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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 ~~June~~December 3031, 2025

☐ 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 ~~July 30~~January 27, ~~2025~~2026: 9095,~~363~~026,~~646~~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
2024 Form 10-K			The Company’s Annual Report on Form 10-K for the year ended September 30, 2024
2025 Form 10-K			The Company’s Annual Report on Form 10-K for the year ended September 30, 2025
2017 Tax Reform Act			Tax legislation referred to as the "Tax Cuts and Jobs Act," enacted December 22, 2017.
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 ~~(e.g.~~pays aSupply ~~marketer)~~Corporation ~~pays~~and/or Empire for gas the customer receives in excess of amounts delivered into ~~pipeline/storage~~Supply Corporation's or ~~distribution~~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.

Table of Content

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
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.

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 ~~Rating~~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.

Table of Content

INDEX						Page
Part I. Financial Information
Item 1. Financial Statements (Unaudited)						6
a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Nine Months Ended June 30, 2025 and 2024						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 and Nine Months Ended June 30, 2025 and 2024						7
b. Consolidated Statements of Comprehensive Income – Three Months Ended December 31, 2025 and 2024						7
c. Consolidated Balance Sheets – June 30, 2025 and September 30, 2024						8
c. Consolidated Balance Sheets – December 31, 2025 and September 30, 2025						8
d. Consolidated Statements of Cash Flows – Nine Months Ended June 30, 2025 and 2024						10
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						2926
Item 3. Quantitative and Qualitative Disclosures About Market Risk						5143
Item 4. Controls and Procedures						5143
Part II. Other Information
Item 1. Legal Proceedings						5144
Item 1 A. Risk Factors						5144
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds						5246
Item 5. Other Information						5246
Item 6. Exhibits						5247
Signatures						5448

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.

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 EndedJune 30,				Nine Months Ended June 30,
	Three Months EndedDecember 31,
(Thousands of U.S. Dollars, Except Per Common Share Amounts)	2025		2024		~~2025~~		~~2024~~
INCOME
Operating Revenues:
Utility Revenues	$	~~157~~259,~~446~~047	$	~~124~~228,~~858~~424	$	~~729,445~~	$	~~616,977~~
Exploration and Production and Other Revenues	303,883		220,905		864,701		739,537
Integrated Upstream and Gathering Revenues	323,223		252,308
Pipeline and Storage and Gathering Revenues	70,501		71,679		217,116		216,228
Pipeline and Storage Revenues	69,237		68,750
	531,830		417,442		1,811,262		1,572,742
	651,507		549,482
Operating Expenses:
Purchased Gas	2785,~~986~~606		465,~~952~~337		~~228,661~~		~~167,444~~
Operation and Maintenance:
Utility	5659,~~053~~897		5355,~~412~~244		~~174,744~~		~~166,405~~
Exploration and Production and Other	35,272		35,148		103,874		102,768
Integrated Upstream and Gathering and Other	56,306		42,905
Pipeline and Storage and Gathering	41,679		40,019		119,982		114,321
Pipeline and Storage	26,786		26,577
Property, Franchise and Other Taxes	24,~~180~~764		2122,~~201~~056		~~71,450~~		~~66,635~~
Depreciation, Depletion and Amortization	~~116~~122,~~408~~025		~~113~~109,~~454~~370		~~337,055~~		~~348,179~~
Impairment of Assets	—		~~200~~141,~~696~~802		~~141,802~~		~~200,696~~
	301,578		468,882		1,177,568		1,166,448
	375,384		463,291
Operating Income (Loss)	230,252		(51,440)		633,694		406,294
Operating Income	276,123		86,191
Other Income (Expense):
Other Income (Deductions)	8,534		3,188		31,486		12,989
Other Income	8,233		7,720
Interest Expense on Long-Term Debt	(3433,~~333~~513)		(3233,~~876~~362)		~~(107,356)~~		~~(89,791)~~
Other Interest Expense	(39,~~556~~861)		(14,~~341~~381)		~~(13,033)~~		~~(14,250)~~
Income (Loss) Before Income Taxes	200,897		(82,469)		544,791		315,242
Income Before Income Taxes	240,982		56,168
Income Tax Expense (Benefit)	51,079		(28,311)		133,629		70,108
Income Tax Expense	59,337		11,182
Net Income (Loss) Available for Common Stock	149,818		(54,158)		411,162		245,134
Net Income Available for Common Stock	181,645		44,986
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	12,~~855~~012,~~366~~529		21,~~090~~727,~~172~~326		~~1,727,326~~		~~1,885,856~~
	2,005,184		2,036,014		2,138,488		2,130,990
	2,194,174		1,772,312
Share Repurchases under Repurchase Plan	~~(3,311)~~—		(1826,~~435~~993)		~~(43,389)~~		~~(22,252)~~
Dividends on Common Stock	(4850,~~340~~834)		(4746,~~195~~671)		~~(141,566)~~		~~(138,354)~~
Balance at June 30	$	1,953,533	$	1,970,384	$	1,953,533	$	1,970,384
Balance at December 31	$	2,143,340	$	1,698,648
Earnings (Loss) Per Common Share:
Earnings Per Common Share:
Basic:
Net Income (Loss) Available for Common Stock	$	1.66	$	(0.59)	$	4.54	$	2.67
Net Income Available for Common Stock	$	1.99	$	0.50
Diluted:
Net Income (Loss) Available for Common Stock	$	1.64	$	(0.59)	$	4.51	$	2.65
Net Income Available for Common Stock	$	1.98	$	0.49
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	9091,~~358~~171,~~018~~715		9190,~~874~~777,~~049~~446		~~90,546,228~~		~~91,966,034~~
Used in Diluted Calculation	91,~~139~~962,~~556~~479		91,~~874~~434,~~049~~741		~~91,247,547~~		~~92,467,787~~
Dividends Per Common Share:
Dividends Declared	$	0.535	$	0.515	$	~~1.565~~	$	~~1.505~~

See Notes to Condensed Consolidated Financial Statements

Table of Content

National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)

Three Months EndedJune 30,

Nine Months Ended June 30,

Three Months EndedDecember 31,

(Thousands of U.S. Dollars)

2025

2024

~~2025~~

~~2024~~

Net Income (Loss) Available for Common Stock

149,818

(54,158)

411,162

245,134

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

~~148~~49,~~888~~098

(2153,~~936~~516)

~~(113,675)~~

~~238,395~~

Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income

(213,~~258~~274)

(7529,~~346~~504)

~~(23,601)~~

~~(155,203)~~

Other Comprehensive Income (Loss), Before Tax

~~146~~35,~~630~~824

(9783,~~282~~020)

~~(137,276)~~

~~83,192~~

Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period

4013,~~070~~146

(614,~~086~~403)

~~(30,593)~~

~~66,146~~

Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income

(~~608~~3,554)

(207,~~906~~940)

~~(6,352)~~

~~(43,064)~~

Income Taxes (Benefits) – Net

399,~~462~~592

(2622,~~992~~343)

~~(36,945)~~

~~23,082~~

Other Comprehensive Income (Loss)

~~107~~26,~~168~~232

(7060,~~290~~677)

~~(100,331)~~

~~60,110~~

Comprehensive Income (Loss)

~~256~~207,~~986~~877

(~~124~~15,~~448~~691)

~~310,831~~

~~305,244~~

See Notes to Condensed Consolidated Financial Statements

Table of Content

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)

	June 30,2025		September 30,2024
	December 31,2025		September 30,2025
(Thousands of U.S. Dollars)
ASSETS
Property, Plant and Equipment	$	15,~~044~~616,~~963~~382	$	1415,~~524~~406,~~798~~329
Less - Accumulated Depreciation, Depletion and Amortization	7,~~588~~800,~~956~~307		7,~~185~~693,~~593~~687
	7,456,007		7,339,205
	7,816,075		7,712,642
Current Assets
Cash and Temporary Cash Investments	39271,~~317~~398		3843,~~222~~166
Receivables – Net of Allowance for Uncollectible Accounts of $23,732 and $26,194, Respectively	222,515		127,222
Receivables – Net of Allowance for Uncollectible Accounts of $17,504 and $17,099, Respectively	265,897		180,801
Unbilled Revenue	1569,~~347~~645		1516,~~521~~219
Gas Stored Underground	1218,~~810~~978		3533,~~055~~468
Materials and Supplies - at average cost	5149,~~022~~862		4750,~~670~~545
Unrecovered Purchased Gas Costs	220,~~903~~723		—5,769
Other Current Assets	6462,~~241~~097		9280,~~229~~759
	408,155		355,919
	758,600		410,727
Other Assets
Recoverable Future Taxes	9092,~~493~~405		8089,~~084~~247
Unamortized Debt Expense	65,~~701~~772		56,~~604~~236
Other Regulatory Assets	~~124~~133,~~300~~604		~~108~~135,~~022~~486
Deferred Charges	7175,~~426~~570		6973,~~662~~941
Other Investments	7368,~~764~~962		8168,~~705~~346
Goodwill	5,476		5,476
Prepaid Pension and Post-Retirement Benefit Costs	~~199~~171,~~286~~569		~~180~~169,~~230~~228
Fair Value of Derivative Financial Instruments	269,~~394~~364		8739,~~905~~388
Other	8,~~158~~475		58,~~958~~387
	581,998		624,646
	631,197		595,735
Total Assets	$	89,~~446~~205,~~160~~872	$	8,~~319~~719,~~770~~104

See Notes to Condensed Consolidated Financial Statements

Table of Content

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)

	June 30,2025		September 30,2024
	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 – 90,355,956 Shares and 91,005,993 Shares, Respectively	$	90,356	$	91,006
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,~~047~~382,~~406~~593		1,~~045~~050,~~487~~918
Earnings Reinvested in the Business	12,~~953~~143,~~533~~340		12,~~727~~012,~~326~~529
Accumulated Other Comprehensive Loss	(~~115~~32,~~807~~990)		(1559,~~476~~222)
Total Comprehensive Shareholders’ Equity	23,~~975~~587,~~488~~960		23,~~848~~094,~~343~~604
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,~~381~~083,~~852~~892		2,~~188~~382,~~243~~861
Total Capitalization	5,~~357~~671,~~340~~852		5,~~036~~477,~~586~~465
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	6190,~~500~~000		90150,~~700~~200
Current Portion of Long-Term Debt	~~300~~600,000		~~500~~300,000
Accounts Payable	~~123~~141,~~131~~674		~~165~~184,~~068~~046
Amounts Payable to Customers	~~24,275~~476		~~42,720~~968
Dividends Payable	4850,~~340~~834		4648,~~872~~353
Interest Payable on Long-Term Debt	3934,~~060~~644		2714,~~247~~393
Customer Advances	—17,108		1917,~~373~~188
Customer Security Deposits	2829,~~739~~875		3629,~~265~~853
Other Accruals and Current Liabilities	~~207~~209,~~179~~202		~~162~~174,~~903~~689
Fair Value of Derivative Financial Instruments	~~57,673~~155		46,~~744~~074
	889,897		1,095,892
	1,173,968		925,764
Other Liabilities
Deferred Income Taxes	1,~~153~~274,~~427~~254		1,~~111~~225,~~165~~262
Taxes Refundable to Customers	~~297~~304,~~602~~370		~~305~~306,~~645~~335
Cost of Removal Regulatory Liability	~~302~~311,~~932~~971		~~292~~307,~~477~~659
Other Regulatory Liabilities	~~137~~120,~~025~~230		~~151~~121,~~452~~944
Other Post-Retirement Liabilities	3,~~393~~731		35,~~511~~252
Asset Retirement Obligations	~~188~~234,~~305~~405		~~203~~236,~~006~~787
Other Liabilities	~~116~~111,~~239~~091		~~120~~112,~~036~~636
	2,198,923		2,187,292
	2,360,052		2,315,875
Commitments and Contingencies (Note 7)	—		—
Commitments and Contingencies (Note 8)	—		—
Total Capitalization and Liabilities	$	89,~~446~~205,~~160~~872	$	8,~~319~~719,~~770~~104

See Notes to Condensed Consolidated Financial Statements

Table of Content

National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)

Nine Months Ended June 30,

Three Months Ended December 31,

(Thousands of U.S. Dollars)

2025

2024

OPERATING ACTIVITIES

Net Income Available for Common Stock

~~411~~181,~~162~~645

~~245~~44,~~134~~986

Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:

Impairment of Assets

~~141,802~~—

~~200~~141,~~696~~802

Depreciation, Depletion and Amortization

~~337~~122,~~055~~025

~~348~~109,~~179~~370

Deferred Income Taxes

6034,~~754~~277

47(5,~~212~~385)

Premiums Paid on Early Redemption of Debt

2,385

—

Stock-Based Compensation

4,094

4,705

Stock-Based Compensation

15,721

15,984

Other

7,701

7,146

Other

19,296

18,542

Change in:

Receivables and Unbilled Revenue

(95138,~~254~~565)

5(115,~~253~~165)

Gas Stored Underground and Materials and Supplies

1815,~~803~~173

1810,~~981~~180

Unrecovered Purchased Gas Costs

(214,~~903~~954)

—

Other Current Assets

2818,~~038~~581

178,~~431~~814

Accounts Payable

121,~~744~~412

~~(13~~9,~~705)~~703

Amounts Payable to Customers

(~~18,445~~492)

~~3,550~~(133)

Customer Advances

(~~19,373~~80)

(214,~~003~~078)

Customer Security Deposits

~~(7,526)~~22

~~7,910~~(174)

Other Accruals and Current Liabilities

4437,~~283~~561

2321,~~846~~266

Other Assets

(355,~~348~~085)

(353,~~346~~892)

Other Liabilities

(398,~~918~~394)

(149,~~649~~057)

Net Cash Provided by Operating Activities

~~862~~274,~~276~~921

~~868~~220,~~015~~088

INVESTING ACTIVITIES

Capital Expenditures

(~~627~~277,~~316~~631)

(~~684~~240,~~200~~427)

Other

9(1,~~352~~255)

(15,~~371)~~878

Net Cash Used in Investing Activities

(~~617~~278,~~964~~886)

(~~685~~234,~~571~~549)

FINANCING ACTIVITIES

Changes in Notes Payable to Banks and Commercial Paper

(2960,200)

~~(287~~109,~~500)~~300

Net Proceeds from Issuance of Long-Term Debt

988,731

299,396

Shares Repurchased Under Repurchase Plan

—

(33,524)

Shares Repurchased Under Repurchase Plan

(54,430)

(27,847)

Dividends Paid on Common Stock

(48,353)

(46,872)

Reduction of Long-Term Debt

(1,004,086)

—

Net Proceeds from Common Stock Sale

347,106

—

Dividends Paid on Common Stock

(140,098)

(136,610)

Net Repurchases of Common Stock Under Stock and Benefit Plans

(6,356)

(3,971)

Net Repurchases of Common Stock Under Stock and Benefit Plans

(4,134)

(3,916)

Net Cash Provided by Financing Activities

232,197

24,933

Net Cash Used in Financing Activities

(243,217)

(156,477)

Net Increase in Cash and Cash Equivalents

228,232

10,472

Net Increase in Cash and Cash Equivalents

1,095

25,967

Cash and Cash Equivalents at October 1

43,166

38,222

Cash and Cash Equivalents at October 1

38,222

55,447

Cash and Cash Equivalents at December 31

271,398

48,694

Cash and Cash Equivalents at June 30

39,317

81,414

Supplemental Disclosure of Cash Flow Information

Non-Cash Investing Activities:

Non-Cash Capital Expenditures

8870,~~627~~359

8071,~~468~~616

Non-Cash Financing Activities:

Non-Cash Accrued Placement Fees from Common Stock Sale

8,531

—

See Notes to Condensed Consolidated Financial Statements

Table of Content

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.

~~Earnings for Interim Periods~~Reclassifications. ~~The~~ As ~~Company,~~reported in ~~its~~the ~~opinion,~~Company's ~~has~~2025 ~~included all adjustments (which consist of only normally recurring adjustments, unless otherwise disclosed in this Quarterly Report on~~ Form 10-Q)K, ~~that~~during ~~are~~the ~~necessary~~quarter ~~for~~ended aSeptember ~~fair~~30, ~~statement~~2025, of the ~~results~~segment ofreporting ~~operations~~structure ~~for~~was ~~the~~modified ~~reported~~to ~~periods.~~merge ~~The~~the ~~consolidated~~Exploration ~~financial statements~~ and ~~notes~~Production ~~thereto,~~segment ~~included~~and ~~herein,~~Gathering ~~should~~segment beinto ~~read~~one inreportable ~~conjunction~~segment ~~with~~called ~~the~~Integrated ~~financial~~Upstream ~~statements~~ and ~~notes~~Gathering. ~~for~~As ~~the~~a ~~years ended September 30~~result, ~~2024,~~revenue ~~2023~~and operation and ~~2022~~maintenance ~~that~~expense ~~are~~line ~~included~~items inon the ~~Company's 2024 Form 10-K. The~~ consolidated ~~financial~~ statements ~~for~~of ~~the~~income ~~year~~in ~~ended~~prior ~~September 30,~~periods ~~2025~~have ~~will~~been bereclassified ~~audited~~to byconform to the ~~Company's~~current ~~independent~~year ~~registered~~presentation. ~~public~~Additional ~~accounting~~discussion ~~firm~~is ~~after~~provided ~~the~~at ~~end~~Note of9 ~~the~~— Business ~~fiscal~~Segment ~~year~~Information.

~~The~~Earnings ~~earnings~~ for ~~the~~Interim ~~nine~~Periods. The ~~months~~Company, ~~ended~~in ~~June 30~~its opinion, ~~2025~~has ~~should~~included ~~not~~all beadjustments ~~taken~~(which asconsist aof ~~prediction~~only ofnormally ~~earnings~~recurring ~~for~~adjustments, ~~the~~unless ~~entire~~otherwise ~~fiscal~~disclosed ~~year~~in ~~ending~~this ~~September 30,~~Quarterly ~~2025. Most~~Report on Form 10-Q) that are necessary for a fair statement of the ~~business~~results of operations for the ~~Utility~~reported ~~segment~~periods. isThe ~~seasonal~~consolidated infinancial ~~nature~~statements and isnotes ~~influenced~~thereto, byincluded ~~weather~~herein, ~~conditions. Due~~should tobe ~~the~~read ~~seasonal~~in ~~nature~~conjunction ofwith the ~~heating~~financial ~~business~~statements inand ~~the~~notes ~~Utility~~for ~~segment,~~the ~~earnings~~years ~~during~~ended ~~the~~September 30, ~~winter~~2025, ~~months~~2024 ~~normally~~and ~~represent~~2023 athat ~~substantial~~are ~~part~~included ofin the ~~earnings~~Company's ~~that~~2025 ~~this~~Form ~~business~~10-K. The isconsolidated ~~expected~~financial tostatements ~~achieve~~ for the ~~entire~~year ~~fiscal~~ended ~~year. The~~September 30, 2026 will be audited by the Company’'s ~~business~~independent ~~segments~~registered ~~are~~public ~~discussed~~accounting ~~more~~firm ~~fully~~after ~~in Note~~the 8end –of ~~Business~~the ~~Segment~~fiscal ~~Information~~year.

