	100,260		59,369
	414,428		761,131
Other Assets
Recoverable Future Taxes	69,045		106,247
Unamortized Debt Expense	7,240		8,884
Other Regulatory Assets	72,138		67,101
Deferred Charges	82,416		77,472
Other Investments	73,976		95,025
Goodwill	5,476		5,476
Prepaid Pension and Post-Retirement Benefit Costs	200,301		196,597
Fair Value of Derivative Financial Instruments	50,487		9,175
Other	4,891		2,677
	565,970		568,654
Total Assets	$	8,280,260	$	7,896,262
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value; Authorized - 200,000,000 Shares; Issued and Outstanding - 91,819,405 Shares and 91,478,064 Shares, Respectively	$	91,819	$	91,478
Paid In Capital	1,040,761		1,027,066
Earnings Reinvested in the Business	1,885,856		1,587,085
Accumulated Other Comprehensive Loss	(55,060)		(625,733)
Total Comprehensive Shareholders’ Equity	2,963,376		2,079,896
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,384,485		2,083,409
Total Capitalization	5,347,861		4,163,305
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	287,500		60,000
Current Portion of Long-Term Debt	—		549,000
Accounts Payable	152,193		178,945
Amounts Payable to Customers	59,019		419
Dividends Payable	45,451		43,452
Interest Payable on Long-Term Debt	20,399		17,376
Customer Advances	21,003		26,108
Customer Security Deposits	28,764		24,283
Other Accruals and Current Liabilities	160,974		257,327
Fair Value of Derivative Financial Instruments	31,009		785,659
	806,312		1,942,569
Other Liabilities
Deferred Income Taxes	1,124,170		698,229
Taxes Refundable to Customers	268,562		362,098
Cost of Removal Regulatory Liability	277,694		259,947
Other Regulatory Liabilities	165,441		188,803
Other Post-Retirement Liabilities	2,915		3,065
Asset Retirement Obligations	165,492		161,545
Other Liabilities	121,813		116,701
	2,126,087		1,790,388
Commitments and Contingencies (Note L)	—		—
Total Capitalization and Liabilities	$	8,280,260	$	7,896,262

See Notes to Consolidated Financial Statements

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NATIONAL FUEL GAS COMPANY

CONSOLIDATED STATEMENTS OF CASH FLOWS


	Year Ended September 30
	2023		2022		2021
	(Thousands of dollars)
Operating Activities
Net Income Available for Common Stock	$	476,866	$	566,021	$	363,647
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Gain on Sale of Assets	—		(12,736)		(51,066)
Impairment of Oil and Gas Producing Properties	—		—		76,152
Depreciation, Depletion and Amortization	409,573		369,790		335,303
Deferred Income Taxes	151,403		104,415		105,993
Premium Paid on Early Redemption of Debt	—		—		15,715


Stock-Based Compensation	20,630		19,506		17,065
Reduction of Other Post-Retirement Regulatory Liability	—		(18,533)		—
Other	19,647		31,983		10,896
Change in:

Receivables and Unbilled Revenue	213,579		(168,769)		(61,413)
Gas Stored Underground and Materials, Supplies and Emission Allowances	(8,406)		3,109		(2,014)
Unrecovered Purchased Gas Costs	99,342		(66,214)		(33,128)
Other Current Assets	(41,077)		291		(11,972)
Accounts Payable	(37,095)		11,907		31,352
Amounts Payable to Customers	58,600		398		(10,767)
Customer Advances	(5,105)		8,885		1,904
Customer Security Deposits	4,481		4,991		2,093
Other Accruals and Current Liabilities	(67,664)		34,260		34,314
Other Assets	(26,564)		(58,924)		1,250
Other Liabilities	(31,135)		(17,859)		(33,771)
Net Cash Provided by Operating Activities	1,237,075		812,521		791,553
Investing Activities
Capital Expenditures	(1,009,868)		(811,826)		(751,734)
Net Proceeds from Sale of Oil and Gas Producing Properties	—		254,439		—
Net Proceeds from Sale of Timber Properties	—		—		104,582
Sale of Fixed Income Mutual Fund Shares in Grantor Trust	10,000		30,000		—
Acquisition of Upstream Assets	(124,758)		—		—
Other	12,279		8,683		13,935
Net Cash Used in Investing Activities	(1,112,347)		(518,704)		(633,217)
Financing Activities
Proceeds from Issuance of Short-Term Note Payable to Bank	250,000		—		—
Repayment of Short-Term Note Payable to Bank	(250,000)		—		—
Net Change in Other Short-Term Notes Payable to Banks and Commercial Paper	227,500		(98,500)		128,500

Net Proceeds from Issuance of Long-Term Debt	297,306		—		495,267
Reduction of Long-Term Debt	(549,000)		—		(515,715)
Net Repurchases of Common Stock	(6,709)		(9,590)		(3,702)
Dividends Paid on Common Stock	(176,096)		(168,147)		(163,089)
Net Cash Used in Financing Activities	(206,999)		(276,237)		(58,739)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	(82,271)		17,580		99,597
Cash, Cash Equivalents and Restricted Cash At Beginning of Year	137,718		120,138		20,541
Cash, Cash Equivalents and Restricted Cash At End of Year	$	55,447	$	137,718	$	120,138
Supplemental Disclosure of Cash Flow Information
Cash Paid For:
Interest	$	124,441	$	124,312	$	135,136
Income Taxes	$	38,098	$	16,680	$	6,374
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$	109,208	$	120,262	$	102,700
Non-Cash Contingent Consideration for Asset Sale	$	—	$	12,571	$	—

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, the majority of which is in the Utility segment, is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic and regulatory environment. Account balances have historically been written off against the allowance approximately twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered. During 2022 and 2021, final billings were suppressed in the Utility segment as a result of state shut-off moratoriums arising from the COVID-19 pandemic. Those moratoriums were lifted in 2022 which allowed for the resumption of final billings during 2022, thereby resulting in higher amounts being written off in 2023.

Activity in the allowance for uncollectible accounts are as follows:


	Year Ended September 30
	2023		2022		2021
	(Thousands)
Balance at Beginning of Year	$	40,228	$	31,639	$	22,810
Additions Charged to Costs and Expenses	14,482		13,209		14,940
Add: Discounts on Purchased Receivables	1,380		1,314		1,168
Deduct: Net Accounts Receivable Written-Off	19,795		5,934		7,279
Balance at End of Year	$	36,295	$	40,228	$	31,639

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.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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

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.

On June 15, 2023, the PaPUC approved the Utility segment’s Pennsylvania rate jurisdiction’s use of a WNC as a five-year pilot program. The program is effective October 2023 and covers the eight-month period from October through May. Prior to October 2023, the Utility segment’s Pennsylvania rate jurisdiction did not have a WNC, causing weather variations to 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

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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, net of accumulated depreciation, depletion and amortization, were $2.4 billion and $1.9 billion at September 30, 2023 and 2022, 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. At September 30, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $794.7 million. In adjusting estimated future net cash flows for hedging under the ceiling test at September 30, 2023, 2022 and 2021, estimated future net cash flows were increased by $38.8 million, decreased by $1.0 billion and decreased by $76.1 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. There were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at September 30, 2023.

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 $235.7 million, $202.4 million and $177.1 million for the years ended September 30, 2023, 2022 and 2021, 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 useful lives of property in service. The following is a summary of depreciable plant by segment:

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	As of September 30
	2023		2022
	(Thousands)
Exploration and Production	$	6,741,095	$	6,088,476
Pipeline and Storage	2,803,690		2,747,948
Gathering	1,032,969		971,665
Utility	2,507,465		2,411,707

All Other and Corporate	15,787		13,712
	$	13,101,006	$	12,233,508

Average depreciation, depletion and amortization rates are as follows:


	Year Ended September 30
	2023			2022			2021
Exploration and Production, per Mcfe(1)	$	0.65		$	0.59		$	0.56
Pipeline and Storage	2.6		%	2.7		%	2.6		%
Gathering	3.6		%	3.6		%	3.6		%
Utility	2.7		%	2.7		%	2.7		%

All Other and Corporate	2.9		%	1.4		%	3.4		%

(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 $0.63, $0.57 and $0.54 per Mcfe of production in 2023, 2022 and 2021, respectively.

Goodwill

The Company has recognized goodwill of $5.5 million as of September 30, 2023 and 2022 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, 2023, 2022 and 2021, 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 natural gas 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 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 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 Loss

The components of Accumulated Other Comprehensive Loss and changes for the years ended September 30, 2023 and 2022, 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, 2023
Balance at October 1, 2022	$	(572,163)	$	(53,570)	$	(625,733)
Other Comprehensive Gains and Losses Before Reclassifications	493,936		(7,376)		486,560
Amounts Reclassified From Other Comprehensive Loss	82,850		1,263		84,113


Balance at September 30, 2023	$	4,623	$	(59,683)	$	(55,060)
Year Ended September 30, 2022
Balance at October 1, 2021	$	(449,962)	$	(63,635)	$	(513,597)
Other Comprehensive Gains and Losses Before Reclassifications	(763,223)		7,392		(755,831)
Amounts Reclassified From Other Comprehensive Loss	641,022		8,480		649,502
Other Post-Retirement Adjustment for Regulatory Proceeding	—		(5,807)		(5,807)


Balance at September 30, 2022	$	(572,163)	$	(53,570)	$	(625,733)

The amounts included in accumulated other comprehensive 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 $0.4 million at both September 30, 2023 and 2022. The total amount for accumulated losses was $59.3 million and $53.2 million at September 30, 2023 and 2022, respectively.

During the quarter ended March 31, 2022, the PaPUC concluded a regulatory proceeding that addressed the recovery of OPEB expenses in Distribution Corporation's Pennsylvania service territory. As a result of that proceeding, Distribution Corporation discontinued regulatory accounting for OPEB expenses in Pennsylvania and a regulatory deferral of $7.4 million ($5.8 million after tax) related to the funded status of Distribution Corporation’s other post-retirement benefit plans in Pennsylvania was reclassified to accumulated other comprehensive loss.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Reclassifications Out of Accumulated Other Comprehensive Loss

The details about the reclassification adjustments out of accumulated other comprehensive loss for the years ended September 30, 2023 and 2022 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):


Details About Accumulated Other Comprehensive Loss Components	Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss for the Year Ended September 30,				Affected Line Item in the Statement Where Net Income is Presented
	2023		2022
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts	$	(88,015)	$	(882,594)	Operating Revenues

Foreign Currency Contracts	(641)		13		Operating Revenues
Amortization of Prior Year Funded Status of the Pension and Other Post-Retirement Benefit Plans:
Prior Service Cost	(82)		(103)		(1)
Net Actuarial Loss	(1,592)		(10,951)		(1)
	(90,330)		(893,635)		Total Before Income Tax
	6,217		244,133		Income Tax Expense
	$	(84,113)	$	(649,502)	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 $32.4 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 2023, including transportation costs, the current cost of replacing this inventory of gas stored underground exceeded the amount stated on a LIFO basis by approximately $3.7 million at September 30, 2023.

