National Fuel Gas (NYSE: NFG) boosts earnings and lines up $2.62B Ohio utility deal

Rhea-AI Filing Summary

National Fuel Gas Company reported strong results for the quarter ended December 31, 2025, with net income available for common stock of $181.6 million, up from $45.0 million a year earlier. Operating revenues rose to $651.5 million from $549.5 million, driven mainly by its Integrated Upstream and Gathering and Utility segments.

Upstream operating revenues increased to $323.2 million on higher gas production volumes and better realized prices after hedging, and the prior-year included a large non‑cash impairment. Utility revenues grew to $259.0 million, helped by colder weather and new New York rates. Cash flow from operations was $274.9 million, supporting $277.6 million of capital expenditures and dividends. The company also issued 4.4 million common shares for net proceeds of $338.6 million to help fund a pending $2.62 billion acquisition of CenterPoint Ohio, which is expected to close in late calendar 2026, subject to regulatory reviews and customary conditions.

Positive

• Sharp earnings improvement: Net income available for common stock rose to $181.6 million from $45.0 million, aided by higher upstream prices/volumes and the absence of prior‑year non‑cash impairments totaling about $108.3 million.
• Transformative regulated acquisition: Agreement to acquire CenterPoint Ohio for $2.62 billion is expected to roughly double the gas utility rate base and expand regulated operations into Ohio.

Negative

• Higher future financing needs: The $2.62 billion CenterPoint Ohio purchase will be funded with $1.42 billion in cash and a $1.2 billion 6.5% promissory note, implying increased reliance on long‑term debt and equity financing.
• Regulatory and integration risk: Closing of the CenterPoint Ohio transaction depends on PUCO review, Hart‑Scott‑Rodino review and other conditions, and the company cites ongoing inflation and volatile interest rates as factors that may affect capital costs.

Insights

Equity and credit analyst

NFG posts sharply higher earnings and lines up equity for a large Ohio utility acquisition.

National Fuel Gas delivered net income of $181.6 million versus $45.0 million a year earlier. The swing reflects stronger Integrated Upstream and Gathering performance, higher natural gas prices and volumes, and the absence of prior‑year non‑cash impairments totaling about $108.3 million.

Operating cash flow of $274.9 million covered capital expenditures of $277.6 million, while the balance sheet showed total assets of $9.21 billion and long‑term debt (including current portion) of $2.68 billion at quarter‑end. The Integrated Upstream and Gathering segment earned $124.0 million, the Pipeline and Storage segment $31.2 million, and the Utility segment $34.1 million.

The pending acquisition of CenterPoint Ohio for $2.62 billion would roughly double the gas utility rate base and is to be funded with $1.42 billion in cash and a $1.2 billion 6.5% promissory note maturing 364 days after closing. Permanent financing will use long‑term debt, common equity and expected free cash flow, supported by a recent private placement of 4,402,513 shares at $79.50, raising net proceeds of $338.6 million. Future filings and regulatory approvals in Ohio and at federal agencies, along with execution on planned pipeline projects such as the Tioga Pathway and Shippingport Lateral, will frame how these commitments affect leverage and earnings mix.

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Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 10-Q

☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended December 31, 2025

OR

☐ 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

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 is a shell company (as defined in Rule 12b-2 of the Exchange Act).  Yes  ☐  No  ☑

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Common stock, par value $1.00 per share, outstanding at January 27, 2026: 95,026,423 shares.

Table of Content

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
PaPUC			Pennsylvania Public Utility Commission
PHMSA			Pipeline and Hazardous Materials Safety Administration
PUCO			Public Utilities Commission of Ohio
SEC			Securities and Exchange Commission

Other
2025 Form 10-K			The Company’s Annual Report on Form 10-K for the year ended September 30, 2025
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 or 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, forward contracts, options, no cost collars and swaps.
Development costs			Costs incurred to obtain access to proved gas and oil reserves and to provide facilities for extracting, treating, gathering and storing the gas and oil.

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Dth			Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
Exchange Act			Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets			Includes capital expenditures, stock acquisitions and/or investments in partnerships.
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.
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.
Hart-Scott-Rodino Act			The Hart-Scott-Rodino Antitrust Improvements Act of 1976, as amended, and the rules and regulations promulgated thereunder by the Federal Trade Commission.
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.
Mcf			Thousand cubic feet (of natural gas)
MD&A			Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth			Thousand decatherms (of natural gas)
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)
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

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Table of Content

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.
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 these reserves productive.
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
Section 7(b)/7(c) application			An application to the FERC under Section 7(b)/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.
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
Stock acquisitions			Investments in corporations.
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
WNA			Weather normalization adjustment; an 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.

4

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INDEX						Page
Part I. Financial Information
Item 1.  Financial Statements (Unaudited)						6
a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three Months Ended December 31, 2025 and 2024						6
b. Consolidated Statements of Comprehensive Income – Three Months Ended December 31, 2025 and 2024						7
c. Consolidated Balance Sheets – December 31, 2025 and September 30, 2025						8
d. Consolidated Statements of Cash Flows – Three Months Ended December 31, 2025 and 2024						10
e. Notes to Condensed Consolidated Financial Statements						11
Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations						26
Item 3.  Quantitative and Qualitative Disclosures About Market Risk						43
Item 4.  Controls and Procedures						43
Part II. Other Information
Item 1.  Legal Proceedings						44
Item 1 A.  Risk Factors						44
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds						46
Item 5.  Other Information						46
Item 6.  Exhibits						47
Signatures						48

    All references to a certain year in this report are to the Company’s fiscal year ended September 30 of that year, unless otherwise noted.

5

Table of Content

Part I.  Financial Information

Item 1.  Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)

			Three Months Ended December 31,
(Thousands of U.S. Dollars, Except Per Common Share Amounts)			2025						2024
INCOME
Operating Revenues:
Utility Revenues			$	259,047					$	228,424
Integrated Upstream and Gathering Revenues			323,223						252,308
Pipeline and Storage Revenues			69,237						68,750
			651,507						549,482
Operating Expenses:
Purchased Gas			85,606						65,337
Operation and Maintenance:
Utility			59,897						55,244
Integrated Upstream and Gathering and Other			56,306						42,905
Pipeline and Storage			26,786						26,577
Property, Franchise and Other Taxes			24,764						22,056
Depreciation, Depletion and Amortization			122,025						109,370
Impairment of Assets			—						141,802
			375,384						463,291
Operating Income			276,123						86,191
Other Income (Expense):
Other Income			8,233						7,720
Interest Expense on Long-Term Debt			(33,513)						(33,362)
Other Interest Expense			(9,861)						(4,381)
Income Before Income Taxes			240,982						56,168
Income Tax Expense			59,337						11,182
Net Income Available for Common Stock			181,645						44,986
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period			2,012,529						1,727,326
			2,194,174						1,772,312
Share Repurchases under Repurchase Plan			—						(26,993)
Dividends on Common Stock			(50,834)						(46,671)
Balance at December 31			$	2,143,340					$	1,698,648
Earnings Per Common Share:
Basic:
Net Income Available for Common Stock			$	1.99					$	0.50
Diluted:
Net Income Available for Common Stock			$	1.98					$	0.49
Weighted Average Common Shares Outstanding:
Used in Basic Calculation			91,171,715						90,777,446
Used in Diluted Calculation			91,962,479						91,434,741
Dividends Per Common Share:
Dividends Declared			$	0.535					$	0.515

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)

			Three Months Ended December 31,
(Thousands of U.S. Dollars)			2025						2024
Net Income Available for Common Stock			$	181,645					$	44,986
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period			49,098						(53,516)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income			(13,274)						(29,504)
Other Comprehensive Income (Loss), Before Tax			35,824						(83,020)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period			13,146						(14,403)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income			(3,554)						(7,940)
Income Taxes (Benefits) – Net			9,592						(22,343)
Other Comprehensive Income (Loss)			26,232						(60,677)
Comprehensive Income (Loss)			$	207,877					$	(15,691)

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)

			December 31, 2025						September 30, 2025
(Thousands of U.S. Dollars)
ASSETS
Property, Plant and Equipment			$	15,616,382					$	15,406,329
Less - Accumulated Depreciation, Depletion and Amortization			7,800,307						7,693,687
			7,816,075						7,712,642
Current Assets
Cash and Temporary Cash Investments			271,398						43,166
Receivables – Net of Allowance for Uncollectible Accounts of $17,504 and $17,099, Respectively			265,897						180,801
Unbilled Revenue			69,645						16,219
Gas Stored Underground			18,978						33,468
Materials and Supplies - at average cost			49,862						50,545
Unrecovered Purchased Gas Costs			20,723						5,769
Other Current Assets			62,097						80,759
			758,600						410,727
Other Assets
Recoverable Future Taxes			92,405						89,247
Unamortized Debt Expense			5,772						6,236
Other Regulatory Assets			133,604						135,486
Deferred Charges			75,570						73,941
Other Investments			68,962						68,346
Goodwill			5,476						5,476
Prepaid Pension and Post-Retirement Benefit Costs			171,569						169,228
Fair Value of Derivative Financial Instruments			69,364						39,388
Other			8,475						8,387
			631,197						595,735
Total Assets			$	9,205,872					$	8,719,104

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)

			December 31, 2025						September 30, 2025
(Thousands of U.S. Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value
Authorized  - 200,000,000 Shares; Issued And Outstanding – 95,017,438 Shares and 90,379,095 Shares, Respectively			$	95,017					$	90,379
Paid in Capital			1,382,593						1,050,918
Earnings Reinvested in the Business			2,143,340						2,012,529
Accumulated Other Comprehensive Loss			(32,990)						(59,222)
Total Comprehensive Shareholders’ Equity			3,587,960						3,094,604
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs			2,083,892						2,382,861
Total Capitalization			5,671,852						5,477,465
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper			90,000						150,200
Current Portion of Long-Term Debt			600,000						300,000
Accounts Payable			141,674						184,046
Amounts Payable to Customers			476						968
Dividends Payable			50,834						48,353
Interest Payable on Long-Term Debt			34,644						14,393
Customer Advances			17,108						17,188
Customer Security Deposits			29,875						29,853
Other Accruals and Current Liabilities			209,202						174,689
Fair Value of Derivative Financial Instruments			155						6,074
			1,173,968						925,764
Other Liabilities
Deferred Income Taxes			1,274,254						1,225,262
Taxes Refundable to Customers			304,370						306,335
Cost of Removal Regulatory Liability			311,971						307,659
Other Regulatory Liabilities			120,230						121,944
Other Post-Retirement Liabilities			3,731						5,252
Asset Retirement Obligations			234,405						236,787
Other Liabilities			111,091						112,636
			2,360,052						2,315,875
Commitments and Contingencies (Note 8)			—						—
Total Capitalization and Liabilities			$	9,205,872					$	8,719,104

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)

			Three Months Ended  December 31,
(Thousands of U.S. Dollars)			2025						2024
OPERATING ACTIVITIES
Net Income Available for Common Stock			$	181,645					$	44,986
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Impairment of Assets			—						141,802
Depreciation, Depletion and Amortization			122,025						109,370
Deferred Income Taxes			34,277						(5,385)
Stock-Based Compensation			4,094						4,705
Other			7,701						7,146
Change in:
Receivables and Unbilled Revenue			(138,565)						(115,165)
Gas Stored Underground and Materials and Supplies			15,173						10,180
Unrecovered Purchased Gas Costs			(14,954)						—
Other Current Assets			18,581						8,814
Accounts Payable			21,412						9,703
Amounts Payable to Customers			(492)						(133)
Customer Advances			(80)						(4,078)
Customer Security Deposits			22						(174)
Other Accruals and Current Liabilities			37,561						21,266
Other Assets			(5,085)						(3,892)
Other Liabilities			(8,394)						(9,057)
Net Cash Provided by Operating Activities			274,921						220,088
INVESTING ACTIVITIES
Capital Expenditures			(277,631)						(240,427)
Other			(1,255)						5,878
Net Cash Used in Investing Activities			(278,886)						(234,549)
FINANCING ACTIVITIES
Changes in Notes Payable to Banks and Commercial Paper			(60,200)						109,300
Shares Repurchased Under Repurchase Plan			—						(33,524)
Dividends Paid on Common Stock			(48,353)						(46,872)
Net Proceeds from Common Stock Sale			347,106						—
Net Repurchases of Common Stock Under Stock and Benefit Plans			(6,356)						(3,971)
Net Cash Provided by Financing Activities			232,197						24,933
Net Increase in Cash and Cash Equivalents			228,232						10,472
Cash and Cash Equivalents at October 1			43,166						38,222
Cash and Cash Equivalents at December 31			$	271,398					$	48,694
Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:
Non-Cash Capital Expenditures			$	70,359					$	71,616
Non-Cash Financing Activities:
Non-Cash Accrued Placement Fees from Common Stock Sale			$	8,531					$	—

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 – 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 exploration and production 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.

