UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

~~[X]~~☑ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended~~December~~ March 31, ~~2017~~2023

~~[ ]~~ ☐TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from____ to_____

Commission File Number 1-3880

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)



New Jersey		13-1086010
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)

6363 Main Street
Williamsville,	New York	14221
(Address of principal executive offices)		(Zip Code)

(716) 857-7000

(Registrant's telephone number, including area code)


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

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. ~~YES~~ þ NO ¨Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ 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 ~~and post~~ such files). ~~YES~~ þ NO ¨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”~~filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act. ~~(Check one):~~



Large Accelerated Filer	þ☑	Accelerated Filer	¨☐
Non-Accelerated Filer	¨~~(Do not check if a smaller reporting company)~~ ☐	Smaller Reporting Company	¨☐
		Emerging Growth Company	¨☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ¨☐

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

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, 2018: 85,801,778~~April 30, 2023: 91,803,996 shares.

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GLOSSARY OF TERMS

Frequently used abbreviations, acronyms, or terms used in this report:



National Fuel Gas Companies
Company		The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Distribution Corporation		National Fuel Gas Distribution Corporation
Empire		Empire Pipeline, Inc.
Midstream ~~Corporation~~Company		National Fuel Gas Midstream ~~Corporation~~Company, LLC
National Fuel		National Fuel Gas Company
~~NFR~~Registrant		~~National Fuel Resources, Inc.~~
~~Registrant~~	National Fuel Gas Company
Seneca		Seneca Resources ~~Corporation~~Company, LLC
Supply Corporation		National Fuel Gas Supply Corporation

~~Regulatory Agencies~~
~~CFTC~~Regulatory Agencies
CFTC			Commodity Futures Trading Commission
EPA			United States Environmental Protection Agency
FASB			Financial Accounting Standards Board
FERC			Federal Energy Regulatory Commission
~~NYDEC~~IRS			Internal Revenue Service
NYDEC			New York State Department of Environmental Conservation
NYPSC			State of New York Public Service Commission
PaDEP			Pennsylvania Department of Environmental Protection
PaPUC			Pennsylvania Public Utility Commission
~~SEC~~PHMSA			Pipeline and Hazardous Materials Safety Administration
SEC			Securities and Exchange Commission



Other
~~2017~~2022 Form 10-K			The Company’s Annual Report on Form 10-K for the year ended September 30, ~~2017~~2022
~~Bbl~~2017 Tax Reform Act			Tax legislation referred to as the "Tax Cuts and Jobs Act," enacted December 22, 2017.
Bbl			Barrel (of oil)
Bcf			Billion cubic feet (of natural gas)
Bcfe (or Mcfe) – represents Bcf (or Mcf) Equivalent			The total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. The Company uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas.
Btu			British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit
Capital expenditure			Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
Cashout revenues			A cash resolution of a gas imbalance whereby a customer (e.g. a marketer) pays for gas the customer receives in excess of amounts delivered into pipeline/storage or distribution systems by the customer’s shipper.
CLCPA			Legislation referred to as the "Climate Leadership & Community Protection Act," enacted by the State of New York on July 18, 2019.
Degree day			A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.

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Derivative			A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, forward contracts, options, no cost collars and swaps.
Development costs			Costs incurred to obtain access to proved oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas
Dodd-Frank Act			Dodd-Frank Wall Street Reform and Consumer Protection Act.

~~Table of Contents~~



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.
EAP		Energy Affordability Program; a program that provides bill discounts to gas customers who receive benefits under qualifying public assistance programs.
Exchange Act		Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets		Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploration costs		Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
Exploratory well		A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
FERC 7(c) application		An application to the FERC under Section 7(c) of the federal Natural Gas Act for authority to construct, operate (and provide services through) facilities to transport or store natural gas in interstate commerce.
Firm transportation and/or storage		The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP		Accounting principles generally accepted in the United States of America
Goodwill		An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging		A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
Hub		Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
ICE		Intercontinental Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Impact Fee		An annual fee imposed on unconventional wells spud in Pennsylvania. The fee is administered by the PaPUC and fees are distributed to counties and municipalities where the well is located.
Interruptible transportation and/or storage		The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LDC		Local distribution company
~~LIBOR~~LIFO		~~London Interbank Offered Rate~~Last-in, first-out
~~LIFO~~		~~Last-in, first-out~~
Marcellus Shale	A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.
Mbbl		Thousand barrels (of oil)
Mcf		Thousand cubic feet (of natural gas)
MD&A		Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth		Thousand decatherms (of natural gas)

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MMBtu		Million British thermal units (heating value of one decatherm of natural gas)
MMcf		Million cubic feet (of natural gas)
~~NEPA~~		~~National Environmental Policy Act of 1969, as amended~~
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.
NYMEX		New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
OPEB		Other Post-Employment Benefit
Open Season		A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.

~~Table of Contents~~



Precedent Agreement	An agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called “conditions precedent”) happen, usually within a specified time.
Proved developed reserves		Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped (PUD) reserves		Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make these reserves productive.
Reserves		The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.
Revenue decoupling mechanism		A rate mechanism which adjusts customer rates to render a utility financially indifferent to throughput decreases resulting from conservation.
S&P		Standard & Poor’s Rating Service
SAR		Stock appreciation right
Service agreement		The binding agreement by which the pipeline company agrees to provide service and the shipper agrees to pay for the service.
SOFR		Secured Overnight Financing Rate
Stock acquisitions		Investments in corporations
Utica Shale		A Middle Ordovician-age geological formation lying several thousand feet below the Marcellus Shale in the Appalachian region of the United States, including much of Ohio, Pennsylvania, West Virginia and southern New York.
VEBA		Voluntary Employees’ Beneficiary Association
~~WNC~~WNC/WNA		Weather normalization ~~clause;~~clause/adjustment; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.

