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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 December 31, 2023
OR
TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)
OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from____ to_____
Commission File Number 1-3880
NATIONAL FUEL GAS COMPANY
(Exact name of registrant as specified in its charter)
New Jersey13-1086010
(State or other jurisdiction of incorporation or organization)(I.R.S. Employer Identification No.)
6363 Main Street 
Williamsville,New York14221
(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 ClassTrading Symbol
Name of Each Exchange
on Which Registered
Common Stock, par value $1.00 per shareNFGNew 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 FilerAccelerated Filer
Non-Accelerated FilerSmaller Reporting Company
Emerging Growth Company
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act.

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).  YES    NO 

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Common stock, par value $1.00 per share, outstanding at January 31, 2024: 92,127,623 shares.


GLOSSARY OF TERMS
 
Frequently used abbreviations, acronyms, or terms used in this report:
 
National Fuel Gas Companies
Company
The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Distribution CorporationNational Fuel Gas Distribution Corporation
EmpireEmpire Pipeline, Inc.
Midstream Company
National Fuel Gas Midstream Company, LLC
National FuelNational Fuel Gas Company
RegistrantNational Fuel Gas Company
SenecaSeneca Resources Company, LLC
Supply CorporationNational Fuel Gas Supply Corporation
Regulatory Agencies
CFTCCommodity Futures Trading Commission
EPAUnited States Environmental Protection Agency
FASBFinancial Accounting Standards Board
FERCFederal Energy Regulatory Commission
IRSInternal Revenue Service
NYDECNew York State Department of Environmental Conservation
NYPSCState of New York Public Service Commission
PaDEPPennsylvania Department of Environmental Protection
PaPUCPennsylvania Public Utility Commission
PHMSAPipeline and Hazardous Materials Safety Administration
SECSecurities 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 ActTax legislation referred to as the "Tax Cuts and Jobs Act," enacted December 22, 2017.
BcfBillion 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.
2

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
Dodd-Frank ActDodd-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.
EAPEnergy Affordability Program; a program that provides bill discounts to gas customers who receive benefits under qualifying public assistance programs.
ESGEnvironmental, social and governance
Exchange ActSecurities 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.
HedgingA 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.
ICEIntercontinental Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Impact FeeAn 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.
LDCLocal distribution company
LIFOLast-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.
McfThousand cubic feet (of natural gas)
MD&A
Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDthThousand 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)
MMcfMillion cubic feet (of natural gas)
Natural GasA naturally occurring mixture of gaseous hydrocarbons consisting primarily of methane and found in underground rock formations.
3

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.
NOAANational Oceanic and Atmospheric Administration
NYMEX
New York Mercantile Exchange.  An exchange which maintains a futures market for crude oil and natural gas.
OPEBOther 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&PStandard & Poor’s Rating Service
SARStock 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.
SOFRSecured Overnight Financing Rate
Stock acquisitionsInvestments 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.
VEBAVoluntary Employees’ Beneficiary Association
WNCWeather normalization clause; a clause/adjustment in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures.  If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs.  If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.



4

INDEXPage
  
6 
  
  
 
Item 3.  Defaults Upon Senior Securities 
Item 4.  Mine Safety Disclosures 
 
• The Company has nothing to report under this item.
 
    All references to a certain year in this report are to the Company’s fiscal year ended September 30 of that year, unless otherwise noted.

5

Part I.  Financial Information
 
Item 1.  Financial Statements
National Fuel Gas Company
Consolidated Statements of Income and Earnings
Reinvested in the Business
(Unaudited)
 Three Months Ended
December 31,
(Thousands of U.S. Dollars, Except Per Common Share Amounts)20232022
INCOME
Operating Revenues:
Utility Revenues$201,920 $311,619 
Exploration and Production and Other Revenues254,019 276,973 
Pipeline and Storage and Gathering Revenues69,422 70,267 
525,361 658,859 
Operating Expenses:
Purchased Gas56,552 171,197 
Operation and Maintenance:
Utility53,705 50,352 
Exploration and Production and Other34,826 26,874 
Pipeline and Storage and Gathering34,962 33,261 
Property, Franchise and Other Taxes22,416 26,205 
Depreciation, Depletion and Amortization115,790 96,600 
 
318,251 404,489 
Operating Income207,110 254,370 
Other Income (Expense):
Other Income (Deductions)3,732 6,318 
Interest Expense on Long-Term Debt(28,462)(29,604)
Other Interest Expense(6,273)(3,843)
Income Before Income Taxes176,107 227,241 
Income Tax Expense43,087 57,552 
Net Income Available for Common Stock133,020 169,689 
EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period1,885,856 1,587,085 
 2,018,876 1,756,774 
Dividends on Common Stock(45,597)(43,598)
Balance at December 31$1,973,279 $1,713,176 
Earnings Per Common Share:
Basic:
Net Income Available for Common Stock$1.45 $1.85 
Diluted:
Net Income Available for Common Stock$1.44 $1.84 
Weighted Average Common Shares Outstanding:
Used in Basic Calculation91,910,244 91,579,814 
Used in Diluted Calculation92,442,145 92,268,210 
Dividends Per Common Share:
Dividends Declared$0.495 $0.475 
See Notes to Condensed Consolidated Financial Statements
6

National Fuel Gas Company
Consolidated Statements of Comprehensive Income
(Unaudited)
                                                      Three Months Ended
December 31,
(Thousands of U.S. Dollars)                                  20232022
Net Income Available for Common Stock$133,020 $169,689 
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
189,167 297,593 
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income(19,708)159,342 
Other Comprehensive Income (Loss), Before Tax169,459 456,935 
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period
52,486 81,377 
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income
(5,468)43,571 
Income Taxes – Net47,018 124,948 
Other Comprehensive Income (Loss)122,441 331,987 
Comprehensive Income$255,461 $501,676 
 
































See Notes to Condensed Consolidated Financial Statements
7

National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
 
December 31,
2023
September 30,
2023
(Thousands of U.S. Dollars)  
ASSETS  
Property, Plant and Equipment$13,857,060 $13,635,303 
Less - Accumulated Depreciation, Depletion and Amortization6,435,129 6,335,441 
 7,421,931 7,299,862 
Current Assets  
Cash and Temporary Cash Investments41,685 55,447 
Receivables – Net of Allowance for Uncollectible Accounts of $37,116 and $36,295, Respectively
189,669 160,601 
Unbilled Revenue48,265 16,622 
Gas Stored Underground26,891 32,509 
Materials and Supplies - at average cost47,692 48,989 
Other Current Assets99,400 100,260 
           453,602 414,428 
Other Assets  
Recoverable Future Taxes73,283 69,045 
Unamortized Debt Expense6,829 7,240 
Other Regulatory Assets72,088 72,138 
Deferred Charges80,347 82,416 
Other Investments76,633 73,976 
Goodwill5,476 5,476 
Prepaid Pension and Post-Retirement Benefit Costs208,015 200,301 
Fair Value of Derivative Financial Instruments184,739 50,487 
Other4,549 4,891 
                   711,959 565,970 
Total Assets$8,587,492 $8,280,260 