~~Consolidated Statements of Cash Flows.~~ The ~~Statement~~earnings ~~of Cash Flows~~ for the ~~nine~~three months ended ~~June 30~~December 31, 2025 ~~and~~should ~~nine~~not ~~months~~be ~~ended~~taken ~~June~~as ~~30,~~a ~~2024~~prediction ~~reconciles~~of ~~the~~earnings ~~net~~for ~~increase~~the inentire ~~cash~~fiscal ~~and~~year ~~cash~~ending ~~equivalents~~September 30, ~~which~~2026. Most ~~consists~~of ~~solely~~the business of ~~cash~~the ~~and~~Utility ~~temporary~~segment ~~cash~~is ~~investments~~seasonal ~~for~~in ~~the~~nature ~~periods~~and ~~presented~~is influenced by weather conditions. Due ~~The~~to ~~Company~~the ~~did~~seasonal ~~not~~nature ~~have~~of ~~any~~the ~~restricted~~heating ~~cash~~business atin ~~June~~the ~~30,~~Utility ~~2025~~segment, ~~October~~earnings 1,during ~~2024,~~the ~~June~~winter ~~30,~~months ~~2024~~normally orrepresent ~~October~~a 1,substantial ~~2023.~~part ~~The~~of ~~Company~~the ~~considers~~earnings ~~all~~that ~~highly~~this ~~liquid~~business ~~debt~~is ~~instruments~~expected ~~purchased~~to ~~with~~achieve afor ~~maturity~~the ~~date~~entire offiscal ~~generally~~year. The ~~three~~Company’s ~~months~~business orsegments ~~less~~are todiscussed bemore ~~equivalents~~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.

Activity in the allowance for uncollectible accounts for the nine months ended June 30, 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
Nine Months Ended June 30, 2025
Allowance for Uncollectible Accounts	$	26,194	$	17,758	$	807	$	(21,027)	$	23,732
Nine Months Ended June 30, 2024
Allowance for Uncollectible Accounts	$	36,295	$	11,774	$	698	$	(16,145)	$	32,622

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~~Gas~~ Activity 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~~allowance ~~and~~for ~~fourth~~uncollectible ~~quarters~~accounts ~~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~~three ~~Balance~~months ~~Sheets~~ended ~~under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $12.7 million at June~~December 3031, 2025, isand ~~reduced~~2024 toare ~~zero by September 30 of each year~~ as ~~the~~follows ~~inventory~~(in ~~is replenished.~~thousands):

Property, Plant and Equipment. In the Company’s Exploration and Production segment, property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of 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 $2.32 billion and $2.28 billion at June 30, 2025 and September 30, 2024, respectively.


	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

~~Capitalized~~Gas ~~costs~~Stored ~~include~~Underground. In ~~costs~~the ~~related~~Utility tosegment, ~~unproved~~gas ~~properties~~stored underground is carried at lower of cost or net realizable value, ~~which~~on ~~are~~a ~~excluded~~LIFO ~~from~~method. Gas ~~amortization~~stored ~~until~~underground ~~proved~~normally ~~reserves~~declines ~~are~~during ~~found~~the orfirst itand issecond ~~determined~~quarters ~~that~~of the ~~unproved~~year ~~properties~~as storage quantities are ~~impaired. Such~~withdrawn ~~costs~~and ~~amounted~~increases toin ~~$132.6~~the ~~million~~third and ~~$201~~fourth quarters as storage quantities are replenished.0 In ~~million~~the atUtility ~~June 30~~segment, ~~2025~~the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and ~~September 30,~~a ~~2024,~~reserve ~~respectively. All~~for ~~costs~~gas ~~related~~replacement tois ~~unproved~~recorded ~~properties~~in ~~are~~the ~~reviewed~~Consolidated ~~quarterly~~Balance toSheets ~~determine~~under ifthe ~~impairment~~caption ~~has~~“Other ~~occurred~~Accruals and Current Liabilities.” Such ~~The~~reserve, ~~amount~~which ofamounted ~~any~~to ~~impairment~~$2.8 million at December 31, 2025, is ~~transferred~~reduced to ~~the~~zero ~~pool~~by September 30 of ~~capitalized~~each ~~costs~~year ~~being~~as ~~amortized~~the inventory is replenished.

~~Capitalized~~Property, ~~costs~~Plant ~~are~~and ~~subject~~Equipment. In to the ~~SEC~~Company’s ~~full~~Integrated ~~cost~~Upstream ~~ceiling~~and ~~test.~~Gathering ~~The ceiling test~~segment, ~~which~~upstream ~~is performed each quarter, determines a limit, or ceiling, on the amount of~~ property acquisition, exploration and development costs ~~that~~are ~~can~~accounted befor ~~capitalized. The ceiling~~ under ~~this test represents (a)~~ the ~~present~~full ~~value~~cost method of ~~estimated~~accounting. ~~future~~Under ~~net~~this ~~cash flows~~methodology, ~~excluding~~all ~~future~~costs ~~cash outflows~~ associated with ~~settling~~property ~~asset retirement obligations that have been accrued on the balance sheet~~acquisition, ~~using~~exploration aand ~~discount~~development ~~factor~~activities ofare ~~10%~~capitalized, ~~which~~including isinternal ~~computed~~costs bydirectly ~~applying~~identified ~~commodity~~with ~~pricing~~acquisition, ~~(as~~exploration ~~adjusted~~and ~~for~~development ~~hedging)~~activities. toThe ~~estimated~~internal ~~future~~costs ~~production~~that ofare ~~proved~~capitalized ~~reserves~~do asnot ofinclude ~~the~~any ~~date~~costs ofrelated ~~the~~to ~~latest balance sheet~~production, ~~less~~general ~~estimated~~corporate ~~future expenditures~~overhead, ~~plus~~or ~~(b) the~~similar ~~cost~~activities. ofThe ~~unproved~~Company ~~properties~~does not ~~being~~recognize ~~depleted,~~any ~~less~~gain ~~(c) income~~or ~~tax~~loss ~~effects~~on ~~related to~~ the ~~differences~~sale ~~between~~or ~~the~~other ~~book~~disposition ~~and tax basis~~ of ~~the~~ properties. ~~The~~unless ~~commodity prices used to calculate~~ the ~~full~~gain ~~cost~~or ~~ceiling~~loss ~~are~~would ~~based~~significantly onalter anthe ~~unweighted~~relationship ~~arithmetic~~between ~~average~~capitalized ofcosts ~~first~~and ~~day~~proved ofreserves ~~the~~attributable ~~month~~to ~~commodity~~a ~~price~~cost ~~for~~center. ~~each~~The ~~month~~Company's ~~within~~capitalized ~~the~~costs ~~twelve-month~~relating ~~period prior~~ to ~~the~~exploration ~~end~~and ofproduction ~~the reporting period. If capitalized costs~~activities, net of accumulated depreciation, depletion and amortization ~~and related deferred income taxes~~, ~~exceed~~were ~~the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter~~$2. At51 ~~June 30,~~billion ~~2025, the ceiling exceeded the book value of the exploration~~ and ~~production properties by approximately~~ $~~798~~2.846 ~~million.~~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 impairment charge of $108.3~~ ~~million for the quarter ended December~~ 31, ~~2024.~~2025 Aand ~~deferred income tax benefit of $29.2~~September million related to the non-cash impairment charge was also recognized for the quarter ended December 31, 2024. The estimated future net cash flows were increased by $338.6 million for hedging under the ceiling test at June 30, 2025., respectively.

~~The~~Capitalized ~~Exploration~~costs ~~and~~include ~~Production~~costs ~~segment~~related ~~also~~to ~~has~~unproved ~~items~~properties, ofwhich ~~property,~~are ~~plant~~excluded ~~and~~from ~~equipment~~amortization ~~that~~until proved reserves are ~~accounted~~found ~~for~~or ~~outside~~it ofis determined that the ~~provisions~~unproved ofproperties ~~the~~are ~~full~~impaired. Such ~~cost~~costs ~~method~~amounted ofto ~~accounting~~$105.7 Asmillion ~~discussed~~and in$112.4 ~~Note~~million 3at –December 31, ~~Fair~~2025 ~~Value~~and ~~Measurements~~September 30, an2025, ~~impairment~~respectively. All ~~charge~~costs related to ~~certain~~unproved ~~water~~properties ~~disposal~~are ~~assets~~reviewed ~~was~~quarterly ~~recorded~~to atdetermine ~~December~~if ~~31,~~impairment ~~2024~~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 ~~principal~~ceiling ~~assets~~test, ofwhich is performed each quarter, determines a limit, or ceiling, on the ~~Utility~~amount of property acquisition, ~~Pipeline~~exploration and ~~Storage~~development ~~and~~costs ~~Gathering~~that ~~segments~~can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, ~~consisting~~excluding ~~primarily~~future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of ~~gas~~10%, ~~distribution~~which ~~pipelines~~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, ~~transmission~~less ~~pipelines~~estimated future expenditures, ~~storage~~plus ~~facilities~~(b) the cost of unproved properties not being depleted, ~~gathering~~less ~~lines~~(c) income tax effects related to the differences between the book and ~~compressor~~tax ~~stations,~~basis ~~are~~of ~~recorded~~the atproperties. ~~historical~~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. ~~There~~ ~~were~~If nocapitalized ~~indications~~costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any ~~impairments~~quarter, a permanent non-cash impairment is required to ~~property~~be charged to earnings in that quarter. At December 31, ~~plant~~2025, the ceiling exceeded the book value of the exploration and ~~equipment~~production inproperties by approximately $1.3 billion. The book value of the ~~Utility~~exploration and production properties exceeded the ceiling at December 31, ~~Pipeline~~2024. As ~~and~~such, ~~Storage~~the Company recognized a non-cash, pre-tax ceiling test impairment charge in the Integrated Upstream and Gathering ~~segments~~segment atof ~~June~~$108.3 30million for the quarter ended December 31, ~~2025~~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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~~Accumulated~~historical ~~Other Comprehensive Income (Loss)~~cost. ~~The~~As ~~components~~discussed ofin ~~Accumulated~~Note ~~Other~~4 ~~Comprehensive~~– ~~Income~~Fair ~~(Loss)~~Value ~~and~~Measurements, ~~changes~~an ~~for~~impairment ~~the~~charge ~~nine~~related ~~months~~to ~~ended~~certain ~~June 30,~~water ~~2025~~disposal ~~and~~assets ~~2024,~~was ~~net~~recorded ofin ~~related~~the ~~tax~~Integrated ~~effect,~~Upstream ~~are~~and asGathering ~~follows~~segment ~~(amounts~~at inDecember ~~parentheses~~31, ~~indicate debits) (in thousands):~~ 2024.

	Gains and Losses on Derivative Financial Instruments		Funded Status of the Pension and Other Post-Retirement Benefit Plans		Total
Three Months Ended June 30, 2025
Balance at April 1, 2025	$	(151,700)	$	(71,275)	$	(222,975)
Other Comprehensive Gains and Losses Before Reclassifications	108,818		—		108,818
Amounts Reclassified From Other Comprehensive Loss	(1,650)		—		(1,650)
Balance at June 30, 2025	$	(44,532)	$	(71,275)	$	(115,807)
Nine Months Ended June 30, 2025
Balance at October 1, 2024	$	55,799	$	(71,275)	$	(15,476)
Other Comprehensive Gains and Losses Before Reclassifications	(83,082)		—		(83,082)
Amounts Reclassified From Other Comprehensive Loss	(17,249)		—		(17,249)
Balance at June 30, 2025	$	(44,532)	$	(71,275)	$	(115,807)
Three Months Ended June 30, 2024
Balance at April 1, 2024	$	135,023	$	(59,683)	$	75,340
Other Comprehensive Gains and Losses Before Reclassifications	(15,850)		—		(15,850)
Amounts Reclassified From Other Comprehensive Income	(54,440)		—		(54,440)
Balance at June 30, 2024	$	64,733	$	(59,683)	$	5,050
Nine Months Ended June 30, 2024
Balance at October 1, 2023	$	4,623	$	(59,683)	$	(55,060)
Other Comprehensive Gains and Losses Before Reclassifications	172,249		—		172,249
Amounts Reclassified From Other Comprehensive Income	(112,139)		—		(112,139)
Balance at June 30, 2024	$	64,733	$	(59,683)	$	5,050

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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Reclassifications Out of Accumulated Other Comprehensive Income (Loss). The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the nine months ended June 30, 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 EndedJune 30,		Nine Months Ended June 30,
	2025	2024	2025	2024
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts	$2,515	$75,462	$24,409	$155,401	Operating Revenues
Foreign Currency Contracts	(257)	(116)	(808)	(198)	Operating Revenues
	2,258	75,346	23,601	155,203	Total Before Income Tax
	(608)	(20,906)	(6,352)	(43,064)	Income Tax Expense
	$1,650	$54,440	$17,249	$112,139	Net of Tax

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

	At June 30, 2025		At September 30, 2024
	At December 31, 2025		At September 30, 2025
Prepayments	$	2213,~~810~~854	$	1816,~~463~~477
Prepaid Property and Other Taxes	1113,~~703~~855		1413,~~187~~920
Federal Income Taxes Receivable	—		814,~~154~~511
State Income Taxes Receivable	~~2,072~~—		~~13,161~~489
Regulatory Assets	2734,~~656~~388		3835,~~264~~362
	$	6462,~~241~~097	$	9280,~~229~~759

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

	At June 30, 2025		At September 30, 2024
	At December 31, 2025		At September 30, 2025
Accrued Capital Expenditures	$	5947,~~166~~178	$	4745,~~344~~932
Regulatory Liabilities	1826,~~650~~367		2920,~~352~~624
Reserve for Gas Replacement	122,~~706~~799		—
Liability for Royalty and Working Interests	2836,~~203~~608		1528,~~007~~076
Federal Income Taxes Payable	155,~~336~~384		—
Non-Qualified Benefit Plan Liability	14,135		14,135
State Income Taxes Payable	4,676		—
Other	58,983		57,065
Pennsylvania Impact Fee	19,955		14,923
	$	207,179	$	162,903
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 ~~and nine months~~ ended ~~June~~December 3031, 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 ~~1,126~~30 securities and ~~1,097~~four securities excluded as being antidilutive for the ~~quarter~~quarters ~~and~~ended ~~nine~~December 31, ~~months~~2025 ~~ended~~and ~~June~~December 3031, ~~2025~~2024, respectively. ~~There were 335 securities~~

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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~~excluded~~Compensation asCommittee ~~being~~("Report ~~antidilutive~~Group"). Three-year total shareholder return for a given company will be based on the ~~nine~~data ~~months~~reported ~~ended~~for ~~June 30,~~that ~~2024.~~company As(with the ~~Company~~starting ~~recognized~~and aending ~~net~~stock ~~loss~~prices over the performance cycle calculated as the average closing stock price for the ~~quarter~~prior ~~ended~~calendar ~~June 30,~~month ~~2024,~~and with dividends reinvested in ~~accordance~~that ~~with~~company’s ~~accounting~~securities ~~guidance,~~at ~~all~~each ~~dilution~~ex-dividend ~~associated~~date) ~~with~~in ~~restricted~~the ~~stock~~Bloomberg ~~units~~database. The number of these TSR Performance Shares that will vest and be paid will depend upon the Company’s performance ~~shares~~relative into the ~~amount~~Report Group and not upon the absolute level of ~~567,681~~return ~~shares,~~achieved ~~was~~by ~~excluded~~the ~~from~~Company. The fair value price at the ~~earnings~~date ~~per~~of ~~share~~grant ~~calculation~~for the TSR Performance Shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the ~~quarter~~present ~~ended~~value ~~June 30~~of forgone dividends over the vesting term of the award. This price is multiplied by the number of TSR Performance Shares awarded, ~~2024~~the result of which is recorded as compensation expense over the vesting term of the award.

~~Share~~ The ~~Repurchases~~Company granted 128,755 restricted stock units during the quarter ended December 31, 2025. The ~~Company~~weighted ~~considers~~average ~~all~~fair ~~shares~~value ~~repurchased~~of assuch ~~cancelled~~restricted ~~shares~~stock ~~restored~~units towas $77.75 per share for the ~~status~~quarter ended December 31, 2025. Restricted stock units represent the right to receive shares of ~~authorized~~common ~~but~~stock ~~unissued~~of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, inas ~~accordance~~determined ~~with~~by ~~New~~the ~~Jersey~~Company) ~~law~~at the end of a specified time period. These ~~The~~restricted ~~repurchases~~stock ~~are~~units ~~accounted~~do ~~for~~not onentitle the ~~date~~participant to receive dividends during the ~~share~~vesting ~~repurchase~~period. The isfair ~~traded~~value asat anthe ~~adjustment~~date toof ~~common~~grant of the restricted stock units (atrepresented ~~par~~by the market value of Company common stock on the date of the award) ~~with~~must be reduced by the ~~excess~~present ~~repurchase~~value ~~price~~of ~~allocated~~forgone ~~between~~dividends ~~paid~~over inthe ~~capital~~vesting ~~and~~term ~~retained~~of ~~earnings~~the award. The ~~Refer~~fair tovalue ~~Note~~of 6restricted ~~– Capitalization~~stock ~~for~~units ~~further~~on ~~discussion~~the date of ~~the~~award ~~Company's~~is ~~share~~recorded ~~repurchase~~as ~~program~~compensation expense over the vesting period.

