National Fuel Gas (NFG) 10-Q 2024 Q3 Quarterly report

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, 2024

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 31, 2024: 91,356,883 shares.

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
2023 Form 10-K	The Company’s Annual Report on Form 10-K for the year ended September 30, 2023
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.

2

Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act.
Dth	Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
ESG	Environmental, social and governance
Exchange Act	Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets	Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploration costs	Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
Exploratory well	A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
FERC 7(c) application	An application to the FERC under Section 7(c) of the federal Natural Gas Act for authority to construct, operate (and provide services through) facilities to transport or store natural gas in interstate commerce.
Firm transportation and/or storage	The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP	Accounting principles generally accepted in the United States of America
Goodwill	An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging	A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often through the use of derivative financial instruments.
Hub	Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
ICE	Intercontinental Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Impact Fee	An annual fee imposed on unconventional wells spud in Pennsylvania. The fee is administered by the PaPUC and fees are distributed to counties and municipalities where the well is located.
Interruptible transportation and/or storage	The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LDC	Local distribution company
LIFO	Last-in, first-out
Marcellus Shale	A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.
Mcf	Thousand cubic feet (of natural gas)
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth	Thousand decatherms (of natural gas)
Methane	The primary component of natural gas. It is a compound made up of one carbon atom and four hydrogen atoms (CH4).
MMBtu	Million British thermal units (heating value of one decatherm of natural gas)
MMcf	Million cubic feet (of natural gas)
Natural Gas	A naturally occurring mixture of gaseous hydrocarbons consisting primarily of methane and found in underground rock formations.
NGA	The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.
NOAA	National Oceanic and Atmospheric Administration

3

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.
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
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

INDEX	Page
Part I. Financial Information
Item 1.  Financial Statements (Unaudited)	6
a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Nine Months Ended June 30, 2024 and 2023	6
b. Consolidated Statements of Comprehensive Income – Three and Nine Months Ended June 30, 2024 and 2023	7
c. Consolidated Balance Sheets – June 30, 2024 and September 30, 2023	8
d. Consolidated Statements of Cash Flows – Nine Months Ended June 30, 2024 and 2023	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	49
Item 4.  Controls and Procedures	49
Part II. Other Information
Item 1.  Legal Proceedings	49
Item 1 A.  Risk Factors	49
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds	50
Item 3.  Defaults Upon Senior Securities	•
Item 4.  Mine Safety Disclosures	•
Item 5.  Other Information	51
Item 6.  Exhibits	51
Signatures	52

• The Company has nothing to report under this item.

    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

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)	2024		2023		2024		2023
INCOME
Operating Revenues:
Utility Revenues	$	124,858	$	144,538	$	616,977	$	862,914
Exploration and Production and Other Revenues	220,905		216,581		739,537		738,107
Pipeline and Storage and Gathering Revenues	71,679		67,585		216,228		203,803
	417,442		428,704		1,572,742		1,804,824
Operating Expenses:
Purchased Gas	4,952		35,425		167,444		450,461
Operation and Maintenance:
Utility	53,412		50,080		166,405		156,885
Exploration and Production and Other	35,148		27,659		102,768		86,315
Pipeline and Storage and Gathering	40,019		38,607		114,321		109,347
Property, Franchise and Other Taxes	21,201		20,427		66,635		71,999
Depreciation, Depletion and Amortization	113,454		102,410		348,179		299,973
Impairment of Exploration and Production Properties	200,696		—		200,696		—
	468,882		274,608		1,166,448		1,174,980
Operating Income (Loss)	(51,440)		154,096		406,294		629,844
Other Income (Expense):
Other Income (Deductions)	3,188		3,551		12,989		12,754
Interest Expense on Long-Term Debt	(32,876)		(26,311)		(89,791)		(83,499)
Other Interest Expense	(1,341)		(5,781)		(14,250)		(15,485)
Income (Loss) Before Income Taxes	(82,469)		125,555		315,242		543,614
Income Tax Expense (Benefit)	(28,311)		32,935		70,108		140,425
Net Income (Loss) Available for Common Stock	(54,158)		92,620		245,134		403,189
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	2,090,172		1,810,454		1,885,856		1,587,085
	2,036,014		1,903,074		2,130,990		1,990,274
Share Repurchases under Repurchase Plan	(18,435)		—		(22,252)		—
Dividends on Common Stock	(47,195)		(45,444)		(138,354)		(132,644)
Balance at June 30	$	1,970,384	$	1,857,630	$	1,970,384	$	1,857,630
Earnings (Loss) Per Common Share:
Basic:
Net Income (Loss) Available for Common Stock	$	(0.59)	$	1.01	$	2.67	$	4.40
Diluted:
Net Income (Loss) Available for Common Stock	$	(0.59)	$	1.00	$	2.65	$	4.37
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	91,874,049		91,803,638		91,966,034		91,725,286
Used in Diluted Calculation	91,874,049		92,294,666		92,467,787		92,268,904
Dividends Per Common Share:
Dividends Declared	$	0.515	$	0.495	$	1.505	$	1.445

See Notes to Condensed Consolidated Financial Statements

6

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)	2024		2023		2024		2023
Net Income (Loss) Available for Common Stock	$	(54,158)	$	92,620	$	245,134	$	403,189
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(21,936)		65,244		238,395		673,381
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	(75,346)		(57,692)		(155,203)		120,590
Other Comprehensive Income (Loss), Before Tax	(97,282)		7,552		83,192		793,971
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(6,086)		17,885		66,146		184,655
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	(20,906)		(15,813)		(43,064)		32,967
Income Taxes (Benefits) – Net	(26,992)		2,072		23,082		217,622
Other Comprehensive Income (Loss)	(70,290)		5,480		60,110		576,349
Comprehensive Income (Loss)	$	(124,448)	$	98,100	$	305,244	$	979,538

See Notes to Condensed Consolidated Financial Statements

7

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)

	June 30, 2024		September 30, 2023
(Thousands of U.S. Dollars)
ASSETS
Property, Plant and Equipment	$	14,245,690	$	13,635,303
Less - Accumulated Depreciation, Depletion and Amortization	6,834,824		6,335,441
	7,410,866		7,299,862
Current Assets
Cash and Temporary Cash Investments	81,414		55,447
Receivables – Net of Allowance for Uncollectible Accounts of $32,622 and $36,295, Respectively	156,846		160,601
Unbilled Revenue	15,032		16,622
Gas Stored Underground	14,186		32,509
Materials and Supplies - at average cost	48,331		48,989
Other Current Assets	82,923		100,260
	398,732		414,428
Other Assets
Recoverable Future Taxes	80,820		69,045
Unamortized Debt Expense	6,007		7,240
Other Regulatory Assets	73,934		72,138
Deferred Charges	89,740		82,416
Other Investments	79,547		73,976
Goodwill	5,476		5,476
Prepaid Pension and Post-Retirement Benefit Costs	230,591		200,301
Fair Value of Derivative Financial Instruments	100,317		50,487
Other	5,007		4,891
	671,439		565,970
Total Assets	$	8,481,037	$	8,280,260

See Notes to Condensed Consolidated Financial Statements

8

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)

	June 30, 2024		September 30, 2023
(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 – 91,612,488 Shares and 91,819,405 Shares, Respectively	$	91,612	$	91,819
Paid in Capital	1,046,479		1,040,761
Earnings Reinvested in the Business	1,970,384		1,885,856
Accumulated Other Comprehensive Income (Loss)	5,050		(55,060)
Total Comprehensive Shareholders’ Equity	3,113,525		2,963,376
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,637,115		2,384,485
Total Capitalization	5,750,640		5,347,861
Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	—		287,500
Current Portion of Long-Term Debt	50,000		—
Accounts Payable	101,200		152,193
Amounts Payable to Customers	62,569		59,019
Dividends Payable	47,195		45,451
Interest Payable on Long-Term Debt	46,926		20,399
Customer Advances	—		21,003
Customer Security Deposits	36,674		28,764
Other Accruals and Current Liabilities	169,133		160,974
Fair Value of Derivative Financial Instruments	2,941		31,009
	516,638		806,312
Other Liabilities
Deferred Income Taxes	1,172,068		1,124,170
Taxes Refundable to Customers	302,733		268,562
Cost of Removal Regulatory Liability	289,356		277,694
Other Regulatory Liabilities	164,390		165,441
Other Post-Retirement Liabilities	2,741		2,915
Asset Retirement Obligations	157,653		165,492
Other Liabilities	124,818		121,813
	2,213,759		2,126,087
Commitments and Contingencies (Note 8)	—		—
Total Capitalization and Liabilities	$	8,481,037	$	8,280,260

See Notes to Condensed Consolidated Financial Statements

9

National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)

	Nine Months Ended  June 30,
(Thousands of U.S. Dollars)	2024		2023
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	245,134	$	403,189
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Impairment of Exploration and Production Properties	200,696		—
Depreciation, Depletion and Amortization	348,179		299,973
Deferred Income Taxes	47,212		101,096
Stock-Based Compensation	15,984		15,807
Other	18,542		16,640
Change in:
Receivables and Unbilled Revenue	5,253		192,324
Gas Stored Underground and Materials and Supplies	18,981		11,757
Unrecovered Purchased Gas Costs	—		75,244
Other Current Assets	17,431		(12,230)
Accounts Payable	(13,705)		(52,340)
Amounts Payable to Customers	3,550		21,972
Customer Advances	(21,003)		(26,108)
Customer Security Deposits	7,910		9,741
Other Accruals and Current Liabilities	23,846		45,363
Other Assets	(35,346)		(39,367)
Other Liabilities	(14,649)		(7,949)
Net Cash Provided by Operating Activities	868,015		1,055,112
INVESTING ACTIVITIES
Capital Expenditures	(684,200)		(727,738)
Acquisition of Upstream Assets	—		(124,758)
Sale of Fixed Income Mutual Fund Shares in Grantor Trust	—		10,000
Other	(1,371)		13,397
Net Cash Used in Investing Activities	(685,571)		(829,099)
FINANCING ACTIVITIES
Proceeds from Issuance of Short-Term Note Payable to Bank	—		250,000
Repayment of Short-Term Note Payable to Bank	—		(250,000)
Net Change in Other Short-Term Notes Payable to Banks and Commercial Paper	(287,500)		78,500
Net Proceeds from Issuance of Long-Term Debt	299,396		297,533
Shares Repurchased Under Repurchase Plan	(27,847)		—
Reduction of Long-Term Debt	—		(549,000)
Dividends Paid on Common Stock	(136,610)		(130,653)
Net Repurchases of Common Stock Under Stock and Benefit Plans	(3,916)		(6,696)
Net Cash Used in Financing Activities	(156,477)		(310,316)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	25,967		(84,303)
Cash, Cash Equivalents, and Restricted Cash at October 1	55,447		137,718
Cash, Cash Equivalents, and Restricted Cash at June 30	$	81,414	$	53,415
Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$	80,468	$	71,823

See Notes to Condensed Consolidated Financial Statements

10

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, 2023, 2022 and 2021 that are included in the Company's 2023 Form 10-K.  The consolidated financial statements for the year ended September 30, 2024 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, 2024 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2024.  Most of the business of the Utility segment is seasonal in nature and is influenced by weather conditions.  Due to the seasonal nature of the heating business in the Utility segment, earnings during the winter months normally represent a substantial part of the earnings that this business is expected to achieve for the entire fiscal year.  The Company’s business segments are discussed more fully in Note 9 – Business Segment Information.