Reclassifications. As reported in the Company's 2025 Form 10-K, during the quarter ended September 30, 2025, the segment reporting structure was modified to merge the Exploration and Production segment and Gathering segment into one reportable segment called Integrated Upstream and Gathering. As a result, revenue and operation and maintenance expense line items on the consolidated statements of income in prior periods have been reclassified to conform to the current year presentation. Additional discussion is provided at Note 9 — Business Segment Information.

Earnings for Interim Periods.  The Company, in its opinion, has included all adjustments (which consist of only normally recurring adjustments, unless otherwise disclosed in this Quarterly Report on Form 10-Q) that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2025, 2024 and 2023 that are included in the Company's 2025 Form 10-K.  The consolidated financial statements for the year ended September 30, 2026 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.

    The earnings for the three months ended December 31, 2025 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2026.  Most of the business of the Utility segment is seasonal in nature and is influenced by weather conditions.  Due to the seasonal nature of the heating business in the Utility segment, earnings during the winter months normally represent a substantial part of the earnings that this business is expected to achieve for the entire fiscal year.  The Company’s business segments are discussed more fully in Note 9 – Business Segment Information.

Consolidated Statements of Cash Flows.  The Statement of Cash Flows for the three months ended December 31, 2025 and the three months ended December 31, 2024 reconciles the net increase in cash and cash equivalents, which consists solely of cash and temporary cash investments for the periods presented. The Company did not have any restricted cash at December 31, 2025, October 1, 2025, December 31, 2024 or October 1, 2024. The Company considers all highly liquid debt instruments purchased with a maturity date of generally three months or less to be equivalents.

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. Starting in the quarter ended March 31, 2025, account balances are being written-off against the allowance approximately three months after the account is final billed or when it is anticipated that the receivable will not be recovered. This change in policy was initiated to better match the timing of write-offs with the recovery of uncollectible expense in rates and resulted in a one-time cumulative adjustment to the allowance during the quarter ended March 31, 2025.

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    Activity in the allowance for uncollectible accounts for the three months ended December 31, 2025 and 2024 are as follows (in thousands):

			Balance at Beginning of Period						Additions Charged to Costs and Expenses						Discounts on Purchased Receivables						Net Accounts Receivable Written-Off						Balance at End of Period
Three Months Ended December 31, 2025
Allowance for Uncollectible Accounts			$	17,099					$	5,214					$	121					$	(4,930)					$	17,504
Three Months Ended December 31, 2024
Allowance for Uncollectible Accounts			$	26,194					$	4,605					$	107					$	(2,522)					$	28,384

Gas Stored Underground.  In the Utility segment, gas stored underground is carried at lower of cost or net realizable value, on a LIFO method.  Gas stored underground normally declines during the first and second quarters of the year as storage quantities are withdrawn and increases in the third and fourth quarters as storage quantities are replenished.  In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.”  Such reserve, which amounted to $2.8 million at December 31, 2025, is reduced to zero by September 30 of each year as the inventory is replenished.

Property, Plant and Equipment.  In the Company’s Integrated Upstream and Gathering segment, upstream property acquisition, exploration and development costs are accounted for under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves attributable to a cost center. The Company's capitalized costs relating to exploration and production activities, net of accumulated depreciation, depletion and amortization, were $2.51 billion and $2.46 billion at December 31, 2025 and September 30, 2025, respectively.

    Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. Such costs amounted to $105.7 million and $112.4 million at December 31, 2025 and September 30, 2025, respectively. 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.

    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 commodity pricing (as adjusted for hedging) to estimated future production of proved 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 commodity prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of first day of the month commodity price 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 December 31, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $1.3 billion. The book value of the exploration and production properties exceeded the ceiling at December 31, 2024. As such, the Company recognized a non-cash, pre-tax ceiling test impairment charge in the Integrated Upstream and Gathering segment of $108.3 million for the quarter ended December 31, 2024. A deferred income tax benefit of $29.2 million related to the non-cash impairment charge was also recognized for the quarter ended December 31, 2024. In adjusting estimated future net cash flows for hedging under the ceiling test at December 31, 2025, estimated future net cash flows were increased by $170.7 million.

    The Integrated Upstream and Gathering segment also has items of property, plant and equipment that are accounted for outside of the provisions of the full cost method of accounting, including water disposal assets used in its upstream operations as well as gathering lines and compressor stations associated with its gathering operations, all of which are recorded at

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historical cost. As discussed in Note 4 – Fair Value Measurements, an impairment charge related to certain water disposal assets was recorded in the Integrated Upstream and Gathering segment at December 31, 2024.

    The principal assets of the Utility and Pipeline and Storage segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities and compressor stations, are recorded at historical cost. There were no indications of any impairments to property, plant and equipment in the Utility and Pipeline and Storage segments at December 31, 2025.

Accumulated Other Comprehensive Income (Loss). The components of Accumulated Other Comprehensive Income (Loss) and changes for the three months ended December 31, 2025 and 2024, net of related tax effect, 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
Three Months Ended December 31, 2025
Balance at October 1, 2025			$	19,950											$	(79,172)					$	(59,222)
Other Comprehensive Gains and Losses Before Reclassifications			35,952												—						35,952
Amounts Reclassified From Other Comprehensive Loss			(9,720)												—						(9,720)
Balance at December 31, 2025			$	46,182											$	(79,172)					$	(32,990)
Three Months Ended December 31, 2024
Balance at October 1, 2024			$	55,799											$	(71,275)					$	(15,476)
Other Comprehensive Gains and Losses Before Reclassifications			(39,113)												—						(39,113)
Amounts Reclassified From Other Comprehensive Loss			(21,564)												—						(21,564)
Balance at December 31, 2024			$	(4,878)											$	(71,275)					$	(76,153)

Reclassifications Out of Accumulated Other Comprehensive Income (Loss).  The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the three months ended December 31, 2025 and 2024 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):

Details About Accumulated Other Comprehensive Income (Loss) Components						Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss)												Affected Line Item in the Statement Where Net Income is Presented
						Three Months Ended December 31,
						2025						2024
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts						$13,395						$29,729																		Operating Revenues
Foreign Currency Contracts						(121)						(225)																		Operating Revenues
						13,274						29,504																		Total Before Income Tax
						(3,554)						(7,940)																		Income Tax Expense
						$9,720						$21,564																		Net of Tax

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Other Current Assets.  The components of the Company’s Other Current Assets are as follows (in thousands):

			At December 31, 2025						At September 30, 2025
Prepayments			$	13,854					$	16,477
Prepaid Property and Other Taxes			13,855						13,920
Federal Income Taxes Receivable			—						14,511
State Income Taxes Receivable			—						489
Regulatory Assets			34,388						35,362
			$	62,097					$	80,759

Other Accruals and Current Liabilities.  The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):

			At December 31, 2025						At September 30, 2025
Accrued Capital Expenditures			$	47,178					$	45,932
Regulatory Liabilities			26,367						20,624
Reserve for Gas Replacement			2,799						—
Liability for Royalty and Working Interests			36,608						28,076
Federal Income Taxes Payable			5,384						—
State Income Taxes Payable			4,676						—
Pennsylvania Impact Fee			19,955						14,923
Non-Qualified Benefit Plan Liability			11,567						11,567
Other			54,668						53,567
			$	209,202					$	174,689

Earnings Per Common Share.  Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock.  For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding were restricted stock units and performance shares. For the quarter ended December 31, 2025, 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. Restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 30 securities and four securities excluded as being antidilutive for the quarters ended December 31, 2025 and December 31, 2024, respectively.

Share Repurchases. The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is traded as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings.

Stock-Based Compensation.  The Company granted 137,995 performance shares during the quarter ended December 31, 2025. The weighted average fair value of such performance shares was $62.07 per share for the quarter ended December 31, 2025. Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied.  Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period.

    The performance shares granted during the quarter ended December 31, 2025 include awards that must meet a performance goal related to relative total shareholder return over a three-year performance cycle ("TSR Performance Shares"). The performance goal related to the TSR Performance Shares over the three-year performance cycle is the Company’s three-year total shareholder return relative to the three-year total shareholder return of other companies in a group selected by the

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Compensation Committee ("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.

    The Company granted 128,755 restricted stock units during the quarter ended December 31, 2025.  The weighted average fair value of such restricted stock units was $77.75 per share for the quarter ended December 31, 2025.  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. These restricted stock units do not entitle the participant to receive dividends during the vesting period. 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.

Note 2 – Pending Acquisition

    On October 20, 2025, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with CenterPoint Energy Resources Corp. (the “Seller”), pursuant to which, among other things, the Company agreed to acquire from the Seller all of the issued and outstanding equity interests of Vectren Energy Delivery of Ohio, LLC (“CenterPoint Ohio”) for an aggregate purchase price of $2.62 billion, subject to customary adjustments, as provided in the Purchase Agreement. This acquisition will add significant regulated scale for the Company, doubling the size of the Company’s gas utility rate base, while expanding its operations beyond New York and Pennsylvania into the neighboring state of Ohio, a state with a constructive regulatory and political environment that is supportive of natural gas. Closing is expected to occur in the fourth quarter of calendar 2026, pending completion of a notice filing and review with the PUCO, Hart-Scott-Rodino review, and other customary closing conditions. The purchase price will include a combination of $1.42 billion in cash and a $1.2 billion promissory note to be issued by the Company to the Seller at closing. The promissory note, which was part of the Seller’s desired transaction structure and was incorporated into the Company’s business valuation, will have a maturity date of 364 days post-closing and will carry an interest rate of 6.5%. Permanent financing, inclusive of the amount to repay the promissory note, will consist of long-term debt and common equity, along with expected future free cash flow. In that regard, on December 17, 2025, the Company completed the issuance and sale, in a private placement, of 4,402,513 shares of the Company's common stock, par value $1.00 per share, at a price of $79.50 per share. After deducting placement fees, the net proceeds to the Company amounted to $338.6 million.

    In connection with its entry into the Purchase Agreement, the Company entered into a senior unsecured bridge loan facility commitment letter supported by The Toronto-Dominion Bank (“TD Bank”), New York Branch and Wells Fargo Bank, National Association (together with TD Bank, the “Commitment Parties”), as well as a 364-day term loan facility commitment letter supported by the Commitment Parties and additional banks, all of which are lenders under the Company’s primary credit facility. The combination of both facilities fully supports any portion of the purchase price that has not been permanently financed.

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Note 3 – Revenue from Contracts with Customers

    The following tables provide a disaggregation of the Company's revenues for the three months ended December 31, 2025 and 2024, presented by type of service from each reportable segment. As reported in the Company's 2025 Form 10-K, the segment reporting structure was modified to merge the Exploration and Production segment and Gathering segment into one reportable segment called Integrated Upstream and Gathering. Prior year disaggregation of revenue information shown below has been restated to reflect this change in presentation.