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 treatment. At September 30, 2023, the remaining weighted average amortization period for such costs was approximately 4 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.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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
	2023		2022		2021		2020
Cash and Temporary Cash Investments	$	55,447	$	46,048	$	31,528	$	20,541
Hedging Collateral Deposits	—		91,670		88,610		—
Cash, Cash Equivalents, and Restricted Cash	$	55,447	$	137,718	$	120,138	$	20,541

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 derivative financial instruments in an unrealized loss position. 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
	2023		2022
	(Thousands)
Prepayments	$	18,966	$	17,757
Prepaid Property and Other Taxes	14,186		14,321
Federal Income Taxes Receivable	14,602		—
State Income Taxes Receivable	16,133		5,933

Regulatory Assets	36,373		21,358
	$	100,260	$	59,369

Other Accruals and Current Liabilities

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


	Year Ended September 30
	2023		2022
	(Thousands)
Accrued Capital Expenditures	$	43,323	$	64,720
Regulatory Liabilities	38,105		31,293



Liability for Royalty and Working Interests	17,679		86,206
Non-Qualified Benefit Plan Liability	13,052		17,474
Other	48,815		57,634
	$	160,974	$	257,327

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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, 2023 and 2022, customers in the balanced billing programs had advanced excess funds of $21.0 million and $26.1 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, 2023 and 2022, the Company had received customer security deposits amounting to $28.8 million and $24.3 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 during fiscal 2023, 2022 and/or 2021 were SARs, restricted stock units and performance shares. For the years ended September 30, 2023 and September 30, 2022, 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 3,888 securities, 2,858 securities and 320,222 securities excluded as being antidilutive for the years ended September 30, 2023, 2022 and 2021, respectively.

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 under all plans have exercise prices equal to the average market price of Company common stock on the date of grant, and generally no SAR is exercisable less than one year or more than ten years after the date of each grant. The Company chose the Black-Scholes-Merton closed form model to calculate the compensation expense associated with SARs. For all Company stock awards, forfeitures are recognized as they occur.

Restricted stock units 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 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

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 and greenhouse gas emissions reductions 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.

Note B — Asset Acquisitions and Divestitures

On June 1, 2023, the Company completed its acquisition of certain upstream assets located primarily in Tioga County, Pennsylvania from SWN Production Company, LLC (“SWN”) for total consideration of $124.8 million. The purchase price, which reflects an effective date of January 1, 2023, was reduced for production revenues less expenses that were retained by SWN from the effective date to the closing date. As part of the transaction, the Company acquired approximately 34,000 net acres in an area that is contiguous with existing Company-owned upstream assets. This transaction was accounted for as an asset acquisition, and, as such, the purchase price was allocated to property, plant and equipment. The following is a summary of the asset acquisition in thousands:


Purchase Price	$	124,178
Transaction Costs	580
Total Consideration	$	124,758

On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which were in the Exploration and Production segment, to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances. The Company also eliminated the asset retirement obligation associated with Seneca’s California oil and gas assets. This obligation amounted to $50.1 million and was accounted for as a reduction of capitalized costs under the full cost method of accounting.

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. 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

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 completed the financing of a July 31, 2020 acquisition of certain upstream assets and midstream gathering assets in Pennsylvania.

Note C — Revenue from Contracts with Customers

The following tables provide a disaggregation of the Company's revenues for the years ended September 30, 2023 and 2022, presented by type of service from each reportable segment.


	Year Ended September 30, 2023
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	$	1,036,499	$	—	$	—	$	—	$	1,036,499	$	—	$	—	$	1,036,499
Production of Crude Oil	2,261		—		—		—		2,261		—		—		2,261
Natural Gas Processing	1,203		—		—		—		1,203		—		—		1,203
Natural Gas Gathering Service	—		—		230,317		—		230,317		—		(216,426)		13,891
Natural Gas Transportation Service	—		291,225		—		98,304		389,529		—		(82,889)		306,640
Natural Gas Storage Service	—		84,962		—		—		84,962		—		(36,283)		48,679
Natural Gas Residential Sales	—		—		—		727,728		727,728		—		—		727,728
Natural Gas Commercial Sales	—		—		—		103,270		103,270		—		—		103,270
Natural Gas Industrial Sales	—		—		—		5,658		5,658		—		(7)		5,651
Other	6,507		3,004		—		508		10,019		—		(947)		9,072
Total Revenues from Contracts with Customers	1,046,470		379,191		230,317		935,468		2,591,446		—		(336,552)		2,254,894
Alternative Revenue Programs	—		—		—		6,892		6,892		—		—		6,892
Derivative Financial Instruments	(88,015)		—		—		—		(88,015)		—		—		(88,015)
Total Revenues	$	958,455	$	379,191	$	230,317	$	942,360	$	2,510,323	$	—	$	(336,552)	$	2,173,771


	Year Ended September 30, 2022
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	$	1,730,723	$	—	$	—	$	—	$	1,730,723	$	—	$	—	$	1,730,723
Production of Crude Oil	150,957		—		—		—		150,957		—		—		150,957
Natural Gas Processing	3,511		—		—		—		3,511		—		—		3,511
Natural Gas Gathering Service	—		—		214,843		—		214,843		—		(202,757)		12,086
Natural Gas Transportation Service	—		289,967		—		106,495		396,462		—		(74,749)		321,713
Natural Gas Storage Service	—		84,565		—		—		84,565		—		(36,382)		48,183
Natural Gas Residential Sales	—		—		—		688,271		688,271		—		—		688,271
Natural Gas Commercial Sales	—		—		—		95,114		95,114		—		—		95,114
Natural Gas Industrial Sales	—		—		—		4,902		4,902		—		—		4,902

Other	7,867		2,512		—		(3,918)		6,461		6		(644)		5,823
Total Revenues from Contracts with Customers	1,893,058		377,044		214,843		890,864		3,375,809		6		(314,532)		3,061,283
Alternative Revenue Programs	—		—		—		7,357		7,357		—		—		7,357
Derivative Financial Instruments	(882,594)		—		—		—		(882,594)		—		—		(882,594)
Total Revenues	$	1,010,464	$	377,044	$	214,843	$	898,221	$	2,500,572	$	6	$	(314,532)	$	2,186,046

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The Company records revenue related to its derivative financial instruments in the Exploration and Production segment. 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. Prior to the completion of the sale of the Company’s California assets on June 30, 2022, natural gas production occurred primarily in the Appalachian region of the United States and crude oil production occurred primarily in the West Coast region of the United States. Subsequent to June 30, 2022, substantially all Exploration and Production segment production consists of natural gas production from the Appalachian 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 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 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

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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: $210.7 million for fiscal 2024; $184.0 million for fiscal 2025; $148.3 million for fiscal 2026; $123.3 million for fiscal 2027; $107.5 million for fiscal 2028; and $581.0 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, and to a lesser extent, other producers' 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, respectively. 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 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 authoritative guidance regarding revenue recognition. The NYPSC has authorized alternative revenue programs that are designed to mitigate the impact that weather and

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conservation have on margin. The NYPSC and PaPUC have 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.

Note D — Leases

The Company follows 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 has elected to apply the following practical expedients provided in the authoritative guidance:

1.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);

2.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).

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, 2023 or September 30, 2022. Aside from a sublease of office space at the Company’s corporate headquarters, which terminated April 30, 2022, 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 one month to sixteen 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. 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 contracts with amended terms and conditions, including a renegotiated day rate fee.

Drilling rig lease costs are capitalized as part of natural gas properties on the Consolidated Balance Sheet when incurred.

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Compressor Equipment

The Company enters into contracts for compressor services with third parties primarily to support its gathering system in Pennsylvania. The primary non-cancelable terms of the Company's compressor equipment leases range from 9 months to 5 years. Most compressor equipment leases include one or more options to renew or to continue past the primary term on a month-to-month basis, generally at the Company's sole discretion. Renewal options are included in the lease term if they are reasonably certain to be exercised.

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 third party shippers 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.

Gas Leases

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Amounts Recognized in the Financial Statements

Operating lease costs, excluding those relating to drilling rig leases that are capitalized as part of oil and natural gas properties under the full cost method of accounting as well as certain equipment leases related to construction projects, 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
	2023		2022
Operating Lease Expense	$	7,484	$	4,909
Variable Lease Expense(1)	507		462
Short-Term Lease Expense(2)	1,694		461
Sublease Income	—		(166)
Total Lease Expense	$	9,685	$	5,666

Lease Costs Recorded to Property, Plant and Equipment(3)	$	24,018	$	19,839

(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.

(3)Lease costs relating to drilling rig leases that are capitalized as part of oil and natural gas properties under full cost pool accounting as well as certain equipment leases used on construction projects.

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 6.1 years and 6.0 years as of September 30, 2023 and 2022, respectively. The weighted average discount rate was 5.48% and 3.92% as of September 30, 2023 and 2022, 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
	2023		2022
Assets:
Deferred Charges	$	39,664	$	37,120

Liabilities:
Other Accruals and Current Liabilities	$	9,969	$	14,239
Other Liabilities	$	29,510	$	22,881

Cash paid for lease liabilities, reported in cash provided by operating activities on the Company’s Consolidated Statement of Cash Flows, was $9.7 million and $5.7 million for the years ended September 30, 2023 and 2022, respectively. The Company did not record any right-of-use assets in exchange for new lease liabilities during the years ended September 30, 2023 or 2022.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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, 2023 (in thousands):


	At September 30, 2023
2024	$	10,187
2025	8,791
2026	6,557
2027	5,809
2028	5,195
Thereafter	9,971
Total Lease Payments	46,510
Less: Interest	(7,031)
Total Lease Liability	$	39,479

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 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 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. Asset retirement obligation costs related to storage tanks have been recorded in the Utility, Pipeline and Storage, and Gathering 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

As discussed in Note B — Asset Acquisitions and Divestitures, on June 30, 2022, the Company completed the sale of Seneca’s California oil and gas assets to Sentinel Peak Resources California LLC. With the divestiture of these assets, the Company reduced its Asset Retirement Obligation at June 30, 2022 by $50.1 million. This reduction is reflected in Liabilities Settled in the table below.

