NATIONAL FUEL GAS CO [NFG] Filings

10-Q 1 nfg-20240331.htm 10-Q nfg-20240331

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2024

☐ 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 April 30, 2024: 91,917,872 shares.

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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 oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas

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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

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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.

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INDEX						Page

Part I. Financial Information

Item 1. Financial Statements (Unaudited)						6

a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Six Months Ended March 31, 2024 and 2023						6
b. Consolidated Statements of Comprehensive Income – Three and Six Months Ended March 31, 2024 and 2023						7
c. Consolidated Balance Sheets – March 31, 2024 and September 30, 2023						8
d. Consolidated Statements of Cash Flows – Six Months Ended March 31, 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						47
Item 4. Controls and Procedures						48

Part II. Other Information

Item 1. Legal Proceedings						48
Item 1 A. Risk Factors						48
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						50
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.

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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 March 31,				Six Months Ended March 31,
(Thousands of U.S. Dollars, Except Per Common Share Amounts)	2024		2023		2024		2023
INCOME
Operating Revenues:
Utility Revenues	$	290,198	$	406,758	$	492,119	$	718,376
Exploration and Production and Other Revenues	264,614		244,552		518,633		521,525
Pipeline and Storage and Gathering Revenues	75,127		65,951		144,549		136,218
	629,939		717,261		1,155,301		1,376,119

Operating Expenses:
Purchased Gas	105,940		243,839		162,491		415,035
Operation and Maintenance:
Utility	59,288		56,453		112,993		106,805
Exploration and Production and Other	32,794		31,782		67,620		58,655
Pipeline and Storage and Gathering	39,340		37,479		74,303		70,740
Property, Franchise and Other Taxes	23,019		25,367		45,434		51,572
Depreciation, Depletion and Amortization	118,935		100,964		234,725		197,564

	379,316		495,884		697,566		900,371

Operating Income	250,623		221,377		457,735		475,748
Other Income (Expense):

Other Income (Deductions)	6,070		2,884		9,801		9,203
Interest Expense on Long-Term Debt	(28,453)		(27,583)		(56,915)		(57,188)
Other Interest Expense	(6,636)		(5,861)		(12,910)		(9,704)
Income Before Income Taxes	221,604		190,817		397,711		418,059
Income Tax Expense	55,332		49,937		98,419		107,489

Net Income Available for Common Stock	166,272		140,880		299,292		310,570

EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	1,973,279		1,713,176		1,885,856		1,587,085
	2,139,551		1,854,056		2,185,148		1,897,655
Share Repurchases under Repurchase Plan	(3,816)		—		(3,816)		—
Dividends on Common Stock	(45,563)		(43,602)		(91,160)		(87,201)


Balance at March 31	$	2,090,172	$	1,810,454	$	2,090,172	$	1,810,454

Earnings Per Common Share:
Basic:
Net Income Available for Common Stock	$	1.81	$	1.53	$	3.25	$	3.39
Diluted:
Net Income Available for Common Stock	$	1.80	$	1.53	$	3.24	$	3.37
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	92,114,415		91,794,765		92,011,772		91,686,110
Used in Diluted Calculation	92,512,447		92,256,348		92,478,604		92,264,717
Dividends Per Common Share:
Dividends Declared	$	0.495	$	0.475	$	0.990	$	0.950

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)


	Three Months Ended March 31,				Six Months Ended March 31,
(Thousands of U.S. Dollars)	2024		2023		2024		2023
Net Income Available for Common Stock	$	166,272	$	140,880	$	299,292	$	310,570
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	71,164		310,544		260,331		608,137
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	(60,148)		18,940		(79,857)		178,281
Other Comprehensive Income (Loss), Before Tax	11,016		329,484		180,474		786,418
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	19,746		85,394		72,232		166,770
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	(16,689)		5,208		(22,158)		48,779
Income Taxes – Net	3,057		90,602		50,074		215,549
Other Comprehensive Income (Loss)	7,959		238,882		130,400		570,869
Comprehensive Income	$	174,231	$	379,762	$	429,692	$	881,439

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	March 31, 2024		September 30, 2023
(Thousands of U.S. Dollars)
ASSETS
Property, Plant and Equipment	$	14,056,169	$	13,635,303
Less - Accumulated Depreciation, Depletion and Amortization	6,548,662		6,335,441
	7,507,507		7,299,862

Current Assets
Cash and Temporary Cash Investments	50,769		55,447

Receivables – Net of Allowance for Uncollectible Accounts of $39,695 and $36,295, Respectively	180,717		160,601
Unbilled Revenue	46,571		16,622
Gas Stored Underground	8,565		32,509
Materials and Supplies - at average cost	47,258		48,989

Other Current Assets	85,123		100,260
	419,003		414,428

Other Assets
Recoverable Future Taxes	77,416		69,045
Unamortized Debt Expense	6,418		7,240
Other Regulatory Assets	69,609		72,138
Deferred Charges	89,004		82,416
Other Investments	78,744		73,976
Goodwill	5,476		5,476
Prepaid Pension and Post-Retirement Benefit Costs	222,834		200,301
Fair Value of Derivative Financial Instruments	196,291		50,487
Other	4,723		4,891
	750,515		565,970

Total Assets	$	8,677,025	$	8,280,260

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	March 31, 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 – 92,031,724 Shares and 91,819,405 Shares, Respectively	$	92,032	$	91,819
Paid in Capital	1,045,929		1,040,761
Earnings Reinvested in the Business	2,090,172		1,885,856
Accumulated Other Comprehensive Income (Loss)	75,340		(55,060)
Total Comprehensive Shareholders’ Equity	3,303,473		2,963,376
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,386,574		2,384,485
Total Capitalization	5,690,047		5,347,861

Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	278,900		287,500

Accounts Payable	93,996		152,193
Amounts Payable to Customers	72,346		59,019
Dividends Payable	45,563		45,451
Interest Payable on Long-Term Debt	22,553		20,399
Customer Advances	—		21,003
Customer Security Deposits	30,600		28,764
Other Accruals and Current Liabilities	183,966		160,974
Fair Value of Derivative Financial Instruments	—		31,009
	727,924		806,312

Other Liabilities
Deferred Income Taxes	1,199,909		1,124,170
Taxes Refundable to Customers	316,455		268,562

Cost of Removal Regulatory Liability	288,819		277,694
Other Regulatory Liabilities	165,023		165,441
Other Post-Retirement Liabilities	2,803		2,915
Asset Retirement Obligations	161,027		165,492
Other Liabilities	125,018		121,813
	2,259,054		2,126,087
Commitments and Contingencies (Note 7)	—		—

Total Capitalization and Liabilities	$	8,677,025	$	8,280,260

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended March 31,
(Thousands of U.S. Dollars)	2024		2023
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	299,292	$	310,570
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:


Depreciation, Depletion and Amortization	234,725		197,564
Deferred Income Taxes	65,187		80,745


Stock-Based Compensation	10,477		11,286

Other	11,874		10,758
Change in:
Receivables and Unbilled Revenue	(50,123)		71,760
Gas Stored Underground and Materials and Supplies	25,675		21,243
Unrecovered Purchased Gas Costs	—		72,491
Other Current Assets	15,201		(15,864)
Accounts Payable	(15,641)		(29,169)
Amounts Payable to Customers	13,327		2,411
Customer Advances	(21,003)		(26,108)
Customer Security Deposits	1,836		10,099
Other Accruals and Current Liabilities	26,927		28,741
Other Assets	(22,165)		(26,901)
Other Liabilities	(9,328)		(8,417)
Net Cash Provided by Operating Activities	586,261		711,209

INVESTING ACTIVITIES
Capital Expenditures	(481,958)		(496,362)


Deposit Paid for Upstream Assets	—		(12,700)

Sale of Fixed Income Mutual Fund Shares in Grantor Trust	—		10,000
Other	(1,189)		14,413
Net Cash Used in Investing Activities	(483,147)		(484,649)

FINANCING ACTIVITIES
Proceeds from Issuance of Short-Term Note Payable to Bank	—		250,000

Net Change in Other Short-Term Notes Payable to Banks and Commercial Paper	(8,600)		100,000


Shares Repurchased Under Repurchase Plan	(4,230)		—
Reduction of Long-Term Debt	—		(549,000)
Dividends Paid on Common Stock	(91,048)		(87,051)
Net Repurchases of Common Stock Under Stock and Benefit Plans	(3,914)		(6,694)
Net Cash Used in Financing Activities	(107,792)		(292,745)
Net Decrease in Cash, Cash Equivalents, and Restricted Cash	(4,678)		(66,185)
Cash, Cash Equivalents, and Restricted Cash at October 1	55,447		137,718
Cash, Cash Equivalents, and Restricted Cash at March 31	$	50,769	$	71,533

Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$	62,921	$	64,495

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 – Summary of Significant Accounting Policies

Principles of Consolidation. The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to oil and gas producing properties accounted for under the full cost method of accounting.