Quarter Ended December 31, 2025 (Thousands)
Revenues By Type of Service			Integrated Upstream and Gathering						Pipeline and Storage						Utility						Total Reportable Segments						All Other						Corporate and Intersegment Eliminations						Total Consolidated
Production of Natural Gas			$	302,460					$	—					$	—					$	302,460					$	—					$	—					$	302,460
Production of Crude Oil			292						—						—						292						—						—						292
Natural Gas Processing			164						—						—						164						—						—						164
Natural Gas Gathering Service			2,767						—						—						2,767						—						—						2,767
Natural Gas Transportation Service			—						81,008						32,618						113,626						—						(26,757)						86,869
Natural Gas Storage Service			—						25,137						—						25,137						—						(10,715)						14,422
Natural Gas Residential Sales			—						—						198,008						198,008						—						—						198,008
Natural Gas Commercial Sales			—						—						27,877						27,877						—						—						27,877
Natural Gas Industrial Sales			—						—						1,409						1,409						—						(1)						1,408
Other			4,145						756						(1,024)						3,877						—						(281)						3,596
Total Revenues from Contracts with Customers			309,828						106,901						258,888						675,617						—						(37,754)						637,863
Alternative Revenue Programs			—						—						249						249						—						—						249
Derivative Financial Instruments			13,395						—						—						13,395						—						—						13,395
Total Revenues			$	323,223					$	106,901					$	259,137					$	689,261					$	—					$	(37,754)					$	651,507

Quarter Ended December 31, 2024 (Thousands)
Revenues By Type of Service			Integrated Upstream and Gathering						Pipeline and Storage						Utility						Total Reportable Segments						All Other						Corporate and Intersegment Eliminations						Total Consolidated
Production of Natural Gas			$	217,458					$	—					$	—					$	217,458					$	—					$	—					$	217,458
Production of Crude Oil			515						—						—						515						—						—						515
Natural Gas Processing			275						—						—						275						—						—						275
Natural Gas Gathering Service			3,448						—						—						3,448						—						—						3,448
Natural Gas Transportation Service			—						81,204						26,921						108,125						—						(27,181)						80,944
Natural Gas Storage Service			—						24,993						—						24,993						—						(10,504)						14,489
Natural Gas Residential Sales			—						—						156,350						156,350						—						—						156,350
Natural Gas Commercial Sales			—						—						22,243						22,243						—						—						22,243
Natural Gas Industrial Sales			—						—						1,338						1,338						—						(1)						1,337
Other			883						415						15,740						17,038						—						(261)						16,777
Total Revenues from Contracts with Customers			222,579						106,612						222,592						551,783						—						(37,947)						513,836
Alternative Revenue Programs			—						—						5,917						5,917						—						—						5,917
Derivative Financial Instruments			29,729						—						—						29,729						—						—						29,729
Total Revenues			$	252,308					$	106,612					$	228,509					$	587,429					$	—					$	(37,947)					$	549,482

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    The Company records revenue related to its derivative financial instruments in the Integrated Upstream and Gathering 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.

    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: $174.8 million for the remainder of fiscal 2026; $218.7 million for fiscal 2027; $164.2 million for fiscal 2028; $130.8 million for fiscal 2029; $123.8 million for fiscal 2030; and $540.0 million thereafter.

Note 4 – 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 December 31, 2025 and September 30, 2025. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement.  

Recurring Fair Value Measures			At fair value as of December 31, 2025
(Thousands of Dollars)			Level 1						Level 2						Level 3						Netting Adjustments(1)						Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds			$	260,901					$	—					$	—					$	—					$	260,901
Derivative Financial Instruments:
Over the Counter Swaps – Gas			—						84,228						—						(32,868)						51,360
Over the Counter No Cost Collars – Gas			—						26,413						—						(8,154)						18,259
Foreign Currency Contracts			—						184						—						(439)						(255)
Other Investments:
Balanced Equity Mutual Fund			14,183						—						—						—						14,183
Fixed Income Mutual Fund			10,203						—						—						—						10,203
Total			$	285,287					$	110,825					$	—					$	(41,461)					$	354,651
Liabilities:
Derivative Financial Instruments:
Over the Counter Swaps – Gas			$	—					$	32,868					$	—					$	(32,868)					$	—
Over the Counter No Cost Collars – Gas			—						8,154						—						(8,154)						—
Foreign Currency Contracts			—						594						—						(439)						155
Total			$	—					$	41,616					$	—					$	(41,461)					$	155
Total Net Assets/(Liabilities)			$	285,287					$	69,209					$	—					$	—					$	354,496

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Recurring Fair Value Measures			At fair value as of September 30, 2025
(Thousands of Dollars)			Level 1						Level 2						Level 3						Netting Adjustments(1)						Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds			$	30,551					$	—					$	—					$	—					$	30,551
Derivative Financial Instruments:
Over the Counter Swaps – Gas			—						62,190						—						(33,615)						28,575
Over the Counter No Cost Collars – Gas			—						24,149						—						(12,805)						11,344
Foreign Currency Contracts			—						144						—						(675)						(531)
Other Investments:
Balanced Equity Mutual Fund			13,786						—						—						—						13,786
Fixed Income Mutual Fund			10,082						—						—						—						10,082
Total			$	54,419					$	86,483					$	—					$	(47,095)					$	93,807
Liabilities:
Derivative Financial Instruments:
Over the Counter Swaps – Gas			$	—					$	34,169					$	—					$	(33,615)					$	554
Over the Counter No Cost Collars – Gas			—						18,036						—						(12,805)						5,231
Foreign Currency Contracts			—						893						—						(675)						218
Total			$	—					$	53,098					$	—					$	(47,095)					$	6,003
Total Net Assets/(Liabilities)			$	54,419					$	33,385					$	—					$	—					$	87,804

(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.

    The following table presents impairments of assets associated with certain nonrecurring fair value measurements within Level 3 of the fair value hierarchy as of December 31, 2025 and 2024 (in thousands):

																					Impairments
Nonrecurring Fair Value Measures																					Quarter Ended December 31,
			Segment						Date of Measurement						Fair Value						2025						2024
Impairment of Assets:
Water Disposal Assets			Integrated Upstream and Gathering						December 31, 2024						$	12,880					$	—					$	33,453

    In exploring the potential sale of certain water disposal assets during the quarter ended December 31, 2024, the Company determined that the fair market value of such assets was less than the recorded net book value resulting in an impairment charge that reduced the net book value to fair market value. These assets are used to dispose of water from operations in the Integrated Upstream and Gathering segment.

Derivative Financial Instruments

    The derivative financial instruments reported in Level 2 at December 31, 2025 and September 30, 2025 include natural gas price swap agreements, natural gas no cost collars, and foreign currency contracts, all of which are used in the Company’s Integrated Upstream and Gathering segment. 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 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 December 31, 2025, 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.

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Note 5 – 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 (in thousands): 

			December 31, 2025												September 30, 2025
			Carrying Amount						Fair Value						Carrying Amount						Fair Value
Long-Term Debt			$	2,683,892					$	2,695,409					$	2,682,861					$	2,696,145

    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 or SOFR 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.

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

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

			At December 31, 2025						At September 30, 2025
Life Insurance Contracts			$	44,576					$	44,478
Equity Mutual Fund			14,183						13,786
Fixed Income Mutual Fund			10,203						10,082
			$	68,962					$	68,346

    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 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 Integrated Upstream and Gathering 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 Integrated Upstream and Gathering segment. These instruments are accounted for as cash flow hedges. The duration of the Company’s cash flow hedges and foreign currency forward contracts do not typically exceed 5 years.

    The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at December 31, 2025 and September 30, 2025.

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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    As of December 31, 2025, the Company had 403.1 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.

    As of December 31, 2025, the Company was hedging a total of $41.0 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

    As of December 31, 2025, the Company had $46.2 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance. Of this amount, it is expected that $45.9 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 Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended December 31, 2025 and 2024 (Thousands of Dollars)
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  Three Months Ended  December 31,						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  Three Months Ended  December 31,
			2025			2024						2025			2024
Commodity Contracts			$	48,880		$	(51,909)		Operating Revenue			$	13,395		$	29,729
Foreign Currency Contracts			218			(1,607)			Operating Revenue			(121)			(225)
Total			$	49,098		$	(53,516)					$	13,274		$	29,504

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 seventeen counterparties of which sixteen are in a net gain position. On average, the Company had $4.3 million of credit exposure per counterparty in a gain position at December 31, 2025. The maximum credit exposure per counterparty in a gain position at December 31, 2025 was $10.8 million. As of December 31, 2025, 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.

    Certain counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps, over-the-counter no cost collars and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit that could be extended to the Company when it is in a derivative financial liability position 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 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 December 31, 2025, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $0.2 million according to the Company's internal model (discussed in Note 4 – Fair Value Measurements), and no hedging collateral deposits were required to be posted by the Company at December 31, 2025. 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.

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    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 6 – Income Taxes

    The effective tax rates for the quarters ended December 31, 2025 and December 31, 2024 were 24.6% and 19.9%, respectively. The increase in the quarterly effective income tax rate was primarily driven by the impact of the impairments of exploration and production properties under the ceiling test and other operational assets recorded during the quarter ended December 31, 2024, which resulted in a smaller income tax expense on income before income taxes during the quarter ended December 31, 2024.

Note 7 – Capitalization

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)
Balance at October 1, 2025			90,379						$	90,379					$	1,050,918					$	2,012,529					$	(59,222)
Net Income Available for Common Stock																					181,645
Dividends Declared on Common Stock ($0.535 Per Share)																					(50,834)
Other Comprehensive Income, Net of Tax																											26,232
Share-Based Payment Expense (1)															3,427
Common Stock Issued from Sale of Common Stock			4,403						4,403						334,173
Common Stock Issued (Repurchased) Under Stock and Benefit Plans			235						235						(5,925)
Balance at December 31, 2025			95,017						$	95,017					$	1,382,593					$	2,143,340					$	(32,990)
Balance at October 1, 2024			91,006						$	91,006					$	1,045,487					$	1,727,326					$	(15,476)
Net Income Available for Common Stock																					44,986
Dividends Declared on Common Stock ($0.515 Per Share)																					(46,671)
Other Comprehensive Loss, Net of Tax																											(60,677)
Share-Based Payment Expense (1)															4,090
Common Stock Issued (Repurchased) Under Stock and Benefit Plans			156						156						(3,511)
Share Repurchases Under Repurchase Plan			(549)						$	(549)					$	(6,361)					$	(26,993)
Balance at December 31, 2024			90,613						$	90,613					$	1,039,705					$	1,698,648					$	(76,153)

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

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Common Stock.  Common stock share activity during the three months ended December 31, 2025 consisted of the following items:

			Three Months Ended December 31, 2025
Vesting of Restricted Stock Units			138,643
Vesting of Performance Shares			167,241
Issuance of Common Stock Pursuant to the Company's Non-Employee Director Equity Compensation Plan and Deferred Compensation Plan for Directors and Officers			7,368
Shares Tendered to Pay Withholding Taxes on Stock-Based Compensation Awards (1)			(77,422)
Common Stock Issued Under Stock and Benefit Plans			235,830
Common Stock Issued from Sale of Common Stock			4,402,513
Total Common Stock Issued During the Three Months Ended December 31, 2025			4,638,343

(1)    The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

    On December 17, 2025, the Company completed the issuance and sale, in a private placement, of 4,402,513 shares of the Company's common stock, par value $1.00 per share, at a price of $79.50 per share. After deducting placement fees, the net proceeds to the Company amounted to $338.6 million. The proceeds of this issuance were used for general corporate purposes, including to fund a portion of the purchase price of the Company's previously announced acquisition of CenterPoint Energy Resources Corp.'s Ohio regulated gas utility business. Refer to Note 2 – Pending Acquisition for further discussion.

Current Portion of Long-Term Debt. The Current Portion of Long-Term Debt at December 31, 2025 consisted of a $300.0 million long-term delayed draw term loan scheduled to mature in February 2026 that was repaid in January 2026 and $300.0 million of 5.50% notes with a maturity date in October 2026. The Current Portion of Long-Term Debt at September 30, 2025 consisted of the aforementioned $300.0 million long-term delayed draw term loan with a maturity date in February 2026.

Delayed Draw Term Loan. On February 14, 2024, the Company entered into a Term Loan Agreement (the “Term Loan Agreement”) with six lenders, all of which are lenders under the Credit Agreement. As of January 22, 2026, the Company repaid the $300.0 million drawn under the Term Loan Agreement and the agreement was therefore terminated. The Term Loan Agreement provided a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company had the ability to select interest periods of one, three or six months for borrowings. In April 2024, pursuant to the delayed draw mechanism, the Company elected to draw a total of $300.0 million under the facility. After deducting debt issuance costs, the net proceeds to the Company amounted to $299.4 million. Borrowings under the Term Loan Agreement bear interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10%, plus a spread of 1.375%.

Note 8 – Commitments and Contingencies

Environmental Matters.  The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment.  The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory requirements.  It is the Company’s policy to accrue estimated environmental clean-up costs (investigation and remediation) when such amounts can reasonably be estimated and it is probable that the Company will be required to incur such costs.

    At December 31, 2025, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $2.9 million.  The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at December 31, 2025. The Company has a regulatory liability of $1.5 million related to environmental clean-up costs at December 31, 2025 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.