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

	Nine Months Ended  June 30, 2024				Nine Months Ended  June 30, 2023
	Balance at June 30, 2024		Balance at October 1, 2023		Balance at June 30, 2023		Balance at October 1, 2022
Cash and Temporary Cash Investments	$	81,414	$	55,447	$	53,415	$	46,048
Hedging Collateral Deposits	—		—		—		91,670
Cash, Cash Equivalents, and Restricted Cash	$	81,414	$	55,447	$	53,415	$	137,718

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

Allowance for Uncollectible Accounts. The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance, the majority of which is in the Utility segment, is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic and regulatory environment. Account balances have historically been written off against the allowance approximately twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered. During 2022 and 2021, final billings were suppressed in the Utility segment as a result of state shut-off moratoriums arising from the COVID-19 pandemic. Those moratoriums were lifted in 2022 which allowed for the resumption of final billings during 2022, thereby resulting in higher amounts being written off in 2023 and 2024.

11

    Activity in the allowance for uncollectible accounts for the nine months ended June 30, 2024 and 2023 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, 2024
Allowance for Uncollectible Accounts	$	36,295	$	11,774	$	698	$	(16,145)	$	32,622
Nine Months Ended June 30, 2023
Allowance for Uncollectible Accounts	$	40,228	$	13,142	$	1,316	$	(11,578)	$	43,108

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 and is replenished during the third and fourth quarters.  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 $6.7 million at June 30, 2024, 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 $2.6 billion and $2.4 billion at June 30, 2024 and September 30, 2023, 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 $202.2 million and $161.1 million at June 30, 2024 and September 30, 2023, 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. The book value of the exploration and production properties exceeded the ceiling at June 30, 2024. As such, the Company recognized a non-cash, pre-tax impairment charge of $200.7 million for the quarter ended June 30, 2024. A deferred income tax benefit of $55.7 million related to the non-cash impairment charge was also recognized for the quarter ended June 30, 2024. In adjusting estimated future cash flows for hedging under the ceiling test at June 30, 2024, estimated future net cash flows were increased by $375.8 million.

    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, 2024.

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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, 2024 and 2023, 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, 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 Loss	(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
Three Months Ended June 30, 2023
Balance at April 1, 2023	$	(1,294)	$	(53,570)	$	(54,864)
Other Comprehensive Gains and Losses Before Reclassifications	47,359		—		47,359
Amounts Reclassified From Other Comprehensive Income	(41,879)		—		(41,879)
Balance at June 30, 2023	$	4,186	$	(53,570)	$	(49,384)
Nine Months Ended June 30, 2023
Balance at October 1, 2022	$	(572,163)	$	(53,570)	$	(625,733)
Other Comprehensive Gains and Losses Before Reclassifications	488,726		—		488,726
Amounts Reclassified From Other Comprehensive Income	87,623		—		87,623
Balance at June 30, 2023	$	4,186	$	(53,570)	$	(49,384)

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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, 2024 and 2023 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,
	2024	2023	2024	2023
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts	$75,462	$57,842	$155,401	($120,088)	Operating Revenues
Foreign Currency Contracts	(116)	(150)	(198)	(502)	Operating Revenues
	75,346	57,692	155,203	(120,590)	Total Before Income Tax
	(20,906)	(15,813)	(43,064)	32,967	Income Tax Expense
	$54,440	$41,879	$112,139	($87,623)	Net of Tax

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

	At June 30, 2024		At September 30, 2023
Prepayments	$	23,972	$	18,966
Prepaid Property and Other Taxes	11,462		14,186
Federal Income Taxes Receivable	—		14,602
State Income Taxes Receivable	12,298		16,133
Regulatory Assets	35,191		36,373
	$	82,923	$	100,260

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

	At June 30, 2024		At September 30, 2023
Accrued Capital Expenditures	$	52,620	$	43,323
Regulatory Liabilities	27,538		38,105
Reserve for Gas Replacement	6,657		—
Liability for Royalty and Working Interests	17,670		17,679
Federal Income Taxes Payable	1,027		—
Non-Qualified Benefit Plan Liability	13,052		13,052
Other	50,569		48,815
	$	169,133	$	160,974

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. 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. For the nine months ended June 30, 2024 and for the quarter and nine months ended June 30, 2023, the diluted weighted average shares

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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 335 securities excluded as being antidilutive for the nine months ended June 30, 2024. There were 8,322 securities and 4,526 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2023, respectively.

Share Repurchases. The Company considers all shares repurchased as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law. The repurchases are accounted for on the date the share repurchase is traded as an adjustment to common stock (at par value) with the excess repurchase price allocated between paid in capital and retained earnings. Refer to Note 7 – Capitalization for further discussion of the Company's share repurchase program.

Stock-Based Compensation. The Company granted 361,729 performance shares during the nine months ended June 30, 2024. The weighted average fair value of such performance shares was $44.23 per share for the nine months ended June 30, 2024. 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, 2024 include awards that must meet a performance goal related to either relative return on capital over a three-year or five-year performance cycle ("ROC performance shares"), methane intensity and greenhouse gas emissions reductions over a three-year performance cycle ("ESG performance shares") or relative shareholder return over a three-year or five-year performance cycle ("TSR performance shares"). The performance goal related to the ROC performance shares over the respective performance cycles 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 ESG 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 the Company's 2030 goals. The number of these ESG performance shares that will vest and be paid out will depend upon the number of methane intensity segment targets achieved and whether the Company meets the total greenhouse gas emissions target. The fair value of these ESG performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award.  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 respective performance cycles is the Company’s three-year (or five-year) total shareholder return relative to the three-year (or five-year) total shareholder return of the other companies in the Report Group.  Three-year (or five-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.

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    The Company granted 220,778 restricted stock units during the nine months ended June 30, 2024.  The weighted average fair value of such restricted stock units was $42.44 per share for the nine months ended June 30, 2024.  Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participant to receive dividends during the vesting period. The fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.

    Pursuant to registration statements for the Company's stock award plans, there were 3,890,301 shares available for future grant at June 30, 2024. These shares include shares available for future options, SARs, restricted stock and performance share grants.

Note 2 – Asset Acquisition

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

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

Note 3 – 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, 2024 and 2023, presented by type of service from each reportable segment.

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

Quarter Ended June 30, 2023 (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	$	157,682	$	—	$	—	$	—	$	—	$	—	$	157,682
Production of Crude Oil	483		—		—		—		—		—		483
Natural Gas Processing	284		—		—		—		—		—		284
Natural Gas Gathering Service	—		—		58,906		—		—		(54,277)		4,629
Natural Gas Transportation Service	—		70,424		—		19,905		—		(20,311)		70,018
Natural Gas Storage Service	—		21,147		—		—		—		(9,006)		12,141
Natural Gas Residential Sales	—		—		—		108,398		—		—		108,398
Natural Gas Commercial Sales	—		—		—		13,971		—		—		13,971
Natural Gas Industrial Sales	—		—		—		866		—		(2)		864
Other	290		824		—		406		—		(199)		1,321
Total Revenues from Contracts with Customers	158,739		92,395		58,906		143,546		—		(83,795)		369,791
Alternative Revenue Programs	—		—		—		1,071		—		—		1,071
Derivative Financial Instruments	57,842		—		—		—		—		—		57,842
Total Revenues	$	216,581	$	92,395	$	58,906	$	144,617	$	—	$	(83,795)	$	428,704

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Nine Months Ended June 30, 2023 (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	$	849,811	$	—	$	—	$	—	$	—	$	—	$	849,811
Production of Crude Oil	1,637		—		—		—		—		—		1,637
Natural Gas Processing	867		—		—		—		—		—		867
Natural Gas Gathering Service	—		—		172,300		—		—		(163,297)		9,003
Natural Gas Transportation Service	—		220,420		—		84,079		—		(62,880)		241,619
Natural Gas Storage Service	—		63,903		—		—		—		(27,221)		36,682
Natural Gas Residential Sales	—		—		—		671,352		—		—		671,352
Natural Gas Commercial Sales	—		—		—		97,432		—		—		97,432
Natural Gas Industrial Sales	—		—		—		5,273		—		(6)		5,267
Other	5,880		831		—		(1,717)		—		(747)		4,247
Total Revenues from Contracts with Customers	858,195		285,154		172,300		856,419		—		(254,151)		1,917,917
Alternative Revenue Programs	—		—		—		6,995		—		—		6,995
Derivative Financial Instruments	(120,088)		—		—		—		—		—		(120,088)
Total Revenues	$	738,107	$	285,154	$	172,300	$	863,414	$	—	$	(254,151)	$	1,804,824

    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: $58.9 million for the remainder of fiscal 2024; $224.8 million for fiscal 2025; $174.5 million for fiscal 2026; $136.4 million for fiscal 2027; $117.2 million for fiscal 2028; and $612.0 million thereafter.