See Notes to Condensed Consolidated Financial Statements
8

National Fuel Gas Company
Consolidated Balance Sheets
(Unaudited)
                                  December 31,
2023
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 – 92,115,581 Shares
and 91,819,405 Shares, Respectively
$92,116 $91,819 
Paid in Capital1,041,226 1,040,761 
Earnings Reinvested in the Business1,973,279 1,885,856 
Accumulated Other Comprehensive Income (Loss)67,381 (55,060)
Total Comprehensive Shareholders’ Equity3,174,002 2,963,376 
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs
2,385,523 2,384,485 
Total Capitalization5,559,525 5,347,861 
Current and Accrued Liabilities  
Notes Payable to Banks and Commercial Paper300,000 287,500 
Accounts Payable105,390 152,193 
Amounts Payable to Customers60,032 59,019 
Dividends Payable45,597 45,451 
Interest Payable on Long-Term Debt42,288 20,399 
Customer Advances23,086 21,003 
Customer Security Deposits30,843 28,764 
Other Accruals and Current Liabilities200,009 160,974 
Fair Value of Derivative Financial Instruments 31,009 
                                                 807,245 806,312 
Other Liabilities  
Deferred Income Taxes1,164,512 1,124,170 
Taxes Refundable to Customers317,838 268,562 
Cost of Removal Regulatory Liability284,687 277,694 
Other Regulatory Liabilities165,988 165,441 
Other Post-Retirement Liabilities2,859 2,915 
Asset Retirement Obligations164,777 165,492 
Other Liabilities120,061 121,813 
                                                 2,220,722 2,126,087 
Commitments and Contingencies (Note 7)  
Total Capitalization and Liabilities$8,587,492 $8,280,260 
 
See Notes to Condensed Consolidated Financial Statements
9

National Fuel Gas Company
Consolidated Statements of Cash Flows
(Unaudited)
                                                        Three Months Ended
 December 31,
(Thousands of U.S. Dollars)20232022
OPERATING ACTIVITIES  
Net Income Available for Common Stock$133,020 $169,689 
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:  
Depreciation, Depletion and Amortization115,790 96,600 
Deferred Income Taxes38,362 53,457 
Stock-Based Compensation4,660 5,575 
Other8,041 4,078 
Change in:  
Receivables and Unbilled Revenue(58,459)(29,522)
Gas Stored Underground and Materials and Supplies6,915 5,622 
Unrecovered Purchased Gas Costs 20,603 
Other Current Assets892 (1,748)
Accounts Payable(3,355)6,091 
Amounts Payable to Customers1,013 (265)
Customer Advances2,083 5,206 
Customer Security Deposits2,079 4,546 
Other Accruals and Current Liabilities28,612 4,523 
Other Assets(6,306)(20,238)
Other Liabilities(2,403)3,122 
Net Cash Provided by Operating Activities270,944 327,339 
INVESTING ACTIVITIES  
Capital Expenditures(246,938)(233,473)
Sale of Fixed Income Mutual Fund Shares in Grantor Trust 10,000 
Other(920)14,637 
Net Cash Used in Investing Activities(247,858)(208,836)
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 Paper12,500 (60,000)
Reduction of Long-Term Debt (150,000)
Dividends Paid on Common Stock(45,451)(43,452)
Net Repurchases of Common Stock(3,897)(6,694)
Net Cash Used in Financing Activities(36,848)(10,146)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash(13,762)108,357 
Cash, Cash Equivalents, and Restricted Cash at October 155,447 137,718 
Cash, Cash Equivalents, and Restricted Cash at December 31$41,685 $246,075 
Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:  
Non-Cash Capital Expenditures$97,922 $110,314 
See Notes to Condensed Consolidated Financial Statements
10

National Fuel Gas Company
Notes to Condensed Consolidated Financial Statements
(Unaudited)

Note 1 – Summary of Significant Accounting Policies
 
Principles of Consolidation. The Company consolidates all entities in which it has a controlling financial interest. All significant intercompany balances and transactions are eliminated. The Company uses proportionate consolidation when accounting for drilling arrangements related to 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 three months ended December 31, 2023 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):
Three Months Ended
 December 31, 2023
Three Months Ended
 December 31, 2022
 Balance at
December 31, 2023
Balance at October 1, 2023Balance at
December 31, 2022
Balance at October 1, 2022
Cash and Temporary Cash Investments$41,685 $55,447 $244,475 $46,048 
Hedging Collateral Deposits  1,600 91,670 
Cash, Cash Equivalents, and Restricted Cash$41,685 $55,447 $246,075 $137,718 

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

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

11

    Activity in the allowance for uncollectible accounts for the three months ended December 31, 2023 and 2022 are as follows (in thousands):

Balance at Beginning of PeriodAdditions Charged to Costs and ExpensesDiscounts on Purchased ReceivablesNet Accounts Receivable Written-OffBalance at End of Period
Three Months Ended December 31, 2023
Allowance for Uncollectible Accounts$36,295 $4,157 $119 $(3,455)$37,116 
Three Months Ended December 31, 2022
Allowance for Uncollectible Accounts$40,228 $5,035 $228 $(1,566)$43,925 

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 $1.2 million at December 31, 2023, 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 $2.5 billion and $2.4 billion at December 31, 2023 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 $159.1 million and $161.1 million at December 31, 2023 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 December 31, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $84.4 million.  The estimated future net cash flows were increased by $307.0 million for hedging under the ceiling test at December 31, 2023.
    
    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 December 31, 2023.