The following is a reconciliation of the change in the Company’s asset retirement obligations:


	Year Ended September 30
	2023		2022		2021
	(Thousands)
Balance at Beginning of Year	$	161,545	$	209,639	$	192,228
Liabilities Incurred	3,313		2,401		7,035
Revisions of Estimates	6,728		10,700		14,509
Liabilities Settled	(14,448)		(71,171)		(14,270)
Accretion Expense	8,354		9,976		10,137
Balance at End of Year	$	165,492	$	161,545	$	209,639

Note F — Regulatory Matters

Regulatory Assets and Liabilities

The Company has recorded the following regulatory assets and liabilities:


	At September 30
	2023		2022
	(Thousands)
Regulatory Assets(1):
Pension Costs(2) (Note K)	$	20,459	$	11,677
Post-Retirement Benefit Costs(2) (Note K)	2,536		6,814
Recoverable Future Taxes (Note G)	69,045		106,247
Environmental Site Remediation Costs(2) (Note L)	—		3,646
Asset Retirement Obligations(2) (Note E)	19,384		18,517
Unamortized Debt Expense (Note A)	7,240		8,884
Other(3)	66,132		47,805
Total Regulatory Assets	184,796		203,590
Less: Amounts Included in Other Current Assets	(36,373)		(21,358)
Total Long-Term Regulatory Assets	$	148,423	$	182,232

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	At September 30
	2023		2022
	(Thousands)
Regulatory Liabilities:
Cost of Removal Regulatory Liability	$	277,694	$	259,947
Taxes Refundable to Customers (Note G)	268,562		362,098
Post-Retirement Benefit Costs(5) (Note K)	159,760		167,305
Pension Costs(4) (Note K)	—		8,242
Amounts Payable to Customers (See Regulatory Mechanisms in Note A)	59,019		419
Environmental Site Remediation Costs(4) (Note L)	619		—
Other(6)	43,167		44,549
Total Regulatory Liabilities	808,821		842,560
Less: Amounts included in Current and Accrued Liabilities	(97,124)		(31,712)
Total Long-Term Regulatory Liabilities	$	711,697	$	810,848

(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)$36,373 and $21,358 are included in Other Current Assets on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively, since such amounts are expected to be recovered from ratepayers in the next 12 months. $29,759 and $26,447 are included in Other Regulatory Assets on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively.

(4)Included in Other Regulatory Liabilities on the Consolidated Balance Sheets.

(5)$5,800 is included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at both September 30, 2023 and 2022, since such amounts are expected to be passed back to ratepayers in the next 12 months. $153,960 and $161,505 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively.

(6)$32,305 and $25,493 are included in Other Accruals and Current Liabilities on the Consolidated Balance Sheets at September 30, 2023 and 2022, respectively, since such amounts are expected to be passed back to ratepayers in the next 12 months. $10,862 and $19,056 are included in Other Regulatory Liabilities on the Consolidated Balance Sheets at September 30, 2023 and 2022, 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

New York Jurisdiction

The 2017 Rate Order authorized the Company to recover approximately $15 million annually for pension and OPEB expenses from customers. Because the Company’s future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July 2022, Distribution Corporation made a filing with the NYPSC to effectuate a temporary pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022. On September 16, 2022, the NYPSC issued an order approving the filing. With the implementation of this surcredit, Distribution Corporation ceased funding the Retirement Plan and its VEBA trusts in its New York jurisdiction. The 2023 Rate Filing proposes to keep the rate recovery of pension and OPEB costs at zero in the rate year and reflect the $15 million of savings in new base delivery rates.

Pennsylvania Jurisdiction

Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC, Distribution Corporation reduced base rates by $7.7 million in order to stop collecting OPEB expenses from customers. It also began to refund to customers overcollected OPEB expenses in the amount of $50.0 million. All matters with respect to this tariff supplement were finalized on February 24, 2022 with the PaPUC’s approval of an Administrative Law Judge’s Recommended Decision. Concurrent with that decision, the Company discontinued regulatory

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

accounting for OPEB expenses and recorded an $18.5 million adjustment during the quarter ended March 31, 2022 to reduce its regulatory liability for previously deferred OPEB income amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company also increased customer refunds of overcollected OPEB expenses from $50.0 million to $54.0 million. All refunds specified in the tariff supplement are being funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company’s Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.

FERC Jurisdiction

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
	2023		2022		2021
	(Thousands)
Current Income Taxes —
Federal	$	11,744	$	—	$	(10)
State	1,386		12,214		8,699
Deferred Income Taxes —
Federal	106,801		137,025		90,970
State	44,602		(32,610)		15,023
Total Income Taxes	$	164,533	$	116,629	$	114,682

On July 8, 2022, House Bill 1342 was signed into law in Pennsylvania. The law reduces the corporate income tax rate to 8.99% for fiscal 2024. Starting with fiscal 2025, the rate is reduced by 0.5% annually until it reaches 4.99% for fiscal 2032. Under GAAP, the tax effects of a change in tax law must be recognized in the period in which the law is enacted. GAAP also requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. During fiscal 2022, the Company's deferred income taxes were initially re-measured based upon the new tax rates. For the Company's non-rate regulated activities, the change in deferred income taxes was $28.4 million as of the enactment date and was recorded as a reduction to income tax expense. For the Company's rate regulated activities, the reduction in deferred income taxes of $37.2 million was recorded as a decrease to Recoverable Future Taxes of $19.8 million and an increase to Taxes Refundable to Customers of $17.4 million

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

during the quarter ended September 30, 2022. As the rate reduction occurs through fiscal 2032, an annual re-measurement will be made. This amount is reflected in State Income Taxes.

On August 16, 2022, the "Inflation Reduction Act" (IRA) was signed into law. The IRA, among other things, includes provisions to expand energy incentives and impose a corporate minimum tax. The provisions of the IRA did not have a material impact on the accompanying financial statements, although some of the provisions may be applicable in future years.

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
	2023		2022		2021
	(Thousands)
U.S. Income Before Income Taxes	$	641,399	$	682,650	$	478,329
Income Tax Expense, Computed at U.S. Federal Statutory Rate of 21%	$	134,694	$	143,357	$	100,449
State Valuation Allowance (1)	—		(24,850)		(5,560)
State Income Taxes (2)	36,331		8,736		24,300

Amortization of Excess Deferred Federal Income Taxes	(6,053)		(5,184)		(5,215)
Plant Flow Through Items	(2,856)		(814)		(1,503)
Stock Compensation	957		820		2,239
Federal Tax Credits	(6)		(5,701)		(310)

Miscellaneous	1,466		265		282
Total Income Taxes	$	164,533	$	116,629	$	114,682

(1)During fiscal 2022, the valuation allowance recorded against certain state deferred tax assets was removed. See discussion below.

(2)The state income tax expense shown above includes adjustments to the estimated state effective tax rates utilized in the calculation of deferred income taxes, including the Pennsylvania rate change discussed above.

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


	At September 30
	2023		2022
	(Thousands)
Deferred Tax Liabilities:
Unrealized Hedging Gains	$	3,385	$	—
Property, Plant and Equipment	1,178,893		954,757
Pension and Other Post-Retirement Benefit Costs	44,358		30,132
Other	21,470		48,893
Total Deferred Tax Liabilities	1,248,106		1,033,782
Deferred Tax Assets:
Unrealized Hedging Losses	—		(215,187)
Tax Loss and Credit Carryforwards	(33,744)		(50,686)
Pension and Other Post-Retirement Benefit Costs	(41,843)		(37,250)
Other	(48,349)		(32,430)


Total Deferred Tax Assets	(123,936)		(335,553)
Total Net Deferred Income Taxes	$	1,124,170	$	698,229

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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


	Year Ended September 30
	2023		2022		2021
	(Thousands)
Balance at Beginning of Year	$	—	$	57,645	$	63,205
Additions	—		—		—
Deductions	—		57,645		5,560
Balance at End of Year	$	—	$	—	$	57,645

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, at each reporting date, 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. On June 30, 2022, the Company completed the sale of Seneca's California oil and gas assets to Sentinel Peak Resources California, LLC. As a result of the sale of the California oil and gas assets, the remaining deferred tax assets and valuation allowance of approximately $27.2 million related to the California net operating loss and tax credit carryforwards were written off, as the Company determined that there was a remote possibility for use as the Company no longer has California operations. During the quarter ended September 30, 2022, the valuation allowance was adjusted because of the Pennsylvania corporate income tax rate change remeasurement described above and for current activity, for a cumulative adjustment of $5.5 million. In addition, the Company determined there was sufficient positive evidence, despite a prior history of subsidiary tax losses, to conclude that it was more likely than not that the remaining state deferred tax assets would be realized. The conclusion was primarily related to the use of net operating losses in Pennsylvania in 2022 due to sustained strong operating results as well as the expectation for future forecasted earnings in Pennsylvania. The sale of California assets also resulted in higher apportionment of income to Pennsylvania on a prospective basis, which further supported realization of existing Pennsylvania net operating loss deferred tax assets. Accordingly, as of September 30, 2022, the Company reversed the remaining valuation allowance and recognized an income tax benefit of approximately $24.9 million.

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 $268.6 million and $362.1 million at September 30, 2023 and 2022, 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 $69.0 million and $106.2 million at September 30, 2023 and 2022, respectively. The primary change in these was due to Distribution Corporation's rate settlement in Pennsylvania. For further discussion of Distribution Corporation rate matters, refer to Note F — Regulatory Matters.

The Company is in the Compliance Maintenance Phase of the IRS Compliance Assurance Process (“CAP”) for fiscal 2023. The CAP program 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 federal statute of limitations remains open for fiscal 2020 and later years. The Company is also subject to various routine state income tax examinations. The Company’s principal subsidiaries have state 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, 2023, 2022, or 2021.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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 IRS released guidance on April 14, 2023, providing a natural gas transmission and distribution property safe harbor method of accounting (“NGSH method”) that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and distribution property must be capitalized or be allowable as deductions for repairs. The Company is planning to elect this change in tax accounting method with its consolidated tax return filing in the upcoming year and has reflected an estimate in the September 30, 2023 financial statements of what is intended to be treated as a repair for tax purposes rather than being capitalized. That estimate, which amounted to $99.5 million, has been recorded in Income Tax Expense.