Note 4 – Fair Value Measurements

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

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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, 2024 and September 30, 2023.  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, 2024
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)		Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	72,625	$	—	$	—	$	—	$	72,625
Derivative Financial Instruments:
Over the Counter Swaps – Gas	—		85,623		—		(17,654)		67,969
Over the Counter No Cost Collars – Gas	—		33,876		—		(3,060)		30,816
Contingent Consideration for Asset Sale	—		2,429		—		—		2,429
Foreign Currency Contracts	—		185		—		(1,082)		(897)
Other Investments:
Balanced Equity Mutual Fund	18,464		—		—		—		18,464
Fixed Income Mutual Fund	16,745		—		—		—		16,745
Total	$	107,834	$	122,113	$	—	$	(21,796)	$	208,151
Liabilities:
Derivative Financial Instruments:
Over the Counter Swaps – Gas	$	—	$	21,018	$	—	$	(17,654)	$	3,364
Over the Counter No Cost Collars – Gas	—		2,190		—		(3,060)		(870)
Foreign Currency Contracts	—		1,082		—		(1,082)		—
Total	$	—	$	24,290	$	—	$	(21,796)	$	2,494
Total Net Assets/(Liabilities)	$	107,834	$	97,823	$	—	$	—	$	205,657

Recurring Fair Value Measures	At fair value as of September 30, 2023
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)		Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	39,332	$	—	$	—	$	—	$	39,332
Derivative Financial Instruments:
Over the Counter Swaps – Gas	—		65,800		—		(37,508)		28,292
Over the Counter No Cost Collars – Gas	—		30,966		—		(14,745)		16,221
Contingent Consideration for Asset Sale	—		7,277		—		—		7,277
Foreign Currency Contracts	—		150		—		(1,453)		(1,303)
Other Investments:
Balanced Equity Mutual Fund	15,837		—		—		—		15,837
Fixed Income Mutual Fund	15,897		—		—		—		15,897
Total	$	71,066	$	104,193	$	—	$	(53,706)	$	121,553
Liabilities:
Derivative Financial Instruments:
Over the Counter Swaps – Gas	$	—	$	68,311	$	—	$	(37,508)	$	30,803
Over the Counter No Cost Collars – Gas	—		14,950		—		(14,745)		205
Foreign Currency Contracts	—		1,454		—		(1,453)		1
Total	$	—	$	84,715	$	—	$	(53,706)	$	31,009
Total Net Assets/(Liabilities)	$	71,066	$	19,478	$	—	$	—	$	90,544

(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.

Derivative Financial Instruments

    The derivative financial instruments reported in Level 2 at June 30, 2024 and September 30, 2023 include natural gas price swap agreements, natural gas no cost collars, and foreign currency contracts, all of which are used in the Company’s

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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, 2024, 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, 2024 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 contingency period expired with the ICE Brent Average falling below $95 per barrel. The fair value of the contingent consideration was calculated using a Monte Carlo simulation model that uses observable inputs, including the ICE Brent closing price as of the valuation date, initial and max trigger price, volatility, risk-free rate, time of maturity and counterparty risk.

    For the quarters ended June 30, 2024 and June 30, 2023, there were no assets or liabilities measured at fair value and classified as Level 3.

Note 5 – Financial Instruments

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

	June 30, 2024				September 30, 2023
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,687,115	$	2,598,784	$	2,384,485	$	2,210,478

    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 Secured Overnight Financing Rates (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.

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

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

	At June 30, 2024		At September 30, 2023
Life Insurance Contracts	$	44,338	$	42,242
Equity Mutual Fund	18,464		15,837
Fixed Income Mutual Fund	16,745		15,897
	$	79,547	$	73,976

    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 7 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 contingency period expired with the ICE Brent Average falling below $95 per barrel. The Company has determined that this contingent consideration meets the definition of a derivative under the authoritative accounting guidance. Changes in the fair value of this contingent consideration are marked-to-market each reporting period, with changes in fair value recognized in Other Income (Deductions) on the Consolidated Statement of Income. The fair value of this contingent consideration was estimated to be $2.4 million and $7.3 million at June 30, 2024 and September 30, 2023, respectively. A $1.2 million mark-to-market adjustment to reduce the fair value of the contingent consideration was recorded during the quarter ended June 30, 2024. A $4.9 million mark-to-market adjustment to reduce the fair value of the contingent consideration was recorded during the nine months ended June 30, 2024.

    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, 2024 and September 30, 2023.

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, 2024, the Company had 334.0 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.

    As of June 30, 2024, the Company was hedging a total of $54.4 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

    As of June 30, 2024, the Company had $64.7 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance. Of this amount, it is expected that $43.1 million of unrealized gains after taxes will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings.

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The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended June 30, 2024 and 2023 (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,
	2024		2023			2024		2023
Commodity Contracts	$	(21,682)	$	64,653	Operating Revenue	$	75,462	$	57,842
Foreign Currency Contracts	(254)		591		Operating Revenue	(116)		(150)
Total	$	(21,936)	$	65,244		$	75,346	$	57,692

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Nine Months Ended June 30, 2024 and 2023 (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,
	2024		2023			2024		2023
Commodity Contracts	$	238,184	$	672,396	Operating Revenue	$	155,401	$	(120,088)
Foreign Currency Contracts	211		985		Operating Revenue	(198)		(502)
Total	$	238,395	$	673,381		$	155,203	$	(120,590)

Credit Risk

    The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions, no cost collars and applicable foreign currency forward contracts with nineteen counterparties of which eighteen are in a net gain position. On average, the Company had $5.4 million of credit exposure per counterparty in a gain position at June 30, 2024. The maximum credit exposure per counterparty in a gain position at June 30, 2024 was $21.2 million. As of June 30, 2024, no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral.

    As of June 30, 2024, sixteen of the nineteen counterparties to the Company’s outstanding derivative financial contracts (specifically the over-the-counter swaps, over-the-counter no cost collars and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit that could be extended to the Company when it is in a derivative financial liability position would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to post or increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative financial instrument contracts with a credit-risk contingency feature were in a liability position (or if the liability were larger) and/or the Company’s credit

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rating declined, then hedging collateral deposits or an increase to such deposits could be required.  At June 30, 2024, the Company did not have any derivative financial instrument liabilities with a credit-risk related contingency feature according to the Company’s internal model (discussed in Note 4 – Fair Value Measurements), and no hedging collateral deposits were required to be posted by the Company at June 30, 2024.  Depending on the movement of commodity prices in the future, it is possible that the Company's derivative asset positions could swing into liability positions, at which point the Company 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 6 – Income Taxes

    The effective tax rates for the quarters ended June 30, 2024 and June 30, 2023 were 34.3% and 26.2%, respectively. The change 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 and a methodology change for repairs and maintenance tax deductions as a result of updated IRS guidance published in 2023, 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, 2024 and June 30, 2023 were 22.2% and 25.8%, respectively. The decrease in the year-to-date effective income tax rate was also primarily due to the impact of the impairment of exploration and production properties under the ceiling test on income before income taxes, and the methodology change for repairs and maintenance tax deductions as a result of updated IRS guidance published in 2023.

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Note 7 – Capitalization

Summary of Changes in Common Stock Equity

	Common Stock			Paid In Capital		Earnings Reinvested in the Business		Accumulated Other Comprehensive Income (Loss)
	Shares	Amount
	(Thousands, except per share amounts)
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
Balance at April 1, 2023	91,795	$	91,795	$	1,031,341	$	1,810,454	$	(54,864)
Net Income Available for Common Stock						92,620
Dividends Declared on Common Stock ($0.495 Per Share)						(45,444)
Other Comprehensive Income, Net of Tax								5,480
Share-Based Payment Expense (1)				4,009
Common Stock Issued Under Stock and Benefit Plans	9	9		502
Balance at June 30, 2023	91,804	$	91,804	$	1,035,852	$	1,857,630	$	(49,384)
Balance at October 1, 2022	91,478	$	91,478	$	1,027,066	$	1,587,085	$	(625,733)
Net Income Available for Common Stock						403,189
Dividends Declared on Common Stock ($1.445 Per Share)						(132,644)
Other Comprehensive Income, Net of Tax								576,349
Share-Based Payment Expense (1)				14,327
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	326	326		(5,541)
Balance at June 30, 2023	91,804	$	91,804	$	1,035,852	$	1,857,630	$	(49,384)

(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.

Common Stock.  During the nine months ended June 30, 2024, the Company issued 112,667 original issue shares of common stock for restricted stock units that vested and 251,255 original issue shares of common stock for performance shares that vested.  The Company also issued 27,310 original issue shares of common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, including the reinvestment of dividends for certain non-employee directors who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's Deferred Compensation Plan for Directors and Officers (the "DCP") during the nine months ended June 30, 2024.  In addition, the Company issued 5,964 original issue shares of common stock to officers of the

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Company who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's DCP Plan during the nine months ended June 30, 2024. Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes.  During the nine months ended June 30, 2024, 77,461 shares of common stock were tendered to the Company for such purposes.  The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

    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. During the nine months ended June 30, 2024, the Company executed transactions to repurchase 526,652 shares at an average price of $54.28 per share. With broker fees and excise taxes, the total cost of these repurchases amounted to $28.8 million. Share repurchases that settled during the nine months ended June 30, 2024 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.

Short-Term Borrowings. On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the "Credit Agreement") with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. As initially entered, the Credit Agreement provided a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027. In February 2024, the Company and eleven of the banks in the syndicate consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. In May 2024, three of the banks in the syndicate assumed the commitments of the sole non-extending lender such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion to February 25, 2028.

Current Portion of Long-Term Debt. The Current Portion of Long-Term Debt at June 30, 2024 consisted of $50.0 million of 7.375% notes that mature in June 2025. None of the Company's long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period.

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. The Company selected an initial six month interest period for these borrowings, locking in a weighted average interest rate of 6.705% through the beginning of October 2024. 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.

Note 8 – Commitments and Contingencies

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

    At June 30, 2024, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $2.5 million.  The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at June 30, 2024. The Company has a regulatory liability of $5.2 million related to environmental clean-up costs at June 30, 2024 and is currently not aware of any material additional exposure to environmental liabilities.  However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company.

Northern Access Project. On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access project described herein. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). Subsequently, FERC

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issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order and FERC's decisions were appealed. The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. On June 29, 2022, the Company received an extension of time from FERC, until December 31, 2024, to construct the project, which was affirmed on March 29, 2024 by the U.S. Court of Appeals for the D.C. Circuit. In light of the recent D.C. Circuit decision, the Company is evaluating next steps for the project, including the status of various regulatory approvals, the $500 million preliminary cost estimate, and the potential in-service date. As of June 30, 2024, the Company has spent approximately $55.0 million on the project, all of which is recorded on the balance sheet.

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 9 – 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 2023 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 2023 Form 10-K.  A listing of segment assets at June 30, 2024 and September 30, 2023 is shown in the tables below.  