12

Accumulated Other Comprehensive Income (Loss). The components of Accumulated Other Comprehensive Income (Loss) and changes for the three months ended December 31, 2023 and 2022, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands): 
 Gains and Losses on Derivative Financial InstrumentsFunded Status of the Pension and Other Post-Retirement Benefit PlansTotal
Three Months Ended December 31, 2023
Balance at October 1, 2023$4,623 $(59,683)$(55,060)
Other Comprehensive Gains and Losses Before Reclassifications
136,681  136,681 
Amounts Reclassified From Other Comprehensive Income(14,240) (14,240)
Balance at December 31, 2023$127,064 $(59,683)$67,381 
Three Months Ended December 31, 2022
Balance at October 1, 2022$(572,163)$(53,570)$(625,733)
Other Comprehensive Gains and Losses Before Reclassifications
216,216  216,216 
Amounts Reclassified From Other Comprehensive Income115,771  115,771 
Balance at December 31, 2022$(240,176)$(53,570)$(293,746)

Reclassifications Out of Accumulated Other Comprehensive Income (Loss).  The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the three months ended December 31, 2023 and 2022 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):
Details About Accumulated Other Comprehensive Income (Loss) ComponentsAmount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss)Affected Line Item in the Statement Where Net Income is Presented
Three Months Ended
December 31,
20232022
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
 
     Commodity Contracts$19,755 ($159,162)Operating Revenues
     Foreign Currency Contracts(47)(180)Operating Revenues
 19,708 (159,342)Total Before Income Tax
 (5,468)43,571 Income Tax Expense
 $14,240 ($115,771)Net of Tax

13

Other Current Assets.  The components of the Company’s Other Current Assets are as follows (in thousands):
                            At December 31, 2023At September 30, 2023
Prepayments$17,993 $18,966 
Prepaid Property and Other Taxes14,778 14,186 
Federal Income Taxes Receivable10,799 14,602 
State Income Taxes Receivable18,208 16,133 
Regulatory Assets37,622 36,373 
 $99,400 $100,260 
 
Other Accruals and Current Liabilities.  The components of the Company’s Other Accruals and Current Liabilities are as follows (in thousands):
                            At December 31, 2023At September 30, 2023
Accrued Capital Expenditures$75,485 $43,323 
Regulatory Liabilities35,770 38,105 
Reserve for Gas Replacement1,247  
Liability for Royalty and Working Interests25,529 17,679 
Non-Qualified Benefit Plan Liability13,052 13,052 
Other48,926 48,815 
 $200,009 $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 ended December 31, 2023, 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 no securities excluded as being antidilutive for the quarter ended December 31, 2023. For the quarter ended December 31, 2022, 1,987 securities were excluded as being antidilutive.

Stock-Based Compensation.  The Company granted 361,729 performance shares during the quarter ended December 31, 2023. The weighted average fair value of such performance shares was $44.23 per share for the quarter ended December 31, 2023. Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied.  Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period.
 
    The performance shares granted during the quarter ended December 31, 2023 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
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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 219,578 restricted stock units during the quarter ended December 31, 2023.  The weighted average fair value of such restricted stock units was $42.44 per share for the quarter ended December 31, 2023.  Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participant to receive dividends during the vesting period. The fair value at the date of grant of the restricted stock units (represented by the market value of Company common stock on the date of the award) must be reduced by the present value of forgone dividends over the vesting term of the award. The fair value of restricted stock units on the date of award is recorded as compensation expense over the vesting period.



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Note 2 – Revenue from Contracts with Customers
 
    The following tables provide a disaggregation of the Company's revenues for the three months ended December 31, 2023 and 2022, presented by type of service from each reportable segment.
Quarter Ended December 31, 2023 (Thousands)   
Revenues By Type of ServiceExploration and ProductionPipeline and StorageGatheringUtilityAll OtherCorporate and Intersegment EliminationsTotal Consolidated
Production of Natural Gas$232,661 $ $ $ $ $ $232,661 
Production of Crude Oil687      687 
Natural Gas Processing267      267 
Natural Gas Gathering Service  62,588   (57,992)4,596 
Natural Gas Transportation Service 71,618  29,285  (20,362)80,541 
Natural Gas Storage Service 21,292    (9,059)12,233 
Natural Gas Residential Sales   146,546   146,546 
Natural Gas Commercial Sales   20,281   20,281 
Natural Gas Industrial Sales   906  (2)904 
Other649 1,503  (567) (251)1,334 
Total Revenues from Contracts with Customers234,264 94,413 62,588 196,451  (87,666)500,050 
Alternative Revenue Programs   5,556   5,556 
Derivative Financial Instruments19,755      19,755 
Total Revenues$254,019 $94,413 $62,588 $202,007 $ $(87,666)$525,361 
Quarter Ended December 31, 2022 (Thousands)   
Revenues By Type of ServiceExploration and ProductionPipeline and StorageGatheringUtilityAll OtherCorporate and Intersegment EliminationsTotal Consolidated
Production of Natural Gas$432,359 $ $ $ $ $ $432,359 
Production of Crude Oil628      628 
Natural Gas Processing374      374 
Natural Gas Gathering Service  56,413   (53,767)2,646 
Natural Gas Transportation Service 76,201  28,378  (20,817)83,762 
Natural Gas Storage Service 21,286    (8,996)12,290 
Natural Gas Residential Sales   244,306   244,306 
Natural Gas Commercial Sales   34,495   34,495 
Natural Gas Industrial Sales   1,638   1,638 
Other2,774 168  (259) (283)2,400 
Total Revenues from Contracts with Customers436,135 97,655 56,413 308,558  (83,863)814,898 
Alternative Revenue Programs   3,123   3,123 
Derivative Financial Instruments(159,162)     (159,162)
Total Revenues$276,973 $97,655 $56,413 $311,681 $ $(83,863)$658,859 
    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.
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    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: $159.1 million for the remainder of fiscal 2024; $191.6 million for fiscal 2025; $149.2 million for fiscal 2026; $123.3 million for fiscal 2027; $107.5 million for fiscal 2028; and $581.0 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.
 
    The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of December 31, 2023 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 MeasuresAt fair value as of December 31, 2023
(Thousands of Dollars)   Level 1Level 2Level 3
Netting
Adjustments(1)
Total(1)
Assets:
 
    
Cash Equivalents – Money Market Mutual Funds$32,781 $ $ $ $32,781 
Derivative Financial Instruments:     
Over the Counter Swaps – Gas 140,548  (16,722)123,826 
Over the Counter No Cost Collars – Gas 57,917   57,917 
Contingent Consideration for Asset Sale 3,078   3,078 
Foreign Currency Contracts 505  (587)(82)
Other Investments:     
Balanced Equity Mutual Fund17,484    17,484 
Fixed Income Mutual Fund16,510    16,510 
Total$66,775 $202,048 $ $(17,309)$251,514 
Liabilities:     
Derivative Financial Instruments:     
Over the Counter Swaps – Gas$ $16,722 $ $(16,722)$ 
Foreign Currency Contracts 587  (587) 
Total$ $17,309 $ $(17,309)$ 
Total Net Assets/(Liabilities)$66,775 $184,739 $ $ $251,514 

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Recurring Fair Value MeasuresAt fair value as of September 30, 2023
(Thousands of Dollars)   Level 1Level 2Level 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 Fund15,837    15,837 
Fixed Income Mutual Fund15,897    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 December 31, 2023 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 internal cash flow model that uses observable inputs (i.e. SOFR based discount rates for the price swap agreements and basis differential information, if applicable, at active natural gas trading markets). The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates. 