~~Stock-Based~~Note ~~Compensation. The~~2 ~~Company~~– ~~granted~~Pending 239,042 performance shares during the nine months ended June 30, 2025. The weighted average fair value of such performance shares was $55.43 per share for the nine months ended June 30, 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.Acquisition

~~The~~On ~~performance~~October ~~shares~~20, ~~granted~~2025, ~~during~~ the ~~nine~~Company ~~months~~entered ~~ended~~into ~~June 30,~~a ~~2025~~Securities ~~include~~Purchase ~~awards~~Agreement ~~that~~(the ~~must~~“Purchase ~~meet~~Agreement”) awith ~~performance~~CenterPoint ~~goal~~Energy ~~related~~Resources Corp. (the “Seller”), pursuant to ~~either~~which, ~~relative~~among ~~total~~other ~~return~~things, onthe ~~capital~~Company ~~over~~agreed ato ~~three-year~~acquire ~~performance~~from ~~cycle~~the ~~("ROC~~Seller ~~Performance~~all ~~Shares"),~~of ~~methane~~the ~~intensity~~issued and ~~greenhouse~~outstanding ~~gas~~equity ~~emissions~~interests ~~reductions~~of ~~over~~Vectren aEnergy ~~three-year~~Delivery ~~performance~~of ~~cycle~~Ohio, LLC (~~"Emissions~~“CenterPoint ~~Performance Shares"~~Ohio”) orfor ~~relative~~an ~~total~~aggregate ~~shareholder~~purchase ~~return~~price ~~over~~of a$2.62 billion, ~~three-year~~subject ~~performance~~to ~~cycle~~customary ~~("TSR~~adjustments, ~~Performance~~as ~~Shares"). The~~provided ~~performance~~in ~~goal~~the ~~related~~Purchase toAgreement. This ~~the~~acquisition ~~ROC~~will ~~Performance~~add ~~Shares~~significant ~~over~~regulated scale for the ~~three-year~~Company, ~~performance~~doubling ~~cycle~~the issize of the Company’s ~~total~~gas ~~return~~utility onrate ~~capital~~base, ~~relative~~while toexpanding ~~the~~its ~~total~~operations ~~return~~beyond onNew ~~capital~~York and Pennsylvania into the neighboring state of ~~other~~Ohio, ~~companies~~a instate with a ~~group~~constructive ~~selected~~regulatory byand ~~the~~political ~~Compensation~~environment ~~Committee~~that ~~(“Report~~is ~~Group”). Total~~supportive ~~return~~of onnatural ~~capital~~gas. ~~for~~Closing ais ~~given~~expected ~~company~~to ~~means~~occur in the ~~average~~fourth quarter of ~~the~~calendar ~~Report~~2026, ~~Group~~pending ~~companies’~~completion ~~returns~~of ona ~~capital~~notice ~~for~~filing ~~each~~and ~~twelve~~review with the PUCO, Hart-~~month~~Scott-Rodino ~~period~~review, ~~corresponding~~and toother ~~each~~customary ofclosing ~~the~~conditions. The ~~Company’s~~purchase ~~fiscal~~price ~~years~~will ~~during~~include ~~the~~a ~~performance~~combination ~~cycle,~~of ~~based~~$1.42 billion onin ~~data~~cash ~~reported~~and ~~for~~a ~~the~~$1.2 billion ~~Report~~promissory ~~Group~~note ~~companies~~to inbe issued by the ~~Bloomberg~~Company ~~database~~to the Seller at closing. The ~~number~~promissory ofnote, ~~these~~which ~~ROC~~was ~~Performance~~part ~~Shares~~of ~~that~~the ~~will~~Seller’s ~~vest~~desired ~~and~~transaction bestructure ~~paid~~and ~~will~~was ~~depend~~incorporated ~~upon~~into the Company’s ~~performance~~business ~~relative~~valuation, towill ~~the~~have ~~Report~~a ~~Group~~maturity ~~and~~date ~~not~~of ~~upon~~364 ~~the~~days ~~absolute~~post-closing ~~level~~and ofwill ~~return~~carry ~~achieved~~an byinterest ~~the~~rate ~~Company~~of 6. ~~The~~5%. Permanent ~~fair~~financing, ~~value~~inclusive of the ~~ROC~~amount ~~Performance~~to ~~Shares~~repay isthe ~~calculated~~promissory bynote, ~~multiplying~~will ~~the~~consist of long-term debt and common equity, along with expected ~~number~~future offree ~~shares~~cash flow. In that ~~will~~regard, beon ~~issued~~December by17, 2025, the ~~average~~Company ~~market~~completed ~~price~~the ofissuance ~~Company~~and ~~common~~sale, ~~stock~~in ona ~~the~~private ~~date~~placement, of ~~grant~~4,402,513 ~~reduced~~shares byof the ~~present~~Company's ~~value~~common ofstock, ~~forgone~~par ~~dividends~~value ~~over~~$1.00 ~~the~~per ~~vesting~~share, ~~term~~at a price of ~~the~~$79.50 ~~award~~per share. ~~The~~ ~~fair~~After ~~value~~deducting isplacement ~~recorded~~fees, asthe ~~compensation~~net ~~expense~~proceeds ~~over~~to the ~~vesting~~Company ~~term~~amounted ofto ~~the award~~$338.6 million.

~~The~~In ~~performance~~connection ~~goal~~with ~~related~~its toentry ~~the~~into ~~Emissions Performance Shares over~~ the ~~three-year~~Purchase ~~performance~~Agreement, ~~cycle consists of two parts: reductions in~~ the ~~rates of intensity of methane emissions for each of the~~ Company's ~~operating~~entered ~~segments,~~into ~~and~~a ~~reduction~~senior ofunsecured ~~the~~bridge ~~consolidated~~loan ~~Company's~~facility ~~total~~commitment ~~greenhouse~~letter ~~gas~~supported ~~emissions.~~ by The ~~Company's~~Toronto-Dominion ~~Compensation~~Bank ~~Committee~~(“TD ~~set~~Bank”), ~~specific~~New ~~target~~York ~~levels~~Branch ~~for methane intensity rates~~ and ~~total~~Wells ~~greenhouse~~Fargo ~~gas emissions~~Bank, ~~and~~National ~~the~~Association ~~performance~~(together ~~goal~~with isTD ~~intended~~Bank, ~~to incentivize and reward performance to~~ the ~~extent~~“Commitment ~~management~~Parties”), ~~achieves~~as ~~methane~~well ~~intensity~~as ~~and~~a ~~greenhouse~~364-day ~~gas~~term ~~reduction~~loan ~~targets~~facility ~~making~~commitment ~~progress~~letter ~~towards~~supported orby ~~exceeding~~ the ~~Company's~~Commitment ~~2030~~Parties ~~goals. The number of these Emissions Performance Shares that will vest~~ and beadditional ~~paid~~banks, ~~out~~all ~~will depend upon the number~~ of ~~methane~~which ~~intensity~~are ~~segment~~lenders ~~targets~~under ~~achieved and whether~~ the Company’s ~~meets~~primary ~~the~~credit ~~total greenhouse gas emissions target~~facility. The ~~fair~~combination ~~value~~ of ~~these~~both ~~Emissions~~facilities ~~Performance~~fully ~~Shares~~supports isany ~~calculated~~portion ~~by multiplying the expected number~~ of ~~shares that will be issued by~~ the ~~average~~purchase ~~market~~ price ofthat ~~Company~~has ~~common~~not ~~stock~~been onpermanently ~~the date of grant reduced by the present value of forgone dividends over the vesting term of the award~~financed. ~~The fair value is recorded as compensation expense over the vesting term of the award.~~

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 the other companies in the Report Group. Three-year total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these TSR Performance Shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value price at the date of grant for the TSR Performance Shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the present value of forgone dividends over the vesting term of the award. This price is multiplied by the number of TSR Performance Shares awarded, the result of which is recorded as compensation expense over the vesting term of the award.

The Company granted 132,352 restricted stock units during the nine months ended June 30, 2025. The weighted average fair value of such restricted stock units was $58.64 per share for the nine months ended June 30, 2025. Restricted stock

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~~units~~Note ~~represent~~3 ~~the~~– ~~right~~Revenue tofrom ~~receive~~Contracts ~~shares~~with 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.Customers

~~Note~~ The 2following –tables ~~Revenue~~provide a disaggregation of the Company's revenues for the three months ended December 31, 2025 and 2024, presented by type of service from ~~Contracts~~each ~~with~~reportable ~~Customers~~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.

The following tables provide a disaggregation of the Company's revenues for the quarter and nine months ended June 30, 2025 and 2024, presented by type of service from each reportable segment.


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 June 30, 2025 (Thousands)
Quarter Ended December 31, 2024 (Thousands)
Revenues By Type of Service	~~Exploration~~Integrated Upstream and ~~Production~~Gathering		Pipeline and Storage		~~Gathering~~Utility		~~Utility~~Total Reportable Segments		All Other		Corporate and Intersegment Eliminations		Total Consolidated
Production of Natural Gas	$	~~300~~217,~~137~~458	$	—	$	—	$	—217,458	$	—	$	—	$	~~300~~217,~~137~~458
Production of Crude Oil	~~434~~515		—		—		—515		—		—		~~434~~515
Natural Gas Processing	~~267~~275		—		—		—275		—		—		~~267~~275
Natural Gas Gathering Service	—3,448		—		~~67,873~~—		—3,448		—		~~(65,354)~~—		23,~~519~~448
Natural Gas Transportation Service	—		8081,~~235~~204		—26,921		21108,~~639~~125		—		(2627,~~845~~181)		7580,~~029~~944
Natural Gas Storage Service	—		2524,~~028~~993		—		—24,993		—		(10,~~604~~504)		14,~~424~~489
Natural Gas Residential Sales	—		—		—156,350		~~118~~156,~~551~~350		—		—		~~118~~156,~~551~~350
Natural Gas Commercial Sales	—		—		—22,243		1522,~~349~~243		—		—		1522,~~349~~243
Natural Gas Industrial Sales	—		—		—1,338		~~732~~1,338		—		(1)		~~731~~1,337
Other	~~530~~883		~~316~~415		—15,740		~~(633)~~17,038		—		(~~224~~261)		~~(11)~~16,777
Total Revenues from Contracts with Customers	~~301~~222,~~368~~579		~~105~~106,~~579~~612		67222,~~873~~592		~~155~~551,~~638~~783		—		(~~103~~37,~~028~~947)		~~527~~513,~~430~~836
Alternative Revenue Programs	—		—		—5,917		15,~~885~~917		—		—		15,~~885~~917
Derivative Financial Instruments	229,~~515~~729		—		—		—29,729		—		—		229,~~515~~729
Total Revenues	$	~~303~~252,~~883~~308	$	~~105~~106,~~579~~612	$	67228,~~873~~509	$	~~157~~587,~~523~~429	$	—	$	(~~103~~37,~~028~~947)	$	~~531~~549,~~830~~482

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Nine Months Ended June 30, 2025 (Thousands)
Revenues By Type of Service	Exploration and Production		Pipeline and Storage		Gathering		Utility		All Other		Corporate and Intersegment Eliminations		Total Consolidated
Production of Natural Gas	$	836,000	$	—	$	—	$	—	$	—	$	—	$	836,000
Production of Crude Oil	1,341		—		—		—		—		—		1,341
Natural Gas Processing	881		—		—		—		—		—		881
Natural Gas Gathering Service	—		—		194,034		—		—		(184,834)		9,200
Natural Gas Transportation Service	—		243,921		—		93,815		—		(81,564)		256,172
Natural Gas Storage Service	—		75,309		—		—		—		(31,799)		43,510
Natural Gas Residential Sales	—		—		—		532,001		—		—		532,001
Natural Gas Commercial Sales	—		—		—		77,194		—		—		77,194
Natural Gas Industrial Sales	—		—		—		4,007		—		(4)		4,003
Other	2,070		2,535		—		12,507		—		(761)		16,351
Total Revenues from Contracts with Customers	840,292		321,765		194,034		719,524		—		(298,962)		1,776,653
Alternative Revenue Programs	—		—		—		10,200		—		—		10,200
Derivative Financial Instruments	24,409		—		—		—		—		—		24,409
Total Revenues	$	864,701	$	321,765	$	194,034	$	729,724	$	—	$	(298,962)	$	1,811,262

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.

Quarter Ended June 30, 2024 (Thousands)
Revenues By Type of Service	Exploration and Production		Pipeline and Storage		Gathering		Utility		All Other		Corporate and Intersegment Eliminations		Total Consolidated
Production of Natural Gas	$	144,374	$	—	$	—	$	—	$	—	$	—	$	144,374
Production of Crude Oil	511		—		—		—		—		—		511
Natural Gas Processing	195		—		—		—		—		—		195
Natural Gas Gathering Service	—		—		60,120		—		—		(56,476)		3,644
Natural Gas Transportation Service	—		79,640		—		21,690		—		(26,826)		74,504
Natural Gas Storage Service	—		24,612		—		—		—		(10,436)		14,176
Natural Gas Residential Sales	—		—		—		89,034		—		—		89,034
Natural Gas Commercial Sales	—		—		—		11,022		—		—		11,022
Natural Gas Industrial Sales	—		—		—		480		—		(1)		479
Other	363		1,167		—		(618)		—		(207)		705
Total Revenues from Contracts with Customers	145,443		105,419		60,120		121,608		—		(93,946)		338,644
Alternative Revenue Programs	—		—		—		3,336		—		—		3,336
Derivative Financial Instruments	75,462		—		—		—		—		—		75,462
Total Revenues	$	220,905	$	105,419	$	60,120	$	124,944	$	—	$	(93,946)	$	417,442

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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Nine Months Ended June 30, 2024 (Thousands)
Recurring Fair Value Measures	At fair value as of September 30, 2025
Revenues By Type of Service	Exploration and Production		Pipeline and Storage		Gathering		Utility		All Other		Corporate and Intersegment Eliminations		Total Consolidated
(Thousands of Dollars)	Level 1		Level 2		Level 3		NettingAdjustments(1)		Total(1)
Production of Natural Gas	$	580,233	$	—	$	—	$	—	$	—	$	—	$	580,233
Assets:
Production of Crude Oil	1,722		—		—		—		—		—		1,722
Cash Equivalents – Money Market Mutual Funds	$	30,551	$	—	$	—	$	—	$	30,551
Natural Gas Processing	765		—		—		—		—		—		765
Derivative Financial Instruments:
Natural Gas Gathering Service	—		—		186,701		—		—		(174,544)		12,157
Over the Counter Swaps – Gas	—		62,190		—		(33,615)		28,575
Natural Gas Transportation Service	—		232,532		—		88,817		—		(73,040)		248,309
Over the Counter No Cost Collars – Gas	—		24,149		—		(12,805)		11,344
Natural Gas Storage Service	—		71,247		—		—		—		(30,520)		40,727
Foreign Currency Contracts	—		144		—		(675)		(531)
Natural Gas Residential Sales	—		—		—		445,971		—		—		445,971
Other Investments:
Natural Gas Commercial Sales	—		—		—		62,117		—		—		62,117
Balanced Equity Mutual Fund	13,786		—		—		—		13,786
Natural Gas Industrial Sales	—		—		—		2,668		—		(5)		2,663
Fixed Income Mutual Fund	10,082		—		—		—		10,082
Other	1,416		4,073		—		(2,066)		—		(695)		2,728
Total	$	54,419	$	86,483	$	—	$	(47,095)	$	93,807
Total Revenues from Contracts with Customers	584,136		307,852		186,701		597,507		—		(278,804)		1,397,392
Liabilities:
Alternative Revenue Programs	—		—		—		19,949		—		—		19,949
Derivative Financial Instruments:
Derivative Financial Instruments	155,401		—		—		—		—		—		155,401
Over the Counter Swaps – Gas	$	—	$	34,169	$	—	$	(33,615)	$	554
Total Revenues	$	739,537	$	307,852	$	186,701	$	617,456	$	—	$	(278,804)	$	1,572,742
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

The Company records revenue related to its derivative financial instruments in the Exploration and Production segment. The Company also records revenue related to alternative revenue programs in its Utility segment. Revenue related to derivative financial instruments and alternative revenue programs are excluded from the scope of the authoritative guidance regarding revenue recognition since they are accounted for under other existing accounting guidance.

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: $59.0 million for the remainder of fiscal 2025; $221.9 million for fiscal 2026; $204.8 million for fiscal 2027; $154.5 million for fiscal 2028; $124.5 million for fiscal 2029; and $650.2 million thereafter.

Note 3 – Fair Value Measurements

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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 June 30, 2025 and September 30, 2024. 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 June 30, 2025
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)		Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	26,831	$	—	$	—	$	—	$	26,831
Derivative Financial Instruments:
Over the Counter Swaps – Gas	—		34,445		—		(32,440)		2,005
Over the Counter No Cost Collars – Gas	—		12,298		—		(11,750)		548
Contingent Consideration for Asset Sale	—		—		—		—		—
Foreign Currency Contracts	—		325		—		(484)		(159)
Other Investments:
Balanced Equity Mutual Fund	13,143		—		—		—		13,143
Fixed Income Mutual Fund	16,848		—		—		—		16,848
Total	$	56,822	$	47,068	$	—	$	(44,674)	$	59,216
Liabilities:
Derivative Financial Instruments:
Over the Counter Swaps – Gas	$	—	$	62,897	$	—	$	(32,440)	$	30,457
Over the Counter No Cost Collars – Gas	—		38,513		—		(11,750)		26,763
Foreign Currency Contracts	—		492		—		(484)		8
Total	$	—	$	101,902	$	—	$	(44,674)	$	57,228
Total Net Assets/(Liabilities)	$	56,822	$	(54,834)	$	—	$	—	$	1,988

Recurring Fair Value Measures	At fair value as of September 30, 2024
(Thousands of Dollars)	Level 1		Level 2		Level 3		NettingAdjustments(1)		Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	29,238	$	—	$	—	$	—	$	29,238
Derivative Financial Instruments:
Over the Counter Swaps – Gas	—		76,009		—		(17,198)		58,811
Over the Counter No Cost Collars – Gas	—		32,584		—		(3,774)		28,810
Contingent Consideration for Asset Sale	—		729		—		—		729
Foreign Currency Contracts	—		281		—		(726)		(445)
Other Investments:
Balanced Equity Mutual Fund	19,523		—		—		—		19,523
Fixed Income Mutual Fund	17,374		—		—		—		17,374
Total	$	66,135	$	109,603	$	—	$	(21,698)	$	154,040
Liabilities:
Derivative Financial Instruments:
Over the Counter Swaps – Gas	$	—	$	22,206	$	—	$	(17,198)	$	5,008
Over the Counter No Cost Collars – Gas	—		3,501		—		(3,774)		(273)
Foreign Currency Contracts	—		726		—		(726)		—
Total	$	—	$	26,433	$	—	$	(21,698)	$	4,735
Total Net Assets/(Liabilities)	$	66,135	$	83,170	$	—	$	—	$	149,305

(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 ~~June~~December 3031, 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

~~Table~~ In exploring the potential sale of ~~Content~~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.

					Impairments
Nonrecurring Fair Value Measures					Nine Months Ended June 30,
	Segment	Date of Measurement	Fair Value		2025		2024
Impairment of Assets:
Water Disposal Assets	Exploration and Production	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 Exploration and Production segment.

Derivative Financial Instruments

The derivative financial instruments reported in Level 2 at ~~June~~December 3031, 2025 and September 30, ~~2024~~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 ~~Exploration~~Integrated Upstream and ~~Production~~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 ~~June~~December 3031, 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.