Tax carryforwards available, prior to valuation allowance, at September 30, 2023, were as follows:


Jurisdiction	Tax Attribute	Amount (Thousands)		Expires


Pennsylvania	Net Operating Loss	$	404,403	2031-2043



Federal	General Business Credits	$	1,819	2042

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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, 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			(513,597)
Net Income Available for Common Stock						566,021
Dividends Declared on Common Stock ($1.86 Per Share)						(170,111)

Other Comprehensive Loss, Net of Tax									(112,136)
Share-Based Payment Expense(1)				17,699

Common Stock Issued (Repurchased) Under Stock and Benefit Plans	296	296		(8,079)
Balance at September 30, 2022	91,478	91,478		1,027,066		1,587,085			(625,733)
Net Income Available for Common Stock						476,866
Dividends Declared on Common Stock ($1.94 Per Share)						(178,095)
Other Comprehensive Income, Net of Tax									570,673
Share-Based Payment Expense(1)				18,746
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	341	341		(5,051)
Balance at September 30, 2023	91,819	$	91,819	$	1,040,761	$	1,885,856	(2)	$	(55,060)

(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.

(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, 2023, $1.7 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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

issue shares purchased directly from the Company or shares purchased on the open market by an independent agent. During 2023, 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 2023, the Company issued 12,055 original issue shares of common stock as a result of SARs exercises, 119,147 original issue shares of common stock for restricted stock units that vested and 278,687 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 2023, 103,059 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 (the "DCP"), as partial consideration for the directors’ services during the fiscal year. Under this program, the Company issued 31,715 original issue shares of common stock during 2023. In addition, the Company issued 2,796 original issue shares of common stock to officers of the Company who elected to defer their shares pursuant to the dividend reinvestment features of the Company's DCP during 2023.

Stock Award Plans

Stock-based compensation expense for the years ended September 30, 2023, 2022 and 2021 was approximately $18.6 million, $17.6 million and $15.2 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, 2023, 2022 and 2021 was approximately $2.4 million, $2.5 million and $2.4 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, 2023, 2022 and 2021. The tax benefit related to stock-based compensation exercises and vestings was $1.2 million for the year ended September 30, 2023.

Pursuant to registration statements for these plans, there were 1,510,900 shares available for future grant at September 30, 2023. These shares include shares available for future options, SARs, restricted stock and performance share grants.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

SARs

Transactions for 2023 involving SARs for all plans are summarized as follows:


	Number of Shares Subject To Option	Weighted Average Exercise Price		Aggregate Intrinsic Value (In thousands)
Outstanding at September 30, 2022	72,008	$	53.05
Granted in 2023	—	$	—
Exercised in 2023	(72,008)	$	53.05
Forfeited in 2023	—	$	—
Expired in 2023	—	$	—

Outstanding at September 30, 2023	—	$	—	$	—
SARs exercisable at September 30, 2023	—	$	—	$	—

The Company did not grant any SARs during the years ended September 30, 2022 and 2021. The Company’s SARs included both performance-based and nonperformance-based SARs, but the performance conditions associated with the performance-based SARs at the time of grant were all 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.

The total intrinsic value of SARs exercised during the years ended September 30, 2023 and 2022 totaled approximately $0.8 million and $2.0 million, respectively. During the year ended September 30, 2021, no SARs were exercised. There were no SARs that became fully vested during the years ended September 30, 2023, 2022 and 2021. The SARs that were outstanding at September 30, 2022 had been fully vested since fiscal 2017.

Restricted Stock Units

Transactions for 2023 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, 2022	347,427	$	44.58
Granted in 2023	133,173	$	58.10
Vested in 2023	(119,147)	$	44.82
Forfeited in 2023	(19,267)	$	46.88
Outstanding at September 30, 2023	342,186	$	49.63

The Company also granted 128,950 and 172,513 nonperformance-based restricted stock units during the years ended September 30, 2022 and 2021, respectively. The weighted average fair value of such nonperformance-based restricted stock units granted in 2022 and 2021 was $54.10 per share and $37.98 per share, respectively. As of September 30, 2023, unrecognized compensation expense related to nonperformance-based restricted stock units totaled approximately $7.5 million, which will be recognized over a weighted average period of 2.2 years.

Vesting restrictions for the nonperformance-based restricted stock units outstanding at September 30, 2023 will lapse as follows: 2024 — 115,652 units; 2025 — 98,343 units; 2026 — 79,021 units; 2027 — 33,527 units; and 2028 — 15,643 units.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Performance Shares

Transactions for 2023 involving performance shares for all plans are summarized as follows:


	Number of Performance Shares	Weighted Average Fair Value per Award
Outstanding at September 30, 2022	607,179	$	48.60
Granted in 2023	202,259	$	64.28
Vested in 2023	(278,687)	$	42.58
Forfeited in 2023	(22,805)	$	57.20
Change in Units Based on Performance Achieved	78,845	$	40.69
Outstanding at September 30, 2023	586,791	$	55.46

The Company also granted 195,397 and 309,470 performance shares during the years ended September 30, 2022 and 2021, respectively. The weighted average grant date fair value of such performance shares granted in 2022 and 2021 was $65.39 per share and $39.19 per share, respectively. As of September 30, 2023, unrecognized compensation expense related to performance shares totaled approximately $12.8 million, which will be recognized over a weighted average period of 1.7 years. Vesting restrictions for the outstanding performance shares at September 30, 2023 will lapse as follows: 2024 — 214,158 shares; 2025 — 179,320 shares; and 2026 — 193,313 shares.

The performance shares granted during the years ended September 30, 2023, 2022 and 2021 include awards that must meet a performance goal related to either relative return on capital over a three-year performance cycle ("ROC performance shares"), methane intensity and greenhouse gas emissions reductions over a three-year performance cycle ("ESG performance shares") or relative shareholder return over a three-year performance cycle ("TSR performance shares").

The performance goal over the respective performance cycles for the ROC performance shares granted during 2023, 2022 and 2021 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 the Report Group companies in the Bloomberg database. The number of these ROC 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 the ROC 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 performance goal over the respective performance cycles for the ESG performance shares granted during 2023 and 2022 consists of two parts: reductions in the rates of intensity of methane emissions for each of the Company's operating segments, and reduction of the consolidated Company's total greenhouse gas emissions. The Company's Compensation Committee set specific target levels for methane intensity rates and total greenhouse gas emissions, and the performance goal is intended to incentivize and reward performance to the extent management achieves methane intensity and greenhouse gas reduction targets making progress towards the Company's 2030 goals. The number of these ESG performance shares that will vest and be paid out will depend upon the number of methane intensity segment targets achieved and whether the Company meets the total greenhouse gas emissions target. The fair value of these ESG 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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The fair value is recorded as compensation expense over the vesting term of the award. There were no ESG performance shares granted in 2021.

The performance goal over the respective performance cycles for the TSR performance shares granted during 2023, 2022 and 2021 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 total 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
	2023		2022		2021
Risk-Free Interest Rate	4.03	%	0.85	%	0.19	%
Remaining Term at Date of Grant (Years)	2.80		2.80		2.80
Expected Volatility	31.6	%	29.7	%	29.1	%
Expected Dividend Yield (Quarterly)	N/A		N/A		N/A

Redeemable Preferred Stock

As of September 30, 2023, there were 10,000,000 shares of $1 par value Preferred Stock authorized but unissued.

Long-Term Debt

The outstanding long-term debt is as follows:


	At September 30
	2023		2022
	(Thousands)
Medium-Term Notes(1):
7.4% due June 2025	$	50,000	$	99,000
Notes(1)(2)(3):
2.95% to 5.50% due July 2025 to March 2031	2,350,000		2,550,000
Total Long-Term Debt	2,400,000		2,649,000
Less Unamortized Discount and Debt Issuance Costs	15,515		16,591
Less Current Portion(4)	—		549,000
	$	2,384,485	$	2,083,409

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

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(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, $500.0 million of 2.95% notes and $300.0 million of 5.50% 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 as of September 30, 2023 had a maturity date within the following twelve-month period. Current Portion of Long-Term Debt at September 30, 2022 consisted of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes. The Company redeemed $150.0 million of the 3.75% notes on November 25, 2022 using a portion of the proceeds from short-term borrowings, as discussed below. In March 2023, the Company redeemed the remaining $350.0 million of the 3.75% notes as well as the $49.0 million of 7.395% notes.

On May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $297.3 million. The proceeds of this debt issuance were used for general corporate purposes, including to repay all indebtedness under the $250.0 million unsecured committed delayed draw term loan under the 364-Day Credit Agreement, discussed below.

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.

As of September 30, 2023, the aggregate principal amounts of long-term debt maturing during the next five years and thereafter are as follows: zero in 2024, $500.0 million in 2025, $500.0 million in 2026, $600.0 million in 2027, $300.0 million in 2028, and $500.0 million thereafter.

Short-Term Borrowings

The Company historically has obtained short-term funds either through bank loans or the issuance of commercial paper. On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the "Credit Agreement") with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. The Credit Agreement provides a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027.

On June 30, 2022, the Company entered into a 364-Day Credit Agreement with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provided an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company used the proceeds for general corporate purposes, which included using $150.0 million for the

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

November 25, 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date of March 1, 2023. All indebtedness under the 364-Day Credit Agreement was repaid on May 18, 2023.

At September 30, 2023, the Company had outstanding commercial paper of $287.5 million with a weighted average interest rate on the commercial paper of 6.13%. The Company did not have any outstanding short-term notes payable to banks at September 30, 2023. At September 30, 2022, the Company had outstanding short-term notes payable to banks of $60.0 million, all of which was issued under the Credit Agreement, with an interest rate of 4.02%. The Company did not have any outstanding commercial paper at September 30, 2022.

Debt Restrictions

The Credit Agreement provides that the Company's debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at September 30, 2023, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement. On May 3, 2022, the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modified the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ended June 30, 2022, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet. Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. At September 30, 2023, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement was 0.46. The constraints specified in the Credit Agreement would have permitted an additional $3.17 billion in short-term and/or long-term debt to be outstanding at September 30, 2023 before the Company’s debt to capitalization ratio exceeded 0.65.

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.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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, 2023, the Company would have been permitted to issue up to a maximum of approximately $3.43 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 the debt to capitalization ratio constraint under the Company's Credit Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to Part II, Item 7, Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

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, 2023 and 2022. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.