Table of Contents


INDEX		Page

Part I. Financial Information

~~INDEX~~	~~Page~~

~~Part I. Financial Information~~

Item 1. Financial Statements (Unaudited)	6

a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Six Months Ended ~~December~~March 31, ~~2017~~2023 and ~~2016~~ 2022		6
b. Consolidated Statements of Comprehensive Income – Three and Six Months Ended ~~December~~March 31, ~~2017~~2023 and ~~2016~~ 2022		7
c. Consolidated Balance Sheets – ~~December~~March 31, ~~2017~~2023 and September 30, ~~2017~~2022		8
d. Consolidated Statements of Cash Flows – ~~Three~~Six Months Ended ~~December~~March 31, ~~2017~~2023 and ~~2016~~ 2022		10
e. Notes to Condensed Consolidated Financial Statements		11
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		2529
Item 3. Quantitative and Qualitative Disclosures About Market Risk		4249
Item 4. Controls and Procedures		4249

Part II. Other Information

Item 1. Legal Proceedings		4249
Item 1 A. Risk Factors		4349
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		4549
Item 3. Defaults Upon Senior Securities		•
Item 4. Mine Safety Disclosures		•
Item 5. Other Information		•
Item 6. Exhibits		4650
Signatures		4751

• 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.

Table of Contents

Part I. Financial Information

Item 1. Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)


								Three Months Ended March 31,				Six Months Ended March 31,
	Three Months Ended December 31,
(Thousands of Dollars, Except Per Common Share Amounts)	2017			2016
(Thousands of U.S. Dollars, Except Per Common Share Amounts)							(Thousands of U.S. Dollars, Except Per Common Share Amounts)	2023		2022		2023		2022
INCOME							INCOME
Operating Revenues:							Operating Revenues:
Utility and Energy Marketing Revenues	$	225,725		$	207,780
Utility Revenues							Utility Revenues	$	406,758	$	369,092	$	718,376	$	605,776
Exploration and Production and Other Revenues	140,450			161,694			Exploration and Production and Other Revenues	244,552		261,676		521,525		505,957
Pipeline and Storage and Gathering Revenues	53,480			53,026			Pipeline and Storage and Gathering Revenues	65,951		70,952		136,218		136,544
	419,655			422,500				717,261		701,720		1,376,119		1,248,277

Operating Expenses:							Operating Expenses:
Purchased Gas	94,034			70,243			Purchased Gas	243,839		199,592		415,035		301,219
Operation and Maintenance:							Operation and Maintenance:
Utility and Energy Marketing	51,369			50,422
Utility							Utility	56,453		53,476		106,805		100,120
Exploration and Production and Other	35,542			30,461			Exploration and Production and Other	31,782		49,806		58,655		95,425
Pipeline and Storage and Gathering	20,037			22,660			Pipeline and Storage and Gathering	37,479		33,518		70,740		63,446
Property, Franchise and Other Taxes	20,848			20,379			Property, Franchise and Other Taxes	25,367		27,717		51,572		52,219
Depreciation, Depletion and Amortization	55,830			56,196			Depreciation, Depletion and Amortization	100,964		91,245		197,564		179,823
	277,660			250,361
								495,884		455,354		900,371		792,252

Operating Income	141,995			172,139			Operating Income	221,377		246,366		475,748		456,025
Other Income (Expense):							Other Income (Expense):
Interest Income	2,249			1,600
Other Income	1,722			1,614

Other Income (Deductions)							Other Income (Deductions)	2,884		10,018		9,203		8,940
Interest Expense on Long-Term Debt	(28,087		)	(29,103		)	Interest Expense on Long-Term Debt	(27,583)		(30,079)		(57,188)		(60,209)
Other Interest Expense	(502		)	(910		)	Other Interest Expense	(5,861)		(1,519)		(9,704)		(2,680)
Income Before Income Taxes	117,377			145,340			Income Before Income Taxes	190,817		224,786		418,059		402,076
Income Tax Expense (Benefit)	(81,277		)	56,432
Income Tax Expense							Income Tax Expense	49,937		57,458		107,489		102,356

Net Income Available for Common Stock	198,654			88,908			Net Income Available for Common Stock	140,880		167,328		310,570		299,720

EARNINGS REINVESTED IN THE BUSINESS							EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	851,669			676,361			Balance at Beginning of Period	1,713,176		1,281,963		1,587,085		1,191,175
	1,050,323			765,269				1,854,056		1,449,291		1,897,655		1,490,895

Dividends on Common Stock	(35,590		)	(34,544		)	Dividends on Common Stock	(43,602)		(41,608)		(87,201)		(83,212)
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation	—			31,916
Balance at December 31	$	1,014,733		$	762,641

Balance at March 31							Balance at March 31	$	1,810,454	$	1,407,683	$	1,810,454	$	1,407,683

Earnings Per Common Share:							Earnings Per Common Share:
Basic:							Basic:
Net Income Available for Common Stock	$	2.32		$	1.04		Net Income Available for Common Stock	$	1.53	$	1.83	$	3.39	$	3.28
Diluted:							Diluted:
Net Income Available for Common Stock	$	2.30		$	1.04		Net Income Available for Common Stock	$	1.53	$	1.82	$	3.37	$	3.26
Weighted Average Common Shares Outstanding:							Weighted Average Common Shares Outstanding:
Used in Basic Calculation	85,630,296			85,189,851			Used in Basic Calculation	91,794,765		91,444,638		91,686,110		91,354,488
Used in Diluted Calculation	86,325,537			85,797,989			Used in Diluted Calculation	92,256,348		92,064,711		92,264,717		92,047,467
Dividends Per Common Share:							Dividends Per Common Share:
Dividends Declared	$	0.415		$	0.405		Dividends Declared	$	0.475	$	0.455	$	0.950	$	0.910

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)

Three Months Ended
December 31,
(Thousands of Dollars) 2017 2016
Net Income Available for Common Stock $ 198,654
$ 88,908
Other Comprehensive Income (Loss), Before Tax:

Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period (44 ) (883 )
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period (5,499 ) (52,501 )
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income (430 ) (741 )
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income (12,548 ) (30,717 )
Other Comprehensive Loss, Before Tax (18,521 ) (84,842 )
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period (65 ) (344 )
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period (2,305 ) (22,052 )
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income (158 ) (273 )
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income (5,197 ) (12,954 )
Income Taxes – Net (7,725 ) (35,623 )
Other Comprehensive Loss (10,796 ) (49,219 )
Comprehensive Income $ 187,858
$ 39,689


	Three Months Ended March 31,				Six Months Ended March 31,
(Thousands of U.S. Dollars)	2023		2022		2023		2022
Net Income Available for Common Stock	$	140,880	$	167,328	$	310,570	$	299,720
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	310,544		(641,606)		608,137		(478,474)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	18,940		130,221		178,281		292,809


Other Post-Retirement Adjustment for Regulatory Proceeding	—		(7,351)		—		(7,351)
Other Comprehensive Income (Loss), Before Tax	329,484		(518,736)		786,418		(193,016)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	85,394		(175,605)		166,770		(130,956)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	5,208		35,641		48,779		80,141



Income Tax Expense (Benefit) Related to Other Post-Retirement Adjustment for Regulatory Proceeding	—		(1,544)		—		(1,544)
Income Taxes – Net	90,602		(141,508)		215,549		(52,359)
Other Comprehensive Income (Loss)	238,882		(377,228)		570,869		(140,657)
Comprehensive Income (Loss)	$	379,762	$	(209,900)	$	881,439	$	159,063

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	March 31, 2023		September 30, 2022
(Thousands of U.S. Dollars)
ASSETS
Property, Plant and Equipment	$	12,978,137	$	12,551,909
Less - Accumulated Depreciation, Depletion and Amortization	6,162,406		5,985,432
	6,815,731		6,566,477

Current Assets
Cash and Temporary Cash Investments	71,533		46,048
Hedging Collateral Deposits	—		91,670
Receivables – Net of Allowance for Uncollectible Accounts of $48,146 and $40,228, Respectively	257,965		361,626
Unbilled Revenue	60,018		30,075
Gas Stored Underground	6,554		32,364
Materials and Supplies - at average cost	45,204		40,637
Unrecovered Purchased Gas Costs	26,851		99,342
Other Current Assets	75,233		59,369
	543,358		761,131

Other Assets
Recoverable Future Taxes	104,426		106,247
Unamortized Debt Expense	8,062		8,884
Other Regulatory Assets	61,497		67,101
Deferred Charges	85,053		77,472
Other Investments	74,618		95,025
Goodwill	5,476		5,476
Prepaid Pension and Post-Retirement Benefit Costs	224,701		196,597
Fair Value of Derivative Financial Instruments	42,424		9,175
Other	1,896		2,677
	608,153		568,654

Total Assets	$	7,967,242	$	7,896,262

December 31,
2017 September 30, 2017
(Thousands of Dollars)
ASSETS
Property, Plant and Equipment $ 10,023,252
$ 9,945,560
Less - Accumulated Depreciation, Depletion and Amortization 5,294,211
5,271,486
4,729,041
4,674,074
Current Assets

Cash and Temporary Cash Investments 166,289
555,530
Hedging Collateral Deposits 4,465
1,741
Receivables – Net of Allowance for Uncollectible Accounts of $24,511 and $22,526, Respectively 161,029
112,383
Unbilled Revenue 74,790
22,883
Gas Stored Underground 24,139
35,689
Materials and Supplies - at average cost 35,139
33,926
Unrecovered Purchased Gas Costs 7,787
4,623
Other Current Assets 47,914
51,505
            521,552
818,280

Other Assets

Recoverable Future Taxes 116,792
181,363
Unamortized Debt Expense 8,148
1,159
Other Regulatory Assets 174,577
174,433
Deferred Charges 34,063
30,047
Other Investments 123,368
125,265
Goodwill 5,476
5,476
Prepaid Post-Retirement Benefit Costs 57,054
56,370
Fair Value of Derivative Financial Instruments 21,107
36,111
Other                   754
742
                    541,339
610,966

Total Assets $ 5,791,932
$ 6,103,320

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


								March 31, 2023		September 30, 2022
	December 31, 2017			September 30, 2017
(Thousands of Dollars)
(Thousands of U.S. Dollars)							(Thousands of U.S. Dollars)
CAPITALIZATION AND LIABILITIES							CAPITALIZATION AND LIABILITIES
Capitalization:							Capitalization:
Comprehensive Shareholders’ Equity							Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value							Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued And Outstanding – 85,760,846 Shares and 85,543,125 Shares, Respectively	$	85,761		$	85,543
Authorized - 200,000,000 Shares; Issued And Outstanding – 91,795,080 Shares and 91,478,064 Shares, Respectively							Authorized - 200,000,000 Shares; Issued And Outstanding – 91,795,080 Shares and 91,478,064 Shares, Respectively	$	91,795	$	91,478
Paid in Capital	800,348			796,646			Paid in Capital	1,031,341		1,027,066
Earnings Reinvested in the Business	1,014,733			851,669			Earnings Reinvested in the Business	1,810,454		1,587,085
Accumulated Other Comprehensive Loss	(40,919		)	(30,123		)	Accumulated Other Comprehensive Loss	(54,864)		(625,733)
Total Comprehensive Shareholders’ Equity	1,859,923			1,703,735			Total Comprehensive Shareholders’ Equity	2,878,726		2,079,896
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,084,465			2,083,681			Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,085,235		2,083,409
Total Capitalization	3,944,388			3,787,416			Total Capitalization	4,963,961		4,163,305