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

(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, 2024	$2,815,598	$2,486,740	$998,176	$2,329,894	$8,630,408	$5,067	$(154,438)	$8,481,037
At September 30, 2023	$2,814,218	$2,427,214	$912,923	$2,247,743	$8,402,098	$4,795	$(126,633)	$8,280,260

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Quarter Ended June 30, 2023 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$216,581	$62,956	$4,629	$144,538	$428,704	$—	$—	$428,704
Intersegment Revenues	$—	$29,439	$54,277	$79	$83,795	$—	$(83,795)	$—
Segment Profit: Net Income (Loss)	$43,329	$23,813	$24,135	$37	$91,314	$(81)	$1,387	$92,620

Nine Months Ended June 30, 2023 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$738,107	$194,800	$9,003	$862,914	$1,804,824	$—	$—	$1,804,824
Intersegment Revenues	$—	$90,354	$163,297	$500	$254,151	$—	$(254,151)	$—
Segment Profit: Net Income (Loss)	$195,503	$77,147	$73,207	$55,574	$401,431	$(430)	$2,188	$403,189

Note 10 – Retirement Plan and Other Post-Retirement Benefits

    Components of Net Periodic Benefit Cost (in thousands):

	Retirement Plan				Other Post-Retirement Benefits
Three Months Ended June 30,	2024		2023		2024		2023
Service Cost	$	1,049	$	1,297	$	109	$	147
Interest Cost	10,890		10,629		3,890		3,912
Expected Return on Plan Assets	(17,086)		(16,648)		(6,660)		(6,403)
Amortization of Prior Service Cost (Credit)	91		109		(107)		(107)
Amortization of (Gains) Losses	(335)		(1,920)		(567)		(2,189)
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	4,057		5,378		2,248		3,829
Net Periodic Benefit Cost (Income)	$	(1,334)	$	(1,155)	$	(1,087)	$	(811)

	Retirement Plan				Other Post-Retirement Benefits
Nine Months Ended June 30,	2024		2023		2024		2023
Service Cost	$	3,148	$	3,891	$	326	$	440
Interest Cost	32,668		31,887		11,671		11,736
Expected Return on Plan Assets	(51,257)		(49,945)		(19,981)		(19,210)
Amortization of Prior Service Cost (Credit)	271		327		(322)		(321)
Amortization of (Gains) Losses	(1,004)		(5,760)		(1,700)		(6,566)
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	12,173		16,134		6,256		11,143
Net Periodic Benefit Cost (Income)	$	(4,001)	$	(3,466)	$	(3,750)	$	(2,778)

(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.

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    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, 2024, and does not anticipate making any such contributions during the remainder of fiscal 2024. 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, 2024, and does not anticipate making any such contributions during the remainder of fiscal 2024.

Note 11 – Regulatory Matters

New York Jurisdiction

    Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017 ("2017 Rate Order"). The 2017 Rate Order provided for a return on equity of 8.7% and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. On October 31, 2023, Distribution Corporation made a filing with the NYPSC seeking an increase of approximately $88 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024 that includes the maximum suspension period permitted under the New York Public Service Law ("2023 Rate Filing"). The Company is also proposing, among other things, to continue its leak prone pipe replacement program and to implement a number of initiatives that will facilitate achievement of the emissions reduction goals of the CLCPA. A Notice of Impending Settlement Negotiations was filed with the NYPSC on March 26, 2024 and settlement discussions with parties are ongoing. To facilitate settlement negotiations, the Company has indicated that it is willing to accept an extension of the suspension period for the effective date of new base delivery rates through and including January 31, 2025. Consistent with normal regulatory practice, the Company’s acceptance is subject to a “make-whole” provision that would permit the Company to recover or refund any revenue under-collections or over-collections, respectively, resulting from the extension period.

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

Pennsylvania Jurisdiction

    On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $28.1 million. A settlement involving all active parties to the proceeding was reached and filed with the PaPUC on April 13, 2023. The settlement provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million. The PaPUC approved the settlement in full, without modification or correction, on June 15, 2023 and new rates went into effect on August 1, 2023.

    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. If approved as filed, beginning October 1, 2024, the Company will be able to recover costs associated with plant placed in service on and after August 1, 2024 if it exceeds approximately $781.3 million of plant as of July 31, 2024 and its quarterly rate of return does not exceed the authorized PaPUC rate of return. As of June 30, 2024, plant placed in service for Distribution Corporation’s Pennsylvania division is $763.7 million. The DSIC petition is currently pending before the PaPUC.

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FERC Jurisdiction

    Supply Corporation filed an NGA Section 4 rate case on July 31, 2023 proposing rate increases to be effective February 1, 2024. On March 8, 2024, Supply Corporation and the parties in the case reached a settlement in principle (the Settlement) to resolve the rate case. Supply Corporation’s March 11, 2024 motion to put in place Settlement Rates effective February 1, 2024, was approved by FERC’s Chief Administrative Law Judge on March 12, 2024. The Settlement was filed with FERC on March 27, 2024. A letter order approving the Settlement as filed was issued on June 11, 2024. The “black box” settlement provides for new rates and resolves all issues in the proceeding. The Settlement Rates are estimated to increase Supply Corporation’s revenues on a yearly basis by approximately $56 million, assuming current contract levels. The Settlement generally provides for the continuation of current depreciation rates with minimal changes. Under the Settlement, 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.

    Empire's 2019 rate settlement requires a Section 4 rate case filing no later than May 1, 2025. Empire has no rate case currently on file.

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. Current development activities are focused primarily in the Marcellus and Utica shales. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian Basin to markets in the eastern United States and Canada. The Company's efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas customers in the Appalachian Basin. The Company reports financial results for four business segments. 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, 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. The Tioga Pathway Project has a target in-service date in late calendar 2026 and a preliminary cost estimate of approximately $101 million. The Tioga Pathway Project is discussed in more detail in the Capital Resources and Liquidity section that follows.

    From a rate perspective, Distribution Corporation, in its Pennsylvania jurisdiction, reached a settlement with the parties to its rate case proceeding. On June 15, 2023, the PaPUC issued an order adopting the settlement in full. The settlement authorized an increase in Distribution Corporation's annual base rate operating revenues of $23 million that became effective August 1, 2023. Distribution Corporation also filed a rate case proceeding with the NYPSC in its New York jurisdiction on October 31, 2023 seeking an increase of approximately $88 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024. In addition, Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023. Settlement rates became effective on February 1, 2024 under a settlement in principle that was filed with FERC on March 27, 2024. The settlement, which is estimated to increase Supply Corporation's revenues by approximately $56 million on an annual basis, was approved on June 11, 2024, with no modifications. For further discussion of Distribution Corporation and Supply Corporation 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. The Company recorded an impairment under the ceiling test during the quarter ended June 30, 2024 of $200.7 million ($145.0 million after-tax). Looking ahead, the first day of the month Henry Hub spot price for natural gas in

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July 2024 was $2.39 per MMBtu. Given the July price, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation for the next two quarters, the Company could experience a ceiling test impairment for the quarter ending September 30, 2024 as well as the quarter ending December 31, 2024. Please refer to the Critical Accounting Estimates section below for a sensitivity analysis concerning commodity price changes.

    From a financing perspective, in February 2024, eleven lenders in the syndicate of twelve banks under the Credit Agreement consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. In May 2024, three of the lenders in the syndicate assumed the commitments of the sole non-extending lender. As a result, the Company has aggregate commitments available under the Credit Agreement of $1.0 billion to February 25, 2028.

    On February 14, 2024, the Company entered into the Term Loan Agreement with six lenders. The Term Loan Agreement established a $300 million unsecured committed delayed draw term loan credit facility with a maturity date of February 14, 2026. In April 2024, the Company elected to draw a total of $300 million under the facility. The Company used the proceeds for general corporate purposes, including the redemption of outstanding commercial paper. For further discussion of the Term Loan Agreement, refer to the Capital Resources and Liquidity section that follows.

    The Company began repurchasing outstanding shares of 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. During the nine months ended June 30, 2024, the Company executed transactions to repurchase 526,652 shares at an average price of $54.28 per share. With broker fees and excise taxes, the total cost of these repurchases amounted to $28.8 million. 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 long-term borrowings, as needed, to meet its financing needs for the remainder of fiscal 2024. The Company continues to evaluate these financing needs and options to meet them. Given the current economic conditions, which include continued inflationary pressures and volatile interest rates, 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 2023 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. The book value of the exploration and production properties exceeded the ceiling at June 30, 2024, resulting in a non-cash impairment charge of $200.7 million ($145.0 million after-tax) for the quarter ended June 30, 2024. 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, 2024, based on the quoted Henry Hub spot price for natural gas, was $2.32 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, 2024. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the additional impairment that the Company would have recorded at June 30, 2024 if natural gas prices were $0.25 per MMBtu lower than the average prices used at June 30, 2024 (all amounts are presented after-tax). These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

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Ceiling Testing Sensitivity to Commodity Price Changes
(Millions)	$0.25/MMBtu Decrease in Natural Gas Prices
Calculated Impairment under Sensitivity Analysis	$	471.5
Actual Impairment Recorded at June 30, 2024	145.0
Additional Impairment	$	326.5

    Looking ahead, the first day of the month Henry Hub spot price for natural gas in July 2024 was $2.39 per MMBtu. Given the July price, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation for the next two quarters, the Company could experience a ceiling test impairment for the quarter ending September 30, 2024 as well as the quarter ending December 31, 2024. For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2023 Form 10-K.

RESULTS OF OPERATIONS

Earnings

    The Company recorded a loss of $54.2 million for the quarter ended June 30, 2024 compared to earnings of $92.6 million for the quarter ended June 30, 2023.  The decrease in earnings is primarily the result of a loss recognized in the Exploration and Production segment. Losses in the Corporate and All Other categories also contributed to the decrease. Higher earnings in the Pipeline and Storage segment, Utility segment and Gathering segment partially offset these decreases.

    The Company's earnings were $245.1 million for the nine months ended June 30, 2024 compared to earnings of $403.2 million for the nine months ended June 30, 2023.  The decrease in earnings of $158.1 million is primarily the result of lower earnings in the Exploration and Production segment and the Corporate category. Higher earnings in the Utility segment, Gathering segment and Pipeline and Storage segment, as well as a lower loss in the All Other category, partially offset these decreases.