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NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	At Fair Value as of September 30, 2023
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	$	39,332	$	—	$	—	$	—	$	39,332

Derivative Financial Instruments:

Over the Counter Swaps — Gas	—		65,800		—		(37,508)		28,292
Over the Counter No Cost Collars — Gas	—		30,966		—		(14,745)		16,221
Contingent Consideration for Asset Sale	—		7,277		—		—		7,277
Foreign Currency Contracts	—		150		—		(1,453)		(1,303)
Other Investments:
Balanced Equity Mutual Fund	15,837		—		—		—		15,837
Fixed Income Mutual Fund	15,897		—		—		—		15,897



Total	$	71,066	$	104,193	$	—	$	(53,706)	$	121,553
Liabilities:
Derivative Financial Instruments:

Over the Counter Swaps — Gas	$	—	$	68,311	$	—	$	(37,508)	$	30,803
Over the Counter No Cost Collars — Gas	—		14,950		—		(14,745)		205
Foreign Currency Contracts	—		1,454		—		(1,453)		1
Total	$	—	$	84,715	$	—	$	(53,706)	$	31,009
Total Net Assets/(Liabilities)	$	71,066	$	19,478	$	—	$	—	$	90,544


	At Fair Value as of September 30, 2022
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	$	35,015	$	—	$	—	$	—	$	35,015
Hedging Collateral Deposits	91,670		—		—		—		91,670
Derivative Financial Instruments:
Over the Counter Swaps — Gas	—		5,177		—		(4,178)		999

Contingent Consideration for Asset Sale	—		8,176		—		—		8,176
Foreign Currency Contracts	—		128		—		(128)		—
Other Investments:
Balanced Equity Mutual Fund	19,506		—		—		—		19,506
Fixed Income Mutual Fund	33,348		—		—		—		33,348



Total	$	179,539	$	13,481	$	—	$	(4,306)	$	188,714
Liabilities:
Derivative Financial Instruments:
Over the Counter Swaps — Gas	$	—	$	517,464	$	—	$	(4,178)	$	513,286
Over the Counter No Cost Collars — Gas	—		270,453		—		—		270,453
Foreign Currency Contracts	—		2,048		—		(128)		1,920
Total	$	—	$	789,965	$	—	$	(4,306)	$	785,659
Total Net Assets/(Liabilities)	$	179,539	$	(776,484)	$	—	$	—	$	(596,945)

(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, 2023, the derivative financial instruments reported in Level 2 consist of natural gas price swap agreements, natural gas no cost collars, and foreign currency contracts, all of which are used in the Company's Exploration and Production segment. Hedging collateral deposits of $91.7 million at September 30, 2022, which were associated with the price swap agreements, no cost collars and foreign currency contracts, have been reported in Level 1. The fair value of the Level 2 price swap agreements and no cost collars is based on an internal cash flow model that uses observable inputs (i.e. SOFR based discount rates for the price swap agreements 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 is determined using the market approach based on observable market transactions of forward Canadian currency rates.

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, 2023, the Company determined that nonperformance risk associated with the price swap agreements, no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

Derivative financial instruments reported in Level 2 at September 30, 2023 and September 30, 2022 also includes the contingent consideration associated with the sale of the Exploration and Production segment's California assets on June 30, 2022, which is discussed at Note B — Asset Acquisitions and Divestitures and at Note J — Financial Instruments. The fair value of the contingent consideration was calculated using a Monte Carlo simulation model that uses observable inputs, including the ICE Brent closing price as of the valuation date, initial and max trigger price, volatility, risk free rate, time of maturity and counterparty risk.

For the years ended September 30, 2023 and 2022, 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
	2023 Carrying Amount		2023 Fair Value		2022 Carrying Amount		2022 Fair Value
	(Thousands)
Long-Term Debt	$	2,384,485	$	2,210,478	$	2,632,409	$	2,453,209

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

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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.

Other Investments

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


	At September 30
	2023		2022
	(Thousands)
Life Insurance Contracts	$	42,242	$	42,171
Equity Mutual Fund	15,837		19,506
Fixed Income Mutual Fund	15,897		33,348

	$	73,976	$	95,025

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 collar and swap agreements for natural gas to manage the price risk associated with forecasted sales of natural gas. 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 7 years.

On June 30, 2022, the Company completed the sale of Seneca’s California assets. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The Company has determined that this contingent consideration meets the definition of a derivative under the authoritative accounting guidance. Changes in the fair value of this contingent consideration are marked-to-market each reporting period, with changes in fair value recognized in Other Income (Deductions) on the Consolidated Statement of Income. The fair value of this contingent consideration was estimated to be $7.3 million and $8.2 million at September 30, 2023 and September 30, 2022, respectively. A $0.9 million mark-to-market adjustment was recorded during the year ended September 30, 2023.

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, 2023 and September 30, 2022.

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.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

As of September 30, 2023, the Company had 411.3 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.

As of September 30, 2023, the Company was hedging a total of $56.9 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

As of September 30, 2023, the Company had $4.6 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance. Of this amount, it is expected that $11.5 million of unrealized gains after taxes will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings. The remaining unrealized losses will be being reclassified into the Consolidated Statement of Income in subsequent periods.


The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the Year Ended September 30, 2023 and 2022 (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,
	2023		2022			2023		2022
Commodity Contracts	$	708,234	$	(1,048,200)	Operating Revenue	$	(88,015)	$	(882,594)	(1)

Foreign Currency Contracts	(28)		(2,631)		Operating Revenue	(641)		13
Total	$	708,206	$	(1,050,831)		$	(88,656)	$	(882,581)

(1)On June 30, 2022, the Company completed the sale of Seneca's California assets. Because of this sale, the Company terminated its remaining crude oil derivative contracts and discontinued hedge accounting for such contracts. A loss of $44.6 million was reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet to Operating Revenues on the Consolidated Statement of Income for the year ended September 30, 2022. This loss is included in the reported reclassification amounts.

Credit Risk

The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over the-counter swap positions, no cost collars and applicable foreign currency forward contracts with nineteen counterparties of which eleven are in a net gain position. On average, the Company had $3.9 million of credit exposure per counterparty in a gain position at September 30, 2023. The maximum credit exposure per counterparty in a gain position at September 30, 2023 was $16.1 million. As of September 30, 2023, no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral.

As of September 30, 2023, sixteen of the nineteen counterparties to the Company’s outstanding derivative financial contracts (specifically the over-the-counter swaps, over-the-counter no cost collars and applicable

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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, 2023, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $7.7 million according to the Company's internal model (discussed in Note I — Fair Value Measurements) and no hedging collateral deposits were required to be posted by the Company at September 30, 2023. 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 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 $5.7 million, $5.3 million and $4.8 million for the years ended September 30, 2023, 2022 and 2021, 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 $8.2 million, $7.8 million and $7.2 million for the years ended September 30, 2023, 2022 and 2021, 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

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

(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.

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 2023, 2022 and 2021.


	Retirement Plan									Other Post-Retirement Benefits
	Year Ended September 30									Year Ended September 30
	2023			2022			2021			2023			2022			2021
	(Thousands)
Change in Benefit Obligation
Benefit Obligation at Beginning of Period	$	813,828		$	1,098,456		$	1,139,105		$	299,283		$	431,213		$	476,722
Service Cost	5,187			8,758			9,865			587			1,328			1,602
Interest Cost	42,516			22,827			21,686			15,648			9,066			9,303
Plan Participants’ Contributions	—			—			—			3,297			3,271			3,216
Retiree Drug Subsidy Receipts	—			—			—			2,969			312			1,244

Actuarial Gain	(27,313)			(251,173)			(8,141)			(20,789)			(120,276)			(34,729)
Benefits Paid	(65,468)			(65,040)			(64,059)			(26,717)			(25,631)			(26,145)
Benefit Obligation at End of Period	$	768,750		$	813,828		$	1,098,456		$	274,278		$	299,283		$	431,213
Change in Plan Assets
Fair Value of Assets at Beginning of Period	$	845,205		$	1,095,729		$	1,016,796		$	461,438		$	575,565		$	547,885
Actual Return on Plan Assets	4,975			(205,884)			122,992			17,449			(94,849)			47,541
Employer Contributions	—			20,400			20,000			235			3,082			3,068
Plan Participants’ Contributions	—			—			—			3,297			3,271			3,216
Benefits Paid	(65,468)			(65,040)			(64,059)			(26,717)			(25,631)			(26,145)
Fair Value of Assets at End of Period	$	784,712		$	845,205		$	1,095,729		$	455,702		$	461,438		$	575,565
Net Amount Recognized at End of Period (Funded Status)	$	15,962		$	31,377		$	(2,727)		$	181,424		$	162,155		$	144,352
Amounts Recognized in the Balance Sheets Consist of:
Non-Current Liabilities	$	—		$	—		$	(2,727)		$	(2,915)		$	(3,065)		$	(4,799)
Non-Current Assets	15,962			31,377			—			184,339			165,220			149,151
Net Amount Recognized at End of Period	$	15,962		$	31,377		$	(2,727)		$	181,424		$	162,155		$	144,352
Accumulated Benefit Obligation	$	751,912		$	793,555		$	1,060,659		N/A			N/A			N/A
Weighted Average Assumptions Used to Determine Benefit Obligation at September 30
Discount Rate	5.99		%	5.57		%	2.75		%	5.99		%	5.56		%	2.76		%
Rate of Compensation Increase	4.60		%	4.60		%	4.70		%	4.60		%	4.60		%	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
	2023			2022			2021			2023			2022			2021
	(Thousands)
Components of Net Periodic Benefit Cost
Service Cost	$	5,187		$	8,758		$	9,865		$	587		$	1,328		$	1,602
Interest Cost	42,516			22,827			21,686			15,648			9,066			9,303
Expected Return on Plan Assets	(66,593)			(52,294)			(58,148)			(25,612)			(29,359)			(28,964)
Amortization of Prior Service Cost (Credit)	436			537			631			(429)			(429)			(429)

Recognition of Actuarial (Gain) Loss(1)	(7,680)			26,405			36,814			(8,755)			(7,610)			849
Net Amortization and Deferral for Regulatory Purposes	21,512			16,854			14,063			15,157			21,340			28,010
Net Periodic Benefit Cost (Income)	$	(4,622)		$	23,087		$	24,911		$	(3,404)		$	(5,664)		$	10,371
Weighted Average Assumptions Used to Determine Net Periodic Benefit Cost at September 30
Effective Discount Rate for Benefit Obligations	5.57		%	2.75		%	2.66		%	5.56		%	2.76		%	2.71		%
Effective Rate for Interest on Benefit Obligations	5.45		%	2.14		%	1.96		%	5.45		%	2.17		%	2.01		%
Effective Discount Rate for Service Cost	5.49		%	2.95		%	3.01		%	5.35		%	3.00		%	3.20		%
Effective Rate for Interest on Service Cost	5.53		%	2.70		%	2.60		%	5.47		%	2.93		%	2.98		%
Expected Return on Plan Assets	6.90		%	5.20		%	6.00		%	5.70		%	5.20		%	5.40		%
Rate of Compensation Increase	4.60		%	4.70		%	4.70		%	4.60		%	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 (Income) 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 whose income level has exceeded certain IRS thresholds or who have been designated as participants 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

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

million and $8.3 million in 2023, 2022 and 2021, respectively. The components of net periodic benefit cost other than service costs associated with these plans are presented in Other Income (Deductions) on the Consolidated Statements of Income. The accumulated benefit obligations for the plans were $58.5 million, $64.9 million and $76.9 million at September 30, 2023, 2022 and 2021, respectively. The projected benefit obligations for the plans were $69.5 million, $77.2 million and $95.8 million at September 30, 2023, 2022 and 2021, respectively. At September 30, 2023, $13.1 million of the projected benefit obligation is recorded in Other Accruals and Current Liabilities and the remaining $56.4 million is recorded in Other Liabilities on the Consolidated Balance Sheets. At September 30, 2022, $17.5 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $59.7 million was recorded in Other Liabilities on the Consolidated Balance Sheets. At September 30, 2021, $15.4 million of the projected benefit obligation was recorded in Other Accruals and Current Liabilities and the remaining $80.4 million was recorded in Other Liabilities on the Consolidated Balance Sheets. The weighted average discount rates for these plans were 5.91%, 5.49% and 2.15% as of September 30, 2023, 2022 and 2021, respectively and the weighted average rate of compensation increase for these plans was 8.00% as of September 30, 2023, 2022 and 2021.