Derivative financial instruments reported in Level 2 at June 30, 2025 also includes the contingent consideration associated with the sale of the Exploration and Production segment's California assets on June 30, 2022. The terms of the purchase and sale agreement specified that the Company could receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated at $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The calendar 2023 and 2024 contingency periods expired with the ICE Brent Average falling below $95 per barrel each calendar year. The fair value of the contingent consideration was calculated using a Monte Carlo simulation model that uses observable inputs, including the ICE Brent closing price as of the valuation date, initial and max trigger price, volatility, risk-free rate, time of maturity and counterparty risk. The fair value of this contingent consideration is estimated to be zero as of June 30, 2025.18

~~Note~~Table 4of ~~– Financial Instruments~~Content

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):

June 30, 2025

September 30, 2024

December 31, 2025

September 30, 2025

CarryingAmount

Fair Value

CarryingAmount

Fair Value

Long-Term Debt

2,~~681~~683,~~852~~892

2,~~668~~695,~~041~~409

2,~~688~~682,~~243~~861

2,~~656~~696,~~888~~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.

20Other 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.

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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 June 30, 2025		At September 30, 2024
	At December 31, 2025		At September 30, 2025
Life Insurance Contracts	$	4344,~~773~~576	$	44,~~808~~478
Equity Mutual Fund	1314,~~143~~183		1913,~~523~~786
Fixed Income Mutual Fund	1610,~~848~~203		1710,~~374~~082
	$	7368,~~764~~962	$	8168,~~705~~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 ~~Exploration~~Integrated Upstream and ~~Production~~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 ~~Exploration~~Integrated Upstream and ~~Production~~Gathering segment. These instruments are accounted for as cash flow hedges. The duration of the Company’s cash flow hedges ~~does~~and ~~not typically exceed 5 years while the~~ foreign currency forward contracts do not typically exceed 65 years.

OnThe ~~June 30, 2022, the~~ Company ~~completed~~has ~~the~~presented ~~sale~~its ofnet ~~Seneca’s~~derivative ~~California~~ assets~~. The~~ ~~terms of the purchase~~ and ~~sale~~liabilities agreement specified that the Company could receive up to three annual contingent payments between calendar year 2023 and calendar year 2025, not to exceed $10 million per year, with the amount of each annual payment calculated as ~~$1.0 million~~“Fair ~~for~~Value each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The calendar 2023 and 2024 contingency periods expired with the ICE Brent Average falling below $95 per barrel each calendar year. The Company has determined that this contingent consideration meets the definition of aDerivative ~~derivative~~Financial ~~under~~Instruments” the authoritative accounting guidance. Changes in the fair value of this contingent consideration are marked-to-market each reporting period, with changes in fair value recognized in Other Income (Deductions) on ~~the~~its Consolidated ~~Statement~~Balance ofSheets ~~Income. The fair value of this contingent consideration was estimated to be zero and $0.7 million~~ at ~~June~~December 3031, 2025 and September 30, ~~2024, respectively. A $0.7 million mark-to-market adjustment to reduce the fair value of the contingent consideration was recorded during the nine months ended June 30,~~ 2025.

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at June 30, 2025 and September 30, 2024.

Cash Flow Hedges

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

~~As of June 30, 2025, the Company had 427.0 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.~~19

As of June 30, 2025, the Company was hedging a total of $47.2 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

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As of ~~June~~December 3031, 2025, the Company had ~~$44~~403.51 ~~million~~Bcf of ~~net~~natural ~~hedging~~gas ~~losses~~commodity ~~after~~derivative ~~taxes~~contracts ~~included~~(swaps inand ~~the~~no ~~accumulated~~cost ~~other comprehensive income (loss~~collars) ~~balance~~outstanding. Of this amount, it is expected that $15.7 million of unrealized losses 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 June 30, 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 June 30,				Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Three Months Ended June 30,
	2025		2024			2025		2024
Commodity Contracts	$	147,594	$	(21,682)	Operating Revenue	$	2,515	$	75,462
Foreign Currency Contracts	1,294		(254)		Operating Revenue	(257)		(116)
Total	$	148,888	$	(21,936)		$	2,258	$	75,346

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.

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Nine Months Ended June 30, 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 Nine Months Ended June 30,				Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Nine Months Ended June 30,
	2025		2024			2025		2024
Commodity Contracts	$	(113,145)	$	238,184	Operating Revenue	$	24,409	$	155,401
Foreign Currency Contracts	(530)		211		Operating Revenue	(808)		(198)
Total	$	(113,675)	$	238,395		$	23,601	$	155,203

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 ~~eighteen~~seventeen counterparties of which ~~three~~sixteen are in a net gain position. On average, the Company had $04.83 million of credit exposure per counterparty in a gain position at ~~June~~December 3031, 2025. The maximum credit exposure per counterparty in a gain position at ~~June~~December 3031, 2025 was $210.08 million. As of ~~June~~December 3031, 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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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 June 30, 2025, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $34.3 million according to the Company's internal model (discussed in Note 3 – Fair Value Measurements), and no hedging collateral deposits were required to be posted by the Company at June 30, 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.

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 56 – Income Taxes

The effective tax rates for the quarters ended ~~June~~December 3031, 2025 and ~~June~~December 3031, 2024 were 2524.46% and 3419.39%, respectively. The ~~decrease~~increase in the quarterly effective income tax rate was primarily driven by the impact of the ~~impairment~~impairments of exploration and production properties under the ceiling test and other operational assets recorded during the quarter ended ~~June~~December 3031, 2024, which resulted in a ~~larger~~smaller income tax ~~benefit~~expense on aincome ~~loss~~ before income taxes during the quarter ended ~~June~~December 3031, 2024.

~~The~~Note ~~effective~~7 ~~tax rates for the nine months ended June~~– 30, 2025 and June 30, 2024 were 24.5% and 22.2%, respectively. The change in the year-to-date effective income tax rate was primarily driven by the impact of the impairments recorded in the quarters ended December 31, 2024 and June 30, 2024. The impairments were related to exploration and production properties under the ceiling test in both nine-month periods and an impairment of certain water disposal assets recorded in the quarter ended December 31, 2024. The impact of the impairments resulted in a smaller income tax expense on income before income taxes during each of the nine-month periods ended June 30, 2025 and June 30, 2024.Capitalization

On July 4, 2025, the One Big Beautiful Bill Act (“OBBBA”) was signed into law. The OBBBA makes permanent key elements of the Tax Cuts and Jobs Act, including 100% bonus depreciation, domestic research cost expensing, and the business interest expense limitation. Additionally, the OBBBA incorporates the immediate deduction of intangible drilling costs for taxpayers subject to the Corporate Alternative Minimum Tax. The Company is still evaluating the OBBBA and the results of such evaluations, which are not expected to have a material effect, are expected to be reflected on the Company’s Form 10-K for the year ended September 30, 2025.

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Note 6 – Capitalization

Summary of Changes in Common Stock Equity

	Common Stock			Paid InCapital		EarningsReinvestedin theBusiness		AccumulatedOtherComprehensiveIncome (Loss)
	Shares	Amount
	(Thousands, except per share amounts)
	(Thousands)
Balance at April 1, 2025	90,398	$	90,398	$	1,042,822	$	1,855,366	$	(222,975)
Balance at October 1, 2025	90,379	$	90,379	$	1,050,918	$	2,012,529	$	(59,222)
Net Income Available for Common Stock						~~149~~181,~~818~~645
Dividends Declared on Common Stock ($0.535 Per Share)						(4850,~~340~~834)
Other Comprehensive Income, Net of Tax								~~107~~26,~~168~~232
Share-Based Payment Expense (1)				43,~~685~~427
Common Stock Issued Under Stock and Benefit Plans	12	12		529
Common Stock Issued from Sale of Common Stock	4,403	4,403		334,173
Share Repurchases Under Repurchase Plan	(54)	(54)		(630)		(3,311)
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	235	235		(5,925)
Balance at June 30, 2025	90,356	$	90,356	$	1,047,406	$	1,953,533	$	(115,807)
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						~~411~~44,~~162~~986
Dividends Declared on Common Stock ($1.565 Per Share)						(141,566)
Dividends Declared on Common Stock ($0.515 Per Share)						(46,671)
Other Comprehensive Loss, Net of Tax								(~~100~~60,~~331~~677)
Share-Based Payment Expense (1)				134,~~911~~090
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	~~179~~156	~~179~~156		(23,~~377~~511)
Share Repurchases Under Repurchase Plan	(~~829~~549)	~~(829)~~$	(549)	~~(9,615)~~$	(6,361)	~~(43,389)~~$	(26,993)
Balance at June 30, 2025	90,356	$	90,356	$	1,047,406	$	1,953,533	$	(115,807)
Balance at December 31, 2024	90,613	$	90,613	$	1,039,705	$	1,698,648	$	(76,153)
Balance at April 1, 2024	92,032	$	92,032	$	1,045,929	$	2,090,172	$	75,340
Net Loss Available for Common Stock						(54,158)
Dividends Declared on Common Stock ($0.515 Per Share)						(47,195)
Other Comprehensive Loss, Net of Tax								(70,290)
Share-Based Payment Expense (1)				4,905
Common Stock Issued Under Stock and Benefit Plans	11	11		587
Share Repurchases Under Repurchase Plan	(431)	$	(431)	$	(4,942)	$	(18,435)
Balance at June 30, 2024	91,612	$	91,612	$	1,046,479	$	1,970,384	$	5,050
Balance at October 1, 2023	91,819	$	91,819	$	1,040,761	$	1,885,856	$	(55,060)
Net Income Available for Common Stock						245,134
Dividends Declared on Common Stock ($1.505 Per Share)						(138,354)
Other Comprehensive Income, Net of Tax								60,110
Share-Based Payment Expense (1)				14,262
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	320	320		(2,514)
Share Repurchases Under Repurchase Plan	(527)	$	(527)	$	(6,030)	$	(22,252)
Balance at June 30, 2024	91,612	$	91,612	$	1,046,479	$	1,970,384	$	5,050

(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 ~~nine~~three months ended ~~June~~December 3031, 2025 consisted of the following items:

			Nine Months Ended June 30, 2025
			Three Months Ended December 31, 2025
Vesting of Restricted Stock Units			~~125~~138,~~528~~643
Vesting of Performance Shares			89167,~~843~~241
Issuance of Common Stock Pursuant to the Company's Non-Employee Director EquityCompensation Plan and Deferred Compensation Plan for Directors and Officers			287,~~699~~368
Shares Tendered to Pay Withholding Taxes on Stock-Based Compensation Awards (1)			(6577,~~387~~422)
Common Stock Issued Under Stock and Benefit Plans			~~178~~235,~~683~~830
Share Repurchases Under Repurchase Plan			(828,720)
Common Stock Issued from Sale of Common Stock			4,402,513
Total Net Shares Repurchased During the Nine Months Ended June 30, 2025			(650,037)
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 ~~March~~December 817, ~~2024~~2025, the Company’s ~~Board~~completed ~~of Directors authorized~~ the ~~Company~~issuance toand ~~implement~~sale, in a ~~share~~private ~~repurchase~~placement, ~~program~~of 4,402,513 ~~whereby~~shares of the Company's ~~may~~common ~~repurchase~~stock, ~~outstanding~~par ~~shares~~value of$1.00 ~~common~~per ~~stock~~share, upat toa anprice ~~aggregate amount~~ of $~~200 million~~79.50 inper ~~the~~share. ~~open~~After ~~market~~deducting orplacement ~~through privately negotiated transactions~~fees, ~~including through~~ the ~~use~~net ofproceeds ~~trading plans intended~~ to ~~qualify~~the ~~under~~Company ~~SEC~~amounted ~~Rule~~to ~~10b5-1,~~$338.6 million. inThe ~~accordance~~proceeds ~~with~~of ~~applicable~~this ~~securities~~issuance ~~laws~~were ~~and~~used ~~other~~for ~~restrictions. In~~general ~~April~~corporate ~~2025~~purposes, ~~repurchases~~including ~~under~~to ~~the~~fund ~~program were temporarily paused. As~~ a ~~result,~~portion of the ~~Company~~purchase ~~expects~~price ~~completion~~ of the ~~program~~Company's ~~will~~previously ~~extend~~announced ~~into~~acquisition ~~calendar 2026. The timing and amount~~ of ~~future~~CenterPoint ~~repurchases~~Energy ~~under~~Resources ~~this~~Corp.'s ~~program~~Ohio ~~will~~regulated ~~depend~~gas onutility abusiness. ~~number~~Refer ~~of factors, including but not limited~~ to ~~stock~~Note ~~price,~~2 ~~market~~– ~~conditions,~~Pending ~~applicable~~Acquisition ~~securities~~for ~~laws~~further ~~(including SEC Rule 10b-18), corporate and regulatory requirements, and capital and liquidity needs~~discussion.

~~During~~Current ~~the~~Portion ~~nine~~of ~~months~~Long-Term ~~ended~~Debt. ~~June 30,~~The ~~2025,~~Current ~~the~~Portion ~~Company~~of ~~executed~~Long-Term ~~transactions~~Debt toat ~~repurchase 828~~December 31,~~720~~ ~~shares~~2025 atconsisted ~~an average price~~ of a $64300.370 ~~per~~million ~~share,~~long-term ~~for~~delayed adraw ~~total~~term ~~cost~~loan ofscheduled ~~$53.8 million~~to ~~(including~~mature ~~broker~~in ~~fees~~February ~~and~~2026 ~~excise taxes). Share repurchases~~ that ~~settled~~was ~~during~~repaid ~~the~~in ~~nine~~January ~~months~~2026 ~~ended~~and ~~June~~$300.0 ~~30,~~million ~~2025~~of ~~were~~5.50% ~~funded~~notes with ~~cash~~a ~~provided~~maturity bydate ~~operating~~in ~~activities~~October ~~and/or short-term borrowings~~2026. InThe ~~the~~Current ~~future,~~Portion itof isLong-Term ~~expected~~Debt ~~that~~at ~~this~~September ~~share~~30, ~~repurchase~~2025 ~~program~~consisted ~~will~~of ~~continue~~the toaforementioned be$300.0 million ~~funded~~long-term ~~with~~delayed ~~cash~~draw ~~provided~~term byloan ~~operating~~with ~~activities~~a ~~and/or~~maturity ~~through~~date ~~the~~in ~~use~~February ~~of short-term borrowings~~2026. ~~The program has no fixed expiration date.~~

~~Short-~~Delayed Draw Term ~~Borrowings~~Loan. ~~The~~ ~~Company~~On isFebruary a14, ~~party~~2024, tothe Company entered into a ~~syndicated~~Term ~~Credit~~Loan Agreement (asthe ~~amended~~“Term ~~from~~Loan ~~time~~Agreement”) towith ~~time~~six lenders, all of which are lenders under the “Credit Agreement”). ~~that~~As ~~provides~~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 $1300.0 ~~billion~~million unsecured committed ~~revolving~~delayed ~~credit~~draw term loan facility. Inwith ~~January~~a ~~2025,~~maturity ~~the~~date ~~Company~~of February 14, 2026, and the ~~banks~~Company inhad the ~~syndicate~~ability ~~consented~~ to aselect ~~second~~interest periods of one~~-year~~, ~~extension~~three ofor ~~the~~six ~~maturity~~months ~~date~~for ofborrowings. ~~the~~In ~~Credit~~April ~~Agreement~~2024, ~~such~~pursuant ~~that~~to the ~~Company~~delayed ~~has~~draw ~~aggregate~~mechanism, ~~commitments~~the ~~available~~Company inelected ~~the~~to ~~full~~draw ~~amount~~a total of $1300.0 ~~billion~~million ~~through~~under ~~February~~the ~~23, 2029~~facility. InAfter ~~May~~deducting ~~2025~~debt issuance costs, the ~~total~~net ~~lenders~~proceeds to the Company amounted to $299.4 million. Borrowings under the ~~Credit~~Term Loan Agreement ~~increased~~bear tointerest ~~twelve~~at as a ~~new~~rate ~~lender~~equal ~~joined~~to SOFR for the ~~syndicate~~applicable interest period, ~~assuming~~plus aan ~~portion~~adjustment of an0.10%, ~~existing~~plus ~~lender's~~a ~~commitment~~spread of 1.375%.

~~Current~~Note ~~Portion~~8 of– ~~Long-Term~~Commitments Debt. The Current Portion of Long-Term Debt at June 30, 2025 consisted of a $300.0 million long-term delayed draw term loan that matures in February 2026. The Current Portion of Long-Term Debt at September 30, 2024 consisted of $50.0 million of 7.38% notes that matured in June 2025 and ~~$450.0 million of 5.20% notes with a maturity date in July 2025. As discussed below, the Company redeemed the $450.0 million of 5.20% notes on March 6, 2025.~~Contingencies

Long-Term Debt. On February 19, 2025, the Company issued $500.0 million of 5.50% notes due March 15, 2030 and $500.0 million of 5.95% notes due March 15, 2035. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.2 million and $493.5 million, respectively. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50% on the 5.50% notes and 7.95% on the 5.95% notes, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded. The proceeds of these debt issuances were used for general corporate purposes, including the March 6, 2025 redemptions of $450.0 million of the Company's 5.20% notes that were scheduled to mature in July 2025 and $500.0 million of the Company's 5.50% notes that were scheduled to mature in January 2026. The Company redeemed those notes for $450.8 million and $503.3 million, respectively, plus accrued interest. In the Exploration and Production and Gathering segments, the call premiums of $0.6 million for the redemption of the 5.20% notes and $1.8 million for the

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redemption of the 5.50% notes, were recorded to Interest Expense on Long-Term Debt on the Consolidated Income Statement during the quarter ended March 31, 2025, and in the Pipeline and Storage segment, the call premiums of $0.2 million for the 5.20% notes redeemed and $1.5 million for the 5.50% notes redeemed were recorded to Unamortized Debt Expense on the Consolidated Balance Sheet as of March 31, 2025. The remaining proceeds of the debt issuances were used to repay a portion of short-term borrowings the Company incurred to fund a trust for the benefit of holders of $50.0 million of 7.38% notes under the Company's 1974 indenture prior to the June 13, 2025 maturity date of these notes. Placing these funds in trust enabled the Company to cancel and discharge the 1974 indenture. This relieved the Company from its obligations to comply with the 1974 indenture's covenants. The funds were paid out of the trust on June 13, 2025 for the redemption of the $50.0 million of 7.38% notes, leaving no notes outstanding under the 1974 indenture.

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. The Term Loan Agreement provides a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company has 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. The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper. Borrowings under the Term Loan Agreement currently 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%. The current weighted average locked-in interest rate is 5.82% until mid-August 2025.

