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Table of Contents
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM 10-Q
☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the quarterly period ended June 30, 2025
OR
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from____ to_____
Commission File Number 1-3880
NATIONAL FUEL GAS COMPANY
(Exact name of registrant as specified in its charter)

New Jersey | 13-1086010
(State or other jurisdiction of incorporation or organization) | (I.R.S. Employer Identification No.)
6363 Main Street |
Williamsville, | New York | 14221
(Address of principal executive offices) | (Zip Code)

(716) 857-7000
(Registrant's telephone number, including area code)

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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.

Large Accelerated Filer | ☑ | Accelerated Filer | ☐
Non-Accelerated Filer | ☐ | Smaller Reporting Company | ☐
|  | Emerging Growth Company | ☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☑
Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Common stock, par value $1.00 per share, outstanding at July 30, 2025: 90,363,646 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
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
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. a marketer) pays for gas the customer receives in excess of amounts delivered into pipeline/storage or distribution systems by the customer’s shipper.
CLCPA | Legislation referred to as the "Climate Leadership & Community Protection Act," enacted by the State of New York on July 18, 2019.
Degree day | A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative | A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, forward contracts, options, no cost collars and swaps.
Development costs | Costs incurred to obtain access to proved gas and oil reserves and to provide facilities for extracting, treating, gathering and storing the gas and oil.

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Dth | Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
Exchange Act | Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets | Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploration costs | Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
Exploratory well | A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
Firm transportation and/or storage | The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP | Accounting principles generally accepted in the United States of America
Goodwill | An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
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 (CH 4).
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.

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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 Service
SAR | Stock appreciation right
Section 7(b)/7(c) application | An application to the FERC under Section 7(b)/7(c) of the federal Natural Gas Act for authority to construct, operate (and provide services through) facilities to transport or store natural gas in interstate commerce.
Service agreement | The binding agreement by which the pipeline company agrees to provide service and the shipper agrees to pay for the service.
SOFR | Secured Overnight Financing Rate
Stock acquisitions | Investments in corporations
Utica Shale | A Middle Ordovician-age geological formation lying several thousand feet below the Marcellus Shale in the Appalachian region of the United States, including much of Ohio, Pennsylvania, West Virginia and southern New York.
VEBA | Voluntary Employees’ Beneficiary Association
WNA | Weather normalization adjustment; an adjustment in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.

4

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 3 0, 2025 and 2024 |  | 6
b. Consolidated Statements of Comprehensive Income – Three and Nine Months Ended June 30, 2025 and 2024 |  | 7
c. Consolidated Balance Sheets – June 3 0, 2025 and September 30, 2024 |  | 8
d. Consolidated Statements of Cash Flows – Nine Months Ended June 30, 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 |  | 29
Item 3. Quantitative and Qualitative Disclosures About Market Risk |  | 51
Item 4. Controls and Procedures |  | 51
Part II. Other Information |  |
Item 1. Legal Proceedings |  | 51
Item 1 A. Risk Factors |  | 51
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds |  | 52
Item 5. Other Information |  | 52
Item 6. Exhibits |  | 52
Signatures |  | 54

All references to a certain year in this report are to the Company’s fiscal year ended September 30 of that year, unless otherwise noted.
5

Table of Content
Part I. Financial Information
Item 1. Financial Statements
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)

| Three Months Ended June 30, |  | Nine Months Ended June 30,
(Thousands of U.S. Dollars, Except Per Common Share Amounts) | 2025 |  | 2024 |  | 2025 |  | 2024
INCOME |  |  |  |  |  |  |
Operating Revenues: |  |  |  |  |  |  |
Utility Revenues | $ | 157,446 |  |  | $ | 124,858 |  |  | $ | 729,445 |  |  | $ | 616,977 |
Exploration and Production and Other Revenues | 303,883 |  |  | 220,905 |  |  | 864,701 |  |  | 739,537 |
Pipeline and Storage and Gathering Revenues | 70,501 |  |  | 71,679 |  |  | 217,116 |  |  | 216,228 |
| 531,830 |  |  | 417,442 |  |  | 1,811,262 |  |  | 1,572,742 |
Operating Expenses: |  |  |  |  |  |  |
Purchased Gas | 27,986 |  |  | 4,952 |  |  | 228,661 |  |  | 167,444 |
Operation and Maintenance: |  |  |  |  |  |  |
Utility | 56,053 |  |  | 53,412 |  |  | 174,744 |  |  | 166,405 |
Exploration and Production and Other | 35,272 |  |  | 35,148 |  |  | 103,874 |  |  | 102,768 |
Pipeline and Storage and Gathering | 41,679 |  |  | 40,019 |  |  | 119,982 |  |  | 114,321 |
Property, Franchise and Other Taxes | 24,180 |  |  | 21,201 |  |  | 71,450 |  |  | 66,635 |
Depreciation, Depletion and Amortization | 116,408 |  |  | 113,454 |  |  | 337,055 |  |  | 348,179 |
Impairment of Assets | — |  |  | 200,696 |  |  | 141,802 |  |  | 200,696 |
| 301,578 |  |  | 468,882 |  |  | 1,177,568 |  |  | 1,166,448 |
Operating Income (Loss) | 230,252 |  |  | (51,440) |  |  | 633,694 |  |  | 406,294 |
Other Income (Expense): |  |  |  |  |  |  |
Other Income (Deductions) | 8,534 |  |  | 3,188 |  |  | 31,486 |  |  | 12,989 |
Interest Expense on Long-Term Debt | (34,333) |  |  | (32,876) |  |  | (107,356) |  |  | (89,791) |
Other Interest Expense | (3,556) |  |  | (1,341) |  |  | (13,033) |  |  | (14,250) |
Income (Loss) Before Income Taxes | 200,897 |  |  | (82,469) |  |  | 544,791 |  |  | 315,242 |
Income Tax Expense (Benefit) | 51,079 |  |  | (28,311) |  |  | 133,629 |  |  | 70,108 |
Net Income (Loss) Available for Common Stock | 149,818 |  |  | (54,158) |  |  | 411,162 |  |  | 245,134 |
EARNINGS REINVESTED IN THE BUSINESS |  |  |  |  |  |  |
Balance at Beginning of Period | 1,855,366 |  |  | 2,090,172 |  |  | 1,727,326 |  |  | 1,885,856 |
| 2,005,184 |  |  | 2,036,014 |  |  | 2,138,488 |  |  | 2,130,990 |
Share Repurchases under Repurchase Plan | (3,311) |  |  | (18,435) |  |  | (43,389) |  |  | (22,252) |
Dividends on Common Stock | (48,340) |  |  | (47,195) |  |  | (141,566) |  |  | (138,354) |
Balance at June 30 | $ | 1,953,533 |  |  | $ | 1,970,384 |  |  | $ | 1,953,533 |  |  | $ | 1,970,384 |
Earnings (Loss) Per Common Share: |  |  |  |  |  |  |
Basic: |  |  |  |  |  |  |
Net Income (Loss) Available for Common Stock | $ | 1.66 |  |  | $ | (0.59) |  |  | $ | 4.54 |  |  | $ | 2.67 |
Diluted: |  |  |  |  |  |  |
Net Income (Loss) Available for Common Stock | $ | 1.64 |  |  | $ | (0.59) |  |  | $ | 4.51 |  |  | $ | 2.65 |
Weighted Average Common Shares Outstanding: |  |  |  |  |  |  |
Used in Basic Calculation | 90,358,018 |  |  | 91,874,049 |  |  | 90,546,228 |  |  | 91,966,034 |
Used in Diluted Calculation | 91,139,556 |  |  | 91,874,049 |  |  | 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
6