    The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities.  At December 31, 2023, 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 December 31, 2023 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 December 31, 2023 and December 31, 2022, there were no assets or liabilities measured at fair value and classified as Level 3.

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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): 
 December 31, 2023September 30, 2023
 Carrying
Amount
Fair ValueCarrying
Amount
Fair Value
Long-Term Debt$2,385,523 $2,286,446 $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.

Other Investments. The components of the Company's Other Investments are as follows (in thousands):
At December 31, 2023At September 30, 2023
Life Insurance Contracts$42,639 $42,242 
Equity Mutual Fund17,484 15,837 
Fixed Income Mutual Fund16,510 15,897 
$76,633 $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 $3.1 million and $7.3 million at December 31, 2023 and September 30, 2023, respectively. A $4.2 million
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mark-to-market adjustment to reduce the fair value of the contingent consideration was recorded during the quarter ended December 31, 2023.

    The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at December 31, 2023 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 December 31, 2023, the Company had 380.2 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.

    As of December 31, 2023, the Company was hedging a total of $53.7 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

    As of December 31, 2023, the Company had $127.1 million of net hedging gains after taxes included in the accumulated other comprehensive income (loss) balance. Of this amount, it is expected that $92.3 million of unrealized gains after taxes will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings.
The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended December 31, 2023 and 2022 (Thousands of Dollars)
Derivatives in Cash Flow Hedging RelationshipsAmount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on
the Consolidated Statement of
Comprehensive Income (Loss)
for the
 Three Months Ended
 December 31,
Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of IncomeAmount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the
 Three Months Ended
 December 31,
 20232022 20232022
Commodity Contracts$187,989 $297,120 Operating Revenue$19,755 $(159,162)
Foreign Currency Contracts1,178 473 Operating Revenue(47)(180)
Total$189,167 $297,593  $19,708 $(159,342)
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 $9.6 million of credit exposure per counterparty in a gain position at December 31, 2023. The maximum credit exposure per counterparty in a gain position at December 31, 2023 was $35.6 million. As of December 31, 2023, 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 December 31, 2023, 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
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derivative financial liability position would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to post or increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative financial instrument contracts with a credit-risk contingency feature were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then hedging collateral deposits or an increase to such deposits could be required.  At December 31, 2023, 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 December 31, 2023.  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 December 31, 2023 and December 31, 2022 were 24.5% and 25.3%, respectively. The reduction in effective income tax rates was primarily driven by a methodology change for repairs and maintenance tax deductions.

Note 6 – Capitalization

Summary of Changes in Common Stock Equity
 Common StockPaid In
Capital
Earnings
Reinvested
in the
Business
Accumulated
Other
Comprehensive
Income (Loss)
SharesAmount
 (Thousands, except per share amounts)
Balance at October 1, 202391,819 $91,819 $1,040,761 $1,885,856 $(55,060)
Net Income Available for Common Stock133,020 
Dividends Declared on Common Stock ($0.495 Per Share)
(45,597)
Other Comprehensive Income, Net of Tax122,441 
Share-Based Payment Expense (1)
4,135 
Common Stock Issued (Repurchased) Under Stock and Benefit Plans297 297 (3,670)
Balance at December 31, 202392,116 $92,116 $1,041,226 $1,973,279 $67,381 
Balance at October 1, 202291,478 $91,478 $1,027,066 $1,587,085 $(625,733)
Net Income Available for Common Stock169,689 
Dividends Declared on Common Stock ($0.475 Per Share)
(43,598)
Other Comprehensive Income, Net of Tax331,987 
Share-Based Payment Expense (1)
5,118 
Common Stock Issued (Repurchased) Under Stock and Benefit Plans309 309 (6,545)
Balance at December 31, 202291,787 $91,787 $1,025,639 $1,713,176 $(293,746)

(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 three months ended December 31, 2023, the Company issued 111,832 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 9,128 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 three months ended December 31, 2023.  In addition, the Company issued 1,055 original issue shares of common stock to officers of
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the Company who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's DCP Plan during the three months ended December 31, 2023. Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes.  During the three months ended December 31, 2023, 77,094 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.

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. On February 7, 2024, the Company and 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.
 
Current Portion of Long-Term Debt. None of the Company's long-term debt as of December 31, 2023 and September 30, 2023 had a maturity date within the following twelve-month period.

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 December 31, 2023, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.2 million.  The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at December 31, 2023. 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. The Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project which is the subject of an ongoing appeal at the U.S. Court of Appeals for the D.C. Circuit. As of December 31, 2023, the Company has spent approximately $56.0 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.
 
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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 December 31, 2023 and September 30, 2023 is shown in the tables below.  
Quarter Ended December 31, 2023 (Thousands)    
 Exploration and ProductionPipeline and StorageGatheringUtilityTotal Reportable SegmentsAll OtherCorporate and Intersegment EliminationsTotal Consolidated
Revenue from External Customers
$254,019$64,826$4,596$201,920$525,361$$$525,361
Intersegment Revenues$$29,587$57,992$87$87,666$$(87,666)$
Segment Profit: Net Income (Loss)
$52,483$24,055$28,825$26,551$131,914$(121)$1,227$133,020
(Thousands)Exploration and ProductionPipeline and StorageGatheringUtilityTotal Reportable SegmentsAll OtherCorporate and Intersegment EliminationsTotal Consolidated
Segment Assets:      
At December 31, 2023$3,057,345$2,439,479$936,547$2,301,116$8,734,487$4,758$(151,753)$8,587,492
At September 30, 2023$2,814,218$2,427,214$912,923$2,247,743$8,402,098$4,795$(126,633)$8,280,260
Quarter Ended December 31, 2022 (Thousands)    
 Exploration and ProductionPipeline and StorageGatheringUtilityTotal Reportable SegmentsAll OtherCorporate and Intersegment EliminationsTotal Consolidated
Revenue from External Customers
$276,973$67,621$2,646$311,619$658,859$$$658,859
Intersegment Revenues$$30,034$53,767$62$83,863$$(83,863)$
Segment Profit: Net Income (Loss)$91,192$29,476$24,738$23,817$169,223$(280)$746$169,689

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Note 9 – Retirement Plan and Other Post-Retirement Benefits
 
    Components of Net Periodic Benefit Cost (in thousands):
 
 Retirement PlanOther Post-Retirement Benefits
Three Months Ended December 31,2023202220232022
Service Cost$1,049 $1,297 $109 $147 
Interest Cost10,890 10,629 3,890 3,912 
Expected Return on Plan Assets(17,086)(16,648)(6,660)(6,403)
Amortization of Prior Service Cost (Credit)91 109 (107)(107)
Amortization of (Gains) Losses(335)(1,920)(567)(2,189)
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)
4,057 5,378 2,238 3,820 
Net Periodic Benefit Cost (Income)$(1,334)$(1,155)$(1,097)$(820)
(1)The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.
 