Note 7 – 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 ~~June~~December 3031, 2025, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $32.79 million. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at ~~June~~December 3031, 2025. The Company has a regulatory liability of $2.1.5 million related to environmental clean-up costs at ~~June~~December 3031, 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 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 8 – Business Segment Information~~ 22

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

The data presented in the tables below reflect financial information for the segments and reconcile to consolidated amounts. As stated in the 2024 Form 10-K, the Company evaluates segment performance based on income before discontinued operations (when applicable). When this is not applicable, the Company evaluates performance based on net income. There have not been any changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s 2024 Form 10-K. A listing of segment assets at June 30, 2025 and September 30, 2024 is shown in the tables below.

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Quarter Ended June 30, 2025 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$303,883	$67,982	$2,519	$157,446	$531,830	$—	$—	$531,830
Intersegment Revenues	$—	$37,597	$65,354	$77	$103,028	$—	$(103,028)	$—
Segment Profit: Net Income (Loss)	$86,671	$28,857	$29,996	$4,997	$150,521	$(209)	$(494)	$149,818

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.

Nine Months Ended June 30, 2025 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$864,701	$207,916	$9,200	$729,445	$1,811,262	$—	$—	$1,811,262
Intersegment Revenues	$—	$113,849	$184,834	$279	$298,962	$—	$(298,962)	$—
Segment Profit: Net Income (Loss)	$137,722	$93,019	$83,483	$101,040	$415,264	$(674)	$(3,428)	$411,162

Note 9 – Business Segment Information

(Thousands)	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Segment Assets:
At June 30, 2025	$2,574,771	$2,421,610	$1,024,345	$2,507,973	$8,528,699	$8,216	$(90,755)	$8,446,160
At September 30, 2024	$2,644,820	$2,446,243	$987,103	$2,398,709	$8,476,875	$6,227	$(163,332)	$8,319,770

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.

Quarter Ended June 30, 2024 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$220,905	$68,035	$3,644	$124,858	$417,442	$—	$—	$417,442
Intersegment Revenues	$—	$37,384	$56,476	$86	$93,946	$—	$(93,946)	$—
Segment Profit: Net Income (Loss)	$(112,028)	$30,690	$24,979	$2,559	$(53,800)	$(124)	$(234)	$(54,158)

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.

Nine Months Ended June 30, 2024 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$739,537	$204,071	$12,157	$616,977	$1,572,742	$—	$—	$1,572,742
Intersegment Revenues	$—	$103,781	$174,544	$479	$278,804	$—	$(278,804)	$—
Segment Profit: Net Income (Loss)	$2,521	$85,482	$82,510	$73,848	$244,361	$(341)	$1,114	$245,134

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.

27 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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Note 9 – Retirement Plan and Other Post-Retirement Benefits


	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 June 30,

2025

2024

2025

2024

Three Months Ended December 31,

2025

2024

2025

2024

Service Cost

~~1,023~~861

1,~~049~~023

~~130~~105

~~109~~130

Interest Cost

98,~~223~~944

109,~~890~~223

3,~~625~~836

3,~~890~~625

Expected Return on Plan Assets

(14,~~647~~710)

(1714,~~086~~647)

(67,~~536~~374)

(6,~~660~~536)

Amortization of Prior Service Cost (Credit)

7663

9176

(~~107~~65)

(107)

Amortization of (Gains) Losses

12,~~620~~421

~~(335)~~1,620

9152

~~(567)~~9

Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)

85(98)

~~4,057~~(165)

(~~447~~148)

~~2,248~~(727)

Net Periodic Benefit Cost (Income)

(2,~~620~~519)

(12,~~334~~870)

(3,~~326~~494)

(13,~~087~~606)

	Retirement Plan				Other Post-Retirement Benefits
Nine Months Ended June 30,	2025		2024		2025		2024
Service Cost	$	3,069	$	3,148	$	389	$	326
Interest Cost	27,669		32,668		10,876		11,671
Expected Return on Plan Assets	(43,940)		(51,257)		(19,608)		(19,981)
Amortization of Prior Service Cost (Credit)	227		271		(322)		(322)
Amortization of (Gains) Losses	4,860		(1,004)		28		(1,700)
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	(3,026)		12,173		(5,333)		6,256
Net Periodic Benefit Cost (Income)	$	(11,141)	$	(4,001)	$	(13,970)	$	(3,750)

(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 ~~nine~~three months ended ~~June~~December 3031, 2025, and does not anticipate making any such contributions during the remainder of fiscal ~~2025~~2026. The Company also did not make any contributions to its VEBA trusts for its other post-retirement benefits during the ~~nine~~three months ended ~~June~~December 3031, 2025, and does not anticipate making any such contributions during the remainder of fiscal ~~2025~~2026.

Note 1011 – 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 ~~authorizes~~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.

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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

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 quarters ended March 31, 2025 and June 30, 2025, Distribution Corporation recovered $0.2 million and $0.3 million, respectively, from customers.25

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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. As ~~well, the revenue sharing mechanism under the 2019 rate case settlement was adjusted and~~ Empire ~~committed to undertake greenhouse gas and reliability reporting. 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 ~~four~~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 ~~that~~in ~~would~~northwest ~~allow~~Tioga ~~for~~County, ~~the~~Pennsylvania. ~~transportation~~On ofMay ~~190~~5,~~000~~ ~~Dth~~2025, ~~per~~FERC ~~day~~issued ofthe ~~shale~~Section ~~gas~~7(b)/7(c) ~~supplies~~certificate ~~from~~for athe ~~new~~project ~~interconnection~~and inon ~~northwest~~January ~~Tioga~~8, ~~County~~2026, ~~Pennsylvania~~FERC toissued anthe ~~existing~~Notice ~~Supply~~to ~~Corporation~~Proceed ~~interconnection~~ with ~~Tennessee~~Construction. Construction ~~Gas~~on ~~Pipeline~~the ~~Company,~~Tioga ~~LLC~~Pathway atProject ~~Ellisburg~~is ~~and~~expected ato ~~new~~commence ~~virtual~~in ~~delivery~~February ~~point~~2026. This ~~into~~project anhas ~~existing~~a ~~Transcontinental~~target ~~Gas~~in-service ~~Pipe~~date ~~Line~~in ~~Company,~~late ~~LLC~~calendar ~~(“Transco”) capacity~~ 2026.

29 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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~~lease,~~and ~~providing~~an ~~access~~additional torevenue ~~Mid-Atlantic~~requirement ~~markets~~increase of $12.7 Onmillion ~~May~~in 5fiscal 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, ~~2025~~2024 and December 31, ~~FERC~~2024. ~~issued~~In Distribution Corporation's Pennsylvania jurisdiction, Distribution Corporation made a filing with the ~~Section~~PaPUC on January 28, 2026 seeking an increase in its annual base rate operating revenues of $19.7~~(b)/7(c)~~ million ~~certificate~~with ~~for~~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 ~~project~~OPEB surcredit to refund $7. ~~Construction~~2 million for customer bill relief. In addition, on ~~the~~March ~~Tioga~~17, ~~Pathway~~2025, ~~Project~~FERC isapproved ~~expected~~an amendment to ~~commence~~Empire's in2019 ~~early~~rate ~~calendar~~case ~~2026~~settlement. This ~~project~~settlement ~~has~~amendment is estimated to decrease Empire's revenues on a ~~target~~yearly ~~in-service~~basis ~~date~~by inapproximately ~~late~~$0.5 ~~calendar~~million. ~~2026~~For further discussion of these and aother ~~preliminary~~rate ~~cost~~matters, ~~estimate~~refer ofto ~~approximately~~the ~~$101~~Rate ~~million~~Matters section below.

~~Supply~~On ~~Corporation~~October ~~has~~20, ~~also~~2025, ~~announced~~the ~~that~~Company itentered ~~expects~~into the Purchase Agreement with CenterPoint Energy Resources Corp. (the “Seller”), pursuant to ~~serve~~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 ~~transporter~~Purchase Agreement. This acquisition will add significant regulated scale for ~~205~~the Company,~~000~~ ~~Dth/day~~doubling the size of ~~natural~~the Company’s gas ~~supplies~~utility torate base, while expanding its operations beyond New York and Pennsylvania into the ~~Shippingport~~neighboring ~~Power~~state ~~Station~~of Ohio, a state with a constructive regulatory and political environment that is supportive of natural gas. ~~power~~Closing ~~generation~~is ~~facility~~expected ~~under~~to ~~development~~occur in ~~Beaver~~the ~~County~~fourth quarter of calendar 2026, ~~Pennsylvania~~pending completion of a notice filing and review with the PUCO, Hart-Scott-Rodino review, and other customary closing conditions. InThe ~~order~~purchase toprice ~~provide~~will ~~this~~include ~~new~~a ~~natural~~combination ~~gas~~of ~~transportation~~$1.42 billion ~~capacity,~~in ~~Supply~~cash ~~Corporation~~and ~~expects~~a $1.2 billion promissory note to ~~construct~~be anissued ~~approximately~~by 7the Company to the Seller at closing.5 The ~~mile~~promissory ~~pipeline~~note, ~~lateral~~which ~~from~~was ~~its~~part ~~existing~~of ~~Line~~the NSeller’s ~~pipeline~~desired ~~system~~transaction tostructure and was incorporated into the Company’s business valuation, will have a ~~direct~~maturity ~~interconnection~~date ~~with~~of 364 days post-closing and will carry an interest rate of 6.5%. Permanent financing, inclusive of the ~~facility~~amount (to repay the ~~“Shippingport~~promissory ~~Lateral~~note, ~~Project”)~~will consist of long-term debt and common equity, along with ~~the~~expected ~~incremental~~future ~~capacity~~free ~~expected~~cash toflow. In ~~come~~that ~~online~~regard, ason ~~early~~December as17, ~~Fall~~2025, ~~2026~~the Company completed the issuance and sale, in a ~~preliminary~~private ~~cost~~placement, ~~estimate~~of 4,402,513 shares of ~~approximately~~the ~~$57~~Company's ~~million.~~common ~~The~~stock, ~~Tioga~~par ~~Pathway~~value ~~Project~~$1.00 ~~and~~per ~~the~~share, ~~Shippingport~~at ~~Lateral~~a ~~Project~~price ~~are~~of ~~both~~$79.50 ~~discussed~~per inshare. After ~~more~~deducting ~~detail~~placement infees, the ~~Capital~~net ~~Resources~~proceeds ~~and~~to ~~Liquidity~~the ~~section~~Company ~~that~~amounted ~~follows~~to $338.6 million.

~~From~~In aconnection ~~rate~~with ~~perspective,~~its ~~Distribution~~entry ~~Corporation,~~into inthe ~~its~~Purchase ~~New York jurisdiction~~Agreement, ~~reached a settlement with~~ the ~~parties~~Company toentered ~~its~~into ~~rate~~a ~~case~~senior ~~proceeding.~~unsecured Onbridge ~~December~~loan ~~19,~~facility ~~2024,~~commitment ~~the~~letter ~~NYPSC~~supported ~~issued~~by ~~an order approving~~ the ~~settlement. The~~Commitment ~~settlement~~Parties, ~~effective~~as ~~January~~well 1,as ~~2025, established~~ a ~~three~~364-~~year~~day ~~rate~~term ~~plan~~loan ~~that~~facility ~~reflects~~commitment aletter ~~return~~supported onby ~~equity~~the ofCommitment ~~9.7%~~Parties and ~~authorizes a revenue requirement increase of $57.3 million in fiscal 2025, an~~ additional ~~revenue requirement increase of $15.8 million in fiscal 2026~~banks, ~~and~~all ~~an additional revenue requirement increase~~ of ~~$12.7~~which ~~million~~are inlenders ~~fiscal~~under ~~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 addition, on March 17, 2025, FERC approved an amendment to Empire'~~Company’s ~~2019~~primary ~~rate~~credit ~~case settlement~~facility. ~~This~~ ~~settlement~~The ~~amendment~~combination isof ~~estimated~~both tofacilities ~~decrease~~fully ~~Empire's~~supports ~~revenues~~any onportion ~~a yearly basis by approximately $0.5 million. For further discussion~~ of ~~these~~the ~~and~~purchase ~~other~~price ~~rate~~that ~~matters,~~has ~~refer~~not tobeen ~~the~~permanently ~~Rate Matters section below~~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. InThe ~~addition to the non-cash impairment charges under the ceiling test that the~~ Company recorded ~~during fiscal 2024, 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 ~~both~~December ~~June 30, 2025 and March~~ 31, 2025, the ceiling exceeded the book value of the exploration and production properties, and thus, did not result in an impairment charge in ~~either~~ the quarter ended ~~June~~December ~~30, 2025 or the quarter ended March~~ 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.

~~From~~The aCompany ~~financing~~expects ~~perspective,~~to onuse ~~February~~cash ~~19,~~from ~~2025~~operations, ~~the~~equity ~~Company issued $500.0 million of 5.50% notes due March 15~~proceeds, ~~2030~~ and ~~$500.0~~short-term ~~million~~and/or oflong-term ~~5.95%~~borrowings, ~~notes~~as ~~due March 15~~needed, ~~2035. The~~to ~~proceeds~~meet ofits ~~these~~financing ~~debt~~needs ~~issuances~~for ~~were~~the ~~used~~remainder ~~for~~of ~~general~~fiscal ~~corporate purposes~~2026, including the ~~March~~repayment ~~2025 redemptions~~ of a $~~450~~300.0 million ofdelayed ~~the~~draw ~~Company's~~term ~~5.20%~~loan ~~notes that were~~ scheduled to mature in ~~July~~February ~~2025~~2026 ~~and $500.0 million of the Company's 5.50% notes~~ that ~~were~~was ~~scheduled~~repaid ~~to mature~~ in January 2026. ~~The~~and ~~Company~~any ~~redeemed~~potential ~~those~~funding ~~notes~~ for ~~$450.8~~the ~~million~~CenterPoint ~~and~~Ohio ~~$503~~acquisition.3 ~~million, respectively, plus accrued interest.~~ The ~~remaining~~Company ~~proceeds~~continues ~~of the debt issuances were used~~ to ~~repay~~evaluate athese ~~portion~~financing ofneeds ~~short-term~~and ~~borrowings~~options ~~the Company incurred~~ to ~~fund~~meet ~~a trust for the benefit of holders of $50~~them.0 ~~million~~Given ~~of 7.38% notes under~~ the ~~Company's~~current ~~1974~~economic ~~indenture~~conditions, ~~prior~~which toinclude ~~the~~continued ~~June~~inflationary 13pressures, ~~2025~~volatile ~~maturity~~interest ~~date~~rates ~~of these notes. Placing these funds in trust enabled the Company to cancel~~ and ~~discharge~~ the ~~1974~~ongoing ~~indenture.~~impacts ~~This relieved the Company from its obligations to comply with the 1974 indenture’s covenants. The funds were paid out~~ of ~~the~~federal ~~trust~~policy ~~on June 13~~changes, ~~2025~~the ~~for~~cost ~~the~~and/or ~~redemption~~availability of ~~the~~capital ~~$50.0~~may ~~million~~be ~~of 7.38% notes~~impacted, ~~leaving~~but ~~no notes outstanding under~~ the ~~1974~~Company ~~indenture. For~~continues ~~details~~to ofexpect ~~these matters, refer~~ to ~~the~~meet ~~Capital~~its ~~Resources~~financing ~~and Liquidity section below~~needs.

The Company is a party to a syndicated Credit Agreement that provides a $1.0 billion unsecured committed revolving credit facility. In January 2025, the Company and the syndicate of banks under the Credit Agreement consented to a second one-year extension on 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 Company began repurchasing outstanding shares of its common stock during the quarter ended March 31, 2024 under a share repurchase program authorized by the Company’s Board of Directors. The program authorizes the Company to repurchase up to an aggregate amount of $200 million of its outstanding common stock in the open market or through privately negotiated transactions. In April 2025, repurchases under the program were temporarily paused. As a result, the Company expects completion of the program will extend into calendar 2026. The timing and amount of future repurchases under this program will depend on a number of factors, including but not limited to stock price, market conditions, applicable securities laws (including SEC Rule 10b-18), corporate and regulatory requirements, and capital and liquidity needs. During the nine months ended June 30, 2025, the Company executed transactions to repurchase 828,720 shares at an average price of $64.37 per share, for a total cost of $53.8 million (including broker fees and excise taxes). As of June 30, 2025, the Company has

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repurchased 1,974,979 shares under the share repurchase program at an average price of $59.70, for a total cost of $119.0 million (including broker fees and excise taxes). The program has no fixed expiration date. These matters are discussed further in the Capital Resources and Liquidity section that follows.

The Company expects to use cash on hand, cash from operations, and short-term and/or long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2025. 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 ~~2024~~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 ~~Exploration~~Integrated Upstream and ~~Production~~Gathering segment, follows the full cost method of accounting for determining the book value of its exploration and production properties~~, with natural gas properties in the Appalachian Region being the primary component after the fiscal 2022 sale of the Company's California exploration and production properties~~. In accordance with the full 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 June 30, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $798.8 million (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 June 30, 2025, based on the quoted Henry Hub spot price for natural gas, was $2.86 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 June 30, 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 June 30, 2025 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's exploration and production properties by approximately $440.1 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 2024 Form 10-K.27

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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.

RESULTS OF OPERATIONS

Earnings

The Company's earnings were $~~149~~181.86 million for the quarter ended ~~June~~December 3031, 2025 compared to aearnings ~~loss~~ of $5445.20 million for the quarter ended ~~June~~December 3031, 2024. The increase in earnings of $~~204~~136.06 million is primarily the result of ~~higher~~current year earnings recognized in the ~~Exploration~~Integrated Upstream and ~~Production~~Gathering segment, ascompared ~~well~~to asa ~~the~~prior ~~Gathering~~year ~~and~~loss combined with higher earnings in the Utility ~~segments~~segment. ~~Lower~~A higher loss in the Corporate category and lower earnings in the Pipeline and Storage segment ~~and~~partially ~~losses~~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 ~~Corporate~~Integrated Upstream and ~~All~~Gathering ~~Other~~segment, ~~categories~~consisting ~~partially~~mostly ~~offset~~of ~~these~~ceiling ~~increases~~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.

The Company's earnings were $411.2 million for the nine months ended June 30, 2025 compared to earnings of $245.1 million for the nine months ended June 30, 2024. The increase in earnings of $166.1 million is primarily the result of higher earnings in all reportable segments, partially offset by losses in the Corporate and All Other categories.