    The Company's earnings for the quarter and nine months ended June 30, 2024 included a non-cash $200.7 million impairment charge ($145.0 million after-tax) recorded during the quarter ended June 30, 2024 for its exploration and production properties, as discussed above. 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)	2024		2023		Increase (Decrease)		2024		2023		Increase (Decrease)
Exploration and Production	$	(112,028)	$	43,329	$	(155,357)	$	2,521	$	195,503	$	(192,982)
Pipeline and Storage	30,690		23,813		6,877		85,482		77,147		8,335
Gathering	24,979		24,135		844		82,510		73,207		9,303
Utility	2,559		37		2,522		73,848		55,574		18,274
Total Reportable Segments	(53,800)		91,314		(145,114)		244,361		401,431		(157,070)
All Other	(124)		(81)		(43)		(341)		(430)		89
Corporate	(234)		1,387		(1,621)		1,114		2,188		(1,074)
Total Consolidated	$	(54,158)	$	92,620	$	(146,778)	$	245,134	$	403,189	$	(158,055)

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Exploration and Production

Exploration and Production Operating Revenues

	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2024		2023		Increase (Decrease)		2024		2023		Increase (Decrease)
Gas Produced in Appalachia (after Hedging)	$	219,836	$	215,524	$	4,312	$	735,634	$	729,723	$	5,911
Other	1,069		1,057		12		3,903		8,384		(4,481)
	$	220,905	$	216,581	$	4,324	$	739,537	$	738,107	$	1,430

Production Volumes

	Three Months Ended June 30,			Nine Months Ended  June 30,
	2024	2023	Increase (Decrease)	2024	2023	Increase (Decrease)
Gas Production per MMcf	96,504	94,747	1,757	300,144	278,562	21,582

Average Prices

	Three Months Ended June 30,						Nine Months Ended  June 30,
	2024		2023		Increase (Decrease)		2024		2023		Increase (Decrease)
Average Gas Price/Mcf
Weighted Average	$	1.50	$	1.66	$	(0.16)	$	1.93	$	3.05	$	(1.12)
Weighted Average After Hedging	$	2.28	$	2.27	$	0.01	$	2.45	$	2.62	$	(0.17)

2024 Compared with 2023

    Operating revenues for the Exploration and Production segment increased $4.3 million for the quarter ended June 30, 2024 as compared with the quarter ended June 30, 2023. Gas production revenue after hedging increased $4.3 million due to the impact of a 1.8 Bcf increase in natural gas production combined with a $0.01 per Mcf increase in the weighted average price of natural gas after hedging. The increase in natural gas production was largely due to additional production from new Marcellus and Utica wells in the Appalachian region.

    Operating revenues for the Exploration and Production segment increased $1.4 million for the nine months ended June 30, 2024 as compared with the nine months ended June 30, 2023. Gas production revenue after hedging increased $5.9 million due to the impact of a 21.6 Bcf increase in natural gas production, offset by a $0.17 per Mcf decrease in the weighted average price of natural gas after hedging. The increase in natural gas production was largely due to additional production from new Marcellus and Utica wells in the Appalachian region during the nine months ended June 30, 2024 as compared with the nine months ended June 30, 2023. In addition, other revenue decreased $4.5 million due to the non-recurrence of temporary capacity release revenue for a portion of this segment's transportation capacity during the nine months ended June 30, 2023.

    The Exploration and Production segment's loss for the quarter ended June 30, 2024 was $112.0 million, a decrease of $155.3 million when compared with earnings of $43.3 million for the quarter ended June 30, 2023. This decrease can be primarily attributed to a non-cash impairment of exploration and production properties during the quarter ended June 30, 2024 ($145.0 million), higher depletion expense ($6.5 million), higher lease operating and transportation expenses ($3.8 million), higher other operating expenses ($3.6 million), higher other taxes ($0.6 million) and an increase in interest expense ($0.8 million). There was also an unrealized loss recognized in the three-month period ended June 30, 2024 ($0.9 million) on contingent consideration received as part of the California asset sale, compared to an unrealized loss that was recognized in the three-month period ended June 30, 2023 ($1.0 million) on such contingent consideration. These decreases were partially offset by higher natural gas production ($3.2 million), higher natural gas prices after hedging ($0.2 million) and a reduction in income tax expense ($1.4 million). The increase in depletion expense was primarily due to the net increase in production combined with a $0.07 per Mcf increase in the depletion rate. The increase in lease operating and transportation expenses was primarily

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the result of higher gathering and transportation costs. The increase in other operating expenses was primarily attributable to recognizing an accrual of plugging and abandonment costs related to certain wells that were formerly owned by Seneca, combined with higher general and administrative costs. The increase in other taxes was primarily attributed to higher Impact Fees in the Appalachian region as a result of additional wells drilled combined with a prior year fee true-up that reduced Impact Fees in the quarter ended June 30, 2023. The increase in interest expense can largely be attributed to higher average interest rates on intercompany short-term and long-term borrowings, as well as higher intercompany long-term debt balances The reduction in income tax expense was primarily driven by lower state income tax expense as a result of both a decrease in pre-tax income and a decrease in Pennsylvania's state income tax rate from 9.99% to 4.99% over a ten year period.

    The Exploration and Production segment's earnings for the nine months ended June 30, 2024 were $2.5 million, a decrease of $193.0 million when compared with earnings of $195.5 million for the nine months ended June 30, 2023. The decrease in earnings was primarily attributable to a non-cash impairment of exploration and production properties ($145.0 million), lower natural gas prices after hedging ($40.0 million) and lower other revenue ($3.6 million), as previously discussed. Higher depletion expense ($31.2 million), higher lease operating and transportation expenses ($11.2 million), higher other operating expenses ($7.9 million) and an increase in interest expense ($4.7 million) also reduced earnings. There was also a higher unrealized loss recognized in the nine months ended June 30, 2024 ($3.5 million) on contingent consideration received as part of the California asset sale as compared to an unrealized loss that was recognized in the nine months ended June 30, 2023 ($2.7 million) on such contingent consideration. These decreases were partially offset by higher natural gas production ($44.7 million) combined with lower other taxes ($3.3 million) and a reduction in income tax expense ($2.9 million). The increase in depletion expense was primarily due to the net increase in production combined with a $0.08 per Mcf increase in the depletion rate. The increase in lease operating and transportation expenses was primarily the result of higher gathering and transportation costs combined with higher workover expenses. The increase in other operating expenses was primarily attributable to recognizing an accrual of plugging and abandonment costs related to certain wells that were formerly owned by Seneca, combined with higher general and administrative costs. The increase in interest expense can largely be attributed to higher average interest rates on intercompany short-term and long-term borrowings, partially offset by lower intercompany long-term debt balances. The decrease in other taxes was primarily attributable to lower Impact Fees in the Appalachian region due to lower NYMEX pricing, which reduces the cost per well due to moving the Company into a lower rate tier. The reduction in income tax expense was primarily driven by lower state income tax expense as a result of both a decrease in pre-tax income and a decrease in Pennsylvania's state income tax rate from 9.99% to 4.99% over a ten year period, partially offset by a lower benefit from permanent differences related to stock compensation.

Pipeline and Storage

Pipeline and Storage Operating Revenues

	Three Months Ended June 30,						Nine Months Ended  June 30,
(Thousands)	2024		2023		Increase (Decrease)		2024		2023		Increase (Decrease)
Firm Transportation	$	79,537	$	70,296	$	9,241	$	232,012	$	219,240	$	12,772
Interruptible Transportation	103		128		(25)		520		1,180		(660)
	79,640		70,424		9,216		232,532		220,420		12,112
Firm Storage Service	24,612		21,147		3,465		71,246		63,901		7,345
Interruptible Storage Service	—		—		—		1		2		(1)
Other	1,167		824		343		4,073		831		3,242
	$	105,419	$	92,395	$	13,024	$	307,852	$	285,154	$	22,698

Pipeline and Storage Throughput

	Three Months Ended June 30,			Nine Months Ended  June 30,
(MMcf)	2024	2023	Increase (Decrease)	2024	2023	Increase (Decrease)
Firm Transportation	168,510	181,440	(12,930)	590,868	637,145	(46,277)
Interruptible Transportation	118	97	21	1,508	2,024	(516)
	168,628	181,537	(12,909)	592,376	639,169	(46,793)

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2024 Compared with 2023

    Operating revenues for the Pipeline and Storage segment increased $13.0 million for the quarter ended June 30, 2024 as compared with the quarter ended June 30, 2023.  The increase in operating revenues was primarily due to an increase in transportation revenues of $9.2 million, an increase in storage revenues of $3.5 million and an increase in other revenues of $0.3 million. The increase in transportation and 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.

    Operating revenues for the Pipeline and Storage segment increased $22.7 million for the nine months ended June 30, 2024 as compared with the nine months ended June 30, 2023. The increase in operating revenues was primarily due to an increase in transportation revenues of $12.1 million, an increase in storage revenues of $7.3 million, and an increase in other revenues of $3.2 million. The increase in transportation and storage revenues was primarily attributable to an increase in Supply Corporation's transportation and storage rates effective February 1, 2024 in accordance with the aforementioned Supply Corporation rate case settlement and final true-up adjustment to the surcharge for pipeline safety and greenhouse gas costs that ended effective February 1, 2024. The increase in transportation revenues was partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions. The increase in other revenues primarily reflects an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense.

    Transportation volume for the quarter ended June 30, 2024 decreased by 12.9 Bcf from the prior year's quarter ended June 30, 2023. For the nine months ended June 30, 2024, transportation volume decreased by 46.8 Bcf from the prior year's nine-month period ended June 30, 2023. The decrease in transportation volume for both the quarter and nine months ended June 30, 2024 is primarily due to a decrease in volume from certain contract expirations combined with a decline in volume from warmer weather. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

    The Pipeline and Storage segment’s earnings for the quarter ended June 30, 2024 were $30.7 million, an increase of $6.9 million when compared with earnings of $23.8 million for the quarter ended June 30, 2023. The increase in earnings was primarily due to the earnings impact of higher operating revenues ($10.3 million), as discussed above. This increase was partially offset by increases in operating expenses ($1.5 million), interest expense ($0.8 million), depreciation expense ($0.6 million) and higher income tax expense ($0.5 million). The increase in operating expenses was primarily due to an increase in personnel costs, partially offset by lower pipeline integrity costs. The increase in interest expense is mainly due to an increase in intercompany short-term and long-term borrowings. The increase in depreciation expense was primarily due to higher average depreciable plant in service compared to the prior year, partially offset by an adjustment to depreciation expense related to the final regulatory approval of Supply Corporation's rate case settlement. The increase in income tax expense is mainly due to higher state income tax expense due to higher pre-tax earnings.

    The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2024 were $85.5 million, an increase of $8.4 million when compared with earnings of $77.1 million for the nine months ended June 30, 2023. The increase in earnings was primarily due to the earnings impact of higher operating revenues ($17.9 million), as discussed above, along with an increase in other income ($1.3 million). The increase in other income is primarily due to an increase in interest income for Empire related to a higher weighted average interest rate on intercompany short-term notes receivables and a higher average amount outstanding on those receivables. These increases were partially offset by increases in operating expenses ($4.5 million), depreciation expense ($2.6 million), interest expense ($2.4 million) and higher income tax expense ($0.8 million). The increase in operating expenses was primarily due to higher personnel costs, as well as higher power costs related to Empire's electric motor drive compressor station. This increase in electric power costs is offset by an equal increase in revenue. The increase in depreciation expense was primarily due to higher average depreciable plant in service compared to the prior year. The increase in interest expense is mainly due to an increase in Supply Corporation's intercompany short-term borrowings along with a higher weighted average interest rate on Supply Corporation's intercompany long-term borrowings. The increase in income tax expense is mainly due to higher state income tax expense due to higher pre-tax earnings.