Other.  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 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

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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 9 – Business Segment Information    

    The Company reports financial results for three segments: Integrated Upstream and Gathering, Pipeline and Storage, and Utility. The division of the Company’s operations into reportable segments is based on a combination of factors including differences in products and services as well as regulatory environments. As reported in the Company's 2025 Form 10-K, the segment reporting structure was modified to merge the Exploration and Production segment and Gathering segment into one reportable segment called Integrated Upstream and Gathering. Prior year segment information shown below has been recast to reflect this change in presentation. The Company's Chief Executive Officer, its Chief Operating Decision Maker (CODM), evaluates segment performance primarily using earnings attributable to the Company. External reporting is consistent with the internal financial reports used by the CODM to regularly assess performance of the business, make operating decisions and allocate resources.

    The Integrated Upstream and Gathering segment is composed of the operations of Seneca and Midstream Company. Seneca is engaged in the exploration for and development of natural gas reserves in the Appalachian region of the United States. Midstream Company builds, owns and operates natural gas processing and pipeline gathering facilities in the Appalachian region, primarily providing gathering services to Seneca.

    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 serving 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 utilities (including Distribution Corporation), natural gas marketers and exploration and production companies (including Seneca) from 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 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 reconciles to consolidated amounts.  As stated in the 2025 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, when applicable.  If discontinued operations are not applicable, the Company evaluates performance based on net income.  There have been no changes in the basis of segmentation or in the basis of measuring segment profit or loss from those used in the Company’s 2025 Form 10-K.  A listing of segment assets at December 31, 2025 and December 31, 2024 is shown in the tables below.

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			Three Months Ended December 31, 2025
			Integrated Upstream and Gathering						Pipeline and Storage									Utility						Total Reportable Segments						All    Other(4)						Corporate and Intersegment   Eliminations(4)						Total Consolidated
			(Thousands)
Revenue from External Customers(1)			$	323,223					$	69,237								$	259,047					$	651,507					$	—					$	—					$	651,507
Intersegment Revenues			—						37,664									90						37,754						—						(37,754)						—
Total Revenues			323,223						106,901									259,137						689,261						—						(37,754)						651,507
Operation and Maintenance Expense(2):
Upstream General and Administrative Expense			19,406						—									—						19,406						—						(63)						19,343
Lease Operating Expense			16,826						—									—						16,826						—						(789)						16,037
Gathering Operation and Maintenance Expense			10,388						—									—						10,388						—						(69)						10,319
All Other Operation and Maintenance Expense			3,378						27,263									60,997						91,638						—						5,652						97,290
Purchased Gas Expense(2)			—						—									122,285						122,285						—						(36,679)						85,606
Depreciation, Depletion and Amortization Expense(2)			84,263						19,102									18,479						121,844						—						181						122,025
Impairment of Assets (Significant Non-Cash Item)(2)			—						—									—						—						—						—						—
Interest Expense(2)			16,133						11,801									11,606						39,540						136						3,698						43,374
Interest Income			(193)						(964)									(1,039)						(2,196)						(10)						(571)						(2,777)
Income Tax Expense (Benefit)(2)			44,111						10,366									7,335						61,812						(37)						(2,438)						59,337
Other Expense (Income) Items(3)			4,864						8,114									5,384						18,362						33						913						19,308
Segment Profit: Net Income (Loss)			$	124,047					$	31,219								$	34,090					$	189,356					$	(122)					$	(7,589)					$	181,645
Expenditures for Additions to Long-Lived Assets			$	141,849					$	37,602								$	43,094					$	222,545					$	—					$	176					$	222,721
			Integrated Upstream and Gathering						Pipeline and Storage									Utility						Total Reportable Segments						All    Other(4)						Corporate and Intersegment   Eliminations(4)						Total Consolidated
			(Thousands)
Segment Assets:
At December 31, 2025			$	3,925,191					$	2,504,541								$	2,645,957					$	9,075,689					$	8,565					$	121,618					$	9,205,872
At September 30, 2025			$	3,701,646					$	2,412,747								$	2,534,289					$	8,648,682					$	8,704					$	61,718					$	8,719,104

			Three Months Ended December 31, 2024
			Integrated Upstream and Gathering						Pipeline and Storage									Utility						Total Reportable Segments						All    Other(4)						Corporate and Intersegment   Eliminations(4)						Total Consolidated
			(Thousands)
Revenue from External Customers(1)			$	252,308					$	68,750								$	228,424					$	549,482					$	—					$	—					$	549,482
Intersegment Revenues			—						37,862									85						37,947						—						(37,947)						—
Total Revenues			252,308						106,612									228,509						587,429						—						(37,947)						549,482
Operation and Maintenance Expense(2):
Upstream General and Administrative Expense			19,326						—									—						19,326						—						(59)						19,267
Lease Operating Expense			10,651						—									—						10,651						—						(1,587)						9,064
Gathering Operation and Maintenance Expense			6,735						—									—						6,735						—						(65)						6,670
All Other Operation and Maintenance Expense			3,867						27,034									56,260						87,161						—						2,564						89,725
Purchased Gas Expense(2)			—						—									101,473						101,473						—						(36,136)						65,337
Depreciation, Depletion and Amortization Expense(2)			73,819						18,585									16,827						109,231						—						139						109,370
Impairment of Assets (Significant Non-Cash Item)(2)			141,802						—									—						141,802						—						—						141,802
Interest Expense(2)			19,410						11,729									10,716						41,855						116						(4,228)						37,743
Interest Income			(679)						(2,006)									(648)						(3,333)						—						1,650						(1,683)
Income Tax Expense (Benefit)(2)			(6,451)						11,177									7,022						11,748						(59)						(507)						11,182
Other Expense (Income) Items(3)			3,460						7,639									4,360						15,459						136						424						16,019
Segment Profit: Net Income (Loss)			$	(19,632)					$	32,454								$	32,499					$	45,321					$	(193)					$	(142)					$	44,986
Expenditures for Additions to Long-Lived Assets			$	135,629					$	19,792								$	36,430					$	191,851					$	—					$	204					$	192,055

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

(2)The Company considers this line to be a significant expense.

(3)Consists of Property, Franchise and Other Taxes, Non-Service Pension and Post-Retirement Benefits Costs (Credits), Other (Income) Deductions, and Purchased Gas Expense for the Pipeline and Storage Segment.

(4)Corporate and All Other categories primarily represent other non-segment business activities and eliminating entries.

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Note 10 – Retirement Plan and Other Post-Retirement Benefits

    Components of Net Periodic Benefit Cost (in thousands):

			Retirement Plan									Other Post-Retirement Benefits
Three Months Ended December 31,			2025			2024						2025			2024
Service Cost			$	861		$	1,023					$	105		$	130
Interest Cost			8,944			9,223						3,836			3,625
Expected Return on Plan Assets			(14,710)			(14,647)						(7,374)			(6,536)
Amortization of Prior Service Cost (Credit)			63			76						(65)			(107)
Amortization of (Gains) Losses			2,421			1,620						152			9
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)			(98)			(165)						(148)			(727)
Net Periodic Benefit Cost (Income)			$	(2,519)		$	(2,870)					$	(3,494)		$	(3,606)

(1)The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.

    The components of net periodic benefit cost other than service cost are presented in Other Income (Deductions) on the Consolidated Statements of Income.

Employer Contributions.    The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the three months ended December 31, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2026. The Company also did not make any contributions to its VEBA trusts for its other post-retirement benefits during the three months ended December 31, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2026.

Note 11 – Regulatory Matters

New York Jurisdiction

    Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on December 19, 2024 with rates effective January 1, 2025 (“2024 Rate Order”). The 2024 Rate Order authorizes a three-year rate plan effective October 1, 2024, with a make-whole provision allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024. It also reflects a return on equity of 9.7% and authorized a revenue requirement increase of $57.3 million in fiscal 2025, an additional revenue requirement increase of $15.8 million in fiscal 2026, and an additional revenue requirement increase of $12.7 million in fiscal 2027. These revenue requirement increases are being reflected in customer bills on a levelized basis over the three-year rate plan. The revenue requirement for each year of the three-year plan has been reduced by $14 million for actuarial projections of income that is expected to be recognized for qualified pension and other post-retirement benefits. Qualified pension and other post-retirement benefit income or costs are matched with amounts included in revenue resulting in zero impact to earnings. The 2024 Rate Order approves the continuation of several ratemaking mechanisms, including revenue decoupling and WNA, and establishes a number of new cost trackers and regulatory deferrals. It also includes an earnings sharing mechanism, gas safety and customer service performance metrics (including maintaining the Company’s leak prone pipe replacement program), and provisions that will facilitate achievement of the emissions reduction goals of the CLCPA.

Pennsylvania Jurisdiction

    Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC in an order issued on June 15, 2023 with rates effective August 1, 2023 (“2023 Rate Order”). The 2023 Rate Order provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million and authorized a new weather normalization adjustment mechanism. On January 28, 2026, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $19.7 million with a proposed effective date of March 29, 2026. The Company is proposing, among other things, a new residential energy efficiency pilot program and to make

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permanent its weather normalization adjustment mechanism.  The Company is also proposing reactivation of the OPEB surcredit (Rider I) to refund $7.2 million for customer bill relief.  The filing will be suspended for seven months by operation of law unless directed otherwise by the PaPUC.

    On April 10, 2024, Distribution Corporation filed with the PaPUC a petition for approval of a distribution system improvement charge (“DSIC”) to recover, between base rate cases, capital expenses related to eligible property constructed or installed to rehabilitate, improve and replace portions of the Company’s natural gas distribution system. The DSIC petition was approved by the PaPUC on December 5, 2024, and on January 1, 2025, the Company initiated recovery of eligible costs on incremental rate base added after September 30, 2024. During the quarter ended December 31, 2025, Distribution Corporation recovered $1.1 million from customers. The DSIC will be reset to zero when new base rates become effective as a result of the Company's recent rate filing.

FERC Jurisdiction

    Supply Corporation’s rate settlement was approved June 11, 2024, with rates effective February 1, 2024, and provides that Supply Corporation may make a rate filing for new rates to be effective at any time. As well, any party can make a filing under NGA Section 5. Supply Corporation has no rate case currently on file.

    On March 17, 2025, FERC approved an amendment to Empire's 2019 rate case settlement, which provides for a modest reduction in Empire’s transportation unit rates, effective November 1, 2025. This settlement amendment is estimated to decrease Empire's revenues on a yearly basis by approximately $0.5 million. Empire will not be able to file a new Section 4 rate case before April 30, 2027 and is required to file a Section 4 rate case by May 31, 2031.

Item 2.  Management's Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

    Please note that this overview is a high-level summary of items that are discussed in greater detail in subsequent sections of this report.

    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. 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. In addition to expansion projects, the Company continues to focus on the ongoing modernization of its regulated Pipeline and Storage and Utility assets. The Company reports financial results for three business segments. For a discussion of the Company's earnings, refer to the Results of Operations section below.

    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, is an expansion and modernization project in northwest Tioga County, Pennsylvania. On May 5, 2025, FERC issued the Section 7(b)/7(c) certificate for the project and on January 8, 2026, FERC issued the Notice to Proceed with Construction. Construction on the Tioga Pathway Project is expected to commence in February 2026. This project has a target in-service date in late calendar 2026.

    Supply Corporation has also announced that it expects to serve as the transporter of natural gas supplies to the Shippingport Power Station, a natural gas power generation facility under development in Beaver County, Pennsylvania. The project obtained FERC authorization under the Commission’s prior notice regulations on November 7, 2025. The Tioga Pathway Project and the Shippingport Lateral Project are both discussed in more detail in the Capital Resources and Liquidity section that follows.

    From a rate perspective, Distribution Corporation, in its New York jurisdiction, reached a settlement with the parties to its rate case proceeding. On December 19, 2024, the NYPSC issued an order approving the settlement. The settlement, effective January 1, 2025, established a three-year rate plan that reflects a return on equity of 9.7% and authorized a revenue requirement increase of $57.3 million in fiscal 2025, an additional revenue requirement increase of $15.8 million in fiscal 2026,

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and an additional revenue requirement increase of $12.7 million in fiscal 2027. The settlement also included standard make-whole language allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024. In Distribution Corporation's Pennsylvania jurisdiction, Distribution Corporation made a filing with the PaPUC on January 28, 2026 seeking an increase in its annual base rate operating revenues of $19.7 million with a proposed effective date of March 29, 2026. The Company is proposing, among other things, a new residential energy efficiency pilot program and to make permanent its weather normalization adjustment mechanism.  The Company is also proposing reactivation of the OPEB surcredit to refund $7.2 million for customer bill relief. In addition, on March 17, 2025, FERC approved an amendment to Empire's 2019 rate case settlement. This settlement amendment is estimated to decrease Empire's revenues on a yearly basis by approximately $0.5 million. For further discussion of these and other rate matters, refer to the Rate Matters section below.