Table of Content
National Fuel Gas Company
Consolidated Statements of Comprehensive Income
(Unaudited)

| Three Months Ended June 30, |  | Nine Months Ended June 30,
(Thousands of U.S. Dollars) | 2025 |  | 2024 |  | 2025 |  | 2024
Net Income (Loss) Available for Common Stock | $ | 149,818 |  |  | $ | (54,158) |  |  | $ | 411,162 |  |  | $ | 245,134 |
Other Comprehensive Income (Loss), Before Tax: |  |  |  |  |  |  |
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | 148,888 |  |  | (21,936) |  |  | (113,675) |  |  | 238,395 |
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income | (2,258) |  |  | (75,346) |  |  | (23,601) |  |  | (155,203) |
Other Comprehensive Income (Loss), Before Tax | 146,630 |  |  | (97,282) |  |  | (137,276) |  |  | 83,192 |
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period | 40,070 |  |  | (6,086) |  |  | (30,593) |  |  | 66,146 |
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income | (608) |  |  | (20,906) |  |  | (6,352) |  |  | (43,064) |
Income Taxes (Benefits) – Net | 39,462 |  |  | (26,992) |  |  | (36,945) |  |  | 23,082 |
Other Comprehensive Income (Loss) | 107,168 |  |  | (70,290) |  |  | (100,331) |  |  | 60,110 |
Comprehensive Income (Loss) | $ | 256,986 |  |  | $ | (124,448) |  |  | $ | 310,831 |  |  | $ | 305,244 |

See Notes to Condensed Consolidated Financial Statements
7

Table of Content
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)

| June 30, 2025 |  | September 30, 2024
(Thousands of U.S. Dollars) |  |  |
ASSETS |  |  |
Property, Plant and Equipment | $ | 15,044,963 |  |  | $ | 14,524,798 |
Less - Accumulated Depreciation, Depletion and Amortization | 7,588,956 |  |  | 7,185,593 |
| 7,456,007 |  |  | 7,339,205 |
Current Assets |  |  |
Cash and Temporary Cash Investments | 39,317 |  |  | 38,222 |
Receivables – Net of Allowance for Uncollectible Accounts of $23,732 and $26,194, Respectively | 222,515 |  |  | 127,222 |
Unbilled Revenue | 15,347 |  |  | 15,521 |
Gas Stored Underground | 12,810 |  |  | 35,055 |
Materials and Supplies - at average cost | 51,022 |  |  | 47,670 |
Unrecovered Purchased Gas Costs | 2,903 |  |  | — |
Other Current Assets | 64,241 |  |  | 92,229 |
| 408,155 |  |  | 355,919 |
Other Assets |  |  |
Recoverable Future Taxes | 90,493 |  |  | 80,084 |
Unamortized Debt Expense | 6,701 |  |  | 5,604 |
Other Regulatory Assets | 124,300 |  |  | 108,022 |
Deferred Charges | 71,426 |  |  | 69,662 |
Other Investments | 73,764 |  |  | 81,705 |
Goodwill | 5,476 |  |  | 5,476 |
Prepaid Pension and Post-Retirement Benefit Costs | 199,286 |  |  | 180,230 |
Fair Value of Derivative Financial Instruments | 2,394 |  |  | 87,905 |
Other | 8,158 |  |  | 5,958 |
| 581,998 |  |  | 624,646 |
Total Assets | $ | 8,446,160 |  |  | $ | 8,319,770 |

See Notes to Condensed Consolidated Financial Statements
8

Table of Content
National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)

| June 30, 2025 |  | September 30, 2024
(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 |
Paid in Capital | 1,047,406 |  |  | 1,045,487 |
Earnings Reinvested in the Business | 1,953,533 |  |  | 1,727,326 |
Accumulated Other Comprehensive Loss | (115,807) |  |  | (15,476) |
Total Comprehensive Shareholders’ Equity | 2,975,488 |  |  | 2,848,343 |
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs | 2,381,852 |  |  | 2,188,243 |
Total Capitalization | 5,357,340 |  |  | 5,036,586 |
Current and Accrued Liabilities |  |  |
Notes Payable to Banks and Commercial Paper | 61,500 |  |  | 90,700 |
Current Portion of Long-Term Debt | 300,000 |  |  | 500,000 |
Accounts Payable | 123,131 |  |  | 165,068 |
Amounts Payable to Customers | 24,275 |  |  | 42,720 |
Dividends Payable | 48,340 |  |  | 46,872 |
Interest Payable on Long-Term Debt | 39,060 |  |  | 27,247 |
Customer Advances | — |  |  | 19,373 |
Customer Security Deposits | 28,739 |  |  | 36,265 |
Other Accruals and Current Liabilities | 207,179 |  |  | 162,903 |
Fair Value of Derivative Financial Instruments | 57,673 |  |  | 4,744 |
| 889,897 |  |  | 1,095,892 |
Other Liabilities |  |  |
Deferred Income Taxes | 1,153,427 |  |  | 1,111,165 |
Taxes Refundable to Customers | 297,602 |  |  | 305,645 |
Cost of Removal Regulatory Liability | 302,932 |  |  | 292,477 |
Other Regulatory Liabilities | 137,025 |  |  | 151,452 |
Other Post-Retirement Liabilities | 3,393 |  |  | 3,511 |
Asset Retirement Obligations | 188,305 |  |  | 203,006 |
Other Liabilities | 116,239 |  |  | 120,036 |
| 2,198,923 |  |  | 2,187,292 |
Commitments and Contingencies (Note 7) | — |  |  | — |
Total Capitalization and Liabilities | $ | 8,446,160 |  |  | $ | 8,319,770 |

See Notes to Condensed Consolidated Financial Statements
9

Table of Content
National Fuel Gas Company
Consolidated Statements of Cash Flows
(Unaudited)

| Nine Months Ended June 30, |
(Thousands of U.S. Dollars) | 2025 |  | 2024 |
OPERATING ACTIVITIES |  |  |  |
Net Income Available for Common Stock | $ | 411,162 |  |  | $ | 245,134 |  |
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities: |  |  |  |
Impairment of Assets | 141,802 |  |  | 200,696 |  |
Depreciation, Depletion and Amortization | 337,055 |  |  | 348,179 |  |
Deferred Income Taxes | 60,754 |  |  | 47,212 |  |
Premiums Paid on Early Redemption of Debt | 2,385 |  |  | — |  |
Stock-Based Compensation | 15,721 |  |  | 15,984 |  |
Other | 19,296 |  |  | 18,542 |  |
Change in: |  |  |  |
Receivables and Unbilled Revenue | (95,254) |  |  | 5,253 |  |
Gas Stored Underground and Materials and Supplies | 18,803 |  |  | 18,981 |  |
Unrecovered Purchased Gas Costs | (2,903) |  |  | — |  |
Other Current Assets | 28,038 |  |  | 17,431 |  |
Accounts Payable | 1,744 |  |  | (13,705) |  |
Amounts Payable to Customers | (18,445) |  |  | 3,550 |  |
Customer Advances | (19,373) |  |  | (21,003) |  |
Customer Security Deposits | (7,526) |  |  | 7,910 |  |
Other Accruals and Current Liabilities | 44,283 |  |  | 23,846 |  |
Other Assets | (35,348) |  |  | (35,346) |  |
Other Liabilities | (39,918) |  |  | (14,649) |  |
Net Cash Provided by Operating Activities | 862,276 |  |  | 868,015 |  |
INVESTING ACTIVITIES |  |  |  |
Capital Expenditures | (627,316) |  |  | (684,200) |  |
Other | 9,352 |  |  | (1,371) |  |
Net Cash Used in Investing Activities | (617,964) |  |  | (685,571) |  |
FINANCING ACTIVITIES |  |  |  |
Changes in Notes Payable to Banks and Commercial Paper | (29,200) |  |  | (287,500) |  |
Net Proceeds from Issuance of Long-Term Debt | 988,731 |  |  | 299,396 |  |
Shares Repurchased Under Repurchase Plan | (54,430) |  |  | (27,847) |  |
Reduction of Long-Term Debt | (1,004,086) |  |  | — |  |
Dividends Paid on Common Stock | (140,098) |  |  | (136,610) |  |
Net Repurchases of Common Stock Under Stock and Benefit Plans | (4,134) |  |  | (3,916) |  |
Net Cash Used in Financing Activities | (243,217) |  |  | (156,477) |  |
Net Increase in Cash and Cash Equivalents | 1,095 |  |  | 25,967 |  |
Cash and Cash Equivalents at October 1 | 38,222 |  |  | 55,447 |  |
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 | $ | 88,627 |  |  | $ | 80,468 |  |