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Gathering

Gathering Operating Revenues

	Three Months Ended June 30,						Nine Months Ended  June 30,
(Thousands)	2024		2023		Increase (Decrease)		2024		2023		Increase (Decrease)
Gathering Revenues	$	60,120	$	58,906	$	1,214	$	186,701	$	172,300	$	14,401

Gathering Volume

	Three Months Ended June 30,			Nine Months Ended  June 30,
	2024	2023	Increase (Decrease)	2024	2023	Increase (Decrease)
Gathered Volume - (MMcf)	118,445	118,707	(262)	367,832	336,078	31,754

2024 Compared with 2023

    Operating revenues for the Gathering segment increased $1.2 million for the quarter ended June 30, 2024 as compared with the quarter ended June 30, 2023. Although gathered volume decreased 0.3 Bcf over the aforementioned time period, changes in the throughput producer mix drove the increase in revenue. Gathered volume decreased 6.7 Bcf in the Gathering segment's western development area (Clermont), partially offset by a net 6.4 Bcf increase in gathered volume in the Gathering segment's eastern development areas (Trout Run and Tioga).

    Operating revenues for the Gathering segment increased $14.4 million for the nine months ended June 30, 2024 as compared with the nine months ended June 30, 2023, which was driven primarily by a 31.8 Bcf increase in gathered volume. Gathered volume increased 47.4 Bcf in the Gathering segment's eastern development areas (Trout Run and Tioga), partially offset by a 15.6 Bcf decrease in gathered volume in the Gathering segment's western development area (Clermont). The net increase can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.

    The Gathering segment’s earnings for the quarter ended June 30, 2024 were $25.0 million, an increase of $0.9 million when compared with earnings of $24.1 million for the quarter ended June 30, 2023. The increase in earnings was primarily due to higher gathering revenues ($1.0 million) and lower operation and maintenance expense ($0.4 million). The increase in gathering revenues was driven by changes in the throughput producer mix, as discussed above. The decrease in operation and maintenance expense was primarily due to lower compressor repairs and services along with lower leased compression costs. This increase was partially offset by higher depreciation expense ($0.6 million). The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga and Clermont gathering systems.

    The Gathering segment’s earnings for the nine months ended June 30, 2024 were $82.5 million, an increase of $9.3 million when compared with earnings of $73.2 million for the nine months ended June 30, 2023.  The increase in earnings was mainly due to higher gathering revenues ($11.4 million) driven by the increase in gathered volume, as discussed above, and lower interest expense ($0.6 million). The decrease in interest expense was primarily due to higher capitalized interest. This increase was partially offset by higher depreciation expense ($1.7 million) and higher income tax expense ($1.0 million). The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga and Clermont gathering systems. The increase in income tax expense was due to higher state income taxes driven by higher pre-tax income.

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Utility

Utility Operating Revenues

	Three Months Ended June 30,						Nine Months Ended  June 30,
(Thousands)	2024		2023		Increase (Decrease)		2024		2023		Increase (Decrease)
Retail Sales Revenues:
Residential	$	91,267	$	108,633	$	(17,366)	$	458,847	$	674,118	$	(215,271)
Commercial	10,614		14,063		(3,449)		62,217		96,976		(34,759)
Industrial	496		868		(372)		2,714		5,297		(2,583)
	102,377		123,564		(21,187)		523,778		776,391		(252,613)
Transportation	23,185		20,647		2,538		95,744		88,740		7,004
Other	(618)		406		(1,024)		(2,066)		(1,717)		(349)
	$	124,944	$	144,617	$	(19,673)	$	617,456	$	863,414	$	(245,958)

Utility Throughput

	Three Months Ended June 30,			Nine Months Ended  June 30,
(MMcf)	2024	2023	Increase (Decrease)	2024	2023	Increase (Decrease)
Retail Sales:
Residential	8,123	9,600	(1,477)	53,168	57,636	(4,468)
Commercial	1,308	1,434	(126)	8,401	8,812	(411)
Industrial	62	87	(25)	389	506	(117)
	9,493	11,121	(1,628)	61,958	66,954	(4,996)
Transportation	12,819	12,468	351	52,984	53,567	(583)
	22,312	23,589	(1,277)	114,942	120,521	(5,579)

Degree Days

Three Months Ended June 30,				Percent Colder (Warmer) Than
	Normal	2024	2023	Normal(1)		Prior Year(1)
Buffalo, NY	912	565	788	(38.0)	%	(28.3)	%
Erie, PA(2)	776	519	802	(33.1)	%	(35.3)	%
Nine Months Ended June 30,
Buffalo, NY	6,491	5,128	5,656	(21.0)	%	(9.3)	%
Erie, PA	5,727	4,759	5,434	(16.9)	%	(12.4)	%

(1)Percents compare actual 2024 degree days to normal degree days and actual 2024 degree days to actual 2023 degree days.

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

2024 Compared with 2023

    Operating revenues for the Utility segment decreased $19.7 million for the quarter ended June 30, 2024 as compared with the quarter ended June 30, 2023. This decrease resulted from a $21.2 million decrease in retail gas sales revenue and a $1.0 million decrease in other revenue, which were partially offset by a $2.5 million increase in transportation revenue. The decrease in retail gas sales revenue reflects a decrease in the cost of gas sold (per Mcf) combined with a 1.6 Bcf decrease in throughput mainly due to warmer weather. 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

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recorded on the consolidated income statement matches the revenues collected from customers. The decrease in retail gas sales revenue was partially offset by the impact of new base rates in Distribution Corporation's Pennsylvania jurisdiction pursuant to a settlement approved by the PaPUC on June 15, 2023. Additional details regarding the base rate regulatory proceeding can be found in the Rate Matters section below. The decrease in other revenue was mainly the result of a larger estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($0.5 million) and a decrease in late payment charges billed to customers ($0.4 million). The increase in transportation revenue was largely attributable to the impact of new base rates in Pennsylvania, as well as an increase in revenues earned under the system modernization and system improvement tracker mechanisms in Distribution Corporation's New York jurisdiction, which allow for the recovery of investments in leak prone pipe replacement.

    Operating revenues for the Utility segment decreased $246.0 million for the nine months ended June 30, 2024 as compared with the nine months ended June 30, 2023. The decrease resulted from a $252.6 million decrease in retail gas sales revenue and a $0.3 million decrease in other revenue. The decrease in retail gas sales revenue was primarily due to a decrease in the cost of gas sold (per Mcf) as well as a 5.0 Bcf decrease in throughput largely due to warmer weather. These factors were partially offset by an increase in base rates in Distribution Corporation's Pennsylvania jurisdiction, as mentioned above. The decrease in other revenue was largely due to decreases in late payment charges billed to customers ($1.5 million) and capacity release revenues ($1.0 million), partially offset by a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($2.1 million). The decreases in retail gas sales revenue and other revenue were partially offset by a $7.0 million increase in transportation revenue, predominantly due to the impact of the new base rates in Pennsylvania in addition to an increase in revenues from the system modernization and system improvement tracker in New York, despite a 0.6 Bcf decrease in throughput due to warmer weather.

    The Utility segment’s earnings for the quarter ended June 30, 2024 were $2.6 million, an increase of $2.5 million when compared with earnings of less than $0.1 million for the quarter ended June 30, 2023. The increase was primarily due to the impact of system modernization and system improvement trackers in New York ($3.5 million), lower income tax expense ($3.3 million), and the impact of new base rates in the Utility segment's Pennsylvania jurisdiction ($2.3 million). The decrease in income tax expense was largely due to an increase in tax deductions related to certain repairs and maintenance expenditures recorded in the Utility's Pennsylvania jurisdiction as a result of updated IRS guidance published in 2023. These increases were partially offset by higher operating expenses ($2.7 million), primarily due to higher personnel costs, a decrease in earnings from the impact of lower usage and weather ($2.4 million), an increase in depreciation and amortization expense ($1.1 million), and a decrease in other operating revenues ($0.4 million). The increase in depreciation expense was primarily the result of higher average plant balances and increased depreciation associated with negative net salvage in the Utility segment's Pennsylvania jurisdiction. The decrease in other operating revenues resulted from decreases in late payment charges billed to customers and capacity release revenues.

    The impact of weather variations on earnings in the Utility segment is mitigated by a WNA. Prior to October 2023, the impact of weather variations on earnings was mitigated by a WNA solely in the Utility segment’s New York rate jurisdiction. However, effective October 2023, the impact of weather variations on earnings is also mitigated by a WNA in the Utility segment’s Pennsylvania rate jurisdiction. 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, 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. For the quarter ended June 30, 2023, the WNA preserved earnings in the Utility segment’s New York jurisdiction of approximately $0.6 million, as the weather was warmer than normal.

    The Utility segment’s earnings for the nine months ended June 30, 2024 were $73.8 million, an increase of $18.2 million when compared with earnings of $55.6 million for the nine months ended June 30, 2023. The increase was mainly due to the impact of new base rates in the Utility segment's Pennsylvania jurisdiction ($17.7 million), lower income tax expense ($7.5 million), the impact of system modernization and system improvement trackers in New York ($6.2 million), and an increase in other income ($1.3 million). The decrease in income tax expense was largely due to an increase in tax deductions related to certain repairs and maintenance expenditures, as discussed above. The increase in other income was primarily driven by a decrease in non-service pension and post-retirement benefit costs in the Utility segment's Pennsylvania jurisdiction. These factors were partially offset by higher operating expenses ($7.7 million), primarily due to higher personnel costs, an increase in depreciation and amortization expense ($2.6 million), a decrease in earnings from regulatory adjustments ($2.1 million), a decrease in other operating revenues ($1.9 million), and a decrease in earnings from the impact of lower usage and weather ($0.7 million).

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    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. For the nine months ended June 30, 2023, the WNA preserved earnings in the Utility segment's New York rate jurisdiction of approximately $4.8 million, as the weather was warmer than normal.

Corporate and All Other

2024 Compared with 2023

    Corporate and All Other operations had a net loss of $0.4 million for the quarter ended June 30, 2024, a decrease of $1.7 million when compared with earnings of $1.3 million for the quarter ended June 30, 2023. The decrease was primarily attributable to lower other income ($0.6 million), higher operating expenses ($0.4 million), and changes in unrealized gains and losses on investments in equity securities. During the quarter ended June 30, 2023, the Company recorded unrealized gains of $0.3 million. During the quarter ended June 30, 2024, the Company recorded unrealized losses of less than $0.1 million.

    For the nine months ended June 30, 2024, Corporate and All Other operations had earnings of $0.8 million, a decrease of $1.0 million when compared with earnings of $1.8 million for the nine months ended June 30, 2023. The decrease in earnings for the nine-month period was primarily attributable to higher operating expenses ($1.6 million), primarily due to higher legal costs.