The preparation of the consolidated financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

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 six months ended March 31, 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 8 – 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):


	Six Months Ended March 31, 2024				Six Months Ended March 31, 2023
	Balance at March 31, 2024		Balance at October 1, 2023		Balance at March 31, 2023		Balance at October 1, 2022

Cash and Temporary Cash Investments	$	50,769	$	55,447	$	71,533	$	46,048
Hedging Collateral Deposits	—		—		—		91,670
Cash, Cash Equivalents, and Restricted Cash	$	50,769	$	55,447	$	71,533	$	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.

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Activity in the allowance for uncollectible accounts for the six months ended March 31, 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
Six Months Ended March 31, 2024
Allowance for Uncollectible Accounts	$	36,295	$	9,766	$	468	$	(6,834)	$	39,695
Six Months Ended March 31, 2023
Allowance for Uncollectible Accounts	$	40,228	$	10,973	$	916	$	(3,971)	$	48,146

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 $20.1 million at March 31, 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, oil and gas 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 oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Company's capitalized costs relating to oil and gas producing activities, net of accumulated depreciation, depletion and amortization, were $2.6 billion and $2.4 billion at March 31, 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 $174.0 million and $161.1 million at March 31, 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 prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter. At March 31, 2024, the ceiling exceeded the book value of the oil and gas properties by approximately $3.1 million. The estimated future net cash flows were increased by $347.1 million for hedging under the ceiling test at March 31, 2024.

The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. There were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at March 31, 2024.

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Accumulated Other Comprehensive Income (Loss). The components of Accumulated Other Comprehensive Income (Loss) and changes for the six months ended March 31, 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 March 31, 2024
Balance at January 1, 2024	$	127,064	$	(59,683)	$	67,381
Other Comprehensive Gains and Losses Before Reclassifications	51,418		—		51,418
Amounts Reclassified From Other Comprehensive Income	(43,459)		—		(43,459)

Balance at March 31, 2024	$	135,023	$	(59,683)	$	75,340
Six Months Ended March 31, 2024
Balance at October 1, 2023	$	4,623	$	(59,683)	$	(55,060)
Other Comprehensive Gains and Losses Before Reclassifications	188,099		—		188,099
Amounts Reclassified From Other Comprehensive Income	(57,699)		—		(57,699)


Balance at March 31, 2024	$	135,023	$	(59,683)	$	75,340
Three Months Ended March 31, 2023
Balance at January 1, 2023	$	(240,176)	$	(53,570)	$	(293,746)
Other Comprehensive Gains and Losses Before Reclassifications	225,150		—		225,150
Amounts Reclassified From Other Comprehensive Income	13,732		—		13,732

Balance at March 31, 2023	$	(1,294)	$	(53,570)	$	(54,864)
Six Months Ended March 31, 2023
Balance at October 1, 2022	$	(572,163)	$	(53,570)	$	(625,733)
Other Comprehensive Gains and Losses Before Reclassifications	441,367		—		441,367
Amounts Reclassified From Other Comprehensive Income	129,502		—		129,502

Balance at March 31, 2023	$	(1,294)	$	(53,570)	$	(54,864)

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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 six months ended March 31, 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 March 31,		Six Months Ended March 31,
	2024	2023	2024	2023
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts	$60,184	($18,768)	$79,939	($177,930)	Operating Revenues

Foreign Currency Contracts	(36)	(172)	(82)	(351)	Operating Revenues
	60,148	(18,940)	79,857	(178,281)	Total Before Income Tax
	(16,689)	5,208	(22,158)	48,779	Income Tax Expense
	$43,459	($13,732)	$57,699	($129,502)	Net of Tax

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


	At March 31, 2024		At September 30, 2023

Prepayments	$	13,693	$	18,966
Prepaid Property and Other Taxes	23,308		14,186
Federal Income Taxes Receivable	—		14,602
State Income Taxes Receivable	12,277		16,133

Regulatory Assets	35,845		36,373
	$	85,123	$	100,260

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


	At March 31, 2024		At September 30, 2023

Accrued Capital Expenditures	$	40,361	$	43,323
Regulatory Liabilities	37,192		38,105
Reserve for Gas Replacement	20,139		—
Liability for Royalty and Working Interests	19,198		17,679
Federal Income Taxes Payable	11,747		—



Non-Qualified Benefit Plan Liability	13,052		13,052
Other	42,277		48,815
	$	183,966	$	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. For the quarter and six months ended March 31, 2024, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. Restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 232 securities excluded as being

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antidilutive for the quarter ended March 31, 2024. There were no securities excluded as being antidilutive for the six months ended March 31, 2024. There were 9,909 securities and 4,094 securities excluded as being antidilutive for the quarter and six months ended March 31, 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 6 – Capitalization for further discussion of the Company's share repurchase program.

Stock-Based Compensation. The Company granted 361,729 performance shares during the six months ended March 31, 2024. The weighted average fair value of such performance shares was $44.23 per share for the six months ended March 31, 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 six months ended March 31, 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.

The Company granted 220,778 restricted stock units during the six months ended March 31, 2024. The weighted average fair value of such restricted stock units was $42.44 per share for the six months ended March 31, 2024. Restricted

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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 3,842,625 shares available for future grant at March 31, 2024. These shares include shares available for future options, SARs, restricted stock and performance share grants.

Note 2 – Revenue from Contracts with Customers

The following tables provide a disaggregation of the Company's revenues for the quarter and six months ended March 31, 2024 and 2023, presented by type of service from each reportable segment.


Quarter Ended March 31, 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	$	203,198	$	—	$	—	$	—	$	—	$	—	$	203,198
Production of Crude Oil	524		—		—		—		—		—		524
Natural Gas Processing	303		—		—		—		—		—		303
Natural Gas Gathering Service	—		—		63,993		—		—		(60,076)		3,917
Natural Gas Transportation Service	—		81,273		—		37,841		—		(25,852)		93,262
Natural Gas Storage Service	—		25,343		—		—		—		(11,024)		14,319
Natural Gas Residential Sales	—		—		—		210,392		—		—		210,392
Natural Gas Commercial Sales	—		—		—		30,815		—		—		30,815
Natural Gas Industrial Sales	—		—		—		1,281		—		(2)		1,279

Other	405		1,404		—		(881)		—		(238)		690
Total Revenues from Contracts with Customers	204,430		108,020		63,993		279,448		—		(97,192)		558,699
Alternative Revenue Programs	—		—		—		11,056		—		—		11,056
Derivative Financial Instruments	60,184		—		—		—		—		—		60,184
Total Revenues	$	264,614	$	108,020	$	63,993	$	290,504	$	—	$	(97,192)	$	629,939

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Six Months Ended March 31, 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	$	435,859	$	—	$	—	$	—	$	—	$	—	$	435,859
Production of Crude Oil	1,211		—		—		—		—		—		1,211
Natural Gas Processing	570		—		—		—		—		—		570
Natural Gas Gathering Service	—		—		126,581		—		—		(118,068)		8,513
Natural Gas Transportation Service	—		152,891		—		67,126		—		(46,214)		173,803
Natural Gas Storage Service	—		46,635		—		—		—		(20,084)		26,551
Natural Gas Residential Sales	—		—		—		356,938		—		—		356,938
Natural Gas Commercial Sales	—		—		—		51,096		—		—		51,096
Natural Gas Industrial Sales	—		—		—		2,188		—		(3)		2,185

Other	1,054		2,907		—		(1,448)		—		(489)		2,024
Total Revenues from Contracts with Customers	438,694		202,433		126,581		475,900		—		(184,858)		1,058,750
Alternative Revenue Programs	—		—		—		16,612		—		—		16,612
Derivative Financial Instruments	79,939		—		—		—		—		—		79,939
Total Revenues	$	518,633	$	202,433	$	126,581	$	492,512	$	—	$	(184,858)	$	1,155,301