    On October 20, 2025, the Company entered into the Purchase Agreement with CenterPoint Energy Resources Corp. (the “Seller”), pursuant to which, among other things, the Company agreed to acquire from the Seller all of the issued and outstanding equity interests of CenterPoint Ohio for an aggregate purchase price of $2.62 billion, subject to customary adjustments, as provided in the Purchase Agreement. This acquisition will add significant regulated scale for the Company, doubling the size of the Company’s gas utility rate base, while expanding its operations beyond New York and Pennsylvania into the neighboring state of Ohio, a state with a constructive regulatory and political environment that is supportive of natural gas. Closing is expected to occur in the fourth quarter of calendar 2026, pending completion of a notice filing and review with the PUCO, Hart-Scott-Rodino review, and other customary closing conditions. The purchase price will include a combination of $1.42 billion in cash and a $1.2 billion promissory note to be issued by the Company to the Seller at closing. The promissory note, which was part of the Seller’s desired transaction structure and was incorporated into the Company’s business valuation, will have a maturity date of 364 days post-closing and will carry an interest rate of 6.5%. Permanent financing, inclusive of the amount to repay the promissory note, will consist of long-term debt and common equity, along with expected future free cash flow. In that regard, on December 17, 2025, the Company completed the issuance and sale, in a private placement, of 4,402,513 shares of the Company's common stock, par value $1.00 per share, at a price of $79.50 per share. After deducting placement fees, the net proceeds to the Company amounted to $338.6 million.

    In connection with its entry into the Purchase Agreement, the Company entered into a senior unsecured bridge loan facility commitment letter supported by the Commitment Parties, as well as a 364-day term loan facility commitment letter supported by the Commitment Parties and additional banks, all of which are lenders under the Company’s primary credit facility. The combination of both facilities fully supports any portion of the purchase price that has not been permanently financed.

    As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its exploration and production properties and that book value is subject to a quarterly ceiling test. The Company recorded a non-cash impairment charge under the ceiling test during the quarter ended December 31, 2024 of $108.3 million ($79.1 million after-tax). At December 31, 2025, the ceiling exceeded the book value of the exploration and production properties, and thus, did not result in an impairment charge in the quarter ended December 31, 2025. Please refer to the Critical Accounting Estimates section below for more details on this matter and a sensitivity analysis concerning commodity price changes.

    The Company expects to use cash from operations, equity proceeds, and short-term and/or long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2026, including the repayment of a $300.0 million delayed draw term loan scheduled to mature in February 2026 that was repaid in January 2026 and any potential funding for the CenterPoint Ohio acquisition. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures, volatile interest rates and the ongoing impacts of federal policy changes, the cost and/or availability of capital may be impacted, but the Company continues to expect to meet its financing needs.

CRITICAL ACCOUNTING ESTIMATES

    For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2025 Form 10-K. There have been no material changes to that disclosure other than as set forth below.  The information presented below updates and should be read in conjunction with the critical accounting estimates in that Form 10-K.

Exploration and Development Costs.  The Company, in its Integrated Upstream and Gathering segment, follows the full cost method of accounting for determining the book value of its exploration and production properties.  In accordance with the full

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cost methodology, the Company is required to perform a quarterly ceiling test.  Under the ceiling test, the present value of future revenues from the Company's exploration and production reserves based on an unweighted arithmetic average of first day of the month commodity prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s exploration and production properties at the balance sheet date. The present value of future revenues is calculated using a 10% discount factor. If the book value of the exploration and production properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of such properties to the calculated ceiling. At December 31, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $1.3 billion (after-tax). The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended December 31, 2025, based on the quoted Henry Hub spot price for natural gas, was $3.39 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 the twelve months ended December 31, 2025. 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 in the twelve-month period used at December 31, 2025 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's exploration and production properties by approximately $953.5 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. 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. For a more complete discussion of the full cost method of accounting, refer to "Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2025 Form 10-K.

RESULTS OF OPERATIONS

Earnings

    The Company's earnings were $181.6 million for the quarter ended December 31, 2025 compared to earnings of $45.0 million for the quarter ended December 31, 2024. The increase in earnings of $136.6 million is primarily the result of current year earnings recognized in the Integrated Upstream and Gathering segment compared to a prior year loss combined with higher earnings in the Utility segment. A higher loss in the Corporate category and lower earnings in the Pipeline and Storage segment partially offset these increases. The Company's earnings for the quarter ended December 31, 2024 included non-cash impairment charges of $141.8 million ($103.6 million after-tax) in the Integrated Upstream and Gathering segment, consisting mostly of ceiling test impairment charges of $108.3 million ($79.1 million after-tax). The remaining charges are related to the impairment of certain water disposal assets. Note that all amounts used in earnings discussions are after-tax amounts, unless otherwise noted.

Earnings (Loss) by Segment

			Three Months Ended December 31,
(Thousands)			2025			2024			Increase (Decrease)
Integrated Upstream and Gathering			$	124,047		$	(19,632)		$	143,679
Pipeline and Storage			31,219			32,454			(1,235)
Utility			34,090			32,499			1,591
Total Reportable Segments			189,356			45,321			144,035
All Other			(122)			(193)			71
Corporate			(7,589)			(142)			(7,447)
Total Consolidated			$	181,645		$	44,986		$	136,659

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Integrated Upstream and Gathering

Integrated Upstream and Gathering Operating Revenues

			Three Months Ended December 31,
(Thousands)			2025			2024			Increase (Decrease)
Gas Produced in Appalachia (after Hedging)			$	315,855		$	247,187		$	68,668
Gathering			2,767			3,448			(681)
Other			4,601			1,673			2,928
			$	323,223		$	252,308		$	70,915

Production Volumes

			Three Months Ended December 31,
			2025			2024			Increase (Decrease)
Gas Production (MMcf)			109,181			97,717			11,464

Average Prices

			Three Months Ended December 31,
			2025			2024			Increase (Decrease)
Average Gas Price/Mcf
Weighted Average			$	2.77		$	2.23		$	0.54
Weighted Average After Hedging			$	2.89		$	2.53		$	0.36

2025 Compared with 2024

    Operating revenues for the Integrated Upstream and Gathering segment increased $70.9 million for the quarter ended December 31, 2025 as compared with the quarter ended December 31, 2024. Gas production revenue after hedging increased $68.7 million due to the impact of a $0.36 per Mcf increase in the weighted average price of natural gas after hedging, combined with a 11.5 Bcf increase in natural gas production. The increase in natural gas production was largely due to pads recently turned in line. In addition, other revenue increased $2.9 million primarily due to changes in segment reporting. The change in segment reporting is fully offset in other operating expenses. Slightly offsetting these increases, Gathering revenue decreased $0.7 million as a result of natural production declines by producers connected to the Trout Run gathering system.

    The Integrated Upstream and Gathering segment's earnings for the quarter ended December 31, 2025 were $124.0 million, an increase of $143.6 million when compared with a loss of $19.6 million for the quarter ended December 31, 2024. The $143.6 million increase can be attributed to the following factors:

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						(Millions)
			Lower non-cash impairments of assets			$	103.6		(1)
			Higher natural gas prices after hedging			31.3
			Higher natural gas production			22.9
			Lower interest expense			2.6			(2)
			Higher other revenue			2.3
			Earnings impact associated with remeasurement of state deferred income taxes due to ceiling test impairments			1.0			(3)
			Higher depletion expense			(8.3)			(4)
			Higher lease operating expenses			(4.9)			(5)
			Higher other operating expenses			(2.6)			(6)
			Higher income tax expense			(2.4)			(7)
			Higher other tax expense			(1.3)			(8)
			Other items			(0.6)
						$	143.6

(1)Includes a ceiling test impairment of $79.1 million and a $24.5 million impairment of certain water disposal assets recorded during the quarter ended December 31, 2024.

(2)The decrease in interest expense is mainly attributed to lower short-term and long-term intercompany borrowings.

(3)The increase was due to a $1.0 million earnings reduction associated with the remeasurement of state deferred income taxes for the quarter ended December 31, 2024.

(4)The increase in depletion is mainly attributed to higher production.

(5)The increase in lease operating expenses was primarily the result of higher third-party gathering and transportation costs combined with higher workover and repairs and maintenance costs.

(6)The increase in other operating expenses is mainly attributed to a change in segment reporting, as well as higher gathering operation and maintenance, higher personnel costs and higher abandonment accretion expense, partially offset by higher abandonment costs recognized in fiscal 2024.

(7)The increase in income tax expense was primarily driven by an increase in state tax expense due to higher pre-tax income.

(8)The increase in other tax expense was primarily attributable to higher Impact Fees in the Appalachian region as the Company moved into a higher rate tier due to higher NYMEX pricing combined with higher well count.

Pipeline and Storage

Pipeline and Storage Operating Revenues

			Three Months Ended December 31,
(Thousands)			2025			2024			Increase (Decrease)
Firm Transportation			$	80,885		$	81,086		$	(201)
Interruptible Transportation			123			118			5
			81,008			81,204			(196)
Firm Storage Service			25,137			24,993			144
Interruptible Storage Service			—			—			—
Other			756			415			341
			$	106,901		$	106,612		$	289

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Pipeline and Storage Throughput

			Three Months Ended December 31,
(MMcf)			2025			2024			Increase (Decrease)
Firm Transportation			214,073			202,882			11,191
Interruptible Transportation			25			62			(37)
			214,098			202,944			11,154

2025 Compared with 2024

    Operating revenues for the Pipeline and Storage segment remained relatively flat for the quarter ended December 31, 2025 as compared with the quarter ended December 31, 2024.

    Transportation volume for the quarter ended December 31, 2025 increased by 11.2 Bcf, from the quarter ended December 31, 2024. The increase in transportation volume for the quarter ended December 31, 2025 is primarily due to increased utilization resulting from colder weather. 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 Pipeline and Storage segment’s earnings for the quarter ended December 31, 2025 were $31.2 million, a decrease of $1.3 million when compared with earnings of $32.5 million for the quarter ended December 31, 2024. The $1.3 million decrease can be attributed to the following factors:

						(Millions)
			Lower other income			$	(1.2)		(1)
			Other items			(0.1)
						$	(1.3)

(1)The decrease in other income was primarily due to a lower average amount outstanding on intercompany short-term notes receivables and a lower weighted average interest rate on those receivables.

Utility

Utility Operating Revenues

			Three Months Ended December 31,
(Thousands)			2025			2024			Increase (Decrease)
Retail Sales Revenues:
Residential			$	196,627		$	171,365		$	25,262
Commercial			26,606			23,212			3,394
Industrial			1,399			1,384			15
			224,632			195,961			28,671
Transportation			32,243			30,622			1,621
Other			2,262			1,926			336
			$	259,137		$	228,509		$	30,628

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Utility Throughput

			Three Months Ended December 31,
(MMcf)			2025			2024			Increase (Decrease)
Retail Sales:
Residential			21,841			18,476			3,365
Commercial			3,548			2,919			629
Industrial			190			199			(9)
			25,579			21,594			3,985
Transportation			19,670			16,942			2,728
			45,249			38,536			6,713

Degree Days

Three Months Ended December 31,												Percent Colder (Warmer) Than
			Normal			2025			2024			Normal(1)			Prior Year(1)
Buffalo, NY(2)			2,126			2,281			1,884			7.3		%	21.1		%
Erie, PA			1,894			2,121			1,697			12.0		%	25.0		%

(1)Percents compare actual 2025 degree days to normal degree days and actual 2025 degree days to actual 2024 degree days.

(2)Normal degree days changed in January 2025 from NOAA 30-year degree days to NOAA 15-year degree days with the implementation of new base rates in New York.