Other Income (Deductions)

    Net other income on the Consolidated Statements of Income was $3.2 million for the quarter ended June 30, 2024, compared to net other income of $3.6 million for the quarter ended June 30, 2023, for a decrease of $0.4 million. This decrease can be attributed primarily to lower income from life insurance policies of $0.6 million partially offset by an increase in interest income of $0.1 million and a decrease of $0.2 million when comparing the quarter over quarter losses associated with revaluing the contingent consideration received from the California asset sale.

    Net other income on the Consolidated Statement of Income was $13.0 million for the nine months ended June 30, 2024, compared to net other income of $12.8 million for the nine months ended June 30, 2023, for an increase of $0.2 million. While the overall variation is not significant, there were a number of items that contributed to the variance. Items increasing other income included $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, a $0.7 million increase in non-service pension and post-retirement benefit income, a $0.6 million increase in the allowance for funds used during construction, and a $0.4 million increase in income from life insurance policies. Items decreasing other income included a $2.8 million decrease in interest income and a $1.1 million period over period increase in losses associated with revaluing the contingent consideration received from the California asset sale.

Interest Expense on Long-Term Debt

    Interest expense on long-term debt on the Consolidated Statement of Income increased $6.6 million for the quarter ended June 30, 2024 as compared to the quarter ended June 30, 2023. For the nine months ended June 30, 2024, interest expense on long-term debt increased $6.3 million as compared with the nine months ended June 30, 2023. These increases are primarily due to higher average balances and a higher weighted average interest rate on long-term debt. In May 2023, the Company issued $300.0 million of 5.50% notes. Additionally, the Company elected to draw a total of $300.0 million under a delayed draw term loan credit facility in April 2024. The Company selected an initial six month interest period for these borrowings, locking in a weighted average interest rate of 6.705% through the beginning of October 2024. Partially offsetting these increases, the Company redeemed 3.75% notes in November 2022 and March 2023, amounting to $500.0 million in the aggregate, and also redeemed $49.0 million of 7.395% notes in March 2023. In addition, there was an increase in capitalized interest (mostly in Midstream Company) as a result of higher capital expenditures.

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CAPITAL RESOURCES AND LIQUIDITY

    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’s primary sources of cash during the nine-month period ended June 30, 2023 consisted of cash provided by operating activities, net proceeds from short-term and long-term borrowings and proceeds from the sale of a fixed income mutual fund held in a grantor trust.

    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 2024, the Company expects to use cash provided by operating activities, as well as net proceeds from short-term and long-term borrowings, to fund the Company's capital expenditures. Looking forward to 2025, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures. The Company also has two long-term debt maturities in 2025, totaling $500.0 million, which the Company anticipates funding with long-term borrowings. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.

Operating Cash Flow

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

    Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire. Prior to October 2023, the weather impact on cash flow in the Utility segment was mitigated by a WNA solely in its New York rate jurisdiction. However, effective October 2023, the weather impact on cash flow in the Utility segment is also mitigated by a WNA in its Pennsylvania rate jurisdiction. The Pennsylvania rate jurisdiction WNA resulted from the PaPUC's approved settlement on June 15, 2023, further discussed in the Rate Matters section below.

    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.

    Net cash provided by operating activities totaled $868.0 million for the nine months ended June 30, 2024, a decrease of $187.1 million compared with $1,055.1 million provided by operating activities for the nine months ended June 30, 2023. The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Exploration and Production segment due to lower cash receipts 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 $655.5 million during the nine months ended June 30, 2024 and $804.1 million during the nine months ended June 30, 2023.  The table below presents these expenditures:

Total Expenditures for Long-Lived Assets
Nine Months Ended June 30,	2024			2023			Increase (Decrease)
(Millions)
Exploration and Production:
Capital Expenditures(1)	$	399.8	(2)	$	592.8	(3)	$	(193.0)
Pipeline and Storage:
Capital Expenditures	68.8		(2)	66.8		(3)	2.0
Gathering:
Capital Expenditures	69.1		(2)	55.4		(3)	13.7
Utility:
Capital Expenditures	117.5		(2)	88.7		(3)	28.8
All Other:
Capital Expenditures	0.3			0.4			(0.1)
	$	655.5		$	804.1		$	(148.6)

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

(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. 

(3)At June 30, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $52.8 million, $7.7 million, $2.8 million and $8.5 million, respectively, of non-cash capital expenditures.  At September 30, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $83.0 million, $15.2 million, $10.7 million and $11.4 million, respectively, of non-cash capital expenditures.  

Exploration and Production 

    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 approximately $248.9 million spent to develop proved undeveloped reserves.

    The Exploration and Production segment capital expenditures for the nine months ended June 30, 2023 were primarily well drilling and completion expenditures in the Appalachian region and included $229.6 million in the Marcellus Shale area and $352.2 million in the Utica Shale area. These amounts included approximately $256.4 million spent to develop proved undeveloped reserves.

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

    In April 2023, the Company completed the acquisition of certain upstream assets located in Lycoming County in Northeast Pennsylvania for total consideration of $11.5 million. This acquisition included 1,145 net acres in Lycoming County. This transaction was accounted for as an asset acquisition and, as such, the purchase price was allocated to property, plant and equipment. The cost of this acquisition is reported as a component of Capital Expenditures on the Consolidated Statement of Cash Flows.

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Pipeline and Storage

    The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2024 and June 30, 2023 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions.

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

    Supply Corporation concluded an Open Season on August 25, 2023, and based on post-open season discussions, has designed a project that would allow for the transportation of 190,000 Dth per day of shale gas supplies from a new interconnection in northwest Tioga County, Pennsylvania to an existing Supply Corporation interconnection with Tennessee Gas Pipeline Company, LLC at Ellisburg and a new virtual delivery point into an existing Transcontinental Gas Pipe Line Company, LLC (“Transco”) capacity lease, providing access to Mid-Atlantic markets (“Tioga Pathway Project”). The Tioga Pathway Project involves the construction of approximately 19 miles of new pipeline and the replacement of approximately four miles of existing pipeline on the Supply Corporation system. Supply Corporation has executed a Precedent Agreement with Seneca for 190,000 Dth per day of transportation capacity. Supply Corporation expects to file a Section 7(c) application with the FERC in August 2024. The Tioga Pathway 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, 2024, approximately $1.5 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, 2024.

Gathering

    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. Midstream Company spent $55.4 million and $10.2 million, respectively, during the nine months ended June 30, 2024 on the development of the 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.

    The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2023 included expenditures related to the continued expansion of Midstream Company's Clermont, Tioga and Trout Run gathering systems. Midstream Company spent $14.7 million, $33.7 million and $6.8 million, respectively, during the nine months ended June 30, 2023 on the development of the Clermont, Tioga and Trout Run gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines, as well as the continued development of centralized station facilities, including increased compression horsepower, at the Clermont, Trout Run, and Tioga gathering systems. In the Tioga gathering system, expenditures were also largely attributable to the expansion of on-pad facilities related to bringing new development online.

Utility 

    The majority of the Utility segment capital expenditures for the nine months ended June 30, 2024 and June 30, 2023 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.

    The Company estimates that the Utility segment capital expenditures are expected to be approximately $165 million for fiscal 2024, which is approximately $25 million higher than the estimate previously reported in the 2023 Form 10-K. This increase is due to the estimated impact of New York State’s recently enacted Roadway Excavation Quality Assurance Act. This Act requires contractors to pay state published prevailing wages on projects that require a permit to operate in a public right of way, which is expected to increase contractor charges to the Company.

Other Investing Activities

    In October 2022, the Company sold $10 million of fixed income mutual fund shares held in a grantor trust that was established for the benefit of Pennsylvania ratepayers. The proceeds were used in the Utility segment's Pennsylvania service

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territory during fiscal 2023 to fund the second year installment of a 5-year pass back of previously overcollected OPEB expenses, as well as to diversify a portion of grantor trust investments into lower risk money market mutual fund shares for purposes of funding future installments.

Project Funding

    During the nine months ended June 30, 2024 and fiscal 2023, 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 and long-term borrowings, as needed, to finance capital expenditures. The level of short-term and/or long-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production and the associated commodity price realizations in the Exploration and Production segment. It will also likely depend on the timing of gas cost recovery in the Utility segment.

    The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive natural gas properties, accelerated development of existing natural gas properties, natural gas storage and transmission facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. The amounts are also subject to modification for opportunities involving emission reductions and/or energy transition including investments directly related to low- and no-carbon fuels. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s business segments depends, to a large degree, upon market and regulatory conditions as well as legislative actions.

Financing Cash Flow

    Consolidated short-term debt decreased $287.5 million when comparing the balance sheet at June 30, 2024 to the balance sheet at September 30, 2023. The maximum amount of short-term debt outstanding during the nine months ended June 30, 2024 was $402.9 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, 2024, the Company did not have any short-term notes payable to banks or commercial paper outstanding.

    On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the “Credit Agreement”) with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. As initially entered, the Credit Agreement provided a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027. In February 2024, the Company and eleven of the banks in the syndicate consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. In May 2024, three of the banks in the syndicate assumed the commitments of the sole non-extending lender such that the Company has aggregate commitments available under the Credit Agreement in the full amount of $1.0 billion to February 25, 2028.

    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. The Company selected an initial six month interest period for these borrowings, locking in a weighted average interest rate of 6.705% through the beginning of October 2024. After

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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.

    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 $526.4 million. As a result, at June 30, 2024, $263.2 million was added back to the Company's total capitalization for purposes of calculating the debt to capitalization ratio under the agreements. 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, 2024, the Company’s debt to capitalization ratio, as calculated under the agreements was 0.45. The constraints specified in the agreements would have permitted an additional $3.46 billion in short-term and/or long-term debt to be outstanding at June 30, 2024 (further limited by the indenture covenants discussed below) 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 May 18, 2023, the Company issued $300.0 million of 5.50% notes due October 1, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $297.3 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 7.50%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded.

    The Current Portion of Long-Term Debt at June 30, 2024 consisted of $50.0 million of 7.375% notes that mature in June 2025. None of the Company's long-term debt as of September 30, 2023 had a maturity date within the following twelve-month period.

    The Company’s embedded cost of long-term debt was 4.91% at June 30, 2024 and 4.70% at June 30, 2023.