Quarter Ended March 31, 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	$	259,770	$	—	$	—	$	—	$	—	$	—	$	259,770
Production of Crude Oil	526		—		—		—		—		—		526
Natural Gas Processing	209		—		—		—		—		—		209
Natural Gas Gathering Service	—		—		56,981		—		—		(55,253)		1,728
Natural Gas Transportation Service	—		73,794		—		35,796		—		(21,751)		87,839
Natural Gas Storage Service	—		21,470		—		—		—		(9,219)		12,251
Natural Gas Residential Sales	—		—		—		318,649		—		—		318,649
Natural Gas Commercial Sales	—		—		—		48,966		—		—		48,966
Natural Gas Industrial Sales	—		—		—		2,768		—		(4)		2,764

Other	2,815		(161)		—		(1,864)		—		(264)		526
Total Revenues from Contracts with Customers	263,320		95,103		56,981		404,315		—		(86,491)		733,228
Alternative Revenue Programs	—		—		—		2,801		—		—		2,801
Derivative Financial Instruments	(18,768)		—		—		—		—		—		(18,768)
Total Revenues	$	244,552	$	95,103	$	56,981	$	407,116	$	—	$	(86,491)	$	717,261

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Six Months Ended March 31, 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	$	692,129	$	—	$	—	$	—	$	—	$	—	$	692,129
Production of Crude Oil	1,154		—		—		—		—		—		1,154
Natural Gas Processing	583		—		—		—		—		—		583
Natural Gas Gathering Service	—		—		113,394		—		—		(109,020)		4,374
Natural Gas Transportation Service	—		149,996		—		64,174		—		(42,568)		171,602
Natural Gas Storage Service	—		42,756		—		—		—		(18,215)		24,541
Natural Gas Residential Sales	—		—		—		562,955		—		—		562,955
Natural Gas Commercial Sales	—		—		—		83,461		—		—		83,461
Natural Gas Industrial Sales	—		—		—		4,407		—		(4)		4,403

Other	5,589		7		—		(2,124)		—		(548)		2,924
Total Revenues from Contracts with Customers	699,455		192,759		113,394		712,873		—		(170,355)		1,548,126
Alternative Revenue Programs	—		—		—		5,923		—		—		5,923
Derivative Financial Instruments	(177,930)		—		—		—		—		—		(177,930)
Total Revenues	$	521,525	$	192,759	$	113,394	$	718,796	$	—	$	(170,355)	$	1,376,119

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: $115.9 million for the remainder of fiscal 2024; $220.7 million for fiscal 2025; $172.5 million for fiscal 2026; $135.5 million for fiscal 2027; $116.7 million for fiscal 2028; and $612.0 million thereafter.

Note 3 – Fair Value Measurements

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

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The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of March 31, 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 March 31, 2024
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)		Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	27,965	$	—	$	—	$	—	$	27,965

Derivative Financial Instruments:

Over the Counter Swaps – Gas	—		154,896		—		(17,371)		137,525
Over the Counter No Cost Collars – Gas	—		55,909		—		—		55,909
Contingent Consideration for Asset Sale	—		3,615		—		—		3,615
Foreign Currency Contracts	—		222		—		(980)		(758)
Other Investments:
Balanced Equity Mutual Fund	18,291		—		—		—		18,291
Fixed Income Mutual Fund	16,591		—		—		—		16,591


Total	$	62,847	$	214,642	$	—	$	(18,351)	$	259,138

Liabilities:
Derivative Financial Instruments:

Over the Counter Swaps – Gas	$	—	$	17,371	$	—	$	(17,371)	$	—

Foreign Currency Contracts	—		980		—		(980)		—
Total	$	—	$	18,351	$	—	$	(18,351)	$	—

Total Net Assets/(Liabilities)	$	62,847	$	196,291	$	—	$	—	$	259,138


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 March 31, 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 Exploration and Production segment. The fair value of the Level 2 price swap agreements and no cost collars is based on an

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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 March 31, 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 March 31, 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 March 31, 2024 and March 31, 2023, there were no assets or liabilities measured at fair value and classified as Level 3.

Note 4 – Financial Instruments

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


	March 31, 2024				September 30, 2023
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,386,574	$	2,291,399	$	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 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 March 31, 2024		At September 30, 2023

Life Insurance Contracts	$	43,862	$	42,242
Equity Mutual Fund	18,291		15,837
Fixed Income Mutual Fund	16,591		15,897

	$	78,744	$	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 $3.6 million and $7.3 million at March 31, 2024 and September 30, 2023, respectively. A $0.5 million mark-to-market adjustment to increase the fair value of the contingent consideration was recorded during the quarter ended March 31, 2024. A $3.7 million mark-to-market adjustment to reduce the fair value of the contingent consideration was recorded during the six months ended March 31, 2024.

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at March 31, 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 March 31, 2024, the Company had 351.2 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.

As of March 31, 2024, the Company was hedging a total of $50.4 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

As of March 31, 2024, the Company had $135.0 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance. Of this amount, it is expected that $100.9 million of unrealized gains after taxes will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings.

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The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended March 31, 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 March 31,				Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Three Months Ended March 31,
	2024		2023			2024		2023
Commodity Contracts	$	71,876	$	310,623	Operating Revenue	$	60,184	$	(18,768)

Foreign Currency Contracts	(712)		(79)		Operating Revenue	(36)		(172)
Total	$	71,164	$	310,544		$	60,148	$	(18,940)


The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Six Months Ended March 31, 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 Six Months Ended March 31,				Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Six Months Ended March 31,
	2024		2023			2024		2023
Commodity Contracts	$	259,865	$	607,743	Operating Revenue	$	79,939	$	(177,930)

Foreign Currency Contracts	466		394		Operating Revenue	(82)		(351)
Total	$	260,331	$	608,137		$	79,857	$	(178,281)

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 all nineteen are in a net gain position. On average, the Company had $10.1 million of credit exposure per counterparty in a gain position at March 31, 2024. The maximum credit exposure per counterparty in a gain position at March 31, 2024 was $33.2 million. As of March 31, 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 March 31, 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

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credit rating declined, then hedging collateral deposits or an increase to such deposits could be required. At March 31, 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 3 – Fair Value Measurements), and no hedging collateral deposits were required to be posted by the Company at March 31, 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 5 – Income Taxes

The effective tax rates for the quarters ended March 31, 2024 and March 31, 2023 were 25.0% and 26.2%, respectively. The effective tax rates for the six months ended March 31, 2024 and March 31, 2023 were 24.7% and 25.7%, respectively. The reduction in effective income tax rates was primarily driven by a methodology change for repairs and maintenance tax deductions as a result of updated IRS guidance published in 2023.

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Note 6 – Capitalization

Summary of Changes in Common Stock Equity


	Common Stock			Paid In Capital		Earnings Reinvested in the Business		Accumulated Other Comprehensive Income (Loss)
	Shares	Amount
	(Thousands, except per share amounts)
Balance at January 1, 2024	92,116	$	92,116	$	1,041,226	$	1,973,279	$	67,381
Net Income Available for Common Stock						166,272
Dividends Declared on Common Stock ($0.495 Per Share)						(45,563)

Other Comprehensive Income, Net of Tax								7,959
Share-Based Payment Expense (1)				5,222

Common Stock Issued Under Stock and Benefit Plans	12	12		569
Share Repurchases Under Repurchase Plan	(96)	(96)		(1,088)		(3,816)
Balance at March 31, 2024	92,032	$	92,032	$	1,045,929	$	2,090,172	$	75,340

Balance at October 1, 2023	91,819	$	91,819	$	1,040,761	$	1,885,856	$	(55,060)
Net Income Available for Common Stock						299,292
Dividends Declared on Common Stock ($0.99 Per Share)						(91,160)

Other Comprehensive Income, Net of Tax								130,400
Share-Based Payment Expense (1)				9,356

Common Stock Issued (Repurchased) Under Stock and Benefit Plans	309	309		(3,100)

Share Repurchases Under Repurchase Plan	(96)	(96)		(1,088)		(3,816)
Balance at March 31, 2024	92,032	$	92,032	$	1,045,929	$	2,090,172	$	75,340

Balance at January 1, 2023	91,787	$	91,787	$	1,025,639	$	1,713,176	$	(293,746)
Net Income Available for Common Stock						140,880
Dividends Declared on Common Stock ($0.475 Per Share)						(43,602)

Other Comprehensive Income, Net of Tax								238,882
Share-Based Payment Expense (1)				5,200

Common Stock Issued Under Stock and Benefit Plans	8	8		502
Balance at March 31, 2023	91,795	$	91,795	$	1,031,341	$	1,810,454	$	(54,864)