    The components of net periodic benefit cost other than service cost are presented in Other Income (Deductions) on the Consolidated Statements of Income.

Employer Contributions.    The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the three months ended December 31, 2023. 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 three months ended December 31, 2023, 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.

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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.

FERC Jurisdiction

    Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023 proposing rate increases to be effective February 1, 2024. The proposed rates reflect an annual cost of service of $385.4 million, a rate base of $1.32 billion and a proposed cost of equity of 15.12%. If the proposed rate increases finally approved at the end of the proceeding exceed the rates that were in effect at July 31, 2023, but are less than rates put into effect subject to refund on February 1, 2024, Supply Corporation would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2023, such lower rates will become effective prospectively from the effective date provided by the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at July 31, 2023.

    Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1, 2025.


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’s (“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. For further discussion of Distribution Corporation and Supply Corporation rate matters, refer to the Rate Matters section below.
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    From a financing perspective, on February 7, 2024, the Company and 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.

    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 December 31, 2023, the ceiling exceeded the book value of the oil and gas properties by approximately $84.4 million. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended December 31, 2023, based on the quoted Henry Hub spot price for natural gas, was $2.64 per MMBtu. (Note: Because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for the twelve months ended December 31, 2023. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.)  In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices in the twelve-month period used at December 31, 2023 in the ceiling test calculation, the book value of the Company's oil and gas properties would have exceeded the ceiling by approximately $250.8 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.   

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

RESULTS OF OPERATIONS
 
Earnings
 
    The Company's earnings were $133.0 million for the quarter ended December 31, 2023 compared to earnings of $169.7 million for the quarter ended December 31, 2022.  The decrease in earnings of $36.7 million is primarily the result of lower earnings in the Exploration and Production segment and the Pipeline and Storage segment. Partially offsetting these decreases were higher earnings in the Gathering segment, Utility segment and Corporate category, as well as a lower loss in the All Other category. Note that all amounts used in earnings discussions are after-tax amounts, unless otherwise noted.
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Earnings (Loss) by Segment
 Three Months Ended
December 31,
(Thousands)20232022Increase
(Decrease)
Exploration and Production$52,483 $91,192 $(38,709)
Pipeline and Storage24,055 29,476 (5,421)
Gathering28,825 24,738 4,087 
Utility26,551 23,817 2,734 
Total Reportable Segments131,914 169,223 (37,309)
All Other(121)(280)159 
Corporate1,227 746 481 
Total Consolidated$133,020 $169,689 $(36,669)
 
Exploration and Production
 
Exploration and Production Operating Revenues
 
 Three Months Ended
December 31,
(Thousands)20232022Increase
(Decrease)
Gas Produced in Appalachia (after Hedging)$252,416 $273,197 $(20,781)
Other1,603 3,776 (2,173)
 $254,019 $276,973 $(22,954)
 
Production Volumes
 Three Months Ended
December 31,
 20232022Increase
(Decrease)
Gas Production per MMcf100,757 90,574 10,183 

Average Prices
 Three Months Ended
December 31,
 20232022Increase
(Decrease)
Average Gas Price/Mcf
Weighted Average$2.31 $4.77 $(2.46)
Weighted Average After Hedging$2.51 $3.02 $(0.51)

2023 Compared with 2022
 
    Operating revenues for the Exploration and Production segment decreased $23.0 million for the quarter ended December 31, 2023 as compared with the quarter ended December 31, 2022. Gas production revenue after hedging decreased $20.8 million due to the impact of a $0.51 per Mcf decrease in the weighted average price of natural gas after hedging, offset by a 10.2 Bcf increase in natural gas production. This was partially offset by increased natural gas production largely due to additional production from new Marcellus and Utica wells in the Appalachian region. In addition, other revenue decreased $2.2 million due to the non-recurrence of temporary capacity release revenue for a portion of this segment's transportation capacity during the quarter ended December 31, 2022.
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    The Exploration and Production segment's earnings for the quarter ended December 31, 2023 were $52.5 million, a decrease of $38.7 million when compared with earnings of $91.2 million for the quarter ended December 31, 2022. The decrease in earnings was attributable to lower natural gas prices after hedging ($40.7 million), higher depletion expense ($13.0 million), higher lease operating and transportation expenses ($4.4 million), higher other operating expenses ($4.1 million), an increase in interest expense ($1.6 million) and an unrealized loss on contingent consideration received as part of the sale of Seneca's California assets ($3.0 million). These decreases were partially offset by higher natural gas production ($24.3 million) and lower other taxes ($2.6 million). The increase in depletion expense was primarily due to the net increase in production combined with a $0.10 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 and saltwater disposal expenses. The increase in other operating expenses was primarily attributable to recognizing an accrual of plugging and abandonment costs related to certain California wells that were formerly owned by Seneca, combined with higher general and administrative costs. The increase in interest expense can largely be attributed to higher average interest rates on intercompany short-term and long-term borrowings, partially offset by lower intercompany long-term debt balances. The decrease in other taxes was primarily attributable to lower Impact Fees in the Appalachian region due to lower NYMEX pricing, which reduces the cost per well due to moving the Company into a lower rate tier.

Pipeline and Storage
 
Pipeline and Storage Operating Revenues
 Three Months Ended
December 31,
(Thousands)20232022Increase
(Decrease)
Firm Transportation$71,495 $75,456 $(3,961)
Interruptible Transportation123 745 (622)
 71,618 76,201 (4,583)
Firm Storage Service21,291 21,284 
Interruptible Storage Service(1)
Other1,503 168 1,335 
                $94,413 $97,655 $(3,242)
 
Pipeline and Storage Throughput
 Three Months Ended
December 31,
(MMcf)20232022Increase
(Decrease)
Firm Transportation200,101 224,623 (24,522)
Interruptible Transportation118 1,308 (1,190)
 200,219 225,931 (25,712)
 
2023 Compared with 2022
 
    Operating revenues for the Pipeline and Storage segment decreased $3.2 million for the quarter ended December 31, 2023 as compared with the quarter ended December 31, 2022.  The decrease in operating revenues was primarily due to a decrease in transportation revenues of $4.6 million, partially offset by an increase in other revenues of $1.3 million. The decrease in transportation revenues is primarily due to contract expirations and revisions combined with a decrease in revenues from an electric surcharge. The increase in other revenues primarily reflects an adjustment to the aforementioned electric surcharge revenues. All customer surcharges and related adjustments for the electric surcharge mechanism are completely offset by an equal amount of electric power costs recorded in operation and maintenance expense.