    Under the Company’s existing indenture covenants at June 30, 2024, the Company would have been permitted to issue up to a maximum of approximately $2.26 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt. The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of exploration and production properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. At the current outlook for natural gas prices, and taking into account the Company’s present plans for capital expenditures, the Company does not expect the indenture covenants to restrict

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incremental long-term financing activities. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

    The Company’s 1974 indenture, pursuant to which $50.0 million (or 1.9%) of the Company’s long-term debt (as of June 30, 2024) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

    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. While the program has no fixed expiration date, the Company is targeting completion of this program by the end of fiscal 2025, depending 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. The Company’s Board of Directors may suspend, discontinue, terminate, modify, cancel or extend the share repurchase program at any time and for any reason. During the nine months ended June 30, 2024, the Company executed transactions to repurchase 526,652 shares at an average price of $54.28 per share. With broker fees and excise taxes, the total cost of these repurchases amounted to $28.8 million. Share repurchases that settled during the nine months ended June 30, 2024 were funded with cash provided by operating activities and/or short-term borrowings. It is expected that future 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.

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.

    Supply Corporation and Empire have developed a project which would move significant prospective Marcellus and Utica production from Seneca's Western Development Area at Clermont to an Empire interconnection with the TC Energy pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York (the “Northern Access project”). The Northern Access project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. On June 29, 2022, the Company received an extension of time from FERC, until December 31, 2024, to construct the project, which was affirmed on March 29, 2024, by the U.S. Court of Appeals for the D.C. Circuit. In light of the recent D.C. Circuit decision, the Company is evaluating next steps for the project, including the status of various regulatory approvals, the $500 million preliminary cost estimate, and the potential in-service date. As of June 30, 2024, approximately $55.0 million has been spent on the Northern Access project, including $24.4 million that has been spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet. The remaining $30.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at June 30, 2024.

    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, 2024, and does not anticipate making any such contributions during the remainder of fiscal 2024. 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, 2024, and does not anticipate making any such contributions during the remainder of fiscal 2024.

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Market Risk Sensitive Instruments

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

    The authoritative guidance for fair value measurements and disclosures requires consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities.  At June 30, 2024, 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 2023 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.” As noted below, the New York division currently has a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.

New York Jurisdiction

    Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017 ("2017 Rate Order"). The 2017 Rate Order provided for a return on equity of 8.7% and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. On October 31, 2023, Distribution Corporation made a filing with the NYPSC seeking an increase of approximately $88 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024 that includes the maximum suspension period permitted under the New York Public Service Law ("2023 Rate Filing"). The Company is also proposing, among other things, to continue its leak prone pipe replacement program and to implement a number of initiatives that will facilitate achievement of the emissions reduction goals of the CLCPA. A Notice of Impending Settlement Negotiations was filed with the NYPSC on March 26, 2024 and settlement discussions with parties are ongoing. To facilitate settlement negotiations, the Company has indicated that it is willing to accept an extension of the suspension period for the effective date of new base delivery rates through and including January 31, 2025. Consistent with normal regulatory practice, the Company’s acceptance is subject to a “make-whole” provision that would permit the Company to recover or refund any revenue under-collections or over-collections, respectively, resulting from the extension period.

    On August 13, 2021, the NYPSC issued an order extending the date through which qualified pipeline replacement costs incurred by the Company can be recovered using the existing system modernization tracker for two years (until March 31, 2023). On December 9, 2022, the Company filed a petition with the NYPSC to effectuate a system improvement tracker

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through which qualified pipeline replacement costs through September 30, 2024 would be tracked and recovered, and to recover certain deferred costs associated with the existing system modernization tracker, effective April 1, 2023. The NYPSC approved the petition by order dated March 17, 2023 contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to October 1, 2024. The 2023 Rate Filing proposes to stop accruing and collecting revenues under its current system modernization and system improvement trackers and shift those revenues into the Company’s new base delivery rates. In the absence of a multi-year rate plan settlement, the Company is requesting that it be allowed to reinstate a tracking mechanism similar to the existing system modernization tracker.

Pennsylvania Jurisdiction

    On October 28, 2022, Distribution Corporation made a filing with the PaPUC seeking an increase in its annual base rate operating revenues of $28.1 million. A settlement involving all active parties to the proceeding was reached and filed with the PaPUC on April 13, 2023. The settlement provided for, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million. The PaPUC approved the settlement in full, without modification or correction, on June 15, 2023 and new rates went into effect on August 1, 2023.

    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. If approved as filed, beginning October 1, 2024, the Company will be able to recover costs associated with plant placed in service on and after August 1, 2024 if it exceeds approximately $781.3 million of plant as of July 31, 2024 and its quarterly rate of return does not exceed the authorized PaPUC rate of return. As of June 30, 2024, plant placed in service for Distribution Corporation’s Pennsylvania division is $763.7 million. The DSIC petition is currently pending before the PaPUC.

Pipeline and Storage

    Supply Corporation filed an NGA Section 4 rate case on July 31, 2023 proposing rate increases to be effective February 1, 2024. On March 8, 2024, Supply Corporation and the parties in the case reached a settlement in principle (the Settlement) to resolve the rate case. Supply Corporation’s March 11, 2024 motion to put in place Settlement Rates effective February 1, 2024, was approved by FERC’s Chief Administrative Law Judge on March 12, 2024. The Settlement was filed with FERC on March 27, 2024. A letter order approving the Settlement as filed was issued on June 11, 2024. The “black box” settlement provides for new rates and resolves all issues in the proceeding. The Settlement Rates are estimated to increase Supply Corporation’s revenues on a yearly basis by approximately $56 million, assuming current contract levels. The Settlement generally provides for the continuation of current depreciation rates with minimal changes. Under the Settlement, 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.

    Empire's 2019 rate settlement requires a Section 4 rate case filing no later than May 1, 2025. Empire has no rate case currently on file.

Environmental Matters

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

    For further discussion of the Company's environmental exposures, refer to Item 1 at Note 8 – Commitments and Contingencies under the heading “Environmental Matters.”

    Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in the United States. These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, restrictive

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permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. For example, the federal Inflation Reduction Act of 2022 (IRA) legislation was signed into law on August 16, 2022. The IRA includes a directive for the EPA, the lead federal agency that regulates greenhouse gas emissions pursuant to the Clean Air Act, to develop a methane charge to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, with potential fees expected to begin in calendar 2025, covering emissions reported for calendar year 2024. The regulations implemented by the EPA also impose stringent leak detection and repair requirements and address reporting and control of methane and volatile organic compound emissions, and these regulations continue to be further expanded upon with the recent publication (March 2024) and finalization of the Standards of Performance for New, Reconstructed, and Modified Sources and Emissions Guidelines for Existing Sources. The Company must continue to comply with all applicable regulations. Additionally, a number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The NYPSC, for example, initiated a proceeding to consider climate-related financial disclosures at the utility operating company level, and the New York State legislature passed the CLCPA that mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. In May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to certain exemptions. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on the promulgation of regulations to implement the CLCPA and on regulatory treatment afforded in the process. The NYDEC, in conjunction with the New York State Energy Research and Development Authority, is also in the early phases of developing a cap-and-invest program in the state, which is anticipated to be effective in 2025. The above-enumerated initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.

Effects of Inflation

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

Safe Harbor for Forward-Looking Statements

    The Company is including the following cautionary statement in this 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

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achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:

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

2.Changes in the price of natural gas;

3.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;

4.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;

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

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

7.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;

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

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

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

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

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

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

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

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

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

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

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

19.Uncertainty of natural gas reserve estimates;

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, 2024.   

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, 2024 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 8 – Commitments and Contingencies, and Part I, Item 2 - MD&A of this report under the heading “Other Matters – Environmental Matters.”

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

Item 1A. Risk Factors

    The risk factors in Item 1A of the Company’s 2023 Form 10-K, as amended by Item 1A of Part II of the Company's Form 10-Q for the quarter ended March 31, 2024, have not materially changed other than as set forth below. The risk factor presented below supersedes the corresponding risk factor in the 2023 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2023 Form 10-K and the March 31, 2024 Form 10-Q.

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FINANCIAL RISKS

Financial accounting requirements regarding exploration and production activities may affect the Company's profitability.

    The Company accounts for its exploration and production activities under the full cost method of accounting. Each quarter, the Company must perform a "ceiling test" calculation, comparing the level of its unamortized investment in exploration and production properties to the present value of the future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses a 12-month historical average price for commodity pricing (based on first day of the month prices and adjusted for hedging) as well as the SEC mandated discount rate. If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be "impaired," and the full cost authoritative accounting and reporting guidance require that the investment must be written down to the calculated net present value. Such an instance would require the Company to recognize an immediate expense in that quarter, and its earnings would be reduced. Depending on the magnitude of any decrease in average prices, that charge could be material. Under the Company's existing indenture covenants, an impairment could restrict the Company's ability to issue incremental long-term unsecured indebtedness for a period of time, beginning with the fourth calendar month following the impairment and ending not later than June 13, 2025, the maturity date of the Company’s remaining indebtedness outstanding under its 1974 indenture. In addition, because an impairment results in a charge to retained earnings, it lowers the Company's total capitalization, all other things being equal, and increases the Company's debt to capitalization ratio. As a result, an impairment can impact the Company's ability to maintain compliance with the debt to capitalization covenant set forth in its committed credit facility. The Company recorded an impairment under the ceiling test during the quarter ended June 30, 2024 in the amount of $200.7 million. Looking ahead, the first day of the month Henry Hub spot price for natural gas in July 2024 was $2.39 per MMBtu. Given the July price, and the expected replacement of higher gas prices with lower gas prices in the historical 12-month average that will be used in the ceiling test calculation for the next two quarters, the Company could experience a ceiling test impairment for the quarter ending September 30, 2024 as well as the quarter ending December 31, 2024.

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

    On April 3, 2024, the Company issued a total of 8,200 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 820 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, 2024. The Company issued an additional 678 unregistered shares in the aggregate on April 15, 2024 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, 2024	139,534	$53.23	125,135	$188,337,817
May 1 - 31, 2024	47,719	$55.51	34,722	$186,408,061
June 1 - 30, 2024	286,138	$55.38	270,662	$171,413,899
Total	473,391	$54.57	430,519	$171,413,899

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(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 42,872 shares purchased other than through a publicly announced share repurchase program, 42,837 were purchased for the Company's 401(k) plans and 35 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 $0.2 million from the beginning of the program to June 30, 2024. 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. In connection with its authorization of the repurchase program, the Board terminated the Company's prior repurchase program, under which 6,971,019 shares had remained available for purchase.

Item 5. Other Information

    During the quarter ended June 30, 2024, 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
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 30, 2024 and 2023.
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, 2024 and 2023, (ii) the Consolidated Statements of Comprehensive Income for the nine months ended June 30, 2024 and 2023, (iii) the Consolidated Balance Sheets at June 30, 2024 and September 30, 2023, (iv) the Consolidated Statements of Cash Flows for the nine months ended June 30, 2024 and 2023 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:  August 1, 2024

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