Balance at October 1, 2022	91,478	$	91,478	$	1,027,066	$	1,587,085	$	(625,733)
Net Income Available for Common Stock						310,570
Dividends Declared on Common Stock ($0.95 Per Share)						(87,201)

Other Comprehensive Income, Net of Tax								570,869
Share-Based Payment Expense (1)				10,318

Common Stock Issued (Repurchased) Under Stock and Benefit Plans	317	317		(6,043)
Balance at March 31, 2023	91,795	$	91,795	$	1,031,341	$	1,810,454	$	(54,864)

(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 six months ended March 31, 2024, the Company issued 112,632 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 18,432 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 six months ended March 31, 2024. In addition, the Company issued 3,559 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 six months ended March 31, 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 six months ended March 31, 2024, 77,426 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 quarter ended March 31, 2024, the Company executed transactions to repurchase 96,133 shares for $5.0 million. Share repurchases that settled during the quarter ended March 31, 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. The Credit Agreement provides a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027. Effective February 7, 2024, certain lenders under the Credit Agreement consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. As a result, the Company has aggregate commitments available under the Credit Agreement of $1.0 billion before February 26, 2027, and $940.0 million in aggregate commitments available on and after February 26, 2027 to February 25, 2028.

Current Portion of Long-Term Debt. None of the Company's long-term debt as of March 31, 2024 and 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 term loan with a maturity date of February 14, 2026. Pursuant to the Term Loan Agreement, there was a delayed draw mechanism, and the Company elected to draw a total of $300.0 million under the facility between April 8, 2024 and April 10, 2024. The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper.

Note 7 – Commitments and Contingencies

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

At March 31, 2024, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $2.7 million. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at March 31, 2024. The Company has recovered its environmental clean-up costs through rate recovery and is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company.

Northern Access Project. On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access project described herein. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order and FERC's decisions were appealed. The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. 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

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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 March 31, 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 8 – Business Segment Information

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

The data presented in the tables below reflect financial information for the segments and reconcile to consolidated amounts. As stated in the 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 March 31, 2024 and September 30, 2023 is shown in the tables below.


Quarter Ended March 31, 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	$264,614	$71,210	$3,917	$290,198	$629,939	$—	$—	$629,939
Intersegment Revenues	$—	$36,810	$60,076	$306	$97,192	$—	$(97,192)	$—
Segment Profit: Net Income (Loss)	$62,065	$30,737	$28,706	$44,739	$166,247	$(96)	$121	$166,272


Six Months Ended March 31, 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	$518,633	$136,036	$8,513	$492,119	$1,155,301	$—	$—	$1,155,301
Intersegment Revenues	$—	$66,397	$118,068	$393	$184,858	$—	$(184,858)	$—
Segment Profit: Net Income (Loss)	$114,548	$54,792	$57,531	$71,289	$298,160	$(217)	$1,349	$299,292


(Thousands)	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Segment Assets:
At March 31, 2024	$3,049,670	$2,472,011	$971,741	$2,359,961	$8,853,383	$4,823	$(181,181)	$8,677,025
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 March 31, 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	$244,552	$64,223	$1,728	$406,758	$717,261	$—	$—	$717,261
Intersegment Revenues	$—	$30,880	$55,253	$358	$86,491	$—	$(86,491)	$—
Segment Profit: Net Income (Loss)	$60,982	$23,858	$24,334	$31,720	$140,894	$(69)	$55	$140,880


Six Months Ended March 31, 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	$521,525	$131,844	$4,374	$718,376	$1,376,119	$—	$—	$1,376,119
Intersegment Revenues	$—	$60,915	$109,020	$420	$170,355	$—	$(170,355)	$—
Segment Profit: Net Income (Loss)	$152,174	$53,335	$49,072	$55,537	$310,118	$(350)	$802	$310,570

Note 9 – Retirement Plan and Other Post-Retirement Benefits

Components of Net Periodic Benefit Cost (in thousands):


	Retirement Plan				Other Post-Retirement Benefits
Three Months Ended March 31,	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		1,769		3,493

Net Periodic Benefit Cost (Income)	$	(1,334)	$	(1,155)	$	(1,566)	$	(1,147)



	Retirement Plan				Other Post-Retirement Benefits
Six Months Ended March 31,	2024		2023		2024		2023

Service Cost	$	2,098	$	2,594	$	217	$	293
Interest Cost	21,779		21,258		7,780		7,824
Expected Return on Plan Assets	(34,172)		(33,297)		(13,321)		(12,806)
Amortization of Prior Service Cost (Credit)	181		218		(214)		(214)

Amortization of (Gains) Losses	(669)		(3,840)		(1,133)		(4,378)
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	8,116		10,756		4,008		7,314

Net Periodic Benefit Cost (Income)	$	(2,667)	$	(2,311)	$	(2,663)	$	(1,967)

(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 six months ended March 31, 2024. In the remainder of fiscal 2024, the Company expects its contributions to the Retirement Plan to be in the range of zero to $5.0 million. The Company did not make any contributions to its VEBA trusts for its other post-retirement benefits during the six months ended March 31, 2024, and does not anticipate making any such contributions during the remainder of fiscal 2024.

Note 10 – Regulatory Matters

New York Jurisdiction

Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on 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.

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 net plant as of July 31, 2024 and its quarterly rate of return does not exceed the authorized PaPUC rate of return. The DSIC petition is currently pending before the PaPUC.

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 Interim 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 and remains pending. The “black box” settlement provides for new rates and resolves all issues in the proceeding. The Interim 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

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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 $90 million. The Tioga Pathway Project is discussed in more detail in the Capital Resources and Liquidity section that follows.

From a rate perspective, Distribution Corporation, in its Pennsylvania jurisdiction, reached a settlement with the parties to its rate case proceeding. On June 15, 2023, the PaPUC issued an order adopting the settlement in full. The settlement authorized an increase in Distribution Corporation's annual base rate operating revenues of $23 million that became effective August 1, 2023. Distribution Corporation also filed a rate case proceeding with the NYPSC in its New York jurisdiction on October 31, 2023 seeking an increase of 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. Interim settlement rates became effective on February 1, 2024 under a settlement in principle that was filed with FERC on March 27, 2024, and are estimated to increase Supply Corporation's revenues by approximately $56 million on an annual basis. The settlement remains subject to final FERC approval. 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 oil and natural gas properties in the Exploration and Production segment and that book value is subject to a quarterly ceiling test. The Company did not record an impairment under the ceiling test during the quarter ended March 31, 2024. Looking ahead, the first day of the month Henry Hub spot price for natural gas in April 2024 was $1.56 per MMBtu. Given the April 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 at June 30, 2024 and September 30, 2024, the Company expects to experience a ceiling test impairment in each of these quarters.

From a financing perspective, effective February 7, 2024, certain lenders under the Credit Agreement consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. As a result, the Company has aggregate commitments available under the Credit Agreement of $1.0 billion before February 26, 2027, and $940 million in aggregate commitments available on and after February 26, 2027 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

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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. Repurchases under this program amounted to 96,133 shares at a total cost of $5.0 million during the quarter ended March 31, 2024. 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.

Oil and Gas 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 oil and natural gas properties, with natural gas properties in the Appalachian Region being the primary component after the fiscal 2022 sale of the Company's California oil and natural gas 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 oil and gas reserves based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s oil and gas 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 oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling. At March 31, 2024, the ceiling exceeded the book value of the oil and gas properties by approximately $3.1 million. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended March 31, 2024, based on the quoted Henry Hub spot price for natural gas, was $2.45 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 March 31, 2024. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices in the twelve-month period used at March 31, 2024 in the ceiling test calculation, the book value of the Company's oil and gas properties would have exceeded the ceiling by approximately $329.9 million (after-tax), which would have resulted in an impairment charge. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates. Looking ahead, the first day of the month Henry Hub spot price for natural gas in April 2024 was $1.56 per MMBtu. Given the April 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 at June 30, 2024 and September 30, 2024, the Company expects to experience a ceiling test impairment in each of these quarters.

It is difficult to predict what additional factors beyond price could contribute to future non-cash impairments under the SEC's full cost ceiling test. Fluctuations in or subtractions from proved reserves and increases in development costs for undeveloped reserves can have an impact on the amount of the ceiling at any point in time. For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2023 Form 10-K.