    Transportation volume for the quarter ended December 31, 2023 decreased by 25.7 Bcf from the prior year's quarter ended December 31, 2022 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,
28

generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

    The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2023 were $24.1 million, a decrease of $5.4 million when compared with earnings of $29.5 million for the quarter ended December 31, 2022. The decrease in earnings was primarily due to the earnings impact of lower operating revenues ($2.6 million), as discussed above, combined with an increase in operating expenses ($1.5 million), an increase in depreciation expense ($0.6 million) and an increase in interest expense ($0.6 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, as discussed above. These increases were partially offset by lower pipeline integrity costs. The increase in depreciation expense was primarily due to certain system modernization projects going into service since the prior-year first quarter. The increase in interest expense is mainly due to an increase in intercompany short-term borrowings.

Gathering
 
Gathering Operating Revenues
 Three Months Ended
December 31,
(Thousands)20232022Increase
(Decrease)
Gathering Revenues$62,588 $56,413 $6,175 

Gathering Volume
 Three Months Ended
December 31,
 20232022Increase
(Decrease)
Gathered Volume - (MMcf)124,261 108,027 16,234 
 
2023 Compared with 2022
 
    Operating revenues for the Gathering segment increased $6.2 million for the quarter ended December 31, 2023 as compared with the quarter ended December 31, 2022, which was driven primarily by a 16.2 Bcf increase in gathered volume. Gathered volume on the Trout Run and Tioga gathering systems increased 12.1 Bcf and 6.3 Bcf, respectively, partially offset by a decrease of 2.2 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.

    The Gathering segment’s earnings for the quarter ended December 31, 2023 were $28.8 million, an increase of $4.1 million when compared with earnings of $24.7 million for the quarter ended December 31, 2022. The increase in earnings was primarily due to higher gathering revenues ($4.9 million) driven by the increase in gathered volume, as discussed above. This increase was partially offset by higher depreciation expense ($0.6 million). The increase in depreciation expense was largely due to additional plant in-service associated with the Tioga and Clermont gathering systems.

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Utility

Utility Operating Revenues
 Three Months Ended
December 31,
(Thousands)20232022Increase
(Decrease)
Retail Sales Revenues:
Residential$149,656 $245,442 $(95,786)
Commercial21,209 35,343 (14,134)
Industrial 911 1,643 (732)
 171,776 282,428 (110,652)
Transportation      30,798 29,512 1,286 
Other(567)(259)(308)
                $202,007 $311,681 $(109,674)

Utility Throughput
Three Months Ended
December 31,
(MMcf)20232022Increase
(Decrease)
Retail Sales:
Residential17,982 20,153 (2,171)
Commercial2,800 2,994 (194)
Industrial138 151 (13)
 20,920 23,298 (2,378)
Transportation17,528 18,310 (782)
 38,448 41,608 (3,160)
 
Degree Days
Three Months Ended December 31,   Percent Colder (Warmer) Than
Normal20232022
Normal(1)
Prior Year(1)
Buffalo, NY2,253 1,858 2,048 (17.5)%(9.3)%
Erie, PA(2)
1,894 1,664 1,987 (12.1)%(16.3)%
 
(1)Percents compare actual 2023 degree days to normal degree days and actual 2023 degree days to actual 2022 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.
 
2023 Compared with 2022
 
    Operating revenues for the Utility segment decreased $109.7 million for the quarter ended December 31, 2023 as compared with the quarter ended December 31, 2022. This decrease resulted from a $110.7 million decrease in retail gas sales revenue and a $0.3 million decrease in other revenues, partially offset by a $1.3 million increase in transportation revenue. The decrease in retail gas sales revenue reflects a decrease in the cost of gas sold (per Mcf) and a 2.4 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. The increase in transportation revenue was also largely attributable to the impact of new base rates in Pennsylvania combined with an increase in revenues earned under the system modernization
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and system improvement tracker mechanisms in Distribution Corporation's New York jurisdiction, which allow for the recovery of investments in leak prone pipe replacement. Additional details regarding the base rate regulatory proceeding in Distribution Corporation's Pennsylvania jurisdiction can be found in the Rate Matters section below.

    The Utility segment’s earnings for the quarter ended December 31, 2023 were $26.6 million, an increase of $2.8 million compared to earnings of $23.8 million for the quarter ended December 31, 2022. The increase was primarily due to the impact of new base rates in the Utility's Pennsylvania jurisdiction ($6.8 million) and lower income tax expense ($1.8 million). The lower income tax expense was largely related to an increase in tax deductions related to certain repairs and maintenance expenditures recorded in the Utility's Pennsylvania jurisdiction as a result of recently updated IRS guidance. These factors were partially offset by higher operating expenses ($3.8 million), primarily due to higher personnel costs, and a decrease in customer usage, primarily due to warmer weather ($2.8 million).

    The impact of weather variations on earnings in the Utility segment is mitigated by a weather normalization clause (WNC). Prior to October 2023, the impact of weather variations on earnings was mitigated by a WNC solely in the Utility segment’s New York rate jurisdiction. However, effective October 2023, the impact of weather variations on earnings is also mitigated by a WNC in the Utility segment’s Pennsylvania rate jurisdiction. The WNC, 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 WNC benefits the Utility segment's customers. For the quarter ended December 31, 2023, the WNC preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $1.4 million and preserved earnings in the Utility segment’s Pennsylvania rate jurisdiction of approximately $0.4 million, as the weather was warmer than normal in both jurisdictions. For the quarter ended December 31, 2022, the WNC preserved earnings in the Utility segment’s New York rate jurisdiction of approximately $0.9 million, as the weather was warmer than normal.

Corporate and All Other
 
2023 Compared with 2022
 
    Corporate and All Other operations had earnings of $1.1 million for the quarter ended December 31, 2023, an increase of $0.6 million when compared with earnings of $0.5 million for the quarter ended December 31, 2022. The increase was primarily attributable to changes in unrealized gains on investments in equity securities. During the quarter ended December 31, 2023, the Company recorded unrealized gains of $0.8 million. During the quarter ended December 31, 2022, the Company recorded unrealized gains of $0.2 million.