Current and Accrued Liabilities							Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	—			—			Notes Payable to Banks and Commercial Paper	410,000		60,000
Current Portion of Long-Term Debt	—			300,000			Current Portion of Long-Term Debt	—		549,000
Accounts Payable	132,409			126,443			Accounts Payable	119,497		178,945
Amounts Payable to Customers	251			—			Amounts Payable to Customers	2,830		419
Dividends Payable	35,590			35,500			Dividends Payable	43,602		43,452
Interest Payable on Long-Term Debt	27,962			35,031			Interest Payable on Long-Term Debt	14,303		17,376
Customer Advances	18,398			15,701			Customer Advances	—		26,108
Customer Security Deposits	22,503			20,372			Customer Security Deposits	34,382		24,283
Other Accruals and Current Liabilities	121,596			111,889			Other Accruals and Current Liabilities	257,923		257,327
Fair Value of Derivative Financial Instruments	6,579			1,103			Fair Value of Derivative Financial Instruments	34,763		785,659
	365,288			646,039				917,300		1,942,569

Deferred Credits
Other Liabilities							Other Liabilities
Deferred Income Taxes	453,285			891,287			Deferred Income Taxes	1,000,526		698,229
Taxes Refundable to Customers	366,768			95,739			Taxes Refundable to Customers	354,274		362,098

Cost of Removal Regulatory Liability	205,554			204,630			Cost of Removal Regulatory Liability	265,626		259,947
Other Regulatory Liabilities	118,551			113,716			Other Regulatory Liabilities	189,378		188,803
Pension and Other Post-Retirement Liabilities	125,055			149,079
Other Post-Retirement Liabilities							Other Post-Retirement Liabilities	2,977		3,065
Asset Retirement Obligations	106,516			106,395			Asset Retirement Obligations	160,910		161,545
Other Deferred Credits	106,527			109,019
Other Liabilities							Other Liabilities	112,290		116,701
	1,482,256			1,669,865				2,085,981		1,790,388
Commitments and Contingencies (Note 6)	—			—
Commitments and Contingencies (Note 8)							Commitments and Contingencies (Note 8)	—		—

Total Capitalization and Liabilities	$	5,791,932		$	6,103,320		Total Capitalization and Liabilities	$	7,967,242	$	7,896,262

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended March 31,
(Thousands of U.S. Dollars)	2023		2022
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	310,570	$	299,720
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:


Depreciation, Depletion and Amortization	197,564		179,823
Deferred Income Taxes	80,745		94,212


Stock-Based Compensation	11,286		10,631
Reduction of Other Post-Retirement Regulatory Liability	—		(18,533)
Other	10,758		14,494
Change in:
Receivables and Unbilled Revenue	71,760		(166,584)
Gas Stored Underground and Materials, Supplies and Emission Allowances	21,243		32,040
Unrecovered Purchased Gas Costs	72,491		29,377
Other Current Assets	(15,864)		(8,605)
Accounts Payable	(29,169)		2,006
Amounts Payable to Customers	2,411		3,401
Customer Advances	(26,108)		(17,223)
Customer Security Deposits	10,099		1,474
Other Accruals and Current Liabilities	28,741		11,164
Other Assets	(26,901)		(32,659)
Other Liabilities	(8,417)		(9,119)
Net Cash Provided by Operating Activities	711,209		425,619

INVESTING ACTIVITIES
Capital Expenditures	(496,362)		(415,415)
Net Proceeds from Sale of Oil and Gas Producing Properties	—		13,525

Deposit Paid for Upstream Assets	(12,700)		—
Sale of Fixed Income Mutual Fund Shares in Grantor Trust	10,000		30,000
Other	14,413		13,689
Net Cash Used in Investing Activities	(484,649)		(358,201)

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

Net Change in Other Short-Term Notes Payable to Banks and Commercial Paper	100,000		59,500


Reduction of Long-Term Debt	(549,000)		—
Dividends Paid on Common Stock	(87,051)		(83,091)
Net Repurchases of Common Stock	(6,694)		(9,026)
Net Cash Used in Financing Activities	(292,745)		(32,617)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	(66,185)		34,801
Cash, Cash Equivalents, and Restricted Cash at October 1	137,718		120,138
Cash, Cash Equivalents, and Restricted Cash at March 31	$	71,533	$	154,939

Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$	64,495	$	63,490

                                                         Three Months Ended
December 31,
(Thousands of Dollars)                                   2017 2016
OPERATING ACTIVITIES

Net Income Available for Common Stock $ 198,654
$ 88,908
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:

Depreciation, Depletion and Amortization 55,830
56,196
Deferred Income Taxes (94,676 ) 44,852
Stock-Based Compensation 3,905
2,482
Other 3,678
3,607
Change in:

Hedging Collateral Deposits (2,724 ) 1,484
Receivables and Unbilled Revenue (83,357 ) (67,395 )
Gas Stored Underground and Materials and Supplies 10,337
10,597
Unrecovered Purchased Gas Costs (3,164 ) (1,257 )
Other Current Assets 3,591
9,576
Accounts Payable 13,173
18,805
Amounts Payable to Customers 251
(16,306 )
Customer Advances 2,697
(983 )
Customer Security Deposits 2,131
673
Other Accruals and Current Liabilities 11,532
5,919
Other Assets (5,275 ) (8,389 )
Other Liabilities (21,775 ) (4,122 )
Net Cash Provided by Operating Activities 94,808
144,647

INVESTING ACTIVITIES

Capital Expenditures (142,613 ) (106,053 )
Net Proceeds from Sale of Oil and Gas Producing Properties —
5,759
Other                                              2,612
(4,297 )
Net Cash Used in Investing Activities (140,001 ) (104,591 )

FINANCING ACTIVITIES

Reduction of Long-Term Debt (307,047 ) —
Dividends Paid on Common Stock (35,500 ) (34,473 )
Net Proceeds from Issuance (Repurchase) of Common Stock (1,501 ) 938
Net Cash Used in Financing Activities (344,048 ) (33,535 )
Net Increase (Decrease) in Cash and Temporary Cash Investments
(389,241 ) 6,521

Cash and Temporary Cash Investments at October 1 555,530
129,972
Cash and Temporary Cash Investments at December 31 $ 166,289
$ 136,493

Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:

Non-Cash Capital Expenditures $ 56,116
$ 48,965
Receivable from Sale of Oil and Gas Producing Properties $ 17,310
$ 20,795

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 -– Summary of Significant Accounting Policies

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

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

Earnings for Interim Periods. The Company, in its opinion, has included all adjustments (which consist of only normally recurring adjustments, unless otherwise disclosed in this Quarterly Report on Form 10-Q) that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, ~~2017, 2016~~2022, 2021 and ~~2015~~2020 that are included in the Company's ~~2017~~2022 Form 10-K. The consolidated financial statements for the year ended September 30, ~~2018~~2023 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.