See Notes to Condensed Consolidated Financial Statements
10

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. The Company, in its opinion, has included all adjustments (which consist of only normally recurring adjustments, unless otherwise disclosed in this Quarterly Report on Form 10-Q) that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2024, 2023 and 2022 that are included in the Company's 2024 Form 10-K. The consolidated financial statements for the year ended September 30, 2025 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.
The earnings for the nine months ended June 30, 2025 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2025. Most of the business of the Utility segment is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility segment, earnings during the winter months normally represent a substantial part of the earnings that this business is expected to achieve for the entire fiscal year. The Company’s business segments are discussed more fully in Note 8 – Business Segment Information.
Consolidated Statements of Cash Flows. The Statement of Cash Flows for the nine months ended June 30, 2025 and nine months ended June 30, 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 June 30, 2025, October 1, 2024, June 30, 2024 or October 1, 2023. 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 Stored Underground. In the Utility segment, gas stored underground is carried at lower of cost or net realizable value, on a LIFO method. Gas stored underground normally declines during the first and second quarters of the year as storage quantities are withdrawn and increases in the third and fourth quarters as storage quantities are replenished. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $12.7 million at June 30, 2025, is reduced to zero by September 30 of each year as the inventory is replenished.
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.
Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. Such costs amounted to $132.6 million and $201.0 million at June 30, 2025 and September 30, 2024, respectively. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.
Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying commodity pricing (as adjusted for hedging) to estimated future production of proved reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The commodity prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of first day of the month commodity price for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter. At June 30, 2025, the ceiling exceeded the book value of the exploration and production properties by approximately $798.8 million. 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. 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. The estimated future net cash flows were increased by $338.6 million for hedging under the ceiling test at June 30, 2025.
The Exploration and Production segment also has items of property, plant and equipment that are accounted for outside of the provisions of the full cost method of accounting. As discussed in Note 3 – Fair Value Measurements, an impairment charge related to certain water disposal assets was recorded at December 31, 2024.
The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. There were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at June 30, 2025.
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Accumulated Other Comprehensive Income (Loss). The components of Accumulated Other Comprehensive Income (Loss) and changes for the nine months ended June 30, 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 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 |

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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 Ended June 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
Prepayments | $ | 22,810 |  |  | $ | 18,463 |
Prepaid Property and Other Taxes | 11,703 |  |  | 14,187 |
Federal Income Taxes Receivable | — |  |  | 8,154 |
State Income Taxes Receivable | 2,072 |  |  | 13,161 |
Regulatory Assets | 27,656 |  |  | 38,264 |
| $ | 64,241 |  |  | $ | 92,229 |

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
Accrued Capital Expenditures | $ | 59,166 |  |  | $ | 47,344 |
Regulatory Liabilities | 18,650 |  |  | 29,352 |
Reserve for Gas Replacement | 12,706 |  |  | — |
Liability for Royalty and Working Interests | 28,203 |  |  | 15,007 |
Federal Income Taxes Payable | 15,336 |  |  | — |
Non-Qualified Benefit Plan Liability | 14,135 |  |  | 14,135 |
Other | 58,983 |  |  | 57,065 |
| $ | 207,179 |  |  | $ | 162,903 |

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 30, 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 securities and 1,097 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2025, respectively. There were 335 securities
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excluded as being antidilutive for the nine months ended June 30, 2024. As the Company recognized a net loss for the quarter ended June 30, 2024, in accordance with accounting guidance, all dilution associated with restricted stock units and performance shares in the amount of 567,681 shares, was excluded from the earnings per share calculation for the quarter ended June 30, 2024.
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. Refer to Note 6 – Capitalization for further discussion of the Company's share repurchase program.
Stock-Based Compensation. The Company granted 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.
The performance shares granted during the nine months ended June 30, 2025 include awards that must meet a performance goal related to either relative total return on capital over a three-year performance cycle ("ROC Performance Shares"), methane intensity and greenhouse gas emissions reductions over a three-year performance cycle ("Emissions Performance Shares") or relative total shareholder return over a three-year performance cycle ("TSR Performance Shares"). The performance goal related to the ROC Performance Shares over the three-year performance cycle is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”). Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve-month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database. The number of these ROC Performance Shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value of the ROC Performance Shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award.
The performance goal related to the Emissions Performance Shares over the three-year performance cycle consists of two parts: reductions in the rates of intensity of methane emissions for each of the Company's operating segments, and reduction of the consolidated Company's total greenhouse gas emissions. The Company's Compensation Committee set specific target levels for methane intensity rates and total greenhouse gas emissions, and the performance goal is intended to incentivize and reward performance to the extent management achieves methane intensity and greenhouse gas reduction targets making progress towards or exceeding the Company's 2030 goals. The number of these Emissions Performance Shares that will vest and be paid out will depend upon the number of methane intensity segment targets achieved and whether the Company meets the total greenhouse gas emissions target. The fair value of these Emissions Performance Shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award.
The performance goal 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 represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participant to receive dividends during the vesting period. The fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.
Note 2 – Revenue from Contracts with Customers
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 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 | $ | 300,137 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 300,137 |
Production of Crude Oil | 434 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 434 |
Natural Gas Processing | 267 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 267 |
Natural Gas Gathering Service | — |  |  | — |  |  | 67,873 |  |  | — |  |  | — |  |  | (65,354) |  |  | 2,519 |
Natural Gas Transportation Service | — |  |  | 80,235 |  |  | — |  |  | 21,639 |  |  | — |  |  | (26,845) |  |  | 75,029 |
Natural Gas Storage Service | — |  |  | 25,028 |  |  | — |  |  | — |  |  | — |  |  | (10,604) |  |  | 14,424 |
Natural Gas Residential Sales | — |  |  | — |  |  | — |  |  | 118,551 |  |  | — |  |  | — |  |  | 118,551 |
Natural Gas Commercial Sales | — |  |  | — |  |  | — |  |  | 15,349 |  |  | — |  |  | — |  |  | 15,349 |
Natural Gas Industrial Sales | — |  |  | — |  |  | — |  |  | 732 |  |  | — |  |  | (1) |  |  | 731 |
Other | 530 |  |  | 316 |  |  | — |  |  | (633) |  |  | — |  |  | (224) |  |  | (11) |
Total Revenues from Contracts with Customers | 301,368 |  |  | 105,579 |  |  | 67,873 |  |  | 155,638 |  |  | — |  |  | (103,028) |  |  | 527,430 |
Alternative Revenue Programs | — |  |  | — |  |  | — |  |  | 1,885 |  |  | — |  |  | — |  |  | 1,885 |
Derivative Financial Instruments | 2,515 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 2,515 |
Total Revenues | $ | 303,883 |  |  | $ | 105,579 |  |  | $ | 67,873 |  |  | $ | 157,523 |  |  | $ | — |  |  | $ | (103,028) |  |  | $ | 531,830 |