2025 Compared with 2024

    Operating revenues for the Utility segment increased $30.6 million for the quarter ended December 31, 2025 as compared with the quarter ended December 31, 2024. This increase resulted from a $28.7 million increase in retail gas sales revenue, a $1.6 million increase in transportation revenue and a $0.3 million increase in other revenue. The increase in retail gas sales revenue and transportation revenue reflects higher base delivery rates effective October 1, 2025 from the impact of the implementation of year two of Distribution Corporation's three-year rate settlement in its New York jurisdiction. Additional details regarding the base rate regulatory proceeding can be found in the Rate Matters section below. The increase in retail gas sales revenue also reflects higher revenues collected from customers for purchased gas costs resulting from a 4.0 Bcf increase in throughput mainly due to colder weather. Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation's earnings are not impacted by fluctuations in gas costs. Purchased gas expense recorded on the consolidated income statement matches the revenues collected from customers. The increase in transportation revenue also reflects a 2.7 Bcf increase in throughput due primarily to colder weather.

    The Utility segment’s earnings for the quarter ended December 31, 2025 were $34.1 million, an increase of $1.6 million when compared with earnings of $32.5 million for the quarter ended December 31, 2024. The increase can be attributed to the following factors:

						(Millions)
			Impact of new base rates in New York			$	2.9
			Impact of higher customer usage			2.8
			Impact of regulatory revenue adjustments			1.0			(1)
			Higher operating expenses			(3.7)			(2)
			Higher depreciation expense			(1.3)			(3)
			Other items			(0.1)
						$	1.6

(1)Amount primarily reflects an increase in earnings from a distribution system improvement charge (“DSIC”) modernization tracker in Pennsylvania that became effective in January 2025. For further discussion of the DSIC tracker, refer to the Rate Matters section below.

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(2)The increase in operating expenses is largely attributable to higher personnel costs and higher uncollectible expenses.

(3)The increase in depreciation expense is attributable to higher average property, plant and equipment balances.

    The impact of weather variations on earnings in the Utility segment is mitigated by a WNA. The WNA, which covers the eight-month period from October through May, has had a stabilizing effect on customer bills and earnings for the Utility segment. For the quarter ended December 31, 2025, the WNA reduced earnings by approximately $0.8 million and $1.0 million, respectively, in the Utility segment’s New York and Pennsylvania rate jurisdictions, as the weather was colder than normal on a cycle-bill basis in both jurisdictions. For the quarter ended December 31, 2024, the WNA preserved earnings of approximately $2.0 million and $1.2 million, respectively, in the Utility segment’s New York and Pennsylvania rate jurisdictions, as the weather was warmer than normal on a cycle-bill basis in both jurisdictions.

ALL OTHER AND CORPORATE OPERATIONS

2025 Compared with 2024

    All Other and Corporate operations reported a net loss of $7.7 million for the quarter ended December 31, 2025, an increase in net loss of $7.4 million when compared with a net loss of $0.3 million for the quarter ended December 31, 2024. The increase in net loss was primarily attributable to costs associated with the Company's planned acquisition of CenterPoint Ohio ($5.9 million). Refer to Part I, Item 1 at Note 2 - Pending Acquisition for further discussion of this acquisition. Additional contributing factors to the increase in net loss were a decrease in the cash surrender value of life insurance policies ($0.9 million) and higher operating expenses ($0.9 million), primarily due to increased legal and consulting fees and outside service costs.

Other Income (Deductions)

    Net other income on the Consolidated Statements of Income was $8.2 million for the quarter ended December 31, 2025, compared to net other income of $7.7 million for the quarter ended December 31, 2024, for an increase of $0.5 million. This increase can be attributed primarily to a $1.1 million increase in interest income. Partially offsetting this increase was a $0.7 million decrease in non-service pension and post-retirement benefit income.

Other Interest Expense

    Other interest expense on the Consolidated Statement of Income increased $5.5 million for the quarter ended December 31, 2025 as compared to the quarter ended December 31, 2024. These increases are primarily due to financing costs incurred associated with the Company's acquisition of CenterPoint Ohio's natural gas utility.

CAPITAL RESOURCES AND LIQUIDITY

    The Company’s primary source of cash during the three-month period ended December 31, 2025 consisted of cash provided by operating activities and net proceeds from the issuance of common stock. The Company’s primary source of cash during the three-month period ended December 31, 2024 consisted of cash provided by operating activities and net proceeds from short-term borrowings.

    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 the remainder of 2026, the Company expects to use cash provided by operating activities and short-term and long-term borrowings to fund the Company's capital expenditures. The Company has repaid the $300.0 million delayed draw term loan that was expected to mature in February 2026. Looking forward to 2027, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures. These cash flow projections include the impact of the CenterPoint Ohio acquisition but do not reflect the impact of other 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 assets, deferred income taxes and stock-based compensation.

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    Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs, weather and regulatory lag 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. The weather impact on cash flow in the Utility segment is mitigated by a WNA in both its New York and Pennsylvania rate jurisdictions.

    Because of the seasonal nature of the heating business in the Utility segment, revenues in this business are relatively high during the heating season, primarily the first and second quarters of the fiscal year, and receivable balances historically increase during these periods from the receivable balances at September 30.

    The storage gas inventory normally declines during the first and second quarters of the fiscal year and is replenished during the third and fourth quarters.  For storage gas inventory accounted for under the LIFO method, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption "Other Accruals and Current Liabilities." Such reserve is reduced as the inventory is replenished.

    Cash provided by operating activities in the Integrated Upstream and Gathering segment may vary from period to period 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 pricing protection obtained from derivative financial instruments will fluctuate over time as instruments expire and are replaced with new instruments reflecting current commodity prices of natural gas.

    Net cash provided by operating activities totaled $274.9 million for the three months ended December 31, 2025, an increase of $54.8 million compared with $220.1 million provided by operating activities for the three months ended December 31, 2024. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Integrated Upstream and Gathering segment, partially offset by lower cash provided by operating activities in the Utility segment. The increase in the Integrated Upstream and Gathering segment is primarily due to higher natural gas prices and production in the Appalachian region combined with the timing of cash receipts and hedge settlements associated with that production. The decrease in the Utility segment is primarily due to higher natural gas prices and throughput combined with the timing of the associated gas cost recovery.

Investing Cash Flow

Expenditures for Long-Lived Assets

    The Company’s expenditures for long-lived assets totaled $222.7 million during the three months ended December 31, 2025 and $192.1 million during the three months ended December 31, 2024.  The table below presents these expenditures:

Total Expenditures for Long-Lived Assets
Three Months Ended December 31,			2025						2024						Increase (Decrease)
(Millions)
Integrated Upstream and Gathering:
Capital Expenditures			$	141.8		(1)			$	135.6		(2)			$	6.2
Pipeline and Storage:
Capital Expenditures			37.6			(1)			19.8			(2)			17.8
Utility:
Capital Expenditures			43.1			(1)			36.5			(2)			6.6
All Other:
Capital Expenditures			0.2						0.2						—
			$	222.7					$	192.1					$	30.6

(1)At December 31, 2025, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $55.5 million, $8.1 million and $6.8 million, respectively, of non-cash capital expenditures. At September 30, 2025, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $87.9 million, $19.4 million and $18.0 million, respectively, of non-cash capital expenditures. 

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(2)At December 31, 2024, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $62.3 million, $4.4 million and $4.9 million, respectively, of non-cash capital expenditures. At September 30, 2024, capital expenditures for the Integrated Upstream and Gathering segment, the Pipeline and Storage segment and the Utility segment included $85.0 million, $14.4 million and $20.6 million, respectively, of non-cash capital expenditures.  

Integrated Upstream and Gathering 

    The Integrated Upstream and Gathering segment capital expenditures for the three months ended December 31, 2025 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $90.9 million spent in the Utica Shale area and $33.5 million spent in the Marcellus Shale area. These amounts included approximately $78.1 million spent to develop proved undeveloped reserves. Integrated Upstream and Gathering segment capital expenditures also included expenditures related to the continued expansion of Midstream Company’s Trout Run and Tioga 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 Integrated Upstream and Gathering segment capital expenditures for the three months ended December 31, 2024 were primarily upstream well drilling and completion expenditures in the Appalachian region, including $90.9 million spent in the Utica Shale area and $27.5 million spent in the Marcellus Shale area. These amounts included approximately $34.6 million spent to develop proved undeveloped reserves. Integrated Upstream and Gathering segment capital expenditures also included expenditures related to the continued expansion of Midstream Company’s Tioga gathering system. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online and system optimization, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

Pipeline and Storage

    The Pipeline and Storage segment capital expenditures for the three months ended December 31, 2025 and December 31, 2024 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 the three months ended December 31, 2025 included expenditures related to Supply's Corporation's Tioga Pathway Project ($5.4 million) and Shippingpoint Lateral Project ($2.4 million).

    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, on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems, including projects to support regional demand for power generation to support the electric grid and data center development. Expansion and modernization projects where the Company has forecasted a significant amount of investment in preliminary survey and investigation costs and/or capital expenditures, and where a precedent agreement has been executed, are discussed below.

    Supply Corporation 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 (“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 and filed a Section 7(b)/7(c) application with the FERC on August 21, 2024. FERC issued the Section 7(b)/7(c) certificate on May 5, 2025 and on January 8, 2026, FERC issued the Notice to Proceed with Construction. Construction on the Tioga Pathway Project is expected to commence in February 2026. This project has a projected in-service date of late calendar year 2026 and an estimated capital cost of approximately $101 million. As of December 31, 2025, approximately $10.5 million has been capitalized as Construction Work in Progress for this project.

    Additionally, Supply Corporation concluded an open season on February 26, 2025, and based on interest in that open season, designed a project that would allow for the transportation of 205,000 Dth per day of natural gas supplies from its existing Line N pipeline system to a new interconnection with the Shippingport Power Station, a natural gas power generation facility under development in Beaver County, Pennsylvania, which is expected to support a co-located data center (the

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“Shippingport Lateral Project”). In order to provide this new natural gas transportation capacity, Supply Corporation expects to construct an approximately 7.5 mile pipeline lateral from its existing Line N pipeline system to a direct interconnection with the facility with the incremental capacity expected to come online in late calendar 2026 and an estimated capital cost of approximately $57 million. Supply Corporation has executed a Precedent Agreement with Shippingport Power Station, LLC, the facility developer, for 100% of the capacity for the Shippingport Lateral Project and filed an application with FERC under the Commission’s prior notice regulations on August 29, 2025. The project obtained FERC authorization on November 7, 2025. As of December 31, 2025, approximately $2.6 million has been spent on this project, including $0.1 million spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet. The remaining $2.5 million spent on the project has been capitalized as Construction Work in Progress.

Utility 

    The majority of the Utility segment capital expenditures for the three months ended December 31, 2025 and December 31, 2024 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.

Project Funding

    During the quarter ended December 31, 2025 and fiscal 2025, the Company has financed capital expenditures with cash from operations and short-term debt. Going forward, the Company expects to use cash from operations, equity proceeds, 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 Integrated Upstream and Gathering segment. It will also likely depend on the timing of gas cost and base rate recovery in the Utility segment as well as the timing of base rate recovery in the Pipeline and Storage segment.

    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 generation 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 and Pipeline and Storage segments 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 decreased $60.2 million when comparing the balance sheet at December 31, 2025 to the balance sheet at September 30, 2025. The maximum amount of short-term debt outstanding during the three months ended December 31, 2025 was $311.0 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 items such as 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. As of December 31, 2025, the Company had outstanding commercial paper of $90.0 million and did not have any short-term notes payable to banks.

    On October 20, 2025, the Company entered into a Securities Purchase Agreement (the “Purchase Agreement”) with CenterPoint Energy Resources Corp. (the “Seller”), pursuant to which, among other things, the Company agreed to acquire from the Seller all of the issued and outstanding equity interests of Vectren Energy Delivery of Ohio, LLC (the “Acquired Company” or “CenterPoint Ohio”), the Seller’s Ohio natural gas local distribution company, for an aggregate purchase price of $2.62 billion, subject to customary adjustments (the “Purchase Price”), as provided in the Purchase Agreement (the “Transaction”). The Purchase Price will be paid through a combination of cash and a promissory note to be issued by the Company to the Seller at closing pursuant to a Seller Note Agreement (the “Seller Note Agreement”) between the Company, as borrower, and the Seller, as lender. The Seller Note Agreement, which was part of the Seller’s desired transaction structure and was incorporated into the Company’s business valuation, will provide a $1.2 billion unsecured term loan credit facility (the “Seller Note Facility”) that matures on the last business day that is not more than 364 days from the closing of the Transaction.

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    The borrowings under the Seller Note Facility will bear interest at a rate of 6.5% per annum. The Seller Note Agreement will contain customary representations and affirmative, negative and financial covenants, consistent with the Company’s February 2024 term loan agreement discussed below. The Seller Note Agreement will also include covenants restricting certain actions with respect to the Acquired Company. The Seller Note Agreement will contain certain specified events of default, and should an event of default occur, the lender is entitled to exercise certain remedies, including acceleration of the loan and related obligations.