The earnings for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2023 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, ~~2018~~.2023. Most of the business of the Utility ~~and Energy Marketing segments~~segment is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility ~~and Energy Marketing segments,~~segment, earnings during the winter months normally represent a substantial part of the earnings that ~~those segments are~~this business is expected to achieve for the entire fiscal year. The Company’s business segments are discussed more fully in Note 79 – Business Segment Information.

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


	Six Months Ended March 31, 2023				Six Months Ended March 31, 2022
	Balance at March 31, 2023		Balance at October 1, 2022		Balance at March 31, 2022		Balance at October 1, 2021

Cash and Temporary Cash Investments	$	71,533	$	46,048	$	52,569	$	31,528
Hedging Collateral Deposits	—		91,670		102,370		88,610
Cash, Cash Equivalents, and Restricted Cash	$	71,533	$	137,718	$	154,939	$	120,138

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~~. This~~ 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 ~~hedging positions.~~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 are charged 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.

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


	Balance at Beginning of Period		Additions Charged to Costs and Expenses		Discounts on Purchased Receivables		Net Accounts Receivable Written-Off		Balance at End of Period
Six Months Ended March 31, 2023
Allowance for Uncollectible Accounts	$	40,228	$	10,973	$	916	$	(3,971)	$	48,146
Six Months Ended March 31, 2022
Allowance for Uncollectible Accounts	$	31,639	$	9,684	$	790	$	(630)	$	41,483

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 ~~$1.7~~$106.8 million at ~~December~~March 31, ~~2017,~~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 $2.2 billion and $1.9 billion at March 31, 2023 and September 30, 2022, 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 ~~$77.1~~$73.0 million and ~~$80.9~~$66.0 million at ~~December~~March 31, ~~2017~~2023 and September 30, ~~2017,~~2022, 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

~~Table of Contents~~

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 ~~unevaluated~~unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The ~~natural~~ 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~~March 31, ~~2017,~~2023, the ceiling exceeded the book value of the oil and gas properties by approximately ~~$334.6 million. In adjusting~~$2.7 billion. The estimated future net cash flows were decreased by $936.8 million for hedging under the ceiling test at ~~December~~March 31, ~~2017, estimated future net cash flows~~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 ~~increased by $18.0 million.~~

~~On December 1, 2015, Seneca~~no indications of any impairments to property, plant and IOG - CRV Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participateequipment in the ~~development~~Utility, Pipeline and Storage and Gathering segments at March 31, 2023.

Table of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension of the joint development agreement. Under the terms of the extended agreement, Seneca and IOG will jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80% working interest in all of the joint development wells. In total, IOG is expected to fund approximately $305 million for its 80% working interest in the 75 joint development wells. Of this amount, IOG has funded $267.1 million as of December 31, 2017, which includes $163.9 million of cash ($137.3 million in fiscal 2016 and $26.6 million in fiscal 2017) shown as Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statements of Cash Flows for fiscal 2016 and fiscal 2017. Such proceeds from sale represent funding received from IOG for costs previously incurred by Seneca to develop a portion of the 75 joint development wells. A receivable of $17.3 million has been recorded at December 31, 2017 in recognition of additional IOG funding that is due to Seneca for costs incurred by Seneca to develop a portion of the 75 joint development wells. This receivable has been shown as a Non-Cash Investing Activity on the Consolidated Statement of Cash Flows for the quarter ended December 31, 2017. As the fee-owner of the property’s mineral rights, Seneca currently retains a 7.5% royalty interest and the remaining 20% working interest (26% net revenue interest) in 56 of the joint development wells. In the remaining 19 wells, Seneca retains a 20% working and net revenue interest. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return.Contents

Accumulated Other Comprehensive Loss.The components of Accumulated Other Comprehensive Loss and changes for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2023 and ~~2016,~~2022, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):


	Gains and Losses on Derivative Financial Instruments		Funded Status of the Pension and Other Post-Retirement Benefit Plans		Total
Three Months Ended March 31, 2023
Balance at January 1, 2023	$	(240,176)	$	(53,570)	$	(293,746)
Other Comprehensive Gains and Losses Before Reclassifications	225,150		—		225,150
Amounts Reclassified From Other Comprehensive Income	13,732		—		13,732

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


Balance at March 31, 2023	$	(1,294)	$	(53,570)	$	(54,864)
Three Months Ended March 31, 2022
Balance at January 1, 2022	$	(213,391)	$	(63,635)	$	(277,026)
Other Comprehensive Gains and Losses Before Reclassifications	(466,001)		—		(466,001)
Amounts Reclassified From Other Comprehensive Loss	94,580		—		94,580
Other Post-Retirement Adjustment for Regulatory Proceeding	—		(5,807)		(5,807)
Balance at March 31, 2022	$	(584,812)	$	(69,442)	$	(654,254)
Six Months Ended March 31, 2022
Balance at October 1, 2021	$	(449,962)	$	(63,635)	$	(513,597)
Other Comprehensive Gains and Losses Before Reclassifications	(347,518)		—		(347,518)
Amounts Reclassified From Other Comprehensive Loss	212,668		—		212,668
Other Post-Retirement Adjustment for Regulatory Proceeding	—		(5,807)		(5,807)


Balance at March 31, 2022	$	(584,812)	$	(69,442)	$	(654,254)

During the quarter ended March 31, 2022, the PaPUC concluded a regulatory proceeding that addressed the recovery of other post-employment benefit (“OPEB”) expenses in Distribution Corporation's Pennsylvania service territory. As a result of that proceeding, Distribution Corporation suspended regulatory accounting for OPEB expenses in Pennsylvania and a regulatory deferral of $7.4 million ($5.8 million after-tax) related to the funded status of Distribution Corporation’s other post-retirement benefit plans in Pennsylvania was reclassified to accumulated other comprehensive loss. For further discussion of this regulatory proceeding, refer to Note 11 — Regulatory Matters under the heading “Pennsylvania Jurisdiction.”