Other Income (Deductions)

    Net other income on the Consolidated Statements of Income was $3.7 million for the quarter ended December 31, 2023, compared to net other income of $6.3 million for the quarter ended December 31, 2022, for a decrease of $2.6 million. This decrease can be attributed primarily to a $4.2 million negative mark-to-market valuation adjustment for the contingent consideration received from the sale of Seneca's California assets in June 2022 (compared to a gain of $0.2 million for the quarter ended December 31, 2022), as well as lower interest income of $1.4 million. The decrease in interest income was mainly due to lower interest income from investments and a decrease in interest from hedging collateral for derivative financial instruments. These decreases were partially offset by $2.0 million of business interruption insurance proceeds that Seneca received during the current quarter related to a pipeline outage impacting Seneca's ability to market its gas, along with changes in realized and unrealized gains and losses on investments in equity securities that increased other income by $0.9 million.

Interest Expense on Long-Term Debt
 
    Interest expense on long-term debt on the Consolidated Statement of Income decreased $1.1 million for the quarter ended December 31, 2023 as compared to the quarter ended December 31, 2022. This was primarily due to lower average long-term debt balances. 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.

31

CAPITAL RESOURCES AND LIQUIDITY
 
    The Company’s primary sources of cash during the three-month period ended December 31, 2023 consisted of cash provided by operating activities and net proceeds from short-term borrowings. The Company’s primary sources of cash during the three-month period ended December 31, 2022 consisted of cash provided by operating activities, net 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, cash provided by operating activities is forecasted to be lower than 2023, but is expected to be more than enough to fund the Company's capital expenditures. Looking forward to 2025, based on current commodity prices, cash provided by operating activities is again 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 WNC 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 WNC in its Pennsylvania rate jurisdiction. The Pennsylvania rate jurisdiction WNC resulted from the PaPUC's approved settlement on June 15, 2023, further discussed in the Rate Matters section below.

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

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

    Cash provided by operating activities in the Exploration and Production segment may vary from period to period as a result of changes in the commodity prices of natural gas as well as changes in production.  The Company uses various derivative financial instruments, including price swap agreements and no cost collars, in an attempt to manage this energy commodity price risk.

    Net cash provided by operating activities totaled $270.9 million for the three months ended December 31, 2023, a decrease of $56.4 million compared with $327.3 million provided by operating activities for the three months ended December 31, 2022. The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Exploration and Production segment, partially offset by higher cash provided by operating activities in the Utility segment. The decrease in the Exploration and Production segment is primarily due to lower cash receipts from lower realized natural gas prices. The increase in the Utility segment is primarily due to the timing of gas cost recovery and the timing of customer receivable balance collections.

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Investing Cash Flow
 
Expenditures for Long-Lived Assets
 
    The Company’s expenditures for long-lived assets totaled $235.7 million during the three months ended December 31, 2023 and $223.5 million during the three months ended December 31, 2022.  The table below presents these expenditures:
Total Expenditures for Long-Lived Assets     
Three Months Ended December 31,2023 2022 Increase (Decrease)
(Millions)  
Exploration and Production:     
Capital Expenditures$161.0 (1)$168.5 (2)$(7.5)
Pipeline and Storage:    
Capital Expenditures24.6 (1)16.4 (2)8.2 
Gathering:    
Capital Expenditures19.6 (1)13.3 (2)6.3 
Utility:    
Capital Expenditures30.5 (1)25.3 (2)5.2 
All Other:
Capital Expenditures— — — 
 $235.7  $223.5  $12.2 

(1)At December 31, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $74.9 million, $5.5 million, $11.1 million and $6.4 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 December 31, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $102.9 million, $2.1 million, $1.1 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 three months ended December 31, 2023 were primarily well drilling and completion expenditures in the Appalachian region, and included $37.5 million in the Marcellus Shale area and $120.2 million in the Utica Shale area. These amounts included approximately $106.0 million spent to develop proved undeveloped reserves.

    The Exploration and Production segment capital expenditures for the three months ended December 31, 2022 were primarily well drilling and completion expenditures in the Appalachian region, and included $60.9 million in the Marcellus Shale area and $104.6 million in the Utica Shale area. These amounts included approximately $110.5 million spent to develop proved undeveloped reserves.

Pipeline and Storage
 
    The Pipeline and Storage segment capital expenditures for the three months ended December 31, 2023 and December 31, 2022 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions.

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

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    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’s (“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 the second half of calendar 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 December 31, 2023, $0.2 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at December 31, 2023.

Gathering
 
    The majority of the Gathering segment capital expenditures for the three months ended December 31, 2023 included expenditures related to the continued expansion of Midstream Company's Tioga and Clermont gathering systems. Midstream Company spent $15.7 million and $3.2 million, respectively, during the three months ended December 31, 2023 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 three months ended December 31, 2022 included expenditures related to the continued expansion of Midstream Company's Clermont and Tioga gathering systems. Midstream Company spent $5.7 million and $5.2 million, respectively, during the three months ended December 31, 2022 on the development of the Clermont and Tioga gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines in the Clermont gathering system. In the Tioga gathering system, expenditures were 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 three months ended December 31, 2023 and December 31, 2022 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. 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.

Project Funding
 
    During the quarter ended December 31, 2023 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.

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    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 increased $12.5 million, to a total of $300.0 million, when comparing the balance sheet at December 31, 2023 to the balance sheet at September 30, 2023. The maximum amount of short-term debt outstanding during the three months ended December 31, 2023 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, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. As of December 31, 2023, the Company had outstanding commercial paper of $300.0 million. The Company did not have any short-term notes payable to banks as of December 31, 2023.

    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. On February 7, 2024, the Company and 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.

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

    The 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, which provides that the Company's debt to capitalization ratio will not exceed 0.65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $400 million. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at December 31, 2023, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement. On May 3, 2022, the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modified the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ended June 30, 2022, 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 Credit Agreement, 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 December 31, 2023, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement was 0.45. The constraints specified in the Credit Agreement would have permitted an additional $3.32 billion in short-term and/or long-term debt to be outstanding at December 31, 2023 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
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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 contains 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. 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 December 31, 2023 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 December 31, 2023 and 4.52% at December 31, 2022.

    Under the Company’s existing indenture covenants at December 31, 2023, the Company would have been permitted to issue up to a maximum of approximately $3.83 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, 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 December 31, 2023) 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.

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. The Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project, which is the subject of an ongoing appeal at the U.S. Court of Appeals for the D.C. Circuit. The Company will update the $500 million preliminary cost estimate and expected in-service date for the project when there is
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further clarity on the timing of receipt of necessary regulatory approvals, including the completion of ongoing litigation. As of December 31, 2023, approximately $56.0 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 $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at December 31, 2023.
 
    The Company did not make any contributions to its tax-qualified, noncontributory defined benefit retirement plan (Retirement Plan) during the three months ended December 31, 2023. 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 three months ended December 31, 2023, 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 December 31, 2023, the Company determined that nonperformance risk associated with its natural gas price swap agreements, natural gas no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation.  To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

    For a complete discussion of all other market risk sensitive instruments used by the Company, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2023 Form 10-K.