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The Company's earnings for the nine months ended June 30, 2025 included non-cash impairment charges of $141.8 million ($103.6 million after-tax) in the Exploration and Production segment, consisting mostly of ceiling test impairment charges of $108.3 million ($79.1 million after-tax), as discussed above. The remaining charges are related to the impairment of certain water disposal assets. The Company's earnings for the quarter and nine months ended June 30, 2024 included a non-cash ceiling test impairment charge of $200.7 million ($145.0 million after-tax) recorded during the quarter ended June 30, 2024 in the Exploration and Production segment. Note that all amounts used in earnings discussions are after-tax amounts, unless otherwise noted.

Earnings (Loss) by Segment

	Three Months EndedJune 30,						Nine Months Ended June 30,
	Three Months EndedDecember 31,
(Thousands)	2025		2024		Increase(Decrease)		~~2025~~		~~2024~~		~~Increase(Decrease)~~
Exploration and Production	$	86,671	$	(112,028)	$	198,699	$	137,722	$	2,521	$	135,201
Integrated Upstream and Gathering	$	124,047	$	(19,632)	$	143,679
Pipeline and Storage	2831,~~857~~219		3032,~~690~~454		(1,~~833~~235)		~~93,019~~		~~85,482~~		~~7,537~~
Gathering	29,996		24,979		5,017		83,483		82,510		973
Utility	34,090		32,499		1,591
Utility	4,997		2,559		2,438		101,040		73,848		27,192
Total Reportable Segments	189,356		45,321		144,035
Total Reportable Segments	150,521		(53,800)		204,321		415,264		244,361		170,903
All Other	(122)		(193)		71
All Other	(209)		(124)		(85)		(674)		(341)		(333)
Corporate	(7,589)		(142)		(7,447)
Corporate	(494)		(234)		(260)		(3,428)		1,114		(4,542)
Total Consolidated	$	181,645	$	44,986	$	136,659
Total Consolidated	$	149,818	$	(54,158)	$	203,976	$	411,162	$	245,134	$	166,028

~~Exploration and Production~~28

~~Exploration~~Table ~~and~~of ~~Production Operating Revenues~~Content

	Three Months EndedJune 30,						Nine Months Ended June 30,
(Thousands)	2025		2024		Increase(Decrease)		2025		2024		Increase(Decrease)
Gas Produced in Appalachia (after Hedging)	$	302,652	$	219,836	$	82,816	$	860,409	$	735,634	$	124,775
Other	1,231		1,069		162		4,292		3,903		389
	$	303,883	$	220,905	$	82,978	$	864,701	$	739,537	$	125,164

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 EndedJune 30,			Nine Months Ended June 30,
	Three Months EndedDecember 31,
	2025	2024	Increase(Decrease)	~~2025~~	~~2024~~	~~Increase(Decrease)~~
Gas Production per MMcf	111,588	96,504	15,084	314,819	300,144	14,675
Gas Production (MMcf)	109,181	97,717	11,464

Average Prices

	Three Months EndedJune 30,						Nine Months Ended June 30,
	Three Months EndedDecember 31,
	2025		2024		Increase(Decrease)		~~2025~~		~~2024~~		~~Increase(Decrease)~~
Average Gas Price/Mcf
Weighted Average	$	2.6977	$	12.5023	$	10.1954	$	~~2.66~~	$	~~1.93~~	$	~~0.73~~
Weighted Average After Hedging	$	2.7189	$	2.2853	$	0.4336	$	~~2.73~~	$	~~2.45~~	$	~~0.28~~

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2025 Compared with 2024

Operating revenues for the ~~Exploration~~Integrated Upstream and ~~Production~~Gathering segment increased $8370.09 million for the quarter ended ~~June~~December 3031, 2025 as compared with the quarter ended ~~June~~December 3031, 2024. Gas production revenue after hedging increased $8268.87 million due to the impact of a $0.4336 per Mcf increase in the weighted average price of natural gas after hedging, combined with a 1511.15 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.

~~Operating~~The ~~revenues~~Integrated ~~for~~Upstream ~~the Exploration~~ and ~~Production~~Gathering segment's ~~increased~~earnings ~~$125.2 million~~ for the ~~nine~~quarter ~~months~~ ended ~~June~~December 3031, 2025 aswere ~~compared with the nine months ended June 30, 2024. Gas production revenue after hedging increased~~ $124.80 million, ~~due~~an toincrease ~~the impact~~ of a $0143.286 ~~per~~million ~~Mcf~~when ~~increase~~compared ~~in the weighted average price of natural gas after hedging, combined~~ with a ~~14.7~~loss ~~Bcf~~of ~~increase in natural gas production~~$19. ~~The~~6 ~~increase~~million ~~in natural gas production~~ for the ~~nine~~quarter ~~months~~ ended ~~June~~December 3031, ~~2025~~2024. The as$143.6 ~~compared~~million ~~with~~increase ~~the~~can ~~nine~~be ~~months~~attributed ~~ended June 30, 2024 was largely due~~ to ~~pads~~the ~~recently~~following ~~turned in line.~~factors:

The Exploration and Production segment's earnings for the quarter ended June 30, 2025 were $86.7 million, an increase of $198.7 million when compared with a loss of $112.0 million for the quarter ended June 30, 2024. The $198.7 million increase can be attributed to the following factors:29

	(Millions)
Non-cash ceiling test impairment	$	145.0
Higher natural gas prices after hedging	38.3
Higher natural gas production	27.1
Change in mark to market adjustment on contingent consideration received as part of the 2022 California asset sale	0.8
Lower interest expense	0.6		(1)
Higher lease operating and transportation expenses	(5.7)		(2)
Higher income tax expense	(5.6)		(3)
Higher other tax expense	(1.6)		(4)
Other items	(0.2)
	$	198.7

(1)Lower interest expense mainly attributed to lower short-term and long-term intercompany borrowings.

(2)The increase in lease operating and transportation expenses was primarily the result of higher production combined with higher gathering and transportation costs.

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

(4)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.

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The Exploration and Production segment's earnings for the nine months ended June 30, 2025 were $137.7 million, an increase of $135.2 million when compared with earnings of $2.5 million for the nine months ended June 30, 2024. The $135.2 million increase can be attributed to the following factors:


	(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

	(Millions)
Higher natural gas prices after hedging	$	70.2
Lower non-cash impairments of assets	41.4		(1)
Higher natural gas production	28.4
Lower depletion expense	13.8		(2)
Change in mark to market adjustment on contingent consideration received as part of the 2022 California asset sale	3.0
Higher income tax expense	(7.9)		(3)
Higher lease operating and transportation expenses	(5.8)		(4)
Lower other income	(2.4)		(5)
Higher other tax expense	(2.4)		(6)
Higher operating expenses	(1.5)		(7)
Premiums paid on early redemption of debt	(1.0)		(8)
Earnings reduction associated with remeasurement of state deferred income taxes due to ceiling test impairment	(1.0)
Other items	0.4
	$	135.2

(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.

(12)~~Includes~~The adecrease ~~ceiling~~in ~~test~~interest ~~impairment~~expense ofis ~~$79.1~~mainly ~~million~~attributed ~~and~~to alower ~~$24.5~~short-term ~~million~~and ~~impairment~~long-term ofintercompany ~~certain water disposal assets recorded during the quarter ended December 31, 2024, offset by a ceiling test impairment of $145~~borrowings.~~0 million in the nine months ending June 30, 2024.~~

(23)The ~~decrease~~increase inwas ~~depletion~~due ~~expense~~to ~~was~~a ~~primarily~~$1.0 ~~due~~million toearnings ~~ceiling~~reduction ~~test~~associated ~~impairments~~with ~~recorded~~the inremeasurement ~~fiscal~~of ~~2024~~state ~~and~~deferred ~~2025~~income ~~that~~taxes ~~lowered~~for ~~Seneca’s~~the ~~full~~quarter ~~cost~~ended ~~pool~~December ~~depletable~~31, ~~base~~2024.

(34)The increase in ~~income~~depletion ~~tax~~is ~~expense~~mainly ~~was~~attributed ~~primarily driven by an increase in state income tax expense due~~ to higher ~~pre-tax income before impairments~~production.

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

(56)The ~~decrease~~increase in other ~~income~~operating expenses is mainly ~~attributable~~attributed to ~~non-recurrence~~a ofchange ~~business~~in ~~interruption~~segment ~~insurance~~reporting, ~~proceeds~~as ~~received~~well ~~during~~as ~~the~~higher ~~quarter~~gathering ~~ended~~operation ~~December~~and 31maintenance, ~~2023~~higher ~~related~~personnel tocosts aand ~~pipeline~~higher ~~outage~~abandonment ~~impacting~~accretion ~~Seneca’s~~expense, ~~ability~~partially tooffset ~~market~~by ~~gas~~higher abandonment costs recognized in fiscal 2024.

(67)The increase in ~~other~~income tax expense was primarily ~~attributable~~driven toby ~~higher~~an ~~Impact~~increase ~~Fees~~ in ~~the~~state ~~Appalachian~~tax ~~region~~expense ~~as the Company moved into a higher rate tier~~ due to higher ~~NYMEX~~pre-tax ~~pricing~~income.

(78)The increase in ~~operating~~other ~~expenses~~tax isexpense ~~mainly~~was ~~attributed~~primarily attributable to higher ~~personnel~~Impact ~~costs,~~Fees ~~higher abandonment accretion expense and higher environmental remediation costs~~ in the ~~nine~~Appalachian ~~months~~region ~~ended~~as ~~June~~the ~~30,~~Company ~~2025,~~moved ~~partially~~into ~~offset~~a by higher ~~abandonment~~rate ~~costs~~tier ~~recognized~~due into ~~the~~higher ~~nine~~NYMEX ~~months~~pricing ~~ended~~combined ~~June~~with ~~30,~~higher ~~2024~~well count.

(8)Represents the Exploration and Production segment’s share of the premiums paid by the Company to redeem long-term debt. Refer to Note 6 – Capitalization for further discussion.

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Pipeline and Storage

Pipeline and Storage Operating Revenues

	Three Months EndedJune 30,						Nine Months Ended June 30,
	Three Months EndedDecember 31,
(Thousands)	2025		2024		Increase(Decrease)		~~2025~~		~~2024~~		~~Increase(Decrease)~~
Firm Transportation	$	80,~~078~~885	$	7981,~~537~~086	$	~~541~~(201)	$	~~243,388~~	$	~~232,012~~	$	~~11,376~~
Interruptible Transportation	~~157~~123		~~103~~118		545		~~533~~		~~520~~		13
	80,235		79,640		595		243,921		232,532		11,389
	81,008		81,204		(196)
Firm Storage Service	25,~~028~~137		24,~~612~~993		~~416~~144		~~75,309~~		~~71,246~~		~~4,063~~
Interruptible Storage Service	—		—		—		—		1		~~(1)~~
Other	~~316~~756		~~1,167~~415		~~(851)~~341		~~2,535~~		~~4,073~~		~~(1,538)~~
	$	~~105~~106,~~579~~901	$	~~105~~106,~~419~~612	$	~~160~~289	$	~~321,765~~	$	~~307,852~~	$	~~13,913~~

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Pipeline and Storage Throughput

Three Months EndedJune 30,

Nine Months Ended June 30,

Three Months EndedDecember 31,

(MMcf)

2025

2024

Increase(Decrease)

~~2025~~

~~2024~~

~~Increase(Decrease)~~

Firm Transportation

~~179~~214,~~033~~073

~~168~~202,~~510~~882

1011,~~523~~191

~~616,644~~

~~590,868~~

~~25,776~~

Interruptible Transportation

~~149~~25

~~118~~62

31(37)

~~665~~

~~1,508~~

~~(843)~~

179,182

168,628

10,554

617,309

592,376

24,933

214,098

202,944

11,154

2025 Compared with 2024

Operating revenues for the Pipeline and Storage segment ~~were~~remained relatively ~~consistent~~flat for the quarter ended ~~June~~December 3031, 2025 as compared with the quarter ended ~~June~~December 3031, 2024. ~~Operating~~ revenues for the Pipeline and Storage segment increased $13.9 million for the nine months ended June 30, 2025 as compared with the nine months ended June 30, 2024. For the nine months ended June 30, 2025, the $11.4 million increase in transportation revenues and $4.1 million increase in storage revenues was primarily attributable to an increase in Supply Corporation's transportation and storage rates effective February 1, 2024 in accordance with Supply Corporation's rate case settlement. The settlement was approved by FERC on June 11, 2024. This increase was partially offset by the impact of a final true-up adjustment recorded in the nine months ended June 30, 2024 to the surcharge for pipeline safety and greenhouse gas costs that ended effective February 1, 2024. The increase in transportation revenues was also partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions. The $1.5 million decrease in other revenues primarily reflects lower cashout revenues, which are completely offset by purchased gas expense, and an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense.

Transportation volume for the quarter ~~and nine months~~ ended ~~June~~December 3031, 2025 increased by 1011.62 Bcf ~~and 24.9 Bcf~~, ~~respectively,~~ from the ~~prior year's~~ quarter ~~and~~ended ~~nine~~December ~~month~~31, ~~periods~~2024. The increase in transportation volume for ~~both~~ the quarter ~~and nine months~~ ended ~~June~~December 3031, 2025 is primarily due to anincreased ~~increase~~utilization inresulting ~~volume~~ from colder weather. ~~This~~ ~~increase for the nine month period was partially offset by lower capacity utilization with certain contract shippers and certain contract expirations and revisions.~~ 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.

35 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:

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	(Millions)
Lower other income	$	(1.2)	(1)

Other items	(0.1)
	$	(1.3)

(1)The ~~Pipeline~~decrease ~~and~~in ~~Storage~~other ~~segment’s~~income ~~earnings~~was ~~for~~primarily ~~the~~due ~~quarter~~to ~~ended June 30, 2025 were $28.9 million,~~ a ~~decrease~~lower ofaverage ~~$1.8~~amount ~~million~~outstanding ~~when~~on ~~compared~~intercompany ~~with~~short-term ~~earnings~~notes ofreceivables ~~$30.7~~and ~~million~~a ~~for~~lower ~~the~~weighted ~~quarter~~average ~~ended~~interest ~~June 30,~~rate ~~2024. The~~on ~~$1.8~~those ~~million decrease can be attributed to the following factors:~~receivables.

	(Millions)
Higher operating expenses	$	(1.7)	(1)
Lower other income	(1.2)		(2)
Lower interest expense	0.5		(3)
Other items	0.6
	$	(1.8)

(1)The increase in operating expenses was primarily due to an increase in personnel costs, as well as an increase in outside service expenses, largely related to system integrity and maintenance spending.

(2)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.

(3)The decrease in interest expense was primarily driven by a decrease in intercompany short-term borrowings, partially offset by an increase in interest on additional intercompany long-term borrowings associated with the Company's February 2025 debt issuance.

The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2025 were $93.0 million, an increase of $7.5 million when compared with earnings of $85.5 million for the nine months ended June 30, 2024. The $7.5 million increase can be attributed to the following factors:

	(Millions)
Higher operating revenues	$	12.2
Lower interest expense	0.8		(1)
Higher operating expenses	(3.8)		(2)
Lower other income	(1.8)		(3)
Other items	0.1
	$	7.5

(1)The decrease in interest expense was primarily driven by a decrease in intercompany short-term borrowings, partially offset by an increase in interest on additional intercompany long-term borrowings associated with the Company's February 2025 debt issuance.

(2)The increase in operating expenses was primarily due to an increase in personnel costs, as well as an increase in outside service expenses, largely related to system integrity and maintenance spending, and higher power costs related to Empire’s electric motor drive compressor station. The increase in electric power costs is offset by an equal increase in revenue.

(3)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, as well as a decline in non-service pension and post-retirement benefit income.

Gathering

Gathering Operating Revenues

	Three Months EndedJune 30,						Nine Months Ended June 30,
(Thousands)	2025		2024		Increase(Decrease)		2025		2024		Increase(Decrease)
Gathering Revenues	$	67,873	$	60,120	$	7,753	$	194,034	$	186,701	$	7,333

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Gathering Volume

	Three Months EndedJune 30,			Nine Months Ended June 30,
	2025	2024	Increase(Decrease)	2025	2024	Increase(Decrease)
Gathered Volume - (MMcf)	133,271	118,445	14,826	384,003	367,832	16,171

2025 Compared with 2024

Operating revenues for the Gathering segment increased $7.8 million for the quarter ended June 30, 2025 as compared with the quarter ended June 30, 2024, which was driven primarily by a 14.8 Bcf increase in gathered volume. Gathered volume increased 11.0 Bcf in the Gathering segment's Eastern Development Area (Tioga and Trout Run), consisting of an increase of 14.0 Bcf in the Tioga gathering system and a decrease of 3.0 Bcf in the Trout Run gathering system. The Gathering segment's Western Development Area (Clermont) also contributed an increase of 3.8 Bcf in gathered volume. The net increase in gathered volume can be attributed to an increase in gross natural gas production in the Appalachian region, largely by Seneca, connected to the aforementioned gathering systems.

Operating revenues for the Gathering segment increased $7.3 million for the nine months ended June 30, 2025 as compared with the nine months ended June 30, 2024, which was primarily driven by a 16.2 Bcf increase in gathered volume. Gathered volume increased 16.0 Bcf in the Gathering segment's Eastern Development Area (Tioga and Trout Run), consisting of an increase of 33.4 Bcf in the Tioga gathering system and a decrease of 17.4 Bcf in the Trout Run gathering system. Additionally, the Gathering segment's Western Development Area (Clermont) contributed an increase of 0.2 Bcf. The net increase can be attributed to an increase in gross natural gas production in the Appalachian region, largely by Seneca, connected to the aforementioned gathering systems.

The Gathering segment’s earnings for the quarter ended June 30, 2025 were $30.0 million, an increase of $5.0 million when compared with earnings of $25.0 million for the quarter ended June 30, 2024. The $5.0 million increase can be attributed to the following factors:

	(Millions)
Higher operating revenues	$	6.1
Higher depreciation expense	(0.9)		(1)
Higher income tax expense	(0.2)		(2)
	$	5.0

(1)The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga gathering system.

(2)The increase in income tax expense was largely due to higher state income taxes driven by higher pre-tax income.

The Gathering segment’s earnings for the nine months ended June 30, 2025 were $83.5 million, an increase of $1.0 million when compared with earnings of $82.5 million for the nine months ended June 30, 2024. The $1.0 million increase can be attributed to the following factors:

	(Millions)
Higher operating revenues	$	5.8
Lower income tax expense	0.7		(1)
Higher depreciation expense	(2.7)		(2)
Higher interest expense	(1.6)		(3)
Higher operating expenses	(0.8)		(4)
Premiums paid on early redemption of debt	(0.7)		(5)
Other items	0.3
	$	1.0

(1)The decrease in income tax expense was largely due to lower state income taxes resulting from the application of different state apportionment factors in 2025 vs. 2024, as well as a lower tax rate in Pennsylvania.