Gains and Losses on Derivative Financial Instruments Gains and Losses on Securities Available for Sale Funded Status of the Pension and Other Post-Retirement Benefit Plans Total
Three Months Ended December 31, 2017
Balance at October 1, 2017 $ 20,801
$ 7,562
$ (58,486 ) $ (30,123 )
Other Comprehensive Gains and Losses Before Reclassifications (3,194 ) 21
—
(3,173 )
Amounts Reclassified From Other Comprehensive Loss (7,351 ) (272 ) —
(7,623 )
Balance at December 31, 2017 $ 10,256
$ 7,311
$ (58,486 ) $ (40,919 )
Three Months Ended December 31, 2016
Balance at October 1, 2016 $ 64,782
$ 6,054
$ (76,476 ) $ (5,640 )
Other Comprehensive Gains and Losses Before Reclassifications (30,449 ) (539 ) —
(30,988 )
Amounts Reclassified From Other Comprehensive Loss (17,763 ) (468 ) —
(18,231 )
Balance at December 31, 2016 $ 16,570
$ 5,047
$ (76,476 ) $ (54,859 )

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Reclassifications Outof Accumulated Other Comprehensive Loss. The details about the reclassification adjustments out of accumulated other comprehensive loss for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2023 and ~~2016~~2022 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):


Details About Accumulated Other Comprehensive Loss Components	Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss				Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended March 31,		Six Months Ended March 31,
	2023	2022	2023	2022
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts	($18,768)	($130,271)	($177,930)	($292,899)	Operating Revenues

Foreign Currency Contracts	(172)	50	(351)	90	Operating Revenues
	(18,940)	(130,221)	(178,281)	(292,809)	Total Before Income Tax
	5,208	35,641	48,779	80,141	Income Tax Expense
	($13,732)	($94,580)	($129,502)	($212,668)	Net of Tax

Details About Accumulated Other Comprehensive Loss Components Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss Affected Line Item in the Statement Where Net Income is Presented
Three Months Ended December 31,
2017 2016
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
     Commodity Contracts
$12,842

$31,320
Operating Revenues
     Commodity Contracts 196
(460 ) Purchased Gas
     Foreign Currency Contracts (490 ) (143 ) Operation and Maintenance Expense
Gains (Losses) on Securities Available for Sale 430
741
Other Income
12,978
31,458
Total Before Income Tax
(5,355 ) (13,227 ) Income Tax Expense

$7,623

$18,231
Net of Tax

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


	At March 31, 2023		At September 30, 2022

Prepayments	$	14,821	$	17,757
Prepaid Property and Other Taxes	23,218		14,321

Prepaid State Income Taxes	5,132		5,933

Regulatory Assets	32,062		21,358
	$	75,233	$	59,369

At December 31, 2017 At September 30, 2017

Prepayments $ 7,259
$ 10,927
Prepaid Property and Other Taxes 14,972
13,974
State Income Taxes Receivable 9,164
9,689
Fair Values of Firm Commitments 3,218
1,031
Regulatory Assets 13,301
15,884
$ 47,914
$ 51,505

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


	At December 31, 2017		At September 30, 2017			At March 31, 2023		At September 30, 2022

Accrued Capital Expenditures	$	28,488	$	37,382	Accrued Capital Expenditures	$	39,232	$	64,720
Regulatory Liabilities	38,920		34,059		Regulatory Liabilities	39,662		31,293
Reserve for Gas Replacement	1,739		—		Reserve for Gas Replacement	106,835		—
Federal Income Taxes Payable	8,688		1,775
2017 Tax Reform Act Refund	6,000		—
Liability for Royalty and Working Interests					Liability for Royalty and Working Interests	14,365		86,206

Non-Qualified Benefit Plan Liability					Non-Qualified Benefit Plan Liability	17,474		17,474
Other	37,761		38,673		Other	40,355		57,634
	$	121,596	$	111,889		$	257,923	$	257,327

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 ~~has~~had outstanding ~~are stock options, SARs,~~were restricted stock units and performance shares. For the quarter and six months ended ~~December~~March 31, ~~2017,~~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. ~~Stock options, SARs, restricted~~Restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were ~~157,603~~9,909 securities and ~~317,686~~4,094 securities

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excluded as being antidilutive for the quarter and six months ended March 31, 2023, respectively. There were 13,815 securities and 11,883 securities excluded as being antidilutive for the ~~quarters~~quarter and six months ended ~~December~~March 31, ~~2017 and December 31, 2016,~~2022, respectively.

~~Table of Contents~~

Stock-Based Compensation. The Company granted ~~208,588~~202,259 performance shares during the ~~quarter~~six months ended ~~December~~March 31, ~~2017.~~2023. The weighted average fair value of such performance shares was ~~$50.95~~$64.28 per share for the ~~quarter~~six months ended ~~December~~March 31, ~~2017.~~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.

~~Half of the~~ The performance shares granted during the ~~quarter~~six months ended ~~December~~March 31, ~~2017~~2023 include awards that must meet a performance goal related to either relative return on capital over ~~the~~a three-year performance cycle ~~of October 1, 2017 to September 30, 2020.~~("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 performance cycle ("TSR performance shares"). The performance goal related to the ROC performance shares over the three-year performance cycle is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”). Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each ~~twelve month~~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 ~~these~~the ROC performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award.