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RESULTS OF OPERATIONS

Earnings

The Company's earnings were $166.3 million for the quarter ended March 31, 2024 compared to earnings of $140.9 million for the quarter ended March 31, 2023. The increase in earnings of $25.4 million is primarily the result of higher earnings in all reportable segments as well as in the Corporate category, slightly offset by a loss in the All Other category.

The Company's earnings were $299.3 million for the six months ended March 31, 2024 compared to earnings of $310.6 million for the six months ended March 31, 2023. The decrease in earnings of $11.3 million is primarily the result of lower earnings in the Exploration and Production segment. Higher earnings in the Utility segment, Gathering segment and Pipeline and Storage segment, as well as higher earnings in the Corporate category and a lower loss in the All Other category partially offset this decrease. Note that all amounts used in earnings discussions are after-tax amounts, unless otherwise noted.

Earnings (Loss) by Segment


	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2024		2023		Increase (Decrease)		2024		2023		Increase (Decrease)
Exploration and Production	$	62,065	$	60,982	$	1,083	$	114,548	$	152,174	$	(37,626)
Pipeline and Storage	30,737		23,858		6,879		54,792		53,335		1,457
Gathering	28,706		24,334		4,372		57,531		49,072		8,459
Utility	44,739		31,720		13,019		71,289		55,537		15,752
Total Reportable Segments	166,247		140,894		25,353		298,160		310,118		(11,958)
All Other	(96)		(69)		(27)		(217)		(350)		133
Corporate	121		55		66		1,349		802		547
Total Consolidated	$	166,272	$	140,880	$	25,392	$	299,292	$	310,570	$	(11,278)

Exploration and Production

Exploration and Production Operating Revenues


	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2024		2023		Increase (Decrease)		2024		2023		Increase (Decrease)
Gas Produced in Appalachia (after Hedging)	$	263,382	$	241,002	$	22,380	$	515,798	$	514,199	$	1,599


Other	1,232		3,550		(2,318)		2,835		7,326		(4,491)
	$	264,614	$	244,552	$	20,062	$	518,633	$	521,525	$	(2,892)

Production Volumes


	Three Months Ended March 31,			Six Months Ended March 31,
	2024	2023	Increase (Decrease)	2024	2023	Increase (Decrease)

Gas Production per MMcf	102,883	93,241	9,642	203,640	183,815	19,825

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Average Prices


	Three Months Ended March 31,						Six Months Ended March 31,
	2024		2023		Increase (Decrease)		2024		2023		Increase (Decrease)
Average Gas Price/Mcf


Weighted Average	$	1.98	$	2.79	$	(0.81)	$	2.14	$	3.77	$	(1.63)
Weighted Average After Hedging	$	2.56	$	2.58	$	(0.02)	$	2.53	$	2.80	$	(0.27)

2024 Compared with 2023

Operating revenues for the Exploration and Production segment increased $20.1 million for the quarter ended March 31, 2024 as compared with the quarter ended March 31, 2023. Gas production revenue after hedging increased $22.4 million due to the impact of a 9.6 Bcf increase in natural gas production, offset by a $0.02 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. In addition, other revenue decreased $2.3 million due to the non-recurrence of temporary capacity release revenue for a portion of this segment's transportation capacity during the quarter ended March 31, 2023.

Operating revenues for the Exploration and Production segment decreased $2.9 million for the six months ended March 31, 2024 as compared with the six months ended March 31, 2023. This decrease resulted primarily from the non-recurrence of temporary capacity release revenue for a portion of this segment’s transportation capacity during the six months ended March 31, 2023, which contributed to a $4.5 million decrease in other revenue period over period. Gas production revenue after hedging increased $1.6 million due to the impact of a 19.8 Bcf increase in natural gas production, offset by a $0.27 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 six months ended March 31, 2024 as compared with the six months ended March 31, 2023.

The Exploration and Production segment's earnings for the quarter ended March 31, 2024 were $62.1 million, an increase of $1.1 million when compared with earnings of $61.0 million for the quarter ended March 31, 2023. The increase in earnings was attributable to higher natural gas production ($19.7 million) and lower other taxes ($1.3 million). There was also an unrealized gain recognized in the three-month period ended March 31, 2024 ($0.4 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 March 31, 2023 ($1.8 million) on such contingent consideration. These increases were partially offset by lower natural gas prices after hedging ($2.0 million) and lower other revenue ($1.8 million) as previously discussed. Higher depletion expense ($11.7 million), higher lease operating and transportation expenses ($3.1 million) and an increase in interest expense ($2.3 million) also reduced earnings. 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 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 and higher workover expenses, offset by lower saltwater disposal expenses. 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 Exploration and Production segment's earnings for the six months ended March 31, 2024 were $114.5 million, a decrease of $37.7 million when compared with earnings of $152.2 million for the six months ended March 31, 2023. The decrease in earnings was attributable to lower natural gas prices after hedging ($42.5 million) and lower other revenue ($3.6 million) as previously discussed. Higher depletion expense ($24.7 million), higher lease operating and transportation expenses ($7.4 million), higher other operating expenses ($4.3 million) and an increase in interest expense ($3.9 million) also reduced earnings. There was also a higher unrealized loss recognized in the six-month period ended March 31, 2024 ($2.7 million) on contingent consideration received as part of the California asset sale as compared to an unrealized loss that was recognized in the six-month period ended March 31, 2023 ($1.7 million) on such contingent consideration. These decreases were partially offset by higher natural gas production ($43.8 million), lower other taxes ($3.9 million) and a reduction in income tax expense ($1.5 million). The increase in depletion expense was primarily due to the net increase in production combined with a $0.09 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

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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 Pennsylvania's tax rate decrease, partially offset by a lower benefit from permanent differences related to stock compensation.

Pipeline and Storage

Pipeline and Storage Operating Revenues


	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2024		2023		Increase (Decrease)		2024		2023		Increase (Decrease)
Firm Transportation	$	80,979	$	73,487	$	7,492	$	152,475	$	148,944	$	3,531
Interruptible Transportation	294		307		(13)		416		1,052		(636)
	81,273		73,794		7,479		152,891		149,996		2,895
Firm Storage Service	25,343		21,470		3,873		46,634		42,754		3,880
Interruptible Storage Service	—		—		—		1		2		(1)
Other	1,404		(161)		1,565		2,907		7		2,900
	$	108,020	$	95,103	$	12,917	$	202,433	$	192,759	$	9,674

Pipeline and Storage Throughput


	Three Months Ended March 31,			Six Months Ended March 31,
(MMcf)	2024	2023	Increase (Decrease)	2024	2023	Increase (Decrease)
Firm Transportation	222,258	231,081	(8,823)	422,359	455,705	(33,346)
Interruptible Transportation	1,271	619	652	1,389	1,927	(538)
	223,529	231,700	(8,171)	423,748	457,632	(33,884)

2024 Compared with 2023

Operating revenues for the Pipeline and Storage segment increased $12.9 million for the quarter ended March 31, 2024 as compared with the quarter ended March 31, 2023. The increase in operating revenues was primarily due to an increase in transportation revenues of $7.5 million, an increase in storage revenues of $3.9 million and an increase in other revenues of $1.6 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 approved interim rates in connection with Supply Corporation's rate case settlement, which is pending final FERC approval. In addition, the increase in transportation and storage revenues was the result of a final true-up adjustment to a surcharge mechanism for pipeline safety and greenhouse gas costs that ended effective February 1, 2024. The increase in other revenues primarily reflects an adjustment to match electric surcharge revenues to electric power costs recorded in operation and maintenance expense.

Operating revenues for the Pipeline and Storage segment increased $9.7 million for the six months ended March 31, 2024 as compared with the six months ended March 31, 2023. The increase in operating revenues was primarily due to an increase in transportation revenues of $2.9 million, an increase in storage revenues of $3.9 million, and an increase in other revenues of $2.9 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 a surcharge for pipeline safety and greenhouse gas costs. 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.

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Transportation volume for the quarter ended March 31, 2024 decreased by 8.2 Bcf from the prior year's quarter ended March 31, 2023. For the six months ended March 31, 2024, transportation volume decreased by 33.9 Bcf from the prior year's six-month period ended March 31, 2023. The decrease in transportation volume for both the quarter and six months ended March 31, 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 March 31, 2024 were $30.7 million, an increase of $6.8 million when compared with earnings of $23.9 million for the quarter ended March 31, 2023. The increase in earnings was primarily due to the earnings impact of higher operating revenues ($10.2 million), as discussed above. This increase was partially offset by increases in operating expenses ($1.4 million), depreciation expense ($1.4 million) and interest expense ($1.0 million). The increase in operating expenses was primarily due to an increase in 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 intercompany short-term borrowings.