Rate Matters
 
Utility Operation
 
    Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” As noted below, the New York division currently has a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.
 
New York Jurisdiction
 
    Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017 ("2017 Rate Order"). The 2017 Rate Order provided for a return on equity of 8.7% and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018. On October 31, 2023, Distribution Corporation made a filing with the NYPSC seeking an increase of approximately $88 million in its total annual operating revenues for the projected rate year ending September 30, 2025, with a proposed effective date of October 1, 2024 that includes the maximum suspension period permitted under the New York Public Service
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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.
         
Pipeline and Storage
 
    Supply Corporation filed a NGA Section 4 rate case at FERC on July 31, 2023 proposing rate increases to be effective February 1, 2024. The proposed rates reflect an annual cost of service of $385.4 million, a rate base of $1.32 billion and a proposed cost of equity of 15.12%. If the proposed rate increases finally approved at the end of the proceeding exceed the rates that were in effect at July 31, 2023, but are less than rates put into effect subject to refund on February 1, 2024, Supply Corporation would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2023, such lower rates will become effective prospectively from the effective date provided by the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at July 31, 2023.

    Empire’s 2019 rate settlement provides that Empire must make a rate case filing no later than May 1, 2025.

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
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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. The Company must continue to comply with all applicable regulations. Additionally, a number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The NYPSC, for example, initiated a proceeding to consider climate-related financial disclosures at the utility operating company level, and the New York State legislature passed the CLCPA that mandates reducing greenhouse gas emissions by 40% from 1990 levels by 2030, and by 85% from 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. In May 2023, New York State passed legislation that prohibits the installation of fossil fuel burning equipment and building systems in new buildings commencing on or after December 31, 2025, subject to certain exemptions. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on the promulgation of regulations to implement the CLCPA and on regulatory treatment afforded in the process. The NYDEC, in conjunction with the New York State Energy Research and Development Authority, is also in the early phases of developing a cap-and-invest program in the state, which is anticipated to be effective in 2025. The above-enumerated initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.

Effects of Inflation

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

Safe Harbor for Forward-Looking Statements
 
    The Company is including the following cautionary statement in this Quarterly Report on Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:
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1.Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing;
2.Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design, retained natural gas and system modernization), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal;
3.The Company’s ability to estimate accurately the time and resources necessary to meet emissions targets;
4.Governmental/regulatory actions and/or market pressures to reduce or eliminate reliance on natural gas;
5.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;
6.Changes in the price of natural gas;
7.Impairments under the SEC's full cost ceiling test for natural gas reserves;
8.The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;
9.Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments, including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;
10.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;
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24.Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war, as well as economic and operational disruptions due to third-party outages;
25.Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or
26.Increasing costs of insurance, changes in coverage and the ability to obtain insurance.
    The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.

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

Item 3.  Quantitative and Qualitative Disclosures About Market Risk
 
    Refer to the "Market Risk Sensitive Instruments" section in Item 2 – MD&A.

Item 4.  Controls and Procedures
 
Evaluation of Disclosure Controls and Procedures
 
    The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal 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 Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2023.   
 
Changes in Internal Control Over Financial Reporting
 
    There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended December 31, 2023 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.    
    
Item 2.  Unregistered Sales of Equity Securities and Use of Proceeds
 
    On October 3, 2023, the Company issued a total of 8,570 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
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Officers (the “DCP”), to the DCP trustee), consisting of 857 shares per director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended December 31, 2023. The Company issued an additional 558 unregistered shares in the aggregate on October 13, 2023 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 ShareTotal Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs
Maximum Number of Shares That May Yet Be Purchased Under Share Repurchase Plans or Programs (b)
Oct. 1 - 31, 202310,443 $53.916,971,019
Nov. 1 - 30, 202311,134 $50.806,971,019
Dec. 1 - 31, 202388,473 $50.506,971,019
Total110,050 $50.856,971,019
(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, and (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. During the quarter ended December 31, 2023, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 110,050 shares purchased other than through a publicly announced share repurchase program, 32,956 were purchased for the Company's 401(k) plans and 77,094 were purchased as a result of shares tendered to the Company by holders of stock-based compensation awards.
(b)In September 2008, the Company’s Board of Directors authorized the repurchase of eight million shares of the Company’s common stock. The Company has not repurchased any shares since September 17, 2008. The repurchase program has no expiration date and management would discuss with the Company's Board of Directors any future repurchases under this program.

Item 5.  Other Information

Trading Arrangements

    During the quarter ended December 31, 2023, 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.

Credit Agreement Extension

    On February 7, 2024, in response to the Company's request to extend the maturity date of the Credit Agreement, certain lenders under the Credit Agreement consented to the Company's request (the “Extension”). The Extension modified the stated maturity date of the Credit Agreement, with such Extension applicable for the lenders approving the Extension, from February 26, 2027 to February 25, 2028. After giving effect to the Extension, 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.

Item 6.  Exhibits
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Exhibit
Number
 
Description of Exhibit
10.5
10.6
31.1
31.2
32••
99
101
Interactive data files submitted pursuant to Regulation S-T, formatted in Inline XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income and Earnings Reinvested in the Business for the three months ended December 31, 2023 and 2022, (ii) the Consolidated Statements of Comprehensive Income for the three months ended December 31, 2023 and 2022, (iii) the Consolidated Balance Sheets at December 31, 2023 and September 30, 2023, (iv) the Consolidated Statements of Cash Flows for the three months ended December 31, 2023 and 2022 and (v) the Notes to Condensed Consolidated Financial Statements.
104Cover Page Interactive Data File (embedded within the Inline XBRL document)
••
In accordance with Item 601(b)(32)(ii) of Regulation S-K and SEC Release Nos. 33-8238 and 34-47986, Final Rule: Management’s Reports on Internal Control Over Financial Reporting and Certification of Disclosure in Exchange Act Periodic Reports, the material contained in Exhibit 32 is “furnished” and not deemed “filed” with the SEC and is not to be incorporated by reference into any filing of the Registrant under the Securities Act of 1933 or the Exchange Act, whether made before or after the date hereof and irrespective of any general incorporation language contained in such filing, except to the extent that the Registrant specifically incorporates it by reference.
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SIGNATURES
 
 
 
 
Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.
 
NATIONAL FUEL GAS COMPANY
(Registrant)
 
 
 
 
 
/s/ T. J. Silverstein
T. J. Silverstein
Treasurer and Principal Financial Officer
 
 
 
 
 
/s/ E. G. Mendel
E. G. Mendel
Controller and Principal Accounting Officer
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
 
Date:  February 8, 2024

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