The ~~other half of the performance shares granted during the quarter ended December 31, 2017 must meet a~~ performance goal related to ~~relative total shareholder return~~the ESG performance shares over the three-year performance cycle consists of ~~October 1, 2017~~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 ~~September 30, 2020.~~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 three-year performance cycle is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group. Three-year total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these ~~total shareholder return~~TSR performance shares ~~("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 ~~89,672 non-performance based~~115,073 restricted stock units during the ~~quarter~~six months ended ~~December~~March 31, ~~2017.~~2023. The weighted average fair value of such ~~non-performance based~~ restricted stock units was ~~$51.23~~$59.69 per share for the ~~quarter~~six months ended ~~December~~March 31, ~~2017.~~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 ~~non-performance based~~ restricted stock units do not entitle the participant to receive dividends during the vesting period. The ~~accounting for non-performance based restricted stock units is the same as the accounting for restricted share awards, except that 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 – Asset Acquisitions and Divestitures

On March 22, 2023, the Company entered into a purchase and sale agreement to acquire certain upstream assets located in Potter and Tioga counties, Pennsylvania from SWN Production Company, LLC effective as of January 1, 2023 for total consideration of $127.0 million, subject to certain purchase price adjustments at closing. These assets are contiguous with existing Company-owned upstream assets in Pennsylvania. The Company made a deposit of $12.7 million at the signing of the purchase and sale agreement and intends to finance the remaining acquisition cost using short and/or long-term borrowings. The transaction is expected to close before the end of June 2023.

On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which are in the Exploration and Production segment, to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing. The Company pursued this sale given the strong commodity price environment and the Company's strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can 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 sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances. The Company also eliminated the asset retirement obligation associated with Seneca’s California oil and gas assets. This obligation amounted to $50.1 million and was accounted for as a reduction of capitalized costs under the full cost method of accounting.

Note 3 – Revenue from Contracts with Customers

~~New Authoritative Accounting~~ The following tables provide a disaggregation of the Company's revenues for the quarter and ~~Financial Reporting Guidance.~~ ~~In May 2014,~~six months ended March 31, 2023 and 2022, presented by type of service from each reportable segment.


Quarter Ended March 31, 2023 (Thousands)
Revenues By Type of Service	Exploration and Production		Pipeline and Storage		Gathering		Utility		All Other		Corporate and Intersegment Eliminations		Total Consolidated
Production of Natural Gas	$	259,770	$	—	$	—	$	—	$	—	$	—	$	259,770
Production of Crude Oil	526		—		—		—		—		—		526
Natural Gas Processing	209		—		—		—		—		—		209
Natural Gas Gathering Service	—		—		56,981		—		—		(55,253)		1,728
Natural Gas Transportation Service	—		73,794		—		35,796		—		(21,751)		87,839
Natural Gas Storage Service	—		21,470		—		—		—		(9,219)		12,251
Natural Gas Residential Sales	—		—		—		318,649		—		—		318,649
Natural Gas Commercial Sales	—		—		—		48,966		—		—		48,966
Natural Gas Industrial Sales	—		—		—		2,768		—		(4)		2,764

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

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Six Months Ended March 31, 2023 (Thousands)
Revenues By Type of Service	Exploration and Production		Pipeline and Storage		Gathering		Utility		All Other		Corporate and Intersegment Eliminations		Total Consolidated
Production of Natural Gas	$	692,129	$	—	$	—	$	—	$	—	$	—	$	692,129
Production of Crude Oil	1,154		—		—		—		—		—		1,154
Natural Gas Processing	583		—		—		—		—		—		583
Natural Gas Gathering Service	—		—		113,394		—		—		(109,020)		4,374
Natural Gas Transportation Service	—		149,996		—		64,174		—		(42,568)		171,602
Natural Gas Storage Service	—		42,756		—		—		—		(18,215)		24,541
Natural Gas Residential Sales	—		—		—		562,955		—		—		562,955
Natural Gas Commercial Sales	—		—		—		83,461		—		—		83,461
Natural Gas Industrial Sales	—		—		—		4,407		—		(4)		4,403

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


Quarter Ended March 31, 2022 (Thousands)
Revenues By Type of Service	Exploration and Production		Pipeline and Storage		Gathering		Utility		All Other		Corporate and Intersegment Eliminations		Total Consolidated
Production of Natural Gas	$	335,961	$	—	$	—	$	—	$	—	$	—	$	335,961
Production of Crude Oil	49,613		—		—		—		—		—		49,613
Natural Gas Processing	985		—		—		—		—		—		985
Natural Gas Gathering Service	—		—		52,604		—		—		(49,447)		3,157
Natural Gas Transportation Service	—		72,671		—		41,483		—		(18,233)		95,921
Natural Gas Storage Service	—		21,451		—		—		—		(9,253)		12,198
Natural Gas Residential Sales	—		—		—		287,027		—		—		287,027
Natural Gas Commercial Sales	—		—		—		43,193		—		—		43,193
Natural Gas Industrial Sales	—		—		—		2,193		—		—		2,193

Other	5,305		1,275		—		(4,147)		—		(143)		2,290
Total Revenues from Contracts with Customers	391,864		95,397		52,604		369,749		—		(77,076)		832,538
Alternative Revenue Programs	—		—		—		(547)		—		—		(547)
Derivative Financial Instruments	(130,271)		—		—		—		—		—		(130,271)
Total Revenues	$	261,593	$	95,397	$	52,604	$	369,202	$	—	$	(77,076)	$	701,720

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Six Months Ended March 31, 2022 (Thousands)
Revenues By Type of Service	Exploration and Production		Pipeline and Storage		Gathering		Utility		All Other		Corporate and Intersegment Eliminations		Total Consolidated
Production of Natural Gas	$	697,242	$	—	$	—	$	—	$	—	$	—	$	697,242
Production of Crude Oil	91,984		—		—		—		—		—		91,984
Natural Gas Processing	2,013		—		—		—		—		—		2,013
Natural Gas Gathering Service	—		—		104,829		—		—		(97,627)		7,202
Natural Gas Transportation Service	—		138,940		—		69,257		—		(35,858)		172,339
Natural Gas Storage Service	—		42,251		—		—		—		(18,278)		23,973
Natural Gas Residential Sales	—		—		—		466,038		—		—		466,038
Natural Gas Commercial Sales	—		—		—		67,191		—		—		67,191
Natural Gas Industrial Sales	—		—		—		3,340		—		—		3,340