The Pipeline and Storage segment’s earnings for the six months ended March 31, 2024 were $54.8 million, an increase of $1.5 million when compared with earnings of $53.3 million for the six months ended March 31, 2023. The increase in earnings was primarily due to the earnings impact of higher operating revenues ($7.6 million), as discussed above. This increase was partially offset by increases in operating expenses ($2.9 million), depreciation expense ($2.0 million) and interest expense ($1.6 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 intercompany short-term borrowings.

Gathering

Gathering Operating Revenues


	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2024		2023		Increase (Decrease)		2024		2023		Increase (Decrease)
Gathering Revenues	$	63,993	$	56,981	$	7,012	$	126,581	$	113,394	$	13,187

Gathering Volume


	Three Months Ended March 31,			Six Months Ended March 31,
	2024	2023	Increase (Decrease)	2024	2023	Increase (Decrease)
Gathered Volume - (MMcf)	125,565	109,344	16,221	249,388	217,371	32,017

2024 Compared with 2023

Operating revenues for the Gathering segment increased $7.0 million for the quarter ended March 31, 2024 as compared with the quarter ended March 31, 2023, which was driven primarily by a 16.2 Bcf increase in gathered volume. Gathered volume on the Trout Run and Tioga gathering systems increased 17.5 Bcf and 5.3 Bcf, respectively, partially offset by a decrease of 6.6 Bcf on the Clermont gathering system. The net increase in gathered volume can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.

Operating revenues for the Gathering segment increased $13.2 million for the six months ended March 31, 2024 as compared with the six months ended March 31, 2023, which was driven primarily by a 32.0 Bcf increase in gathered volume. Contributors to the increase included the Trout Run and Tioga gathering systems, which recorded increases of 29.2 Bcf and 11.6 Bcf, respectively, partially offset by the Clermont gathering system, which recorded a decrease of 8.8 Bcf. The net increase

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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 March 31, 2024 were $28.7 million, an increase of $4.4 million when compared with earnings of $24.3 million for the quarter ended March 31, 2023. The increase in earnings was primarily due to higher gathering revenues ($5.5 million) driven by the increase in gathered volume, as discussed above. This increase was partially offset by higher depreciation expense ($0.5 million) and higher income tax expense ($0.5 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.

The Gathering segment’s earnings for the six months ended March 31, 2024 were $57.5 million, an increase of $8.4 million when compared with earnings of $49.1 million for the six months ended March 31, 2023. The increase in earnings was mainly due to higher gathering revenues ($10.4 million) driven by the increase in gathered volume, as discussed above. This increase was partially offset by higher depreciation expense ($1.1 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.

Utility

Utility Operating Revenues


	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2024		2023		Increase (Decrease)		2024		2023		Increase (Decrease)
Retail Sales Revenues:
Residential	$	217,924	$	320,043	$	(102,119)	$	367,580	$	565,484	$	(197,904)
Commercial	30,393		47,569		(17,176)		51,603		82,913		(31,310)
Industrial	1,307		2,787		(1,480)		2,218		4,430		(2,212)
	249,624		370,399		(120,775)		421,401		652,827		(231,426)
Transportation	41,761		38,581		3,180		72,559		68,093		4,466

Other	(881)		(1,864)		983		(1,448)		(2,124)		676
	$	290,504	$	407,116	$	(116,612)	$	492,512	$	718,796	$	(226,284)

Utility Throughput


	Three Months Ended March 31,			Six Months Ended March 31,
(MMcf)	2024	2023	Increase (Decrease)	2024	2023	Increase (Decrease)
Retail Sales:
Residential	27,063	27,884	(821)	45,045	48,037	(2,992)
Commercial	4,293	4,384	(91)	7,093	7,378	(285)
Industrial	190	267	(77)	327	418	(91)
	31,546	32,535	(989)	52,465	55,833	(3,368)
Transportation	22,637	22,788	(151)	40,166	41,098	(932)

	54,183	55,323	(1,140)	92,631	96,931	(4,300)

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Degree Days


Three Months Ended March 31,				Percent Colder (Warmer) Than
	Normal	2024	2023	Normal(1)		Prior Year(1)
Buffalo, NY	3,326	2,705	2,820	(18.7)	%	(4.1)	%
Erie, PA(2)	3,057	2,576	2,645	(15.7)	%	(2.6)	%
Six Months Ended March 31,
Buffalo, NY	5,579	4,563	4,868	(18.2)	%	(6.3)	%
Erie, PA	4,951	4,240	4,632	(14.4)	%	(8.5)	%

(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 $116.6 million for the quarter ended March 31, 2024 as compared with the quarter ended March 31, 2023. This decrease resulted from a $120.8 million decrease in retail gas sales revenue, which was partially offset by a $3.2 million increase in transportation revenue and a $1.0 million increase in other revenue. The decrease in retail gas sales revenue reflects a decrease in the cost of gas sold (per Mcf) combined with a 1.0 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 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 increase in transportation revenue was also 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. The increase in other revenue was mainly the result of a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($2.2 million), partially offset by decreases in late payment charges billed to customers ($0.7 million) and capacity release revenues ($0.6 million).

Operating revenues for the Utility segment decreased $226.3 million for the six months ended March 31, 2024 as compared with the six months ended March 31, 2023. The decrease resulted from a $231.4 million decrease in retail gas sales revenue, primarily due to a decrease in the cost of gas sold (per Mcf) as well as a 3.4 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 retail gas sales revenue was partially offset by a $4.5 million increase in transportation revenue and a $0.7 million increase in other revenue. The increase in transportation revenue was also predominantly due to the impact of the new base rates in Pennsylvania in addition to an increase in the system modernization and system improvement tracker allocation to customers in New York, despite a 1.0 Bcf decrease in throughput due to warmer weather. The increase in other revenue was largely due to a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($2.6 million), partially offset by decreases in late payment charges billed to customers ($1.1 million) and capacity release revenues ($1.0 million).

The Utility segment’s earnings for the quarter ended March 31, 2024 were $44.7 million, an increase of $13.0 million compared to earnings of $31.7 million for the quarter ended March 31, 2023. The increase was primarily due to the impact of new base rates in the Utility segment's Pennsylvania jurisdiction ($8.5 million), lower income tax expense ($2.4 million), and the impact of system modernization and system improvement trackers in New York ($1.8 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. The Utility segment's earnings also increased $4.5 million due to the impact of higher usage and weather, with current quarter earnings benefiting from the implementation of a weather normalization adjustment (WNA) in the Utility segment's Pennsylvania jurisdiction. These increases were partially offset by higher operating expenses ($2.3 million), primarily due to higher personnel costs, and a decrease in earnings from regulatory adjustments ($1.6 million).

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.

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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 March 31, 2024, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $5.0 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $3.6 million, as the weather was warmer than normal in both jurisdictions. For the quarter ended March 31, 2023, the WNA preserved earnings in the Utility segment’s New York jurisdiction of approximately $3.3 million, as the weather was warmer than normal.

The Utility segment’s earnings for the six months ended March 31, 2024 were $71.3 million, an increase of $15.8 million when compared with earnings of $55.5 million for the six months ended March 31, 2023. The increase was mainly due to the impact of new base rates in the Utility segment's Pennsylvania jurisdiction ($15.4 million), lower income tax expense ($4.2 million), and the impact of system modernization and system improvement trackers in New York ($2.7 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 Utility segment's earnings also increased $1.7 million due to the impact of higher usage and weather, with current year earnings benefiting from the implementation of a WNA in the Utility segment's Pennsylvania rate jurisdiction. These factors were partially offset by higher operating expenses ($5.0 million), primarily due to higher personnel costs, a decrease in earnings from regulatory adjustments ($2.0 million), and an increase in depreciation and amortization expense ($1.5 million), which was primarily the result of the higher average plant balances and increased depreciation for negative net salvage in Pennsylvania.

For the six months ended March 31, 2024, the WNA preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $6.4 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $4.1 million, as the weather was warmer than normal in both jurisdictions. For the six months ended March 31, 2023, the WAC preserved earnings in the Utility segment's New York rate jurisdiction of approximately $4.2 million, as the weather was warmer than normal.