    The Seller Note Agreement will contain a covenant defeasance provision that permits the Company to relieve itself from its obligations to comply with covenants under the Seller Note Agreement upon deposit of an amount with a paying agent sufficient to pay the principal of and interest due on the loan on each applicable interest payment date and the maturity date.

    In connection with its entry into the Purchase Agreement, the Company entered into a bridge facility commitment letter (the “Bridge Commitment Letter”), pursuant to which The Toronto-Dominion Bank, New York Branch (“TD Bank”) and Wells Fargo Bank, National Association (“Wells Fargo Bank” and, together with TD Bank, the “Commitment Parties”), agreed to provide to the Company loans under a senior unsecured bridge loan facility (the “Bridge Facility”) composed of a $1.42 billion 364-day tranche (the “Acquisition Tranche”), the proceeds of which will be used, if needed, to finance the Transaction, and a $1.2 billion 364-day tranche (the “Seller Note Tranche”), the proceeds of which will be used, if needed, to refinance the Seller Note Facility at its scheduled maturity.

    On November 6, 2025, the Company entered into a 364-day term loan facility commitment letter (the “Term Loan Commitment Letter”), pursuant to which the Commitment Parties and ten additional banks, all of which are lenders under our primary credit facility, agreed to provide to the Company loans under a 364-day senior unsecured term loan facility (the “Term Loan Facility”) in the amount of $1.42 billion, the proceeds of which will be used, if needed, to finance the Transaction. Entering into the Term Loan Commitment Letter enabled the Company to terminate the commitments under the Bridge Commitment Letter in respect of the Acquisition Tranche. Also on November 6, 2025, the same ten additional banks joined the Commitment Parties as parties to the Bridge Commitment Letter in respect of the Seller Note Tranche.

    Subject to the conditions in the respective commitment letters, the commitments under the Term Loan Facility and the Bridge Facility (together, the “Commitments”) may be reduced by proceeds of certain additional indebtedness that may be incurred by the Company and certain equity offerings of the Company to finance the Transaction. On December 17, 2025, the Company completed the issuance and sale, in a private placement, of 4,402,513 shares of the Company's common stock, par value $1.00 per share, at a price of $79.50 per share. After deducting placement fees, the net proceeds to the Company amounted to $338.6 million. The Company is using the net proceeds from the issuance for general corporate purposes, including to finance a portion of the Purchase Price for the Transaction. The net proceeds of the issuance reduced the commitments under the Term Loan Facility to $1.08 billion. The Company expects to further reduce the Commitments through additional financings, possibly to zero, prior to the closing date of the Transaction or the scheduled maturity of the Seller Note Facility, as applicable, but there can be no assurance such financings will occur and any such expectation is subject to market conditions.

    The Company is subject to certain customary fees with respect to the Term Loan Facility and the Bridge Facility. Interest on borrowings under the Term Loan Facility or the Bridge Facility would accrue at one of two rates, at the option of the Company: Term SOFR plus an applicable margin of 1.125% to 1.750%, or a base rate (at least as great as one-month Term SOFR plus 1.0%) plus an applicable margin of 0.125% to 0.750%. In each case, the applicable margin would depend on the Company’s credit ratings (at current ratings, the applicable margin would be 1.500% for Term SOFR loans and 0.500% for base rate loans). With respect to the Term Loan Facility, the Company will pay a fee on the 270th day after the funding date in an amount equal to 0.025% of the principal amount of any loans outstanding under such facility at the close of business on that date. With respect to the Bridge Facility, the applicable margin would increase by an additional 0.25% on each of the 90th, 180th and 270th day after the funding date for any loans outstanding under the Bridge Facility. Any borrowings under the Term Loan Facility or the Bridge Facility would mature 364 days from the funding date, which, for the Term Loan Facility, would be on or around the closing date of the Transaction and, for the Bridge Facility, would be on or around the scheduled maturity of the Seller Note Facility.

    The availability of borrowings under the Term Loan Facility and the Bridge Facility is subject to the satisfaction of certain customary conditions for transactions of these types. Any definitive financing documentation for the Term Loan Facility or the Bridge Facility will contain customary representations and warranties, covenants and events of defaults for transactions of these types. The Company expects to execute permanent financing prior to the respective funding dates of the Term Loan

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Facility and the Bridge Facility, such that borrowings under the facilities would not be incurred. There can be no assurance, however, such permanent financing will occur and any such expectation is subject to market conditions.

    The Company is a party to a syndicated Credit Agreement (as amended from time to time, the “Credit Agreement”) that provides a $1.0 billion unsecured committed revolving credit facility. In January 2025, the Company and the banks in the syndicate consented to a second one-year extension of the maturity date of the Credit Agreement, such that the Company has aggregate commitments available in the full amount of $1.0 billion through February 23, 2029. In May 2025, the total lenders under the Credit Agreement increased to twelve as a new lender joined the syndicate, assuming a portion of an existing lender's commitment.

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

    The Company entered into a term loan agreement (the “Term Loan Agreement”) on February 14, 2024, with six of the 12 banks that are lenders under the Credit Agreement. As of January 22, 2026, the Company repaid the $300.0 million drawn under the Term Loan Agreement, and the agreement was therefore terminated. The Term Loan Agreement provided a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company had the ability to select interest periods of one, three or six months for borrowings. In April 2024, pursuant to the delayed draw mechanism, the Company elected to draw a total of $300.0 million under the facility. After deducting debt issuance costs, the net proceeds to the Company amounted to $299.4 million. Borrowings under the Term Loan Agreement bear interest at a rate equal to SOFR for the applicable interest period, plus an adjustment of 0.10%, plus a spread of 1.375%.

    Both the Credit Agreement and the Term Loan Agreement provide 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 that date, the Company recorded non-cash, after-tax ceiling test impairments totaling $797.0 million. As a result, at December 31, 2025, $398.5 million was added back to the Company’s total capitalization for purposes of calculating the debt to capitalization ratio under the Credit Agreement and the Term Loan Agreement. In addition, for purposes of calculating the debt to capitalization ratio, the following amounts included in Accumulated Other Comprehensive Income (Loss) on the Company’s consolidated balance sheet will be excluded from the determination of comprehensive shareholders’ equity: 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. As a result of these exclusions, such unrealized gains or losses will not positively or negatively affect the calculation of the debt to capitalization ratio. Finally, pursuant to amendments to the Credit Agreement and Term Loan Agreement entered into as of November 6, 2025, for purposes of calculating the debt to capitalization ratio, the Company’s $1.2 billion obligation under the Seller Note Facility, which is to be incurred at the closing of the Transaction, will be excluded from the definition of consolidated indebtedness upon such time and to the extent that the Company, in accordance with the Seller Note Agreement, deposits with a paying agent funds for defeasance of the Seller Note Facility.

    At December 31, 2025, the Company’s debt to capitalization ratio, as calculated under the agreements, was 0.41. The constraints specified in the Credit Agreement and the Term Loan Agreement would have permitted an additional $4.54 billion in short-term and/or long-term debt to be outstanding at December 31, 2025 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 and the Term Loan Agreement each contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the

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Credit Agreement or Term Loan Agreement, as applicable. 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.

    The Current Portion of Long-Term Debt at December 31, 2025 consisted of a $300.0 million long-term delayed draw term loan scheduled to mature in February 2026 that was repaid in January 2026 and $300.0 million of 5.50% notes with a maturity date in October 2026. The Current Portion of Long-Term Debt at September 30, 2025 consisted of the aforementioned $300.0 million long-term delayed draw term loan with a maturity date in February 2026. The Company's present liquidity position is believed to be adequate to satisfy known demands.

    The Company’s embedded cost of long-term debt was 4.85% at December 31, 2025 and 4.83% at December 31, 2024.

OTHER MATTERS

    In addition to the legal proceedings disclosed in Part II, Item 1 of this report, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

    The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the three months ended December 31, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2026. The Company also did not make any contributions to its VEBA trusts for its other post-retirement benefits during the three months ended December 31, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2026.

Market Risk Sensitive Instruments

    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 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 December 31, 2025, 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.

    For a complete discussion of all other market risk sensitive instruments used by the Company, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2025 Form 10-K.

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.” In both jurisdictions,

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delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.

New York Jurisdiction

    Distribution Corporation’s current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on December 19, 2024 with rates effective January 1, 2025 (“2024 Rate Order”). The 2024 Rate Order authorizes a three-year rate plan effective October 1, 2024, with a make-whole provision allowing full recovery of revenues that would have been billed at the new rates between October 1, 2024 and December 31, 2024. It also reflects a return on equity of 9.7% and authorized a revenue requirement increase of $57.3 million in fiscal 2025, an additional revenue requirement increase of $15.8 million in fiscal 2026, and an additional revenue requirement increase of $12.7 million in fiscal 2027. These revenue requirement increases are being reflected in customer bills on a levelized basis over the three-year rate plan. The revenue requirement for each year of the three-year plan has been reduced by $14 million for actuarial projections of income that is expected to be recognized for qualified pension and other post-retirement benefits. Qualified pension and other post-retirement benefit income or costs are matched with amounts included in revenue resulting in zero impact to earnings. The 2024 Rate Order approves the continuation of several ratemaking mechanisms, including revenue decoupling and WNA, and establishes a number of new cost trackers and regulatory deferrals. It also includes an earnings sharing mechanism, gas safety and customer service performance metrics (including maintaining the Company’s leak prone pipe replacement program), and provisions that will facilitate achievement of the emissions reduction goals of the CLCPA.

Pennsylvania Jurisdiction

    Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC in an order issued on June 15, 2023 with rates effective August 1, 2023 (“2023 Rate Order”). The 2023 Rate Order provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million and authorized a new weather normalization adjustment mechanism. On January 28, 2026, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $19.7 million with a proposed effective date of March 29, 2026. The Company is proposing, among other things, a new residential energy efficiency pilot program and to make permanent its weather normalization adjustment mechanism.  The Company is also proposing reactivation of the OPEB surcredit (Rider I) to refund $7.2 million for customer bill relief.  The filing will be suspended for seven months by operation of law unless directed otherwise by the PaPUC.

    On April 10, 2024, Distribution Corporation filed with the PaPUC a petition for approval of a distribution system improvement charge ("DSIC") to recover, between base rate cases, capital expenses related to eligible property constructed or installed to rehabilitate, improve and replace portions of the Company’s natural gas distribution system. The DSIC petition was approved by the PaPUC on December 5, 2024, and on January 1, 2025, the Company initiated recovery of eligible costs on incremental rate base added after September 30, 2024. During the quarter ended December 31, 2025, Distribution Corporation recovered $1.1 million from customers. The DSIC will be reset to zero when new base rates become effective as a result of the Company's recent rate filing.

Pipeline and Storage

    Supply Corporation’s rate settlement was approved June 11, 2024 with rates effective February 1, 2024, and provides that Supply Corporation may make a rate filing for new rates to be effective at any time. As well, any party can make a filing under NGA Section 5. Supply Corporation has no rate case currently on file.

    On March 17, 2025, FERC approved an amendment to Empire’s 2019 rate case settlement, which provides for a modest reduction in Empire’s transportation unit rates, effective November 1, 2025. This settlement amendment is estimated to decrease Empire’s revenues on a yearly basis by approximately $0.5 million. Empire will not be able to file a new Section 4 rate case before April 30, 2027 and is required to file a Section 4 rate case by May 31, 2031.

Environmental Matters

    The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and to comply with regulatory requirements. 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

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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 1 at Note 8 – Commitments and Contingencies under the heading “Environmental Matters.”

    While the current federal administration has initiated efforts to roll-back and/or limit certain environmental initiatives, legislative and regulatory measures concerning 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, cap-and-invest and cap-and-trade programs, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources.