The cumulative amounts recognized in accumulated other comprehensive income (loss), regulatory assets, and regulatory liabilities through fiscal 2023, as well as the changes in such amounts during 2023, 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)	$	(128,118)	$	18,440	$	(17,286)
Prior Service (Cost) Credit	(2,036)		1,115		—
Net Amount Recognized	$	(130,154)	$	19,555	$	(17,286)
Changes to Accumulated Other Comprehensive Income (Loss), Regulatory Assets and Regulatory Liabilities Recognized During Fiscal 2023(1)
Increase in Actuarial Gain (Loss), excluding amortization(2)	$	(34,305)	$	12,626	$	(2,139)
Change due to Amortization of Actuarial (Gain) Loss	(7,680)		(8,755)		3,572

Prior Service (Cost) Credit	436		(429)		—
Net Change	$	(41,549)	$	3,442	$	1,433

(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 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, 2023, the Company recorded a $28.7 million increase to Other Regulatory Assets in the Company’s Utility and Pipeline and Storage segments and a $8.0 million (pre-tax) decrease to Accumulated Other Comprehensive Income.

The effect of the discount rate change for the Retirement Plan in 2023 was to decrease the projected benefit obligation of the Retirement Plan by $28.4 million. The mortality improvement projection scale was updated, which decreased the projected benefit obligation of the Retirement Plan in 2023 by $0.7 million. Other actuarial experience increased the projected benefit obligation for the Retirement Plan in 2023 by $1.8 million. The effect of the discount rate change for the Retirement Plan in 2022 was to decrease the projected

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

benefit obligation of the Retirement Plan by $262.2 million. 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 Company did not make any cash contributions to the Retirement Plan during the year ended September 30, 2023. The Company expects that the annual contribution to the Retirement Plan in 2024 will be in the range of zero to $5.0 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: $67.9 million in 2024; $67.4 million in 2025; $66.9 million in 2026; $66.2 million in 2027; $65.5 million in 2028; and $310.4 million in the five years thereafter.

The effect of the discount rate change in 2023 was to decrease the other post-retirement benefit obligation by $10.7 million. The mortality improvement projection scale was updated, which decreased the other post-retirement benefit obligation in 2023 by $0.4 million. The health care cost trend rates were updated, which increased the other post-retirement benefit obligation in 2023 by $3.2 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2023 by $12.9 million, the majority of which was attributable to a revision in assumed per-capita claims cost, premiums, retiree contributions and retiree drug subsidy assumptions based on actual experience.

The effect of the discount rate change in 2022 was to decrease the other post-retirement benefit obligation by $98.9 million. The mortality improvement projection scale was updated, which increased the other post-retirement benefit obligation in 2022 by $1.1 million. Other actuarial experience decreased the other post-retirement benefit obligation in 2022 by $22.5 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 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 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
2024	$	25,334	$	(1,787)
2025	$	25,479	$	(1,881)
2026	$	25,466	$	(1,969)
2027	$	25,389	$	(2,039)
2028	$	25,260	$	(2,091)
2029 through 2033	$	120,390	$	(10,896)

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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:


	2023			2022			2021
Rate of Medical Cost Increase for Pre Age 65 Participants	6.25	%	(1)	5.30	%	(2)	5.38	%	(2)
Rate of Medical Cost Increase for Post Age 65 Participants	5.00	%	(1)	4.84	%	(2)	4.84	%	(2)
Annual Rate of Increase in the Per Capita Cost of Covered Prescription Drug Benefits	6.85	%	(1)	6.29	%	(2)	6.53	%	(2)
Annual Rate of Increase in the Per Capita Medicare Part B Reimbursement	5.00	%	(1)	4.84	%	(2)	4.84	%	(2)
Annual Rate of Increase in the Per Capita Medicare Part D Subsidy	6.60	%	(1)	5.96	%	(2)	6.15	%	(2)

(1)It was assumed that this rate would gradually decline to 4% by 2048.

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

The Company did not make any cash contributions to its VEBA trusts during the year ended September 30, 2023. In addition, the Company made direct payments of $0.2 million to retirees not covered by the VEBA trusts and 401(h) accounts during the year ended September 30, 2023. The Company does not expect to make any contributions to its VEBA trusts in 2024.

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, 2023 and 2022, 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, 2023
	Total Fair Value		Level 1		Level 2		Level 3		Measured at NAV(7)
Retirement Plan Investments
Domestic Equities(1)	$	37,611	$	37,611	$	—	$	—	$	—
International Equities(2)	—		—		—		—		—
Global Equities(3)	36,088		—		—		—		36,088
Domestic Fixed Income(4)	612,820		—		556,504		—		56,316
International Fixed Income(5)	7,778		—		7,778		—		—


Real Estate (6)	123,859		—		—		—		123,859
Cash Held in Collective Trust Funds	36,800		—		—		—		36,800
Total Retirement Plan Investments	854,956		37,611		564,282		—		253,063
401(h) Investments	(73,319)		(3,212)		(48,184)		—		(21,923)
Total Retirement Plan Investments (excluding 401(h) Investments)	$	781,637	$	34,399	$	516,098	$	—	$	231,140
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash	3,075
Total Retirement Plan Assets	$	784,712

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	At September 30, 2022
	Total Fair Value		Level 1		Level 2		Level 3		Measured at NAV(7)
Retirement Plan Investments
Domestic Equities(1)	$	41,633	$	41,633	$	—	$	—	$	—
International Equities(2)	1,363		—		—		—		1,363
Global Equities(3)	44,434		—		—		—		44,434
Domestic Fixed Income(4)	658,833		—		579,606		—		79,227
International Fixed Income(5)	7,782		—		7,782		—		—


Real Estate (6)	140,739		—		—		—		140,739
Cash Held in Collective Trust Funds	17,388		—		—		—		17,388
Total Retirement Plan Investments	912,172		41,633		587,388		—		283,151
401(h) Investments	(73,044)		(3,310)		(46,694)		—		(23,040)
Total Retirement Plan Investments (excluding 401(h) Investments)	$	839,128	$	38,323	$	540,694	$	—	$	260,111
Miscellaneous Accruals, Interest Receivables, and Non-Interest Cash	6,077
Total Retirement Plan Assets	$	845,205

(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)Real Estate consists of investments held in a collective trust fund and a real estate investment trust.

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


	At September 30, 2023
	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	$	72,285	$	—	$	—	$	—	$	72,285


Exchange Traded Funds — Fixed Income	289,666		289,666		—		—		—

Cash Held in Collective Trust Funds	9,637		—		—		—		9,637
Total VEBA Trust Investments	371,588		289,666		—		—		81,922
401(h) Investments	73,319		3,212		48,184		—		21,923
Total Investments (including 401(h) Investments)	$	444,907	$	292,878	$	48,184	$	—	$	103,845
Miscellaneous Accruals (including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative)	10,795
Total Other Post-Retirement Benefit Assets	$	455,702

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	At September 30, 2022
	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	$	104,554	$	—	$	—	$	—	$	104,554
Exchange Traded Funds — Fixed Income	270,581		270,581		—		—		—

Cash Held in Collective Trust Funds	10,635		—		—		—		10,635
Total VEBA Trust Investments	385,770		270,581		—		—		115,189
401(h) Investments	73,044		3,310		46,694		—		23,040
Total Investments (including 401(h) Investments)	$	458,814	$	273,891	$	46,694	$	—	$	138,229
Miscellaneous Accruals (Including Current and Deferred Taxes, Claims Incurred But Not Reported, Administrative)	2,624
Total Other Post-Retirement Benefit Assets	$	461,438

(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, 2023 and September 30, 2022, 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, 2021							$	319	$	(24)	$	295

Unrealized Gains/(Losses)	234		(18)		216

Sales	(553)		42		(511)
Balance at September 30, 2022	—		—		—

Unrealized Gains/(Losses)	—		—		—

Sales	—		—		—
Balance at September 30, 2023	$	—	$	—	$	—

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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, 2021	$	24

Unrealized Gains/(Losses)	18

Sales	(42)
Balance at September 30, 2022	—

Unrealized Gains/(Losses)	—
Sales	—
Balance at September 30, 2023	$	—

The Company’s assumption regarding the expected long-term rate of return on plan assets is 7.40% (Retirement Plan) and 6.00% (other post-retirement benefits), effective for fiscal 2024. 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 and fiscal 2022, 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 during both years, particularly equity securities and return seeking fixed income securities, held in the Retirement Plan, and increased its allocation to hedging fixed income securities in conjunction with the Company’s liability driven investment strategy. The actual asset allocations as of September 30, 2023 are noted in the table above, and such allocations are subject to change, but the majority of the assets will remain hedging fixed income assets. 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.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Note L — Commitments and Contingencies

Environmental Matters

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, 2023, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.7 million. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at September 30, 2023. The Company has recovered its environmental clean-up costs through rate recovery and 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 and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project, which is the subject of an ongoing appeal at the U.S. Court of Appeals for the D.C. Circuit. As of September 30, 2023, the Company has spent approximately $55.9 million on the project, all of which is recorded on the balance sheet.

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: $201.7 million in 2024, $91.1 million in 2025, $113.8 million in 2026, $118.3 million in 2027, $121.7 million in 2028 and $768.9 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, 2023, the future contractual commitments related to the system modernization and expansion projects are $74.9 million in 2024, $8.4 million in 2025, $7.2 million in 2026, $5.9 million in 2027, $3.3 million in 2028 and $4.7 million thereafter.