Corporate and All Other

2024 Compared with 2023

Corporate and All Other operations had earnings of less than $0.1 million for the quarter ended March 31, 2024, essentially flat when compared with a net loss of less than $0.1 million for the quarter ended March 31, 2023. For the six months ended March 31, 2024, Corporate and All Other operations had earnings of $1.1 million, an increase of $0.6 million when compared with earnings of $0.5 million for the six months ended March 31, 2023. The increase in earnings for the six-month period was primarily attributable to changes in unrealized gains on investments in equity securities. During the six months ended March 31, 2024, the Company recorded unrealized gains of $1.4 million. During the six months ended March 31, 2023, the Company recorded unrealized gains of $1.0 million.

Other Income (Deductions)

Net other income on the Consolidated Statements of Income was $6.1 million for the quarter ended March 31, 2024, compared to net other income of $2.9 million for the quarter ended March 31, 2023, for an increase of $3.2 million. This increase can be attributed primarily to a $0.5 million gain on the revaluation of the contingent consideration received from the sale of Seneca's California assets in June 2022 (compared to a loss of $2.5 million for the quarter ended March 31, 2023), as well as an increase of $0.9 million in allowance for funds used during construction and an increase in the cash surrender value of life insurance policies of $0.8 million. These increases were partially offset by a decrease in interest income of $0.9 million that was mainly due to lower interest income from investments as well as changes in unrealized gains and losses on investments in equity securities that decreased other income by $0.5 million.

Net other income on the Consolidated Statement of Income was $9.8 million for the six months ended March 31, 2024, compared to net other income of $9.2 million for the six months ended March 31, 2023, for an increase of $0.6 million. This increase was primarily due to $2.0 million of business interruption insurance proceeds that Seneca received during the current fiscal year related to a pipeline outage impacting Seneca's ability to market its gas, along with an increase in the cash surrender value of life insurance policies of $1.0 million. There was also a $0.6 million increase in non-service pension and post-retirement benefit income year over year and an increase of $0.6 million in allowance for funds used during construction. These increases were partially offset by a decrease in interest income of $2.4 million that was mainly due to lower interest income from investments and a decrease in interest from hedging collateral for derivative financial instruments as well as a $3.7

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million loss on the revaluation of the contingent consideration received from the sale of Seneca's California assets in June 2022 (compared to a loss of $2.3 million for the six months ended March 31, 2023).

Interest Expense on Long-Term Debt

Interest expense on long-term debt on the Consolidated Statement of Income increased $0.9 million for the quarter ended March 31, 2024 as compared to the quarter ended March 31, 2023. This was primarily due to a higher weighted average interest rate on long-term debt. For the six months ended March 31, 2024, interest expense on long-term debt decreased $0.3 million as compared with the six months ended March 31, 2023. This decrease is primarily due to an increase in capitalized interest (mostly in Midstream Company) as a result of higher capital expenditures. This was partially offset by a higher weighted average interest rate on long-term debt. In November 2022 and March 2023, the Company redeemed 3.75% notes, which in the aggregate amounted to $500.0 million, and in March 2023, the Company also redeemed $49.0 million of 7.395% notes. These redemptions were partially offset by the issuance of $300.0 million of 5.50% notes in May 2023.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary source of cash during the six-month period ended March 31, 2024 consisted of cash provided by operating activities. The Company’s primary sources of cash during the six-month period ended March 31, 2023 consisted of cash provided by operating activities, proceeds from short-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 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 cash on hand as well as short-term and long-term borrowings. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.

Operating Cash Flow

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

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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 $586.3 million for the six months ended March 31, 2024, a decrease of $124.9 million compared with $711.2 million provided by operating activities for the six months ended March 31, 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 lower realized natural gas prices for this segment's natural gas production.

Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $435.7 million during the six months ended March 31, 2024 and $440.6 million during the six months ended March 31, 2023. The table below presents these expenditures:


Total Expenditures for Long-Lived Assets
Six Months Ended March 31,	2024			2023			Increase (Decrease)
(Millions)
Exploration and Production:
Capital Expenditures	$	285.1	(1)	$	323.6	(2)	$	(38.5)
Pipeline and Storage:
Capital Expenditures	42.6		(1)	33.3		(2)	9.3
Gathering:
Capital Expenditures	39.5		(1)	34.1		(2)	5.4
Utility:
Capital Expenditures	68.3		(1)	49.2		(2)	19.1
All Other:
Capital Expenditures	0.2			0.4			(0.2)

	$	435.7		$	440.6		$	(4.9)

(1)At March 31, 2024, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $44.4 million, $5.0 million, $5.5 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.

(2)At March 31, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $56.1 million, $2.2 million, $2.0 million and $4.2 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 six months ended March 31, 2024 were primarily well drilling and completion expenditures in the Appalachian region, and included $52.0 million in the Marcellus Shale area and $224.9 million in the Utica Shale area. These amounts included approximately $185.8 million spent to develop proved undeveloped reserves.

The Exploration and Production segment capital expenditures for the six months ended March 31, 2023 were primarily well drilling and completion expenditures in the Appalachian region, and included $143.2 million in the Marcellus Shale area and $172.4 million in the Utica Shale area. These amounts included approximately $208.2 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2024 and March 31, 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.

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In addition, due to the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, specifically in the Marcellus and Utica Shale producing areas, Supply Corporation and Empire have completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems. An expansion and modernization project where the Company has forecasted a significant amount of investment in preliminary survey and investigation costs and/or capital expenditures, 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 late summer 2024. The Tioga Pathway Project has a projected in-service date of late calendar year 2026 and an estimated capital cost of approximately $90 million. As of March 31, 2024, approximately $1.0 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at March 31, 2024.

Gathering

The majority of the Gathering segment capital expenditures for the six months ended March 31, 2024 included expenditures related to the continued expansion of Midstream Company's Tioga and Clermont gathering systems. Midstream Company spent $31.2 million and $7.0 million, respectively, during the six months ended March 31, 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, 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 six months ended March 31, 2023 included expenditures related to the continued expansion of Midstream Company's Clermont, Tioga and Trout Run gathering systems. Midstream Company spent $10.2 million, $16.8 million and $3.8 million, respectively, during the six months ended March 31, 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 and centralized station facilities related to bringing new development online.

Utility

The majority of the Utility segment capital expenditures for the six months ended March 31, 2024 and March 31, 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 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.

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Project Funding

During the six months ended March 31, 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 $8.6 million, to a total of $278.9 million, when comparing the balance sheet at March 31, 2024 to the balance sheet at September 30, 2023. The maximum amount of short-term debt outstanding during the six months ended March 31, 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 March 31, 2024, the Company did not have any short-term notes payable to banks and had outstanding commercial paper of $278.9 million.

On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the "Credit Agreement") with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. The Credit Agreement provides a $1.0 billion unsecured committed revolving credit facility with a maturity date of February 26, 2027. Effective February 7, 2024, certain lenders under the Credit Agreement consented to an extension of the maturity date of the Credit Agreement from February 26, 2027 to February 25, 2028. As a result, the Company has aggregate commitments available under the Credit Agreement of $1.0 billion before February 26, 2027, and $940.0 million in aggregate commitments available on and after February 26, 2027 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 term loan with a maturity date of February 14, 2026. Pursuant to the Term Loan Agreement, there was a delayed draw mechanism and the Company elected to draw a total of $300.0 million under the facility between April 8, 2024 and April 10, 2024. The Company used the proceeds for general corporate purposes, which included the redemption of outstanding commercial paper.

Both the Credit Agreement and Term Loan Agreement require 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

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any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at March 31, 2024, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under these agreements. In addition, for purposes of calculating the debt to capitalization ratio under these agreements, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's consolidated balance sheet. Under the agreements, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. At March 31, 2024, the Company’s debt to capitalization ratio, as calculated under the agreements was 0.44. The constraints specified in the agreements would have permitted an additional $3.57 billion in short-term and/or long-term debt to be outstanding at March 31, 2024 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.

None of the Company's long-term debt as of March 31, 2024 and September 30, 2023 had a maturity date within the following twelve-month period.

The Company’s embedded cost of long-term debt was 4.69% at March 31, 2024 and 4.58% at March 31, 2023.

Under the Company’s existing indenture covenants at March 31, 2024, the Company would have been permitted to issue up to a maximum of approximately $4.02 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by the debt to capitalization ratio constraint under the Credit Agreement and Term Loan Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy known demands. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

The Company’s 1974 indenture pursuant to which $50.0 million (or 2.1%) of the Company’s long-term debt (as of March 31, 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,

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discontinue, terminate, modify, cancel or extend the share repurchase program at any time and for any reason. During the quarter ended March 31, 2024, the Company executed transactions to repurchase 96,133 shares for $5.0 million. Share repurchases that settled during the quarter ended March 31, 2024 were funded with cash provided by operating activities and/or short-term borrowings. It is expected that future repurchase, 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 March 31, 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 March 31, 2024.