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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 |

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 |

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Nine Months 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 | $ | 580,233 |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | — |  |  | $ | 580,233 |
Production of Crude Oil | 1,722 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 1,722 |
Natural Gas Processing | 765 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 765 |
Natural Gas Gathering Service | — |  |  | — |  |  | 186,701 |  |  | — |  |  | — |  |  | (174,544) |  |  | 12,157 |
Natural Gas Transportation Service | — |  |  | 232,532 |  |  | — |  |  | 88,817 |  |  | — |  |  | (73,040) |  |  | 248,309 |
Natural Gas Storage Service | — |  |  | 71,247 |  |  | — |  |  | — |  |  | — |  |  | (30,520) |  |  | 40,727 |
Natural Gas Residential Sales | — |  |  | — |  |  | — |  |  | 445,971 |  |  | — |  |  | — |  |  | 445,971 |
Natural Gas Commercial Sales | — |  |  | — |  |  | — |  |  | 62,117 |  |  | — |  |  | — |  |  | 62,117 |
Natural Gas Industrial Sales | — |  |  | — |  |  | — |  |  | 2,668 |  |  | — |  |  | (5) |  |  | 2,663 |
Other | 1,416 |  |  | 4,073 |  |  | — |  |  | (2,066) |  |  | — |  |  | (695) |  |  | 2,728 |
Total Revenues from Contracts with Customers | 584,136 |  |  | 307,852 |  |  | 186,701 |  |  | 597,507 |  |  | — |  |  | (278,804) |  |  | 1,397,392 |
Alternative Revenue Programs | — |  |  | — |  |  | — |  |  | 19,949 |  |  | — |  |  | — |  |  | 19,949 |
Derivative Financial Instruments | 155,401 |  |  | — |  |  | — |  |  | — |  |  | — |  |  | — |  |  | 155,401 |
Total Revenues | $ | 739,537 |  |  | $ | 307,852 |  |  | $ | 186,701 |  |  | $ | 617,456 |  |  | $ | — |  |  | $ | (278,804) |  |  | $ | 1,572,742 |

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
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.
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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 |  | Netting Adjustments(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 30, 2025 and 2024 (in thousands):
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|  |  |  |  |  |  | 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 30, 2025 and September 30, 2024 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 and Production 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 30, 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.
Note 4 – 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
| Carrying Amount |  | Fair Value |  | Carrying Amount |  | Fair Value
Long-Term Debt | $ | 2,681,852 |  |  | $ | 2,668,041 |  |  | $ | 2,688,243 |  |  | $ | 2,656,888 |

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.
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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
Life Insurance Contracts | $ | 43,773 |  |  | $ | 44,808 |
Equity Mutual Fund | 13,143 |  |  | 19,523 |
Fixed Income Mutual Fund | 16,848 |  |  | 17,374 |
| $ | 73,764 |  |  | $ | 81,705 |

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 and Production segment. The Company enters into over-the-counter no cost collar and swap agreements for natural gas to manage the price risk associated with forecasted sales of natural gas. In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. These instruments are accounted for as cash flow hedges. The duration of the Company’s cash flow hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 6 years.
On June 30, 2022, the Company completed the sale of Seneca’s California assets. 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 as $1.0 million for each $1 per barrel that the ICE Brent Average for each calendar year exceeds $95 per barrel up to $105 per barrel. The 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 a derivative under the authoritative accounting guidance. Changes in the fair value of this contingent consideration are marked-to-market each reporting period, with changes in fair value recognized in Other Income (Deductions) on the Consolidated Statement of Income. The fair value of this contingent consideration was estimated to be zero and $0.7 million at June 30, 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.
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 30, 2025, the Company had $44.5 million of net hedging losses after taxes included in the accumulated other comprehensive income (loss) balance. 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 |

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 |

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 counterparties of which three are in a net gain position. On average, the Company had $0.8 million of credit exposure per counterparty in a gain position at June 30, 2025. The maximum credit exposure per counterparty in a gain position at June 30, 2025 was $2.0 million. As of June 30, 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
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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 5 – Income Taxes
The effective tax rates for the quarters ended June 30, 2025 and June 30, 2024 were 25.4% and 34.3%, respectively. The decrease in the quarterly effective income tax rate was primarily driven by the impact of the impairment of exploration and production properties under the ceiling test recorded during the quarter ended June 30, 2024, which resulted in a larger income tax benefit on a loss before income taxes during the quarter ended June 30, 2024.
The effective 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.
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 In Capital |  | Earnings Reinvested in the Business |  | Accumulated Other Comprehensive Income (Loss)
Shares |  | Amount |
| (Thousands, except per share amounts)
Balance at April 1, 2025 | 90,398 |  |  | $ | 90,398 |  |  | $ | 1,042,822 |  |  | $ | 1,855,366 |  |  | $ | (222,975) |
Net Income Available for Common Stock |  |  |  |  |  |  | 149,818 |  |  |
Dividends Declared on Common Stock ($0.535 Per Share) |  |  |  |  |  |  | (48,340) |  |  |
Other Comprehensive Income, Net of Tax |  |  |  |  |  |  |  |  | 107,168 |
Share-Based Payment Expense (1) |  |  |  |  | 4,685 |  |  |  |  |
Common Stock Issued Under Stock and Benefit Plans | 12 |  |  | 12 |  |  | 529 |  |  |  |  |
Share Repurchases Under Repurchase Plan | (54) |  |  | (54) |  |  | (630) |  |  | (3,311) |  |  |
Balance at June 30, 2025 | 90,356 |  |  | $ | 90,356 |  |  | $ | 1,047,406 |  |  | $ | 1,953,533 |  |  | $ | (115,807) |
Balance at October 1, 2024 | 91,006 |  |  | $ | 91,006 |  |  | $ | 1,045,487 |  |  | $ | 1,727,326 |  |  | $ | (15,476) |
Net Income Available for Common Stock |  |  |  |  |  |  | 411,162 |  |  |
Dividends Declared on Common Stock ($1.565 Per Share) |  |  |  |  |  |  | (141,566) |  |  |
Other Comprehensive Loss, Net of Tax |  |  |  |  |  |  |  |  | (100,331) |
Share-Based Payment Expense (1) |  |  |  |  | 13,911 |  |  |  |  |
Common Stock Issued (Repurchased) Under Stock and Benefit Plans | 179 |  |  | 179 |  |  | (2,377) |  |  |  |  |
Share Repurchases Under Repurchase Plan | (829) |  |  | (829) |  |  | (9,615) |  |  | (43,389) |  |  |
Balance at June 30, 2025 | 90,356 |  |  | $ | 90,356 |  |  | $ | 1,047,406 |  |  | $ | 1,953,533 |  |  | $ | (115,807) |
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 months ended June 30, 2025 consisted of the following items:

| Nine Months Ended June 30, 2025
Vesting of Restricted Stock Units | 125,528 |
Vesting of Performance Shares | 89,843 |
Issuance of Common Stock Pursuant to the Company's Non-Employee Director Equity Compensation Plan and Deferred Compensation Plan for Directors and Officers | 28,699 |
Shares Tendered to Pay Withholding Taxes on Stock-Based Compensation Awards (1) | (65,387) |
Common Stock Issued Under Stock and Benefit Plans | 178,683 |
Share Repurchases Under Repurchase Plan | (828,720) |
Total Net Shares Repurchased During the Nine Months Ended June 30, 2025 | (650,037) |