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(2)The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga gathering system.

(3)The increase in interest expense was primarily driven by additional short-term intercompany borrowings.

(4)The increase in operating expenses was primarily due to higher personnel costs.

(5)Represents the Gathering segment’s share of the premiums paid by the Company to redeem long-term debt. Refer to Note 6 – Capitalization for further discussion.

Utility

Utility Operating Revenues

Three Months EndedJune 30,

Nine Months Ended June 30,

Three Months EndedDecember 31,

(Thousands)

2025

2024

Increase(Decrease)

~~2025~~

~~2024~~

~~Increase(Decrease)~~

Retail Sales Revenues:

Residential

~~118~~196,~~819~~627

91171,~~267~~365

2725,~~552~~262

~~546,841~~

~~458,847~~

~~87,994~~

Commercial

1426,~~283~~606

1023,~~614~~212

3,~~669~~394

~~75,112~~

~~62,217~~

~~12,895~~

Industrial

~~735~~1,399

~~496~~1,384

~~239~~15

~~4,030~~

~~2,714~~

~~1,316~~

133,837

102,377

31,460

625,983

523,778

102,205

224,632

195,961

28,671

Transportation

2132,~~577~~243

2330,~~185~~622

(1,~~608)~~621

~~96,979~~

~~95,744~~

~~1,235~~

Other

2,~~109~~262

~~(618)~~1,926

~~2,727~~336

~~6,762~~

~~(2,066)~~

~~8,828~~

~~157~~259,~~523~~137

~~124~~228,~~944~~509

3230,~~579~~628

~~729,724~~

~~617,456~~

~~112,268~~

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Utility Throughput

	Three Months EndedJune 30,			Nine Months Ended June 30,
	Three Months EndedDecember 31,
(MMcf)	2025	2024	Increase(Decrease)	~~2025~~	~~2024~~	~~Increase(Decrease)~~
Retail Sales:
Residential	1021,~~151~~841	818,~~123~~476	23,~~028~~365	~~60,738~~	~~53,168~~	~~7,570~~
Commercial	13,~~658~~548	12,~~308~~919	~~350~~629	~~9,997~~	~~8,401~~	~~1,596~~
Industrial	93190	62199	31(9)	~~594~~	~~389~~	~~205~~
	11,902	9,493	2,409	71,329	61,958	9,371
	25,579	21,594	3,985
Transportation	1319,~~853~~670	1216,~~819~~942	12,~~034~~728	~~55,881~~	~~52,984~~	~~2,897~~
	25,755	22,312	3,443	127,210	114,942	12,268
	45,249	38,536	6,713

Degree Days

Three Months Ended June 30,				Percent Colder (Warmer) Than
Three Months Ended December 31,				Percent Colder (Warmer) Than
	Normal	2025	2024	Normal(1)		Prior Year(1)
Buffalo, NY(2)	~~843~~2,126	~~825~~2,281	~~565~~1,884	(27.1)3	%	4621.01	%
Erie, PA	~~776~~1,894	~~813~~2,121	~~519~~1,697	412.80	%	5625.60	%
Nine Months Ended June 30,
Buffalo, NY(2)	6,195	5,825	5,128	(6.0)	%	13.6	%
Erie, PA	5,693	5,527	4,759	(2.9)	%	16.1	%

(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.

effective October 2024.

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2025 Compared with 2024

Operating revenues for the Utility segment increased $3230.6 million for the quarter ended ~~June~~December 3031, 2025 as compared with the quarter ended ~~June~~December 3031, 2024. This increase resulted from a $3128.57 million increase in retail gas sales revenue, a $1.6 million increase in transportation revenue and a $20.73 million increase in other revenue. The increase in retail gas sales revenue ~~reflects~~and ~~the~~transportation ~~impact~~revenue ofreflects ~~new~~higher base delivery rates ineffective ~~Distribution~~October ~~Corporation's~~1, ~~New~~2025 ~~York~~from ~~jurisdiction~~the ~~pursuant~~impact toof athe ~~settlement~~implementation ~~approved~~of byyear ~~the~~two ~~NYPSC~~of onDistribution ~~December~~Corporation's ~~19,~~three-year ~~2024~~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 ~~revenues~~costs resulting from a 2.4.0 Bcf increase in throughput mainly due to colder weather ~~combined with an increase in the cost of gas sold (per Mcf)~~. ItUnder ~~should be noted that 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 other revenue was mainly due to the elimination of the refund provision that was required to defer and return the income tax benefits resulting from the 2017 Tax Reform Act to customers ($2.8 million). The refund provision is no longer necessary because Distribution Corporation's new base delivery rates now reflect a revenue requirement determined with the current federal income tax rate of 21% and the refund of excess accumulated deferred income taxes. The increases in retail gas sales revenue and other revenue were partially offset by a $1.6 million decrease in transportation revenue, ~~primarily~~also ~~due~~reflects ~~to the the amortization of certain regulatory assets in accordance with the New York rate settlement, despite~~ a 12.07 Bcf increase in throughput ~~and~~due ~~the~~primarily ~~impact~~to ofcolder ~~new base rates in New York discussed above~~weather.

~~Operating~~The ~~revenues for the~~ Utility segment’s ~~increased~~earnings ~~$112.3 million~~ for the ~~nine~~quarter ~~months~~ ended ~~June~~December 3031, 2025 aswere ~~compared with the nine months ended June 30, 2024. The increase resulted from a~~ $~~102~~34.~~2 million increase in retail gas sales revenue, a $~~1.2 million ~~increase in transportation revenue~~, ~~and~~ an ~~$8.8 million~~ increase ~~in other revenue. The increases in retail gas sales and transportation revenues reflect the impact~~ of ~~new base delivery rates in Distribution Corporation's New York jurisdiction, as mentioned above~~$1.6 ~~The~~million ~~increase~~when incompared ~~retail gas sales revenue also reflects higher purchased gas revenues resulting from a 9.4 Bcf increase in throughput mainly due to colder weather combined~~ with anearnings ~~increase in the cost~~ of ~~gas sold (per Mcf)~~$32.5 ~~The~~million ~~increase~~for inthe ~~transportation~~quarter ~~revenue~~ended ~~also reflects a 2.9 Bcf increase in throughput due primarily to colder weather~~December 31, ~~partially offset by the amortization of certain regulatory assets in accordance with the New York rate settlement~~2024. The increase incan ~~other~~be ~~revenue~~attributed ~~was largely due~~ to the ~~elimination~~following of the refund provision that was required to defer and return the income tax benefits resulting from the 2017 Tax Reform Act to customers ($10.8 million), as discussed above, partially offset by decreases in capacity release revenues ($0.9 million), other gas revenues ($0.7 million), and late payment charges billed to customers ($0.4 million).factors:

The Utility segment’s earnings for the quarter ended June 30, 2025 were $5.0 million, an increase of $2.4 million when compared with earnings of $2.6 million for the quarter ended June 30, 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

	(Millions)
Higher other income	$	3.2	(1)
Impact of new base rates in New York	2.8
Impact of higher customer usage	2.7
Higher operating expenses	(2.1)		(2)
Higher interest expense	(2.0)		(3)
Higher depreciation expense	(1.2)		(4)
Higher income tax expense	(1.2)		(5)
Other items	0.2
	$	2.4

(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.

~~(1)The increase in other income reflects the recognition of non-service pension and post-retirement benefit income in accordance with the New York rate settlement.~~ 32

(2)The increase in operating expenses is attributable to higher personnel costs, partially offset by amortizations of certain regulatory assets and a reduction in uncollectible expenses as a result of a tracker implemented, both of which were associated with the New York rate settlement.

(3)The increase in interest expense is mainly attributed to an increase in long-term intercompany debt balances.

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

(5)The increase in income tax expense was primarily driven by updates to the amortization of excess deferred income taxes in accordance with the New York rate settlement.

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(2)The ~~impact~~increase ~~of weather variations on cash flows and customer bills~~ in ~~the~~operating ~~Utility~~expenses ~~segment~~ is ~~mitigated~~largely byattributable ato ~~WNA.~~higher ~~The~~personnel ~~WNA,~~costs which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the Utility segment. In addition, in periods of colder than normal weather, the WNA benefits the Utility segment's customers. For the quarter ended June 30, 2025, the WNA preserved earnings of approximately $1.3 million in the Utility segment’s New York rate jurisdiction and ~~preserved~~higher ~~earnings~~uncollectible ~~of approximately $0~~expenses.5 million in the Utility segment's Pennsylvania rate jurisdiction, as the weather was warmer than normal on a cycle-bill basis in both jurisdictions. For the quarter ended June 30, 2024, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $1.7 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $1.4 million, as the weather was warmer than normal in both jurisdictions.

(3)The ~~Utility segment’s earnings for the nine months ended June 30, 2025 were $101.0 million, an~~ increase ofin ~~$27.2~~depreciation ~~million~~expense ~~when~~is ~~compared~~attributable ~~with~~to ~~earnings~~higher ofaverage ~~$73.8 million for the nine months ended June 30~~property, ~~2024.~~plant ~~The~~and ~~increase~~equipment ~~can be attributed to the following factors:~~balances.

	(Millions)
Impact of new base rates in New York	$	25.2
Higher other income	14.9		(1)
Impact of higher customer usage	5.4
Higher operating expenses	(6.7)		(2)
Higher interest expense	(5.7)		(3)
Higher depreciation expense	(2.6)		(4)
Higher income tax expense	(2.3)		(5)
Lower other operating revenues	(1.4)
Other items	0.4
	$	27.2

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.

~~(1)The~~ALL ~~increase~~OTHER inAND ~~other~~CORPORATE ~~income reflects the recognition of non-service pension and post-retirement benefit income in accordance with the New York rate settlement.~~ OPERATIONS

(2)The increase in operating expenses is attributable to higher personnel costs partially offset by amortizations of certain regulatory assets associated with the New York rate settlement.

(3)The increase in interest expense is mainly attributed to an increase in both short-term and long-term intercompany debt balances.

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

(5)The increase in income tax expense was primarily driven by updates to the amortization of excess deferred income taxes in accordance with the New York rate settlement and higher state income tax expense due to higher pre-tax income.

For the nine months ended June 30, 2025, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $3.9 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $1.7 million, as the weather was warmer than normal on a cycle-bill basis in both jurisdictions. For the nine months ended June 30, 2024, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $8.1 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $5.5 million, as the weather was warmer than normal in both jurisdictions.

Corporate and All Other

2025 Compared with 2024

~~Corporate and~~ All Other and Corporate operations ~~recorded~~reported a net loss of $07.7 million for the quarter ended ~~June~~December 3031, 2025, ~~which~~an ~~was~~increase ~~relatively~~in ~~consistent~~net loss of $7.4 million when compared with ~~the~~a net loss of $0.43 million for the quarter ended ~~June~~December 3031, 2024. ~~For~~The ~~the~~increase ~~nine~~in ~~months~~net ~~ended~~loss ~~June 30,~~was ~~2025,~~primarily ~~Corporate~~attributable ~~and~~to ~~All~~costs ~~Other~~associated ~~operations~~with ~~recorded~~the aCompany's ~~net~~planned ~~loss~~acquisition of ~~$4.1~~CenterPoint ~~million,~~Ohio ~~a decrease of~~ ($45.9 million ~~when compared with earnings of $0~~).8 ~~million~~Refer ~~for~~to ~~the~~Part ~~nine months ended June 30~~I, ~~2024.~~Item ~~The~~1 ~~decrease~~at ~~for~~Note ~~the~~2 ~~nine~~-~~month~~ ~~period~~Pending ~~was~~Acquisition ~~primarily~~for ~~attributable~~further todiscussion ~~changes~~of inthis ~~unrealized~~acquisition. ~~gains~~Additional ~~and~~contributing ~~losses~~factors onto ~~investments~~the increase in ~~equity~~net ~~securities.~~loss ~~During~~were ~~nine~~a ~~months~~decrease ~~ended~~in ~~June 30,~~the ~~2025,~~cash ~~the~~surrender ~~Company~~value ~~recorded~~of ~~unrealized~~life ~~losses~~insurance ofpolicies ($10.49 million.) ~~During~~and ~~the~~higher ~~nine~~operating ~~months~~expenses ~~ended June 30, 2024, the Company recorded unrealized gains of~~ ($10.49 million.), ~~Also~~primarily ~~contributing~~due to ~~the~~increased ~~decrease~~legal ~~included~~and ~~higher~~consulting ~~interest~~fees ~~expense~~and ~~($2.7~~outside ~~million)~~service costs.

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mainly due to a higher average amount of long-term borrowings and higher operating expense ($1.7 million) mainly due to higher legal and consulting fees and outside service expenses. These changes were partially offset by realized gains from investment securities sold during the current nine-month period ($1.2 million), an increase in interest income on temporary cash investments ($0.8 million), and a decrease in non-service pension and post-retirement benefit costs ($0.4 million).

Other Income (Deductions)

Net other income on the Consolidated Statements of Income was $8.52 million for the quarter ended ~~June~~December 3031, 2025, compared to net other income of $37.27 million for the quarter ended ~~June~~December 3031, 2024, for an increase of $50.35 million. This increase can be attributed primarily to a $41.71 million increase in ~~non-service~~interest ~~pension~~income. ~~and~~Partially ~~post-retirement~~offsetting ~~benefit~~this ~~income,~~increase ~~primarily~~was ~~due~~a to$0.7 ~~the~~million ~~recognition~~decrease ofin non-service pension and post-retirement benefit income ~~in accordance with Distribution Corporation's New York rate settlement, along with a $1~~.2 million change in the quarter-over-quarter revaluation of the contingent consideration received as part of the 2022 California asset sale. Also contributing to the increase was an increase in the quarter-over-quarter unrealized gains on investment securities of $0.9 million. Partially offsetting these increases, was a decrease in interest income of $1.4 million.

Net other income on the Consolidated Statements of Income was $31.5 million for the nine months ended June 30, 2025, compared to net other income of $13.0 million for the nine months ended June 30, 2024, for an increase of $18.5 million. This increase can be attributed primarily to a $21.1 million increase in non-service pension and post-retirement benefit income, as discussed above, along with a $4.1 million change in the year-over-year revaluation of the contingent consideration received as part of the 2022 California asset sale. These increases were offset by year-over-year changes in the value of investment securities. During the nine months ended June 30, 2025, there were net losses of $0.3 million on investment securities, compared to net gains of $2.0 million on investment securities during the nine months ended June 30, 2024. Other ~~offsetting~~Interest factors were the non-recurrence of $2.0 million of business interruption insurance proceeds received during the nine months ended June 30, 2024 related to a pipeline outage that impacted Seneca's ability to market its gas, along with a $1.9 million decrease in interest income.Expense

~~Interest~~ Other ~~Expense~~interest expense on ~~Long-Term~~the ~~Debt~~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.

Interest expense on long-term debt on the Consolidated Statement of Income increased $1.5 million for the quarter ended June 30, 2025 as compared to the quarter ended June 30, 2024. For the nine months ended June 30, 2025, interest expense on long-term debt increased $17.6 million as compared with the nine months ended June 30, 2024. These increases are primarily due to higher average balances and a higher weighted average interest rate on long-term debt. On February 19, 2025, the Company issued $500 million of 5.50% notes and $500 million of 5.95% notes. On March 6, 2025, the Company redeemed $450 million of 5.20% notes and $500 million of 5.50% notes and paid early redemption premiums totaling $2.4 million that were recorded as interest expense on long-term debt in the Exploration and Production and Gathering segments. The Company also redeemed $50 million of 7.38% notes on June 13, 2025. In addition, in April 2024, the Company elected to draw a total of $300.0 million under a delayed draw term loan credit facility. These borrowings had a locked-in weighted average interest rate of 5.86% and 5.99% for the quarter and nine months ended June 30, 2025, respectively.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary source of cash during the ~~nine~~three-month period ended ~~June~~December 3031, 2025 consisted of cash provided by operating activities and net proceeds from ~~long-term~~the ~~borrowings~~issuance of common stock. The Company’s primary source of cash during the ~~nine~~three-month period ended ~~June~~December 3031, 2024 consisted of cash provided by operating activities and net proceeds from ~~long~~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 ~~2025~~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 ~~2026~~2027, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures. ~~The~~These ~~Company~~cash ~~also~~flow ~~has~~projections ainclude ~~delayed~~the ~~draw~~impact ~~term~~of ~~loan that matures in February 2026, which~~ the ~~Company~~CenterPoint ~~anticipates~~Ohio ~~funding~~acquisition ~~with~~but ~~cash on hand as well as short-term or long-term borrowings. These cash flow projections~~ do not reflect the impact of other acquisitions or divestitures that may arise in the future.

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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 ~~Exploration~~Integrated Upstream and ~~Production~~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 $~~862~~274.39 million for the ~~nine~~three months ended ~~June~~December 3031, 2025, aan ~~decrease~~increase of $554.78 million compared with $~~868~~220.01 million provided by operating activities for the ~~nine~~three months ended ~~June~~December 3031, 2024. The ~~decrease~~increase in cash provided by operating activities primarily reflects ~~lower~~higher cash provided by operating activities in the ~~Utility~~Integrated Upstream and Gathering segment, partially offset by ~~higher~~lower cash provided by operating activities in the ~~Exploration~~Utility ~~and Production~~ segment. The ~~decrease~~increase in the ~~Utility~~Integrated Upstream and Gathering segment is ~~driven~~primarily bydue ~~the~~to ~~timing~~higher ofnatural gas ~~cost~~prices ~~recovery,~~and ~~partially~~production ~~offset~~in by the ~~impact~~Appalachian ofregion ~~higher~~combined ~~revenues~~with ~~resulting from~~ the ~~base~~timing ~~rate~~of ~~increase~~cash inreceipts ~~Distribution~~and ~~Corporation's~~hedge ~~New~~settlements ~~York~~associated ~~rate~~with ~~jurisdiction~~that production. The ~~increase~~decrease in the ~~Exploration~~Utility ~~and Production~~ segment is primarily due to ~~the~~higher ~~timing~~natural ofgas ~~cash~~prices ~~receipts~~ and ~~hedge~~throughput ~~settlements~~combined ~~from~~with ~~natural~~the ~~gas~~timing ~~production~~of in the ~~Appalachian~~associated ~~region~~gas cost recovery.