The Company, in its Exploration and Production segment, has entered into contractual obligations to support its development activities and operations in Pennsylvania, including hydraulic fracturing and other well

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

completion services, well tending services, well workover activities, tubing and casing purchases, production equipment purchases, water hauling services and contracts for drilling rig services. The future contractual commitments are $279.5 million in 2024, $185.1 million in 2025, and $47.3 million in 2026. There are no contractual commitments extending beyond 2026.

In addition to the regulatory matters discussed in Note F — Regulatory Matters, the Company is involved in other regulatory and litigation matters arising in the normal course of business. These other regulatory and litigation matters may include, for example, tax, regulatory or other governmental audits, inspections, investigations, negligence claims 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 reserves in the Appalachian region of the United States.

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.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	Year Ended September 30, 2023
	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)(2)	$	958,455	$	259,646	$	13,891	$	941,779	$	2,173,771	$	—	$	—	$	2,173,771
Intersegment Revenues	$	—	$	119,545	$	216,426	$	581	$	336,552	$	—	$	(336,552)	$	—
Interest Income	$	3,259	$	7,052	$	534	$	6,296	$	17,141	$	—	$	(5,662)	$	11,479
Interest Expense	$	54,317	$	43,499	$	14,989	$	34,233	$	147,038	$	157	$	(15,309)	$	131,886
Depreciation, Depletion and Amortization	$	241,142	$	70,827	$	35,725	$	61,450	$	409,144	$	—	$	429	$	409,573
Income Tax Expense (Benefit)	$	87,796	$	34,489	$	36,128	$	7,267	$	165,680	$	(164)	$	(983)	$	164,533


Segment Profit: Net Income (Loss)	$	232,275	$	100,501	$	99,724	$	48,395	$	480,895	$	(531)	$	(3,498)	$	476,866
Expenditures for Additions to Long-Lived Assets	$	737,725	$	141,877	$	103,295	$	139,922	$	1,122,819	$	—	$	754	$	1,123,573
	At September 30, 2023
	(Thousands)
Segment Assets	$	2,814,218	$	2,427,214	$	912,923	$	2,247,743	$	8,402,098	$	4,795	$	(126,633)	$	8,280,260


	Year Ended September 30, 2022
	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)(3)	$	1,010,464	$	265,415	$	12,086	$	897,916	$	2,185,881	$	—	$	165	$	2,186,046
Intersegment Revenues	$	—	$	111,629	$	202,757	$	305	$	314,691	$	6	$	(314,697)	$	—
Interest Income	$	1,929	$	2,275	$	198	$	2,730	$	7,132	$	3	$	(1,024)	$	6,111
Interest Expense	$	53,401	$	42,492	$	16,488	$	24,115	$	136,496	$	4	$	(6,143)	$	130,357
Depreciation, Depletion and Amortization	$	208,148	$	67,701	$	33,998	$	59,760	$	369,607	$	—	$	183	$	369,790
Income Tax Expense (Benefit)	$	43,898	$	35,043	$	24,949	$	17,165	$	121,055	$	3	$	(4,429)	$	116,629

Significant Item: Gain on Sale of Assets	$	12,736	$	—	$	—	$	—	$	12,736	$	—	$	—	$	12,736
Segment Profit: Net Income (Loss)	$	306,064	$	102,557	$	101,111	$	68,948	$	578,680	$	(9)	$	(12,650)	$	566,021
Expenditures for Additions to Long-Lived Assets	$	565,791	$	95,806	$	55,546	$	111,033	$	828,176	$	—	$	1,212	$	829,388
	At September 30, 2022
	(Thousands)
Segment Assets	$	2,507,541	$	2,394,697	$	878,796	$	2,299,473	$	8,080,507	$	2,036	$	(186,281)	$	7,896,262

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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 Assets	$	—	$	—	$	—	$	—	$	—	$	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

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

(2)Revenue from one customer of the Company's Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $208 million of the Company's consolidated revenue for the year ended September 30, 2023. This one customer was also a customer of the Company's Pipeline and Storage segment, accounting for an additional $14 million of the Company's consolidated revenue for the year ended September 30, 2023.

(3)Revenues from three customers of the Company's Exploration and Production segment, exclusive of hedging losses transacted with separate parties, represented approximately $850 million of the Company's consolidated revenue for the year ended September 30, 2022. These three customers were also customers of the Company's Pipeline and Storage segment, accounting for an additional $15 million of the Company's consolidated revenue for the year ended September 30, 2022.


Geographic Information	At September 30
	2023		2022		2021
	(Thousands)
Long-Lived Assets:
United States	$	7,865,832	$	7,135,131	$	6,942,376

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.

-117-

NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The following supplementary information is presented in accordance with the authoritative guidance regarding disclosures about oil and gas producing activities and related SEC authoritative guidance. As discussed in Note B — Asset Acquisitions and Divestitures, the Company completed the sale of its California assets on June 30, 2022. With the completion of this sale, the Company no longer has any oil or gas reserves in the West Coast region of the U.S.

Capitalized Costs Relating to Oil and Gas Producing Activities


	At September 30
	2023		2022
	(Thousands)
Proved Properties(1)	$	6,555,088	$	5,915,807
Unproved Properties	161,097		65,994
	6,716,185		5,981,801
Less — Accumulated Depreciation, Depletion and Amortization	4,269,959		4,034,266
	$	2,446,226	$	1,947,535

(1)Includes asset retirement costs of $129.2 million and $120.8 million at September 30, 2023 and 2022, 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 2028. It expects the majority of its development and exploration costs associated with unproved properties to be transferred into the amortization base by 2026. Following is a summary of costs excluded from amortization at September 30, 2023:


	Total as of September 30, 2023		Year Costs Incurred
			2023		2022		2021		Prior
	(Thousands)
Acquisition Costs	$	143,860	$	120,349	$	—	$	—	$	23,511
Development Costs	17,207		8,034		3,001		3,704		2,468
Exploration Costs	—		—		—		—		—
Capitalized Interest	30		30		—		—		—
	$	161,097	$	128,413	$	3,001	$	3,704	$	25,979

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

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


	Year Ended September 30
	2023		2022		2021
	(Thousands)
United States
Property Acquisition Costs:
Proved	$	33,190	$	2,491	$	1,801
Unproved	129,061		10,665		5,102
Exploration Costs(1)	10,055		9,631		15,413
Development Costs(2)	553,469		528,684		329,368
Asset Retirement Costs	8,363		9,768		20,194
	$	734,138	$	561,239	$	371,878

(1)Amounts for 2023, 2022 and 2021 include capitalized interest of zero, zero and $0.1 million respectively.

(2)Amounts for 2023, 2022 and 2021 include capitalized interest of $0.1 million, $0.6 million and $0.4 million, respectively.

For the years ended September 30, 2023, 2022 and 2021, the Company spent $342.0 million, $154.3 million and $81.2 million, respectively, developing proved undeveloped reserves.

Results of Operations for Producing Activities


	Year Ended September 30
	2023		2022		2021
United States	(Thousands, except per Mcfe amounts)
Operating Revenues:
Gas (includes transfers to operations of $1,957, $5,696 and $3,061, respectively)(1)	$	1,036,499	$	1,730,723	$	780,477
Oil, Condensate and Other Liquids	2,261		150,957		135,191
Total Operating Revenues(2)	1,038,760		1,881,680		915,668
Production/Lifting Costs	253,555		283,914		267,316
Franchise/Ad Valorem Taxes	17,532		25,112		22,128
Purchased Emission Allowance Expense	—		1,305		2,940
Accretion Expense	5,673		7,530		7,743
Depreciation, Depletion and Amortization ($0.63, $0.57 and $0.54 per Mcfe of production, respectively)	235,694		202,418		177,055
Impairment of Oil and Gas Producing Properties	—		—		76,152
Income Tax Expense	145,574		368,925		98,593
Results of Operations for Producing Activities (excluding corporate overheads and interest charges)	$	380,732	$	992,476	$	263,741

(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.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

Reserve Quantity Information

The Company's proved oil and gas reserve estimates are prepared by the Company's 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 June 25, 2019. The Company maintains comprehensive internal reserve guidelines and a continuing education program designed to keep its staff up to date with current SEC regulations and guidance.

The Company's Vice President of Reservoir Engineering is the primary technical person responsible for overseeing the Company's reserve estimation process and engaging and overseeing the third party reserve audit. His qualifications include a Bachelor of Science Degree in Petroleum Engineering and over 14 years of Petroleum Engineering experience with independent oil and gas companies, licensure as a Professional Engineer 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 Vice President of Reservoir Engineering reviews and approves all new reserve assignments and significant reserve revisions. Access to the reserve database is restricted. Significant changes to the reserve report are reviewed by senior management on a quarterly basis. Periodically, the Company's internal audit department assesses the design of these controls and performs testing to determine the effectiveness of such controls.

All of the Company's reserve estimates are audited annually by Netherland, Sewell & 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 2019 and with over 6 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, 2023 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.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	Gas MMcf
	U.S.
	Appalachian Region		West Coast Region	Total Company
Proved Developed and Undeveloped Reserves:
September 30, 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
Extensions and Discoveries	837,510	(1)	—	837,510
Revisions of Previous Estimates	2,882		71	2,953
Production	(341,700)	(2)	(1,211)	(342,911)

Sale of Minerals in Place	(21,178)		(29,145)	(50,323)
September 30, 2022	4,170,662		—	4,170,662
Extensions and Discoveries	670,438	(1)	—	670,438
Revisions of Previous Estimates	32,379		—	32,379
Production	(372,271)	(2)	—	(372,271)

Purchases of Minerals in Place	33,876		—	33,876
September 30, 2023	4,535,084		—	4,535,084
Proved Developed Reserves:
September 30, 2020	2,744,851		28,972	2,773,823
September 30, 2021	3,061,178		30,285	3,091,463
September 30, 2022	3,312,568		—	3,312,568
September 30, 2023	3,550,034		—	3,550,034
Proved Undeveloped Reserves:
September 30, 2020	551,262		—	551,262
September 30, 2021	631,970		—	631,970
September 30, 2022	858,094		—	858,094
September 30, 2023	985,050		—	985,050

(1)Extensions and discoveries include 180 Bcf (during 2021), 301 Bcf (during 2022) and 163 Bcf (during 2023), of Marcellus Shale gas (which exceed 15% of total reserves) in the Appalachian region. Extensions and discoveries include 497 Bcf (during 2021), 537 Bcf (during 2022) and 507 Bcf (during 2023), of Utica Shale gas (which exceed 15% of total reserves) in the Appalachian region.