(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 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. In the future, it is expected that this share repurchase 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.
Short-Term Borrowings. 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.
Current Portion of Long-Term 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.
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 30, 2025, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.7 million. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at June 30, 2025. The Company has a regulatory liability of $2.1 million related to environmental clean-up costs at June 30, 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
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

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

(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

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)

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

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Note 9 – 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
Service Cost | $ | 1,023 |  | $ | 1,049 |  |  | $ | 130 |  | $ | 109 |
Interest Cost | 9,223 |  | 10,890 |  |  | 3,625 |  | 3,890 |
Expected Return on Plan Assets | (14,647) |  | (17,086) |  |  | (6,536) |  | (6,660) |
Amortization of Prior Service Cost (Credit) | 76 |  | 91 |  |  | (107) |  | (107) |
Amortization of (Gains) Losses | 1,620 |  | (335) |  |  | 9 |  | (567) |
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1) | 85 |  | 4,057 |  |  | (447) |  | 2,248 |
Net Periodic Benefit Cost (Income) | $ | (2,620) |  | $ | (1,334) |  |  | $ | (3,326) |  | $ | (1,087) |

| 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 months ended June 30, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2025. The Company also did not make any contributions to its VEBA trusts for its other post-retirement benefits during the nine months ended June 30, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2025.
Note 10 – 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 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. The revenue requirement for each year of the three-year plan has been reduced by $14 million for actuarial projections of income that is
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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 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.
FERC Jurisdiction
Supply Corporation’s rate settlement, approved June 11, 2024, 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 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 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
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lease, providing access to Mid-Atlantic markets. On May 5, 2025, FERC issued the Section 7(b)/7(c) certificate for the project. Construction on the Tioga Pathway Project is expected to commence in early calendar 2026. This project has a target in-service date in late calendar 2026 and a preliminary cost estimate of approximately $101 million.
Supply Corporation has also announced that it expects to serve as the transporter for 205,000 Dth/day of natural gas supplies to the Shippingport Power Station, a natural gas power generation facility under development in Beaver County, Pennsylvania. 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 (the “Shippingport Lateral Project”), with the incremental capacity expected to come online as early as Fall 2026 and a preliminary cost estimate of approximately $57 million. 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 authorizes 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. 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's 2019 rate case settlement. This settlement amendment is estimated to decrease Empire's revenues on a yearly basis by approximately $0.5 million. For further discussion of these and other rate matters, refer to the Rate Matters section below.
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. In 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 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 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 a financing perspective, 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. The proceeds of these debt issuances were used for general corporate purposes, including the March 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. For details of these matters, refer to the Capital Resources and Liquidity section below.
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 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 and Production 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.
RESULTS OF OPERATIONS
Earnings
The Company's earnings were $149.8 million for the quarter ended June 30, 2025 compared to a loss of $54.2 million for the quarter ended June 30, 2024. The increase in earnings of $204.0 million is primarily the result of higher earnings in the Exploration and Production segment, as well as the Gathering and Utility segments. Lower earnings in the Pipeline and Storage segment and losses in the Corporate and All Other categories partially offset these increases.
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 Ended June 30, | Nine Months Ended June 30,
(Thousands) | 2025 | 2024 | Increase (Decrease) | 2025 | 2024 | Increase (Decrease)
Exploration and Production | $ | 86,671 |  | $ | (112,028) |  | $ | 198,699 |  | $ | 137,722 |  | $ | 2,521 |  | $ | 135,201 |
Pipeline and Storage | 28,857 |  | 30,690 |  | (1,833) |  | 93,019 |  | 85,482 |  | 7,537 |
Gathering | 29,996 |  | 24,979 |  | 5,017 |  | 83,483 |  | 82,510 |  | 973 |
Utility | 4,997 |  | 2,559 |  | 2,438 |  | 101,040 |  | 73,848 |  | 27,192 |
Total Reportable Segments | 150,521 |  | (53,800) |  | 204,321 |  | 415,264 |  | 244,361 |  | 170,903 |
All Other | (209) |  | (124) |  | (85) |  | (674) |  | (341) |  | (333) |
Corporate | (494) |  | (234) |  | (260) |  | (3,428) |  | 1,114 |  | (4,542) |
Total Consolidated | $ | 149,818 |  | $ | (54,158) |  | $ | 203,976 |  | $ | 411,162 |  | $ | 245,134 |  | $ | 166,028 |

Exploration and Production
Exploration and Production Operating Revenues

| Three Months Ended June 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 |

Production Volumes

| Three Months Ended June 30, | Nine Months Ended June 30,
| 2025 | 2024 | Increase (Decrease) | 2025 | 2024 | Increase (Decrease)
Gas Production per MMcf | 111,588 |  | 96,504 |  | 15,084 |  | 314,819 |  | 300,144 |  | 14,675 |

Average Prices

| Three Months Ended June 30, | Nine Months Ended June 30,
| 2025 | 2024 | Increase (Decrease) | 2025 | 2024 | Increase (Decrease)
Average Gas Price/Mcf |  |  |  |  |  |
Weighted Average | $ | 2.69 |  | $ | 1.50 |  | $ | 1.19 |  | $ | 2.66 |  | $ | 1.93 |  | $ | 0.73 |
Weighted Average After Hedging | $ | 2.71 |  | $ | 2.28 |  | $ | 0.43 |  | $ | 2.73 |  | $ | 2.45 |  | $ | 0.28 |

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2025 Compared with 2024
Operating revenues for the Exploration and Production segment increased $83.0 million for the quarter ended June 30, 2025 as compared with the quarter ended June 30, 2024. Gas production revenue after hedging increased $82.8 million due to the impact of a $0.43 per Mcf increase in the weighted average price of natural gas after hedging, combined with a 15.1 Bcf increase in natural gas production. The increase in natural gas production was largely due to pads recently turned in line.
Operating revenues for the Exploration and Production segment increased $125.2 million for the nine months ended June 30, 2025 as compared with the nine months ended June 30, 2024. Gas production revenue after hedging increased $124.8 million due to the impact of a $0.28 per Mcf increase in the weighted average price of natural gas after hedging, combined with a 14.7 Bcf increase in natural gas production. The increase in natural gas production for the nine months ended June 30, 2025 as compared with the nine months ended June 30, 2024 was largely due to pads recently turned in line.
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:

|  | (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) |
| 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, offset by a ceiling test impairment of $145.0 million in the nine months ending June 30, 2024.
(2)The decrease in depletion expense was primarily due to ceiling test impairments recorded in fiscal 2024 and 2025 that lowered Seneca’s full cost pool depletable base.
(3)The increase in income tax expense was primarily driven by an increase in state income tax expense due to higher pre-tax income before impairments.
(4)The increase in lease operating and transportation expenses was primarily the result of higher production combined with higher gathering and transportation costs.
(5)The decrease in other income is mainly attributable to non-recurrence of business interruption insurance proceeds received during the quarter ended December 31, 2023 related to a pipeline outage impacting Seneca’s ability to market gas.
(6)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.
(7)The increase in operating expenses is mainly attributed to higher personnel costs, higher abandonment accretion expense and higher environmental remediation costs in the nine months ended June 30, 2025, partially offset by higher abandonment costs recognized in the nine months ended June 30, 2024.
(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 Ended June 30, | Nine Months Ended June 30,
(Thousands) | 2025 | 2024 | Increase (Decrease) | 2025 | 2024 | Increase (Decrease)
Firm Transportation | $ | 80,078 |  | $ | 79,537 |  | $ | 541 |  | $ | 243,388 |  | $ | 232,012 |  | $ | 11,376 |
Interruptible Transportation | 157 |  | 103 |  | 54 |  | 533 |  | 520 |  | 13 |
| 80,235 |  | 79,640 |  | 595 |  | 243,921 |  | 232,532 |  | 11,389 |
Firm Storage Service | 25,028 |  | 24,612 |  | 416 |  | 75,309 |  | 71,246 |  | 4,063 |
Interruptible Storage Service | — |  | — |  | — |  | — |  | 1 |  | (1) |
Other | 316 |  | 1,167 |  | (851) |  | 2,535 |  | 4,073 |  | (1,538) |
| $ | 105,579 |  | $ | 105,419 |  | $ | 160 |  | $ | 321,765 |  | $ | 307,852 |  | $ | 13,913 |

Pipeline and Storage Throughput

| Three Months Ended June 30, | Nine Months Ended June 30,
(MMcf) | 2025 | 2024 | Increase (Decrease) | 2025 | 2024 | Increase (Decrease)
Firm Transportation | 179,033 |  | 168,510 |  | 10,523 |  | 616,644 |  | 590,868 |  | 25,776 |
Interruptible Transportation | 149 |  | 118 |  | 31 |  | 665 |  | 1,508 |  | (843) |
| 179,182 |  | 168,628 |  | 10,554 |  | 617,309 |  | 592,376 |  | 24,933 |

2025 Compared with 2024
Operating revenues for the Pipeline and Storage segment were relatively consistent for the quarter ended June 30, 2025 as compared with the quarter ended June 30, 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 30, 2025 increased by 10.6 Bcf and 24.9 Bcf, respectively, from the prior year's quarter and nine month periods. The increase in transportation volume for both the quarter and nine months ended June 30, 2025 is primarily due to an increase in 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.
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The Pipeline and Storage segment’s earnings for the quarter ended June 30, 2025 were $28.9 million, a decrease of $1.8 million when compared with earnings of $30.7 million for the quarter ended June 30, 2024. The $1.8 million decrease can be attributed to the following factors:

|  | (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 Ended June 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 Ended June 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 Ga thering segm ent 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 revenue s for the Gathering segm ent 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.
Th e 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 Ended June 30, | Nine Months Ended June 30,
(Thousands) | 2025 | 2024 | Increase (Decrease) | 2025 | 2024 | Increase (Decrease)
Retail Sales Revenues: |  |  |  |  |  |
Residential | $ | 118,819 |  | $ | 91,267 |  | $ | 27,552 |  | $ | 546,841 |  | $ | 458,847 |  | $ | 87,994 |
Commercial | 14,283 |  | 10,614 |  | 3,669 |  | 75,112 |  | 62,217 |  | 12,895 |
Industrial | 735 |  | 496 |  | 239 |  | 4,030 |  | 2,714 |  | 1,316 |
| 133,837 |  | 102,377 |  | 31,460 |  | 625,983 |  | 523,778 |  | 102,205 |
Transportation | 21,577 |  | 23,185 |  | (1,608) |  | 96,979 |  | 95,744 |  | 1,235 |
Other | 2,109 |  | (618) |  | 2,727 |  | 6,762 |  | (2,066) |  | 8,828 |
| $ | 157,523 |  | $ | 124,944 |  | $ | 32,579 |  | $ | 729,724 |  | $ | 617,456 |  | $ | 112,268 |

Utility Throughput

| Three Months Ended June 30, | Nine Months Ended June 30,
(MMcf) | 2025 | 2024 | Increase (Decrease) | 2025 | 2024 | Increase (Decrease)
Retail Sales: |  |  |  |  |  |
Residential | 10,151 |  | 8,123 |  | 2,028 |  | 60,738 |  | 53,168 |  | 7,570 |
Commercial | 1,658 |  | 1,308 |  | 350 |  | 9,997 |  | 8,401 |  | 1,596 |
Industrial | 93 |  | 62 |  | 31 |  | 594 |  | 389 |  | 205 |
| 11,902 |  | 9,493 |  | 2,409 |  | 71,329 |  | 61,958 |  | 9,371 |
Transportation | 13,853 |  | 12,819 |  | 1,034 |  | 55,881 |  | 52,984 |  | 2,897 |
| 25,755 |  | 22,312 |  | 3,443 |  | 127,210 |  | 114,942 |  | 12,268 |

Degree Days

Three Months Ended June 30, |  |  |  | Percent Colder (Warmer) Than
Normal | 2025 | 2024 | Normal(1) | Prior Year(1)
Buffalo, NY(2) | 843 |  | 825 |  | 565 |  | (2.1) | % | 46.0 | %
Erie, PA | 776 |  | 813 |  | 519 |  | 4.8 | % | 56.6 | %
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 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 $32.6 million for the quarter ended June 30, 2025 as compared with the quarter ended June 30, 2024. This increase resulted from a $31.5 million increase in retail gas sales revenue and a $2.7 million increase in other revenue. The increase in retail gas sales revenue reflects the impact of new base delivery rates in Distribution Corporation's New York jurisdiction pursuant to a settlement approved by the NYPSC on December 19, 2024. 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 purchased gas revenues resulting from a 2.4 Bcf increase in throughput mainly due to colder weather combined with an increase in the cost of gas sold (per Mcf). It 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 due to the the amortization of certain regulatory assets in accordance with the New York rate settlement, despite a 1.0 Bcf increase in throughput and the impact of new base rates in New York discussed above.
Operating revenues for the Utility segment increased $112.3 million for the nine months ended June 30, 2025 as compared with the nine months ended June 30, 2024. The increase resulted from a $102.2 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. The increase in 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 an increase in the cost of gas sold (per Mcf). The increase in transportation revenue also reflects a 2.9 Bcf increase in throughput due primarily to colder weather, partially offset by the amortization of certain regulatory assets in accordance with the New York rate settlement. The increase in other revenue was largely 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 ($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).
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) |
| 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)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.
(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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The impact of weather variations on cash flows and customer bills 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 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 earnings of approximately $0.5 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.
The Utility segment’s earnings for the nine months ended June 30, 2025 were $101.0 million, an increase of $27.2 million when compared with earnings of $73.8 million for the nine months ended June 30, 2024. The increase can be attributed to the following factors:

|  | (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 |  |

(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.
(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 operations recorded a net loss of $0.7 million for the quarter ended June 30, 2025, which was relatively consistent with the net loss of $0.4 million for the quarter ended June 30, 2024. For the nine months ended June 30, 2025, Corporate and All Other operations recorded a net loss of $4.1 million, a decrease of $4.9 million when compared with earnings of $0.8 million for the nine months ended June 30, 2024. The decrease for the nine-month period was primarily attributable to changes in unrealized gains and losses on investments in equity securities. During nine months ended June 30, 2025, the Company recorded unrealized losses of $1.4 million. During the nine months ended June 30, 2024, the Company recorded unrealized gains of $1.4 million. Also contributing to the decrease included higher interest expense ($2.7 million)
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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 $8.5 million for the quarter ended June 30, 2025, compared to net other income of $3.2 million for the quarter ended June 30, 2024, for an increase of $5.3 million. This increase can be attributed primarily to a $4.7 million increase in non-service pension and post-retirement benefit income, primarily due to the recognition of 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 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.
Interest Expense on Long-Term Debt
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-month period ended June 30, 2025 consisted of cash provided by operating activities and net proceeds from long-term borrowings. The Company’s primary source of cash during the nine-month period ended June 30, 2024 consisted of cash provided by operating activities and net proceeds from long-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, the Company expects to use cash provided by operating activities and short-term borrowings to fund the Company's capital expenditures. Looking forward to 2026, based on current commodity prices, cash provided by operating activities is again expected to exceed capital expenditures. The Company also has a delayed draw term loan that matures in February 2026, which the Company anticipates funding with cash on hand as well as short-term or long-term borrowings. These cash flow projections do not reflect the impact of 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.
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 and Production 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 $862.3 million for the nine months ended June 30, 2025, a decrease of $5.7 million compared with $868.0 million provided by operating activities for the nine months ended June 30, 2024. The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Utility segment, partially offset by higher cash provided by operating activities in the Exploration and Production segment. The decrease in the Utility segment is driven by the timing of gas cost recovery, partially offset by the impact of higher revenues resulting from the base rate increase in Distribution Corporation's New York rate jurisdiction. The increase in the Exploration and Production segment is due to the timing of cash receipts and hedge settlements from natural gas production in the Appalachian region.
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Investing Cash Flow
Expenditures for Long-Lived Assets
The Company’s expenditures for long-lived assets totaled $596.0 million during the nine months ended June 30, 2025 and $655.5 million during the nine months ended June 30, 2024. The table below presents these expenditures:

Total Expenditures for Long-Lived Assets |  |  |  |  |
Nine Months Ended June 30, | 2025 |  | 2024 |  | Increase (Decrease)
(Millions) |  |
Exploration and Production: |  |  |  |  |
Capital Expenditures | $ | 354.4 |  | (1) | $ | 399.8 |  | (2) | $ | (45.4) |
Pipeline and Storage: |  |  |  |  |
Capital Expenditures | 58.1 |  | (1) | 68.8 |  | (2) | (10.7) |
Gathering: |  |  |  |  |
Capital Expenditures | 58.2 |  | (1) | 69.1 |  | (2) | (10.9) |
Utility: |  |  |  |  |
Capital Expenditures | 128.3 |  | (1) | 117.5 |  | (2) | 10.8 |
All Other: |  |  |  |  |
Capital Expenditures | 0.5 |  |  | 0.3 |  |  | 0.2 |
Eliminations | (3.5) |  |  | — |  |  | (3.5) |
| $ | 596.0 |  |  | $ | 655.5 |  |  | $ | (59.5) |

(1)At June 30, 2025, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $61.5 million, $5.7 million, $11.6 million and $9.8 million, respectively, of non-cash capital expenditures. At September 30, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $63.3 million, $14.4 million, $21.7 million and $20.6 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.
Exploration and Production
The Exploration and Production segment capital expenditures for the nine months ended June 30, 2025 were primarily well drilling and completion expenditures in the Appalachian region, and included $104.3 million in the Marcellus Shale area and $239.2 million in the Utica Shale area. These amounts included $182.6 million spent to develop proved undeveloped reserves.
The Exploration and Production segment capital expenditures for the nine months ended June 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.
Pipeline and Storage
The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2025 and June 30, 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, 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. 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, is discussed below.
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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. Construction on the Tioga Pathway Project is expected to commence in early calendar 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 June 30, 2025, approximately $4.3 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.
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 months ended June 30, 2025 and June 30, 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 months ended June 30, 2025 and fiscal 2024, the Company has been financing capital expenditures with cash from operations and short-term debt. Going forward, the Company expects to use cash on hand, cash from operations and short-term or long-term borrowings, as needed, to finance capital expenditures. The level of short-term and/or long-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production and the associated commodity price realizations in the Exploration and Production segment. It will also likely depend on the timing of gas cost 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
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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 $29.2 million when comparing the balance sheet at June 30, 2025 to the balance sheet at September 30, 2024. The maximum amount of short-term debt outstanding during the nine months ended June 30, 2025 was $330.0 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 30, 2025, the Company had outstanding commercial paper of $61.5 million and did not have any short-term notes payable to banks.
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.
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.
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, 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, 2025, the Company’s debt to capitalization ratio, as calculated under the agreements, was 0.45. The constraints specified in the Credit Agreement and the Term Loan Agreement would have
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permitted an additional $3.60 billion in short-term and/or long-term debt to be outstanding at June 30, 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 Credit Agreement or Term Loan Agreement, as applicable. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.
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 months ended June 30, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2025. The Company also did not make any contributions to its VEBA trusts for its other post-retirement benefits during the nine months ended June 30, 2025, and does not anticipate making any such contributions during the remainder of fiscal 2025.
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 30, 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 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
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 a revenue requirement increase of $57.3 million in fiscal 2025, an additional revenue requirement increase of
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$15.8 million in fiscal 2026, and an additional revenue requirement increase of $12.7 million in fiscal 2027. The revenue requirement for each year of the three-year plan has been reduced by $14 million for actuarial projections of income that is expected to be recognized for qualified pension and other post-retirement benefits. Qualified pension and other post-retirement benefit income or costs are matched with amounts included in revenue resulting in zero impact to earnings. The 2024 Rate Order approves the continuation of several ratemaking mechanisms, including revenue decoupling and WNA, and establishes a number of new cost trackers and regulatory deferrals. It also includes an earnings sharing mechanism, gas safety and customer service performance metrics (including maintaining the Company’s leak prone pipe replacement program), and provisions that will facilitate achievement of the emissions reduction goals of the CLCPA.
Pennsylvania Jurisdiction
Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC in an order issued on June 15, 2023 with rates effective August 1, 2023 (“2023 Rate Order”). The 2023 Rate Order provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million and authorized a new weather normalization adjustment mechanism.
On 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.
Pipeline and Storage
Supply Corporation's rate settlement, approved June 11, 2024, 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 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.”
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 March 2024 publication and finalization of the Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources and its May 2024 finalization of the Greenhouse Gas Reporting Program, Part 98 - Subpart W Final Rule.
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 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, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also reduce demand for natural gas and delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by federal and state administrative agencies, make it difficult to predict a long-term business impact across twenty or more years. Federal, state or local governments may also provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources.
Effects of Inflation
The Company’s operations are sensitive to increases in the rate of inflation because of its operational and capital spending requirements in both its regulated and non-regulated businesses. For the regulated businesses, recovery of increasing costs from customers can be delayed by the regulatory process of a rate case filing. For the non-regulated businesses, prices received for services performed or products produced are determined by market factors that are not necessarily correlated to the underlying costs required to provide the service or product.
Safe Harbor for Forward-Looking Statements
The Company is including the following cautionary statement in this Quarterly Report on Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:
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1.Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing;
2.Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design, retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal;
3.Changes in economic conditions, including the imposition of additional tariffs on U.S. imports and related retaliatory tariffs, inflationary pressures, supply chain issues, liquidity challenges, and global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services;
4.The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets;
5.Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas;
6.Impairments under the SEC's full cost ceiling test for natural gas reserves;
7.Changes in the price of natural gas;
8.The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;
9.Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;
10.The Company's ability to complete strategic transactions;
11.Changes in price differentials between similar quantities of natural gas sold at different geographic locations, and the effect of such changes on commodity production, revenues and demand for pipeline transportation capacity to or from such locations;
12.The impact of information technology disruptions, cybersecurity or data security breaches, including the impact of issues that may arise from the use of artificial intelligence technologies;
13.Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas reserves, including among others geology, lease availability and costs, title disputes, weather conditions, water availability and disposal or recycling opportunities of used water, shortages, delays or unavailability of equipment and services required in drilling operations, insufficient gathering, processing and transportation capacity, the need to obtain governmental approvals and permits, and compliance with environmental laws and regulations;
14.Increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators;
15.Increasing health care costs and the resulting effect on health insurance premiums and on the obligation to provide other post-retirement benefits;
16.Other changes in price differentials between similar quantities of natural gas having different quality, heating value, hydrocarbon mix or delivery date;
17.The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;
18.Negotiations with the collective bargaining units representing the Company's workforce, including potential work stoppages during negotiations;
19.Uncertainty of natural gas reserve estimates;
20.Significant differences between the Company’s projected and actual production levels for natural gas;
21.Changes in demographic patterns and weather conditions (including those related to climate change);
22.Changes in the availability, price or accounting treatment of derivative financial instruments;
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23.Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;
24.Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to third-party outages;
25.Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or
26.Increasing costs of insurance, changes in coverage and the ability to obtain insurance.
The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.
Forward-looking and other statements in this Quarterly Report on Form 10-Q regarding methane and greenhouse gas reduction plans and goals are not an indication that these statements are necessarily material to investors or required to be disclosed in our filings with the SEC. In addition, historical, current and forward-looking statements regarding methane and greenhouse gas emissions may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve and assumptions that are subject to change in the future.
Item 3. Quantitative and Qualitative Disclosures About Market Risk
Refer to the "Market Risk Sensitive Instruments" section in Item 2 – MD&A.
Item 4. Controls and Procedures
Evaluation of Disclosure Controls and Procedures
The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Chief Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 2025.
Changes in Internal Control Over Financial Reporting
There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended June 30, 2025 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.
Part II. Other Information
Item 1. Legal Proceedings
For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 7 – Commitments and Contingencies, and Part I, Item 2 - MD&A of this report under the heading “Other Matters – Environmental Matters.”
For a discussion of certain rate matters involving the NYPSC, refer to Part I, Item 1 of this report at Note 10 – Regulatory Matters.
Item 1A. Risk Factors
The risk factors in Item 1A of the Company’s 2024 Form 10-K, as amended by Item 1A of Part II of the Company's Form 10-Q for the quarter ended March 31, 2025, have not materially changed.
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Item 2. Unregistered Sales of Equity Securities and Use of Proceeds
On April 1, 2025, the Company issued a total of 5,520 unregistered shares of Company common stock to non-employee directors of the Company then serving on the Board of Directors of the Company (or, in the case of non-employee directors who elected to defer receipt of such shares pursuant to the Company’s Deferred Compensation Plan for Directors and Officers (the “DCP”), to the DCP trustee), consisting of 552 shares per director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended June 30, 2025. The Company issued an additional 617 unregistered shares in the aggregate on April 15, 2025 pursuant to the dividend reinvestment feature of the DCP, to the six non-employee directors who participate in the DCP. These transactions were exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as transactions not involving a public offering.
Issuer Purchases of Equity Securities