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Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $~~596~~222.07 million during the ~~nine~~three months ended ~~June~~December 3031, 2025 and $~~655~~192.51 million during the ~~nine~~three months ended ~~June~~December 3031, 2024. The table below presents these expenditures:

Total Expenditures for Long-Lived Assets
Nine Months Ended June 30,	2025			2024			Increase (Decrease)
Three Months Ended December 31,	2025			2024			Increase (Decrease)
(Millions)
Exploration and Production:
Integrated Upstream and Gathering:
Capital Expenditures	$	~~354~~141.48	(1)	$	~~399~~135.86	(2)	$	~~(45~~6.4)2
Pipeline and Storage:
Capital Expenditures	5837.16		(1)	6819.8		(2)	~~(10~~17.7)8
Gathering:
Capital Expenditures	58.2		(1)	69.1		(2)	(10.9)
Utility:
Capital Expenditures	~~128~~43.31		(1)	~~117~~36.5		(2)	106.86
All Other:
Capital Expenditures	0.52			0.32			~~0.2~~—
Eliminations	(3.5)			—			(3.5)
	$	222.7		$	192.1		$	30.6
	$	596.0		$	655.5		$	(59.5)

(1)At ~~June~~December 3031, 2025, capital expenditures for the ~~Exploration~~Integrated Upstream and ~~Production~~Gathering segment, the Pipeline and Storage segment, ~~the Gathering segment~~ and the Utility segment included $6155.5 million, $58.71 million, ~~$11.6 million~~ and $96.8 million, respectively, of non-cash capital expenditures. At September 30, ~~2024~~2025, capital expenditures for the ~~Exploration~~Integrated Upstream and ~~Production~~Gathering segment, the Pipeline and Storage segment, ~~the Gathering segment~~ and the Utility segment included $6387.39 million, $1419.4 million, ~~$21.7 million~~ and $2018.60 million, respectively, of non-cash capital expenditures.

(2)At June 30, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $50.9 million, $7.0 million, $14.6 million and $8.0 million, respectively, of non-cash capital expenditures. At September 30, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $43.2 million, $31.8 million, $20.6 million and $13.6 million, respectively, of non-cash capital expenditures. 34

~~Exploration~~Table ~~and~~of ~~Production~~ Content

~~The~~(2)At ~~Exploration~~December 31, ~~and~~2024, ~~Production segment~~ capital expenditures for the ~~nine~~Integrated ~~months~~Upstream ~~ended~~and ~~June~~Gathering 30segment, ~~2025~~the ~~were~~Pipeline ~~primarily~~and ~~well~~Storage ~~drilling~~segment and ~~completion~~the ~~expenditures~~Utility insegment ~~the~~included ~~Appalachian~~$62.3 ~~region~~million, ~~and~~$4.4 ~~included~~million and $~~104~~4.39 million, inrespectively, of non-cash capital expenditures. At September 30, 2024, capital expenditures for the ~~Marcellus~~Integrated ~~Shale~~Upstream ~~area~~and Gathering segment, the Pipeline and ~~$239.2~~Storage ~~million~~segment inand the ~~Utica~~Utility ~~Shale~~segment ~~area~~included $85.0 ~~These~~million, ~~amounts~~$14.4 ~~included~~million and $~~182~~20.6 million, ~~spent~~respectively, toof ~~develop~~non-cash ~~proved~~capital ~~undeveloped reserves~~expenditures.

~~The~~Integrated ~~Exploration~~Upstream and ~~Production segment capital expenditures for the nine months ended June~~Gathering 30, 2024 were primarily well drilling and completion expenditures in the Appalachian region, and included $60.2 million in the Marcellus Shale area and $325.7 million in the Utica Shale area. These amounts included $248.9 million spent to develop proved undeveloped reserves.

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 ~~nine~~three months ended ~~June~~December 3031, 2025 and ~~June~~December 3031, 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, isare discussed below.

43 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.

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~~Supply~~“Shippingport ~~Corporation~~Lateral ~~has~~Project”). ~~designed~~In aorder ~~project~~to ~~that~~provide ~~would~~this ~~allow~~new ~~for~~natural ~~the~~gas transportation ~~of 190~~capacity,~~000~~ ~~Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing~~ Supply Corporation ~~interconnection~~expects ~~with~~to ~~Tennessee~~construct ~~Gas~~an ~~Pipeline~~approximately ~~Company,~~7.5 ~~LLC~~mile atpipeline ~~Ellisburg~~lateral ~~and~~from aits ~~new virtual delivery point into an~~ existing ~~Transcontinental Gas Pipe~~ Line ~~Company,~~N ~~LLC~~pipeline ~~(“Transco”)~~system ~~capacity lease, providing access~~ to ~~Mid-Atlantic~~a ~~markets~~direct ~~(“Tioga~~interconnection ~~Pathway~~with ~~Project”).~~the ~~The~~facility ~~Tioga~~with ~~Pathway~~the ~~Project~~incremental ~~involves~~capacity ~~the~~expected ~~construction~~to ofcome ~~approximately~~online 19in ~~miles~~late ofcalendar ~~new~~2026 ~~pipeline~~ and ~~the~~an ~~replacement~~estimated ofcapital ~~approximately~~cost ~~four miles~~ of ~~existing~~approximately ~~pipeline~~$57 ~~on the Supply Corporation system~~million. Supply Corporation has executed a Precedent Agreement with ~~Seneca~~Shippingport ~~for~~Power ~~190~~Station,~~000~~ ~~Dth~~LLC, ~~per~~the ~~day~~facility ofdeveloper, ~~transportation~~for ~~capacity~~100% ~~and~~of ~~filed~~the acapacity ~~Section~~for ~~7(b)/7(c)~~the ~~application~~Shippingport ~~with~~Lateral ~~the~~Project ~~FERC~~and onfiled ~~August~~an ~~21,~~application ~~2024.~~with FERC ~~issued~~under the ~~Section~~Commission’s ~~7(b)/7(c)~~prior ~~certificate~~notice regulations on ~~May~~August 529, 2025. ~~Construction~~The ~~on the Tioga Pathway Project is expected to commence in early calendar 2026. This~~ project ~~has~~obtained aFERC ~~projected~~authorization ~~in-service~~on ~~date~~November of7, ~~late calendar year 2026 and an estimated capital cost of approximately $101 million~~2025. As of ~~June 30~~December 31, 2025, approximately $42.36 million has been spent toon ~~study~~ this project, ~~all~~including of$0.1 ~~which~~million ~~has~~spent ~~been~~to study the project that is included in Deferred Charges on the Consolidated Balance Sheet. atThe ~~June 30,~~remaining ~~2025~~$2.5 million spent on the project has been capitalized as Construction Work in Progress.

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 support a co-located data center (the "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 as early as Fall 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. As of June 30, 2025, approximately $0.4 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at June 30, 2025.

Gathering

The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2025 included expenditures related to the continued expansion of Midstream Company's Tioga and Trout Run gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines related to bringing new development online and system optimization, as well as the continued development of centralized station facilities, including increased dehydration capacity and compression horsepower.

The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2024 included expenditures related to the continued expansion of Midstream Company's Tioga and Clermont gathering systems. 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.

Utility

The majority of the Utility segment capital expenditures for the ~~nine~~three months ended ~~June~~December 3031, 2025 and ~~June~~December 3031, 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 ~~nine~~quarter ~~months~~ ended ~~June~~December 3031, 2025 and fiscal ~~2024~~2025, the Company has ~~been~~financed ~~financing~~ capital expenditures with cash from operations and short-term debt. Going forward, the Company expects to use cash onfrom ~~hand~~operations, ~~cash~~equity ~~from~~proceeds, ~~operations~~ and short-term or long-term borrowings, as needed, to finance capital expenditures. The level of short-term and/or long-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production and the associated commodity price realizations in the ~~Exploration~~Integrated Upstream and ~~Production~~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.

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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 segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s business segments depends, to a large degree, upon market and regulatory conditions as well as legislative actions.

Financing Cash Flow

Consolidated short-term debt decreased $2960.2 million when comparing the balance sheet at ~~June~~December 3031, 2025 to the balance sheet at September 30, ~~2024~~2025. The maximum amount of short-term debt outstanding during the ~~nine~~three months ended ~~June~~December 3031, 2025 was $~~330~~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, ~~repurchases of stock,~~ 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 ~~June~~December 3031, 2025, the Company had outstanding commercial paper of $6190.50 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.

OnThe ~~February 14, 2024, the~~ Company entered into a ~~Term~~term ~~Loan~~loan ~~Agreement~~agreement (the “Term Loan Agreement”) ~~with~~on ~~six~~February ~~lenders~~14, ~~all~~2024, with six of ~~which~~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 ~~provides~~provided a $300.0 million unsecured committed delayed draw term loan facility with a maturity date of February 14, 2026, and the Company ~~has~~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. ~~The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper.~~ Borrowings under the Term Loan Agreement ~~currently~~ 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%. ~~The~~ ~~current weighted average locked-in interest rate is 5.82% until mid-August 2025.~~

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 ~~June 30~~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. At ~~June 30~~Finally, pursuant to amendments to the Credit Agreement and Term Loan Agreement entered into as of November 6, 2025, ~~the~~for ~~Company’s~~purposes of calculating the debt to capitalization ratio, asthe ~~calculated~~Company’s $1.2 billion obligation under the ~~agreements~~Seller Note Facility, ~~was~~which ~~0.45. The~~is ~~constraints~~to ~~specified~~be inincurred at the ~~Credit~~closing ~~Agreement~~of the Transaction, will be excluded from the definition of consolidated indebtedness upon such time and to the ~~Term~~extent ~~Loan~~that the Company, in accordance with the Seller Note Agreement, ~~would~~deposits ~~have~~with a paying agent funds for defeasance of the Seller Note Facility.

45 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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~~permitted~~Credit anAgreement ~~additional~~or $3Term Loan Agreement, as applicable.60 ~~billion~~In inparticular, ~~short-term~~a ~~and/~~repayment obligation could be triggered if (i) the Company or ~~long-term~~any ~~debt~~of its significant subsidiaries fails to bemake ~~outstanding~~a atpayment ~~June~~when due of any principal or interest on any other indebtedness aggregating $40.0 30million or more or (ii) an event occurs that causes, ~~2025~~or ~~before~~would permit the ~~Company’s~~holders ~~debt~~of toany ~~capitalization~~other ~~ratio~~indebtedness ~~exceeded~~aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.~~65.~~

AThe ~~downgrade~~Current inPortion ~~the~~of ~~Company’s~~Long-Term ~~credit~~Debt ~~ratings~~at ~~could~~December 31, ~~increase~~2025 ~~borrowing~~consisted ~~costs,~~of ~~negatively~~a ~~impact~~$300.0 ~~the~~million ~~availability~~long-term ofdelayed ~~capital~~draw ~~from~~term ~~banks,~~loan ~~commercial~~scheduled ~~paper~~to ~~purchasers~~mature ~~and~~in ~~other~~February ~~sources,~~2026 ~~and~~that ~~require~~was ~~the~~repaid ~~Company's~~in ~~subsidiaries~~January to2026 ~~post~~and ~~letters~~$300.0 million of ~~credit,~~5.50% ~~cash~~notes orwith ~~other~~a ~~assets~~maturity asdate ~~collateral~~in ~~with~~October ~~certain counterparties~~2026. IfThe ~~the~~Current ~~Company~~Portion isof ~~not~~Long-Term ~~able~~Debt toat ~~maintain~~September ~~investment~~30, ~~grade~~2025 ~~credit~~consisted ~~ratings,~~of itthe ~~may~~aforementioned ~~not~~$300.0 bemillion ~~able~~long-term todelayed ~~access~~draw ~~commercial~~term ~~paper~~loan ~~markets. However,~~with ~~the~~a ~~Company~~maturity ~~expects~~date ~~that~~in itFebruary ~~could~~2026. ~~borrow~~The ~~under~~Company's ~~its~~present ~~credit~~liquidity ~~facilities~~position oris ~~rely~~believed ~~upon~~to ~~other~~be ~~liquidity~~adequate ~~sources~~to satisfy known demands.

The ~~Credit Agreement and the Term Loan Agreement each contain a cross-default provision whereby the failure by the~~ Company’s orembedded ~~its~~cost ~~significant subsidiaries to make payments under other borrowing arrangements, or the occurrence~~ of ~~certain~~long-term ~~events~~debt ~~affecting~~was ~~those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement or Term Loan Agreement, as applicable~~4.85% Inat ~~particular~~December 31, a2025 ~~repayment~~and ~~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~~4.~~0 million~~83% orat ~~more or (ii)~~December ~~an event occurs that causes~~31, ~~or would permit the holders of any other indebtedness aggregating $40~~2024.~~0 million or more to cause, such indebtedness to become due prior to its stated maturity.~~

On February 19, 2025, the Company issued $500.0 million of 5.50% notes due March 15, 2030 and $500.0 million of 5.95% notes due March 15, 2035. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.2 million and $493.5 million, respectively. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50% on the 5.50% notes and 7.95% on the 5.95% notes, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded. The proceeds of these debt issuances were used for general corporate purposes, including the March 6, 2025 redemptions of $450.0 million of the Company's 5.20% notes that were scheduled to mature in July 2025 and $500.0 million of the Company's 5.50% notes that were scheduled to mature in January 2026. The Company redeemed those notes for $450.8 million and $503.3 million, respectively, plus accrued interest. The remaining proceeds of the debt issuances were used to repay a portion of short-term borrowings the Company incurred to fund a trust for the benefit of holders of $50.0 million of 7.38% notes under the Company's 1974 indenture prior to the June 13, 2025 maturity date of these notes. Placing these funds in trust enabled the Company to cancel and discharge the 1974 indenture. This relieved the Company from its obligations to comply with the 1974 indenture's covenants. The funds were paid out of the trust on June 13, 2025 for the redemption of the $50.0 million of 7.38% notes, leaving no notes outstanding under the 1974 indenture.

The Current Portion of Long-Term Debt at June 30, 2025 consisted of a $300.0 million long-term delayed draw term loan that matures in February 2026. The Current Portion of Long-Term Debt at September 30, 2024 consisted of $50.0 million of 7.38% notes that matured in June 2025 and $450.0 million of 5.20% notes with a maturity date in July 2025. As discussed above, the Company redeemed the $450.0 million of 5.20% notes on March 6, 2025. 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 4.92% at June 30, 2025 and 4.91% at June 30, 2024.

On March 8, 2024, the Company’s Board of Directors authorized the Company to implement a share repurchase program, whereby the Company may repurchase outstanding shares of common stock, up to an aggregate amount of $200 million 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 April 2025, repurchases under the program were temporarily paused. As a result, the Company expects completion of the program will extend into calendar 2026. The timing and amount of future repurchases under this program will depend on a number of factors, including but not limited to stock price, market conditions, applicable securities laws (including SEC Rule 10b-18), corporate and regulatory requirements, and capital and liquidity needs.

During the nine months ended June 30, 2025, the Company executed transactions to repurchase 828,720 shares at an average price of $64.37 per share, for a total cost of $53.8 million (including broker fees and excise taxes). Share repurchases that settled during the nine months ended June 30, 2025 were funded with cash provided by operating activities and/or short-term borrowings. As of June 30, 2025, the Company has repurchased 1,974,979 shares under the share repurchase program at an average price of $59.70, for a total cost of $119.0 million (including broker fees and excise taxes). It is expected that future

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repurchases, if any, under this program will continue to be funded with cash provided by operating activities and/or through the use of short-term borrowings. The program has no fixed expiration date.

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 ~~nine~~three months ended ~~June~~December 3031, 2025, and does not anticipate making any such contributions during the remainder of fiscal ~~2025~~2026. The Company also did not make any contributions to its VEBA trusts for its other post-retirement benefits during the ~~nine~~three months ended ~~June~~December 3031, 2025, and does not anticipate making any such contributions during the remainder of fiscal ~~2025~~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 ~~June~~December 3031, 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 ~~2024~~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, 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~~39

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~~$15.8 million~~delivery inrates ~~fiscal~~do ~~2026,~~not ~~and~~reflect ~~an additional revenue requirement increase of $12.7 million in fiscal 2027. The revenue requirement for each year of~~ the ~~three-year~~recovery ~~plan has been reduced by $14 million for actuarial projections~~ of ~~income~~purchased ~~that~~gas ~~is expected to be recognized for qualified pension and other post-retirement benefits~~costs. ~~Qualified pension and other post~~ Prudently-~~retirement~~incurred ~~benefit~~gas ~~income or~~ costs are ~~matched~~recovered ~~with~~through ~~amounts~~operation ~~included in revenue resulting in zero impact to earnings. The 2024 Rate Order approves the continuation~~ of ~~several~~automatic ~~ratemaking~~adjustment ~~mechanisms~~clauses, ~~including revenue decoupling~~ and ~~WNA,~~are ~~and~~collected ~~establishes~~primarily through a ~~number~~separately-stated of“supply ~~new~~charge” ~~cost~~on ~~trackers~~the ~~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~~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

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 ~~quarters~~quarter ended ~~March~~December 31, 2025 ~~and June 30~~, ~~2025,~~ Distribution Corporation recovered $01.21 million ~~and~~from $0customers.3 ~~million,~~The ~~respectively,~~DSIC ~~from~~will ~~customers~~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. ~~As well, the revenue sharing mechanism under the 2019 rate case settlement was adjusted and~~ Empire ~~committed to undertake greenhouse gas and reliability reporting. 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 ~~processes~~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 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 7 – Commitments and Contingencies under the heading “Environmental Matters.”~~40

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, 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. For example, the EPA's regulations, which impose stringent leak detection and repair requirements and address reporting and control of methane and volatile organic compound emissions, were further expanded with the

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~~agency's~~measuring ~~March~~progress ~~2024~~against ~~publication~~these ~~and~~reduction ~~finalization~~targets. ofThe ~~the~~Company's ~~Standards~~ability ofto ~~Performance~~estimate ~~for~~accurately ~~New,~~the ~~Reconstructed~~time, ~~and~~costs ~~Modified Sources~~ and ~~Emissions~~resources ~~Guidelines~~necessary ~~for~~to ~~Existing~~meet ~~Sources~~emissions ~~and~~targets ~~its~~may ~~May~~be ~~2024~~impacted ~~finalization~~as ofenvironmental ~~the~~exposures, ~~Greenhouse~~technology ~~Gas~~and ~~Reporting~~opportunities ~~Program,~~change ~~Part~~and 98regulatory -and ~~Subpart~~policy Wupdates ~~Final~~are ~~Rule~~issued.

~~Additionally,~~For afurther ~~number~~discussion 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 other state authorities have acknowledged 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. 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. 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~~exposures, ~~requiring~~refer 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~~Item 1 ~~permits~~at ~~and~~Note ~~other~~8 ~~regulatory~~– ~~approvals.~~Commitments ~~Changing market conditions~~ and ~~new~~Contingencies ~~regulatory~~under 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~~heading of“Environmental ~~specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources~~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.

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