The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the six months ended March 31, 2024. In the remainder of fiscal 2024, the Company expects its contributions to the Retirement Plan to be in the range of zero to $5.0 million. The Company did not make any contributions to its VEBA trusts for its other post-retirement benefits during the six months ended March 31, 2024, and does not anticipate making any such contributions during the remainder of fiscal 2024.

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 March 31, 2024, the Company determined that nonperformance risk associated with its natural gas price

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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

Pennsylvania Jurisdiction

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Pipeline and Storage

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 7 — 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 permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. For example, the federal Inflation Reduction Act of 2022 (IRA) legislation was signed into law on August 16, 2022. The IRA includes a methane charge that is expected to be applicable to the reported annual methane emissions of certain oil and gas facilities, above specified methane intensity thresholds, starting in calendar year 2024. This portion of the IRA is to be administered by the EPA and potential fees will begin with emissions reported for calendar year 2024. The EPA is the lead federal agency that regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented by the EPA impose stringent leak detection and repair requirements and address reporting and control of methane and volatile organic compound emissions, 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

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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 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.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;

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

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

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

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

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

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

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

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

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

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

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

19.Uncertainty of natural gas reserve estimates;

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

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

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

23.Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;

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

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

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

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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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 March 31, 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 March 31, 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 7 – Commitments and Contingencies, and Part I, Item 2 - MD&A of this report under the heading “Other Matters – Environmental Matters.”

For a discussion of certain rate matters involving the NYPSC, refer to Part I, Item 1 of this report at Note 10 – Regulatory Matters.

Item 1A. Risk Factors

The risk factors in Item 1A of the Company’s 2023 Form 10-K have not materially changed other than as set forth below. The risk factors presented below supersede the corresponding risk factors in the 2023 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2023 Form 10-K.

STRATEGIC RISKS

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

The laws, regulations and other initiatives to address climate change, may impact the Company’s financial results. In early 2021, the U.S. rejoined the Paris Agreement, the international effort to establish emissions reduction goals for signatory countries. Under the Paris Agreement, signatory countries are expected to submit their nationally determined contributions to curb greenhouse gas emissions and meet the agreed temperature objectives every five years. On April 22, 2021, the federal administration announced the U.S. nationally determined contribution to achieve a fifty to fifty-two percent reduction from 2005 levels in economy-wide net greenhouse gas pollution by 2030. Executive orders from the federal administration, in addition to federal, state and local legislative and regulatory initiatives proposed or adopted in an attempt to limit the effects of climate change, including greenhouse gas emissions, could have significant impacts on the energy industry including government-imposed limitations, prohibitions or moratoriums on the use and/or production of natural gas, establishment of a carbon tax and/or methane fee, lack of support for system modernization, as well as accelerated depreciation of assets and/or stranded assets.

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

A number of states have also adopted energy strategies or plans with goals that include the reduction of greenhouse gas emissions. For example, Pennsylvania has a methane reduction framework for the natural gas industry which has resulted in permitting changes with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. In March 2024, Pennsylvania Governor Josh Shapiro proposed the Pennsylvania Climate Emissions Reduction Act that would establish a fee on emissions from power plants as part of a cap-and-invest program, and a companion proposal, the Pennsylvania Reliable Energy Sustainability Standard, which would require Pennsylvania to obtain fifty percent of its electricity from low carbon energy sources by 2035. Furthermore, in 2019, the New York State legislature passed the CLCPA, which created emission reduction and electrification mandates, and could ultimately impact the Utility segment’s customer base and business. Pursuant to the CLCPA, New York's Climate Action Council (“CAC”) approved a final scoping plan that includes recommendations to strategically downsize and decarbonize the natural gas system and curtail use of natural gas and natural gas appliances. The final scoping plan was approved on December 19, 2022 and includes detailed recommendations to meet the CLCPA’s emissions reduction targets in the transportation, buildings, electricity, industry, agriculture & forestry and waste sectors. The final scoping plan also recommends statewide and cross-sector policies relevant to gas system transition, economywide strategies, land use, local government and adaptation and resilience. Additionally, the scoping plan recommends the implementation of a cap-and-invest program in New York. In January 2023, New York’s Governor directed the NYDEC and the New York State Energy Research and Development Authority to advance an economywide cap-and-invest program that establishes a declining cap on greenhouse gas emissions, and invests in programs to drive emissions reductions. If this proposed program or a similar program becomes effective and the Company becomes subject to new or revised cap-and-trade programs, cap-and-invest programs, methane charges, fees for carbon-based fuels or other similar costs or charges, the Company may experience additional costs and incremental operating expenses, which would impact our future earnings and cash flows, and may also experience decreased revenue in the event that implementation of these policies leads to reduced demand for natural gas.

In addition to the CLCPA scoping plan, legislation or regulation that aims to reduce greenhouse gas emissions could also include natural gas bans, greenhouse gas emissions limits and reporting requirements, carbon taxes and/or similar fees on carbon dioxide, methane or equivalent emissions, restrictive permitting, increased efficiency standards requiring system remediation and/or changes in operating practices, and incentives or mandates to conserve energy or use renewable energy sources. For example, in May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to various exemptions. While the Company does not currently expect that this legislation will have a substantial impact on its financial results or operations, future legislation or regulation that aims to reduce natural gas demand or to impose additional operations requirements or restrictions on natural gas facilities, if effectuated, could impact our future earnings and cash flows.

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

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

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 oil and natural gas properties to the present value of the future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses a 12-month historical average price for oil and

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natural gas (based on first day of the month prices and adjusted for hedging) as well as the SEC mandated discount rate. If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be "impaired," and the full cost authoritative accounting and reporting guidance require that the investment must be written down to the calculated net present value. Such an instance would require the Company to recognize an immediate expense in that quarter, and its earnings would be reduced. Depending on the magnitude of any decrease in average prices, that charge could be material. Under the Company's existing indenture covenants, an impairment could restrict the Company's ability to issue 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 last recognized non-cash, pre-tax impairment charges on its oil and natural gas properties in fiscal years 2020 and 2021, in the amounts of $449.4 million and $76.2 million, respectively. The Company did not record an impairment under the ceiling test during the quarter ended March 31, 2024. Looking ahead, the first day of the month Henry Hub spot price for natural gas in April 2024 was $1.56 per MMBtu. Given the April 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 at June 30, 2024 and September 30, 2024, the Company expects to experience a ceiling test impairment in each of these quarters.

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

On January 2, 2024, the Company issued a total of 8,650 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 865 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 March 31, 2024. The Company issued an additional 654 unregistered shares in the aggregate on January 12, 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)
Jan. 1 - 31, 2024	15,968	$49.86	—	6,971,019
Feb. 1 - 29, 2024	15,620	$47.68	—	6,971,019
Mar. 1 - 31, 2024	110,455	$51.91	96,133	$195,000,278
Total	142,043	$51.24	96,133

(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 45,910 shares purchased other than through a publicly announced share repurchase program, 45,578 were purchased for the Company's 401(k) plans and 332 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. 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 March 31, 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.

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Item 6. Exhibits


Exhibit Number						Description of Exhibit
10.1						Credit Agreement Existing Maturity Date Extension Consent, dated February 1, 2024, among the Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent.

•						Term Loan Agreement, dated as of February 14, 2024, among the Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (Exhibit 10.1, Form 8-K dated February 14, 2024).

•						National Fuel Gas Company 2010 Equity Compensation Plan (Exhibit 10.1, Form 8-K dated March 11, 2024).

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 March 31, 202 4 and 202 3 .

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 six months ended March 31, 2024 and 2023, (ii) the Consolidated Statements of Comprehensive Income for the six months ended March 31, 2024 and 2023, (iii) the Consolidated Balance Sheets at March 31, 2024 and September 30, 2023, (iv) the Consolidated Statements of Cash Flows for the six months ended March 31, 2024 and 2023 and (v) the Notes to Condensed Consolidated Financial Statements.

104						Cover Page Interactive Data File (embedded within the Inline XBRL document)

•						Incorporated herein by reference as indicated.



••						In accordance with Item 601(b)(32)(ii) of Regulation S-K and SEC Release Nos. 33-8238 and 34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference.

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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: May 2, 2024