Period | Total Number of Shares Purchased (a) | Average Price Paid per Share | Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs | Maximum Number (or Approximate Dollar Value) of Shares That May Yet Be Purchased Under Share Repurchase Plans or Programs (b)
Apr. 1 - 30, 2025 | 64,677 |  | $73.72 | 53,952 | $82,094,302
May 1 - 31, 2025 | 11,376 |  | $81.35 | — | $82,094,302
Jun. 1 - 30, 2025 | 11,433 |  | $81.62 | — | $82,094,302
Total | 87,486 |  | $75.35 | 53,952 | $82,094,302

(a)Represents (i) shares of common stock of the Company purchased with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, (ii) shares of common stock of the Company, if any, tendered to the Company by holders of stock-based compensation awards for the payment of applicable withholding taxes, and (iii) shares of common stock of the Company purchased on the open market pursuant to the Company's share repurchase program. Of the 33,534 shares purchased other than through a publicly announced share repurchase program, 32,214 were purchased for the Company's 401(k) plans and 1,320 were purchased as a result of shares tendered to the Company by holders of stock-based compensation awards.
(b)On March 8, 2024, the Company’s Board of Directors authorized the repurchase of up to $200 million of shares of the Company’s common stock. The calculation of the dollar value of shares remaining available for purchase excludes excise taxes and brokerage fees paid by the Company in connection with the repurchase program which in the aggregate totaled $1.08 million from the beginning of the program to June 30, 2025. Repurchases may be made from time to time in the open market or through privately negotiated transactions, including through the use of trading plans intended to qualify under SEC Rule 10b5-1, in accordance with applicable securities laws and other restrictions. The repurchase program has no expiration date.
Item 5. Other Information
Trading Arrangements
During the quarter ended June 30, 2025, no director or officer (as defined in Rule 16a-1(f) promulgated under the Exchange Act) of the Company adopted or terminated any “Rule 10b5–1 trading arrangement” or any “non-Rule 10b5–1 trading arrangement,” as each term is defined in Item 408 of Regulation S-K.
Item 6. Exhibits

Exhibit Number |  | Description of Exhibit
10.1 |  | Consulting Services Agreement, dated as of June 13, 2025, between National Fuel Gas Company and Donna L. DeCarolis.
31.1 |  | Written statements of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act.
31.2 |  | Written statements of Chief Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act.
32•• |  | Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.
99 |  | National Fuel Gas Company Consolidated Statements of Income for the Twelve Months Ended June 3 0, 2025 and 2024.

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Exhibit Number |  | Description of Exhibit
101 |  | Interactive data files submitted pursuant to Regulation S-T, formatted in Inline XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income and Earnings Reinvested in the Business for the nine months ended June 30, 2025 and 2024, (ii) the Consolidated Statements of Comprehensive Income for the nine months ended June 30, 2025 and 2024, (iii) the Consolidated Balance Sheets at June 30, 2025 and September 30, 2024, (iv) the Consolidated Statements of Cash Flows for the nine months ended June 30, 2025 and 2024 and (v) the Notes to Condensed Consolidated Financial Statements.
104 |  | Cover Page Interactive Data File (embedded within the Inline XBRL document)
•• |  | In accordance with Item 601(b)(32)(ii) of Regulation S-K and SEC Release Nos. 33-8238 and 34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference.

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SIGNATURES
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

NATIONAL FUEL GAS COMPANY |
(Registrant) |
/s/ T. J. Silverstein |
T. J. Silverstein |
Treasurer and Chief Financial Officer |
/s/ E. G. Mendel |
E. G. Mendel |
Controller and Chief Accounting Officer |

Date: July 31, 2025
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