    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. In New York, the CLCPA, which was passed in 2019, 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. Statements from New York's Governor and the state's 2025 New York State Energy Plan acknowledge that the near term targets of the statute may not be achievable in the required timeframes. The NYPSC has initiated and/or modified various proceedings in an effort to help the State meet these emissions reduction targets. 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, and in December 2025 the Governor approved legislation that will require residential natural gas service applicants to pay the installation costs for the first 100 feet of facilities necessary to provide service commencing December 19, 2026. The May 2023 legislation is subject to ongoing litigation, with the parties agreeing, in November 2025, to suspend the requirements of the legislation pending resolution of appellate proceedings. In addition, the NYDEC, in conjunction with the New York State Energy Research and Development Authority, is developing a cap-and-invest program in the state, although issuance of certain key regulations necessary to implement the program has been delayed. In October 2025, a New York State Supreme Court judge issued an order requiring the NYDEC to promulgate regulations in accordance with the CLCPA by February 6, 2026. An appeal of that order filed by NYDEC on November 25, 2025 stayed all proceedings to enforce the order pending resolution of the appeal. The above-enumerated initiatives could impact the Company's customer base and assets, and 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 reduce demand for natural gas and 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 federal and state administrative agencies, make it difficult to predict a long-term business impact across twenty or more years. Federal, state or local governments may also 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.

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 Quarterly Report on Form 10-Q 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

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in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:

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

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

3.Changes in economic conditions, including the imposition of additional tariffs on U.S. imports and related retaliatory tariffs, 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;

4.The Company's ability to complete strategic transactions, such as the pending transaction with CenterPoint Energy Resources Corp., including receipt of required regulatory clearances and satisfaction of other conditions to closing, and to recognize the anticipated benefits of such transactions;

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

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

7.Changes in the price of natural gas;

8.Impairments under the SEC's full cost ceiling test for natural gas reserves;

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

10.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, other investments, and acquisitions, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;

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

12.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;

13.The impact of information technology disruptions, cybersecurity or data security breaches, including the impact of issues that may arise from the use of artificial intelligence technologies;

14.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;

15.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;

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

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

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

19.Uncertainty of natural gas reserve estimates;

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 Quarterly Report on Form 10-Q 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.

Item 3.  Quantitative and Qualitative Disclosures About Market Risk

    Refer to the "Market Risk Sensitive Instruments" section in Item 2 – MD&A.

Item 4.  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 Chief 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 Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2025.   

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 December 31, 2025 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

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Part II.  Other Information

Item 1.  Legal Proceedings

    For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 8 – Commitments and Contingencies, and Part I, Item 2 - MD&A of this report under the heading “Other Matters – Environmental Matters.”

    For a discussion of certain rate matters involving the NYPSC, refer to Part I, Item 1 of this report at Note 11 – Regulatory Matters.

Item 1A.  Risk Factors

    The risk factors in Item 1A of the Company’s 2025 Form 10-K have not materially changed other than as set forth below. The risk factors presented below supersede the corresponding risk factors in the 2025 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2025 Form 10-K.

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 indenture, depend on the Company’s compliance with its obligations under the facilities, agreements and indenture.

    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 short periods of time (up to six months), 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, $2.4 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, we may be subject to financial risks related to our planned acquisition of all of the issued and outstanding equity interests of CenterPoint Ohio from the Seller. For discussion of these risks, refer to the risk factor under the heading “The planned acquisition of CenterPoint Ohio may limit our financial flexibility.”

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

    The laws, regulations and other initiatives to address climate change may impact the Company’s financial results. 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, carbon tax, or other similar mechanisms to provide incentive for the reduction of

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greenhouse gas emissions. 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, in December 2022, 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, as well as 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. In addition, in October 2025, a New York State court directed NYDEC to promulgate rules and regulations to ensure compliance with emissions reductions limits outlined in the CLCPA by February 6, 2026, which may include such a cap-and-invest program. An appeal of that order filed by NYDEC on November 25, 2025 stayed all proceedings to enforce the order pending resolution of the appeal, however, 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 CLCPA, 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 (this date is currently stayed pending resolution of appellate activity), and in December 2025 the Governor approved legislation that will require residential natural gas service applicants to pay the installation cost for the first 100 feet of facilities necessary to provide service commencing December 19, 2026. 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. In addition, in December 2024 (and later amended in February 2025), New York’s Governor signed the Climate Change Superfund Act into law, which will require certain fossil fuel producers, refiners and related entities to pay into a state “climate superfund” an amount commensurate with the entity’s past global greenhouse gas emissions over a specified period of time. The NYDEC has until June 2027 to develop implementing regulations. The Act is currently the subject of multiple federal court lawsuits challenging its constitutionality.

    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 Part II, Item 7, MD&A under the heading “Environmental Matters.”

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

RISKS RELATED TO OUR PLANNED ACQUISITION OF CENTERPOINT OHIO

The planned acquisition of CenterPoint Ohio may limit our financial flexibility.

    We expect to acquire CenterPoint Ohio for total consideration of $2.62 billion, inclusive of the amount to repay a $1.2 billion promissory note. Although we have obtained committed financing for the entirety of the purchase price and have completed the necessary equity financing in connection with the transaction via a private placement, we expect to obtain further permanent financing for the planned acquisition by accessing the capital markets, which we expect will include the issuance of long-term debt. If we are not able to obtain permanent financing on favorable terms, we may be required to finance a portion of

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the purchase price of the planned acquisition at interest rates higher than currently expected, which could limit our financial flexibility. In addition, our ability to make payments on our debt, fund our other liquidity needs, and make planned capital expenditures following the planned acquisition of CenterPoint Ohio will depend on our ability to generate cash in the future. Our ability to generate cash, to a certain extent, is subject to general economic, financial, competitive, legislative, regulatory, and other factors that are beyond our control. The degree to which we will be leveraged following the completion of the planned acquisition could require us to dedicate a substantial portion of our cash flow from operations to the payment of debt service, reducing the availability of our cash flow to fund working capital, capital expenditures, acquisitions, and other general corporate purposes.

Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds

    On October 1, 2025, the Company issued a total of 4,710 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 471 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 December 31, 2025. The Company issued an additional 628 unregistered shares in the aggregate on October 15, 2025 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 (“Securities Act”), as transactions not involving a public offering.

    On December 17, 2025, the Company completed the issuance and sale of 4,402,513 shares of the Company's common stock, par value $1.00 per share, to certain institutional investors, at a price of $79.50 per share. After deducting placement fees of $11.4 million from the aggregate offering price of $350.0 million, the net proceeds to the Company amounted to $338.6 million. The shares were sold and issued without registration under the Securities Act, in reliance on the exemptions provided by Section 4(a)(2) of the Securities Act as a transaction not involving a public offering and Rule 506 promulgated thereunder, and in reliance on similar exemptions under applicable state laws.

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 (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under Share Repurchase Plans or Programs (b)
Oct. 1 - 31, 2025			9,459			$88.20			—			$82,094,302
Nov. 1 - 30, 2025			12,118			$79.35			—			$82,094,302
Dec. 1 - 31, 2025			87,587			$82.12			—			$82,094,302
Total			109,164			$82.44			—			$82,094,302

(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, (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, and (iii) shares of common stock of the Company purchased on the open market pursuant to the Company's share repurchase program. Of the 109,164 shares purchased other than through a publicly announced share repurchase program, 31,742 were purchased for the Company's 401(k) plans and 77,422 were purchased as a result of shares tendered to the Company by holders of stock-based compensation awards.

(b)On March 8, 2024, the Company’s Board of Directors authorized the repurchase of up to $200 million of shares of the Company’s common stock. The calculation of the dollar value of shares remaining available for purchase excludes excise taxes and brokerage fees paid by the Company in connection with the repurchase program which in the aggregate totaled $1.07 million from the beginning of the program to December 31, 2025. Repurchases may be made from time to time in the open market or through privately negotiated transactions, including through the use of trading plans intended to qualify under SEC Rule 10b5-1, in accordance with applicable securities laws and other restrictions. In light of the Company’s agreement to acquire CenterPoint Ohio’s natural gas utility, repurchases under the program have been suspended. The repurchase program has no expiration date.

Item 5.  Other Information

Trading Arrangements

    During the quarter ended December 31, 2025, 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.

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Item 6.  Exhibits

Exhibit Number						Description of Exhibit
•						Securities Purchase Agreement, dated as of October 20, 2025, by and between National Fuel Gas Company and CenterPoint Energy Resources Corp. (Exhibit 10.1, Form 8-K dated October 21, 2025)*
•						Amendment No. 2 to Credit Agreement, dated as of November 6, 2025, among National Fuel Gas Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A. as Administrative Agent (Exhibit 10.1, Form 10-K for fiscal year ended September 30, 2025)
•						Amendment No. 1 to Term Loan Agreement, dated as of November 6, 2025, among National Fuel Gas Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A. as Administrative Agent (Exhibit 10.2, Form 10-K for fiscal year ended September 30, 2025)
•						National Fuel Gas Company Annual Incentive Plan (Exhibit 10.1, Form 8-K dated December 10, 2025)
•						Common Stock Subscription Agreement, dated as of December 12, 2025, by and among National Fuel Gas Company and the investors party thereto (Exhibit 10.1, Form 8-K dated December 15, 2025)
10.1						Form of Award Notice for Total Shareholder Return Performance Shares under the National Fuel Gas Company 2010 Equity Compensation Plan
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 Chief 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						National Fuel Gas Company Consolidated Statements of Income for the Twelve Months Ended December 31, 2025 and 2024.
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 three months ended December 31, 2025 and 2024, (ii) the Consolidated Statements of Comprehensive Income for the three months ended December 31, 2025 and 2024, (iii) the Consolidated Balance Sheets at December 31, 2025 and September 30, 2025, (iv) the Consolidated Statements of Cash Flows for the three months ended December 31, 2025 and 2024 and (v) the Notes to Condensed Consolidated Financial Statements.
104						Cover Page Interactive Data File (embedded within the Inline XBRL document)
•						Incorporated herein by reference as indicated.
••						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.
*						Certain schedules and similar attachments to this Exhibit have been omitted pursuant to Item 601(a)(5) of Regulation S-K. The Company agrees to furnish supplementally to the SEC, upon request, an unredacted copy of any schedule or attachment to this Exhibit.

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SIGNATURES

Pursuant to the requirements 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)

/s/ T. J. Silverstein

T. J. Silverstein

Treasurer and Chief Financial Officer

/s/ E. G. Mendel

E. G. Mendel

Controller and Chief Accounting Officer

Date:  January 29, 2026

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FAQ

How did National Fuel Gas (NFG) perform financially in the quarter ended December 31, 2025?

National Fuel Gas reported net income available for common stock of $181.6 million, up from $45.0 million a year earlier, on operating revenues of $651.5 million versus $549.5 million. Higher upstream prices and volumes and no repeat of prior non‑cash impairments drove the improvement.

Which segments contributed most to NFG’s quarterly earnings?

The Integrated Upstream and Gathering segment earned $124.0 million, Pipeline and Storage earned $31.2 million, and the Utility segment earned $34.1 million. Upstream results benefited from higher realized gas prices after hedging and increased production, while Utility earnings rose with colder weather and new New York rates.

What are the key details of NFG’s planned acquisition of CenterPoint Ohio?

NFG agreed to acquire all equity of CenterPoint Ohio for $2.62 billion, using $1.42 billion in cash and a $1.2 billion promissory note at 6.5% interest, maturing 364 days post‑closing. The deal is expected to double NFG’s gas utility rate base and close in late calendar 2026, subject to approvals.

How is NFG financing the CenterPoint Ohio acquisition and other needs?

Permanent financing will combine long‑term debt, common equity and expected free cash flow. NFG raised net proceeds of about $338.6 million from a private placement of 4,402,513 shares at $79.50 per share and has committed bridge and 364‑day term loan facilities supporting any unfunded purchase price.

What were NFG’s operating cash flow and capital expenditures this quarter?

Net cash provided by operating activities was $274.9 million, compared with $220.1 million a year earlier. Capital expenditures totaled $277.6 million, including $141.8 million in Integrated Upstream and Gathering, $37.6 million in Pipeline and Storage, and $43.1 million in Utility assets.

Did NFG record any ceiling test impairments on its upstream properties in this quarter?

No. At December 31, 2025, the full cost ceiling exceeded the book value of exploration and production properties by about $1.3 billion after tax. In the prior‑year quarter, the company recorded a non‑cash, pre‑tax ceiling test impairment charge of $108.3 million in its upstream segment.

What recent regulatory rate actions affect NFG’s Utility and Pipeline and Storage segments?

In New York, a three‑year rate plan effective October 1, 2024 includes a 9.7% allowed return on equity and staged revenue requirement increases. In Pennsylvania, NFG requested a $19.7 million base rate increase. FERC also approved an Empire settlement amendment expected to reduce annual revenues by about $0.5 million.