(2)Production includes 218,016 MMcf (during 2021), 209,463 MMcf (during 2022) and 190,290 MMcf (during 2023), from Marcellus Shale fields. Production includes 93,253 MMcf (during 2021), 130,240 MMcf (during 2022) and 180,750 MMcf (during 2023), from Utica Shale fields.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)


	Oil Mbbl
	U.S.
	Appalachian Region	West Coast Region	Total Company
Proved Developed and Undeveloped Reserves:
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
Extensions and Discoveries	—	296	296
Revisions of Previous Estimates	255	532	787
Production	(16)	(1,588)	(1,604)

Sales of Minerals in Place	—	(20,766)	(20,766)
September 30, 2022	250	—	250

Revisions of Previous Estimates	(4)	—	(4)
Production	(30)	—	(30)


September 30, 2023	216	—	216
Proved Developed Reserves:
September 30, 2020	12	22,088	22,100
September 30, 2021	11	20,930	20,941
September 30, 2022	250	—	250
September 30, 2023	216	—	216
Proved Undeveloped Reserves:
September 30, 2020	—	—	—
September 30, 2021	—	596	596
September 30, 2022	—	—	—
September 30, 2023	—	—	—

The Company’s proved undeveloped (PUD) reserves increased from 858 Bcfe at September 30, 2022 to 985 Bcfe at September 30, 2023. PUD reserves in the Utica Shale increased from 503 Bcfe at September 30, 2022 to 873 Bcfe at September 30, 2023. PUD reserves in the Marcellus Shale decreased from 355 Bcfe at September 30, 2022 to 112 Bcfe at September 30, 2023. The Company’s total PUD reserves were 21.7% of total proved reserves at September 30, 2023, up from 20.6% of total proved reserves at September 30, 2022.

The Company’s PUD reserves increased from 636 Bcfe at September 30, 2021 to 858 Bcfe at September 30, 2022. PUD reserves in the Utica Shale increased from 411 Bcfe at September 30, 2021 to 503 Bcfe at September 30, 2022. PUD reserves in the Marcellus Shale increased from 220 Bcfe at September 30, 2021 to 355 Bcfe at September 30, 2022. PUD reserves in the West Coast region decreased from 5 Bcfe at September 30, 2021 to zero at September 30, 2022. The Company’s total PUD reserves were 20.6% of total proved reserves at September 30, 2022, up from 16.5% of total proved reserves at September 30, 2021.

The increase in PUD reserves in 2023 of 127 Bcfe is a result of 554 Bcfe in new PUD reserve additions, 14 Bcfe for one PUD well added back into the schedule and 23 Bcfe in upward revisions to remaining PUD reserves. These upward revisions were partially offset by 402 Bcfe in PUD conversions to developed reserves (275 Bcfe from the Marcellus Shale and 127 Bcfe from the Utica Shale), and 62 Bcfe in PUD reserves removed for seven PUD locations due to schedule and pad layout changes.

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NATIONAL FUEL GAS COMPANY

NOTES TO CONSOLIDATED FINANCIAL STATEMENTS - (Continued)

The increase in PUD reserves in 2022 of 222 Bcfe is a result of 502 Bcfe in new PUD reserve additions and 23 Bcfe in upward revisions to remaining PUD reserves, partially offset by 287 Bcfe in PUD conversions to developed reserves (55 Bcfe from the Marcellus Shale, 231 Bcfe from the Utica Shale and 1 Bcfe from the West Coast region), and 13 Bcfe in PUD reserves removed for one Utica PUD location due to pad layout changes. The remaining change of 3 Bcf was due to removing West Coast region PUDs included in the beginning of year balances through development and divesture of Seneca's California assets.

The Company invested $342 million during the year ended September 30, 2023 to convert 402 Bcfe (440 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 47% of the net PUD reserves recorded at September 30, 2022. The Company developed 39 of 77 PUD locations in 2023. PUD expenditures in 2023 were higher than the 2022 estimate due to schedule changes and changes in service costs.

The Company invested $154 million during the year ended September 30, 2022 to convert 287 Bcfe (333 Bcfe after revisions) of predominantly Marcellus and Utica Shale PUD reserves to developed reserves. This represents 45% of the net PUD reserves recorded at September 30, 2021. In the Appalachian region, 31 of 65 PUD locations were developed while the West Coast region developed 6 of 17 PUD locations prior to the divesture. PUD expenditures in 2022 were lower than the 2021 estimate primarily due to changes in the development schedule.

In 2024, the Company estimates that it will invest approximately $315 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 was adopted, and over the last five years, the Company developed 39% of its beginning year PUD reserves in fiscal 2019, 36% of its beginning year PUD reserves in fiscal 2020, 34% of its beginning year PUD reserves in fiscal 2021, 45% of its beginning year PUD reserves in fiscal 2022 and 47% of its beginning year PUD reserves in fiscal 2023.

At September 30, 2023, 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
	2023		2022		2021
	(Thousands)
United States
Future Cash Inflows	$	11,947,345	$	19,209,099	$	10,175,182
Less:
Future Production Costs	3,538,389		3,138,226		3,423,629
Future Development Costs	1,095,096		781,847		597,662
Future Income Tax Expense at Applicable Statutory Rate	1,867,457		3,876,272		1,397,175
Future Net Cash Flows	5,446,403		11,412,754		4,756,716
Less:
10% Annual Discount for Estimated Timing of Cash Flows	2,874,295		5,964,424		2,403,144
Standardized Measure of Discounted Future Net Cash Flows	$	2,572,108	$	5,448,330	$	2,353,572

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


	Year Ended September 30
	2023		2022		2021
	(Thousands)
United States

Standardized Measure of Discounted Future Net Cash Flows at Beginning of Year	$	5,448,330	$	2,353,572	$	1,222,470
Sales, Net of Production Costs	(767,487)		(1,572,402)		(626,132)
Net Changes in Prices, Net of Production Costs	(3,918,392)		4,132,889		1,478,995
Extensions and Discoveries	237,057		1,355,257		462,040
Changes in Estimated Future Development Costs	(222,233)		(32,160)		48,247
Purchases of Minerals in Place	34,346		—		—
Sales of Minerals in Place	—		(311,308)		—
Previously Estimated Development Costs Incurred	342,024		154,253		81,239
Net Change in Income Taxes at Applicable Statutory Rate	959,728		(1,180,349)		(415,993)
Revisions of Previous Quantity Estimates	33,192		3,316		(52,383)
Accretion of Discount and Other	425,543		545,262		155,089
Standardized Measure of Discounted Future Net Cash Flows at End of Year	$	2,572,108	$	5,448,330	$	2,353,572

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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, 2023.

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, 2023. 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, 2023.

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, 2023. 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, 2023 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.


Item 9B			Other Information

During the quarter ended September 30, 2023, no director or officer (as defined in Rule 16a-1(f) promulgated under the Exchange Act) of the Company adopted or terminated any “Rule 10b5–1 trading arrangement” or any “non-Rule 10b5–1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.


Item 9C			Disclosure Regarding Foreign Jurisdictions that Prevent Inspections

None.

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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, 2023. 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 2025,” and “Continuing Directors Whose Terms Expire in 2025,” and is incorporated herein by reference. The information concerning corporate governance will be set forth in the definitive Proxy Statement under the heading entitled “Meetings of the Board of Directors and Standing Committees” and is incorporated herein by reference. Information concerning the Company’s executive officers can be found in Part I, Item 1, of this report.

The Company has adopted a Code of Business Conduct and Ethics that applies to the Company’s directors, officers and employees and has posted such Code of Business Conduct and Ethics on the Company’s website, www.nationalfuel.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.nationalfuel.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

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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.

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 June 15, 2022 (Exhibit 3.1, Form 8-K dated June 17, 2022)

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)

•			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 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)

•			Officer’s Certificate establishing 5.50% Notes due 2026, dated May 18, 2023 (Exhibit 4.1.1, Form 8-K dated May 18, 2023)

10			Material Contracts:

•			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)

•			Credit Agreement, dated as of February 28, 2022, among the Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A. as Administrative Agent (Exhibit 10.1, Form 8-K dated February 28, 2022)

•			Amendment No. 1 to Credit Agreement, dated as of May 3, 2022, among the Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A. as Administrative Agent (Exhibit 10.1, Form 10-Q dated May 6, 2022)

			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)

•			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)

•			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)

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Exhibit Number			Description of Exhibits
•			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)

•			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, 2022)

•			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, 2022)

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Exhibit Number			Description of Exhibits
•			Form of Award Notice for ESG Performance Shares under the National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.3, Form 10-Q for the quarterly period ended December 31, 2022)

•			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, 2021)

•			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, 2021)

•			Form of Award Notice for ESG Performance Shares under the National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.3, Form 10-Q for the quarterly period ended December 31, 2021)

•			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)

•			Retirement and Consulting Services Agreement, dated as of March 9, 2023, between National Fuel Gas Distribution Corporation and Karen M. Camiolo (Exhibit 10.1, Form 10-Q for the quarterly period ended March 31, 2023)

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

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, 2023, 2022 and 2021, (ii) the Consolidated Statements of Comprehensive Income for the years ended September 30, 2023, 2022 and 2021, (iii) the Consolidated Balance Sheets at September 30, 2023 and September 30, 2022, (iv) the Consolidated Statements of Cash Flows for the years ended September 30, 2023, 2022 and 2021 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.

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Exhibit Number			Description of Exhibits
			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.


Item 16			Form 10-K Summary

None.

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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 17, 2023

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 17, 2023

D. F. Smith

/s/ D. H. Anderson

Director

Date: November 17, 2023

D. H. Anderson

/s/ B. M. Baumann

Director

Date: November 17, 2023

B. M. Baumann

/s/ D. C. Carroll

Director

Date: November 17, 2023

D. C. Carroll

/s/ S. C. Finch

Director

Date: November 17, 2023

S.C. Finch

/s/ J. N. Jaggers

Director

Date: November 17, 2023

J. N. Jaggers

/s/ R. Ranich

Director

Date: November 17, 2023

R. Ranich

/s/ J. W. Shaw

Director

Date: November 17, 2023

J. W. Shaw

/s/ T. E. Skains

Director

Date: November 17, 2023

T. E. Skains

/s/ R. J. Tanski

Director

Date: November 17, 2023

R. J. Tanski

/s/ D. P. Bauer

President and Chief Executive Officer and Director

Date: November 17, 2023

D. P. Bauer

/s/ T. J. Silverstein

Treasurer and Principal Financial Officer

Date: November 17, 2023

T. J. Silverstein

/s/ E. G. Mendel

Controller and Principal Accounting Officer

Date: November 17, 2023

E. G. Mendel

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