Other	7,451		2,556		—		(6,147)		6		(293)		3,573
Total Revenues from Contracts with Customers	798,690		183,747		104,829		599,679		6		(152,056)		1,534,895
Alternative Revenue Programs	—		—		—		6,281		—		—		6,281
Derivative Financial Instruments	(292,899)		—		—		—		—		—		(292,899)
Total Revenues	$	505,791	$	183,747	$	104,829	$	605,960	$	6	$	(152,056)	$	1,248,277

The Company records revenue related to its derivative financial instruments in the ~~FASB issued~~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. The authoritative guidance provides a single, comprehensive revenue~~ recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The original effective date of this authoritative guidance was as of the Company's first quarter of fiscal 2018. However, the FASB has delayed the effective date of the new revenue standard by one year, and the guidance will now be effective as of the Company's first quarter of fiscal 2019. Working towards this implementation date, the Company is currently evaluating the guidance and the various issues identified by industry based revenue recognition task forces. The Company does not believe that its revenue recognition policies will change materially, although the Company is still assessing the impact. The Company will need to enhance its financial statement disclosures to comply with the new authoritative guidance.

In February 2016, the FASB issued authoritative guidance requiring organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, regardless of whethersince they are ~~considered to be capital leases or operating leases.~~accounted for under other existing accounting guidance.

The FASB’s previous authoritative guidance required organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by capital leases while excluding operating leases from balance sheet recognition. The new authoritative guidance will be effective as of the Company’s ~~first quarter of fiscal 2020, with early adoption permitted. The Company does not anticipate early adoption and is currently evaluating the provisions of the revised guidance.~~

~~Table of Contents~~

In March 2016, the FASB issued authoritative guidance simplifying several aspects of the accounting for stock-based compensation. The Company adopted this guidance effective as of October 1, 2016, recognizing a cumulative effect adjustment that increased retained earnings by $31.9 million. The cumulative effect represents the tax benefit of previously unrecognized tax deductions in excess of stock compensation recorded for financial reporting purposes. On a prospective basis, the tax effect of all future differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation will be recognized upon vesting or settlement as income tax expense or benefit in the income statement. From a statement of cash flows perspective, the tax benefits relating to differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation are now included in cash provided by operating activities instead of cash provided by financing activities. The changes to the statement of cash flows were applied prospectively at the time of adoption.

In March 2017, the FASB issued authoritative guidance related to the presentation of net periodic pension cost and net periodic postretirement benefit cost. The new guidance requires segregation of the service cost component from the other components of net periodic pension cost and net periodic postretirement benefit cost for financial reporting purposes. The service cost component is to be presented on the income statement in the same line items as other compensation costs included within Operating Expenses and the other components of net periodic pension cost and net periodic postretirement benefit cost are to be presented on the income statement below the subtotal labeled Operating Income (Loss). Under this guidance, the service cost component shall be the only component eligible to be capitalized as part of the cost of inventory or property, plant and equipment. The new guidance will be effective as of the Company’s first quarter of fiscal 2019, with early adoption permitted. The Company does not anticipate early adoption and is currently evaluating the interaction of this authoritative guidance with the various regulatory provisions concerning pension and postretirement benefit costs in the Company’s Utility and Pipeline and Storage ~~segments.~~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: $106.0 million for the remainder of fiscal 2023; $206.4 million for fiscal 2024; $181.1 million for fiscal 2025; $146.9 million for fiscal 2026; $123.0 million for fiscal 2027; and $692.6 million thereafter.

Note 24 – 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.

1518

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The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of ~~December~~March 31, ~~2017~~2023 and September 30, ~~2017~~.2022. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. ~~The fair value presentation for over~~


Recurring Fair Value Measures	At fair value as of March 31, 2023
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)		Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	53,519	$	—	$	—	$	—	$	53,519

Derivative Financial Instruments:

Over the Counter Swaps – Gas	—		59,179		—		(52,327)		6,852
Over the Counter No Cost Collars – Gas	—		56,879		—		(26,070)		30,809
Contingent Consideration for Asset Sale	—		5,903		—		—		5,903
Foreign Currency Contracts	—		213		—		(1,353)		(1,140)
Other Investments:
Balanced Equity Mutual Fund	15,924		—		—		—		15,924
Fixed Income Mutual Fund	15,949		—		—		—		15,949


Total	$	85,392	$	122,174	$	—	$	(79,750)	$	127,816

Liabilities:
Derivative Financial Instruments:

Over the Counter Swaps – Gas	$	—	$	91,509	$	—	$	(52,327)	$	39,182
Over the Counter No Cost Collars – Gas	—		21,616		—		(26,070)		(4,454)
Foreign Currency Contracts	—		1,388		—		(1,353)		35
Total	$	—	$	114,513	$	—	$	(79,750)	$	34,763

Total Net Assets/(Liabilities)	$	85,392	$	7,661	$	—	$	—	$	93,053


Recurring Fair Value Measures	At fair value as of September 30, 2022
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)		Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	35,015	$	—	$	—	$	—	$	35,015
Hedging Collateral Deposits	91,670		—		—		—		91,670
Derivative Financial Instruments:

Over the Counter Swaps – Gas	—		5,177		—		(4,178)		999

Contingent Consideration for Asset Sale	—		8,176		—		—		8,176
Foreign Currency Contracts	—		128		—		(128)		—
Other Investments:
Balanced Equity Mutual Fund	19,506		—		—		—		19,506
Fixed Income Mutual Fund	33,348		—		—		—		33,348



Total	$	179,539	$	13,481	$	—	$	(4,306)	$	188,714

Liabilities:
Derivative Financial Instruments:

Over the Counter Swaps – Gas	$	—	$	517,464	$	—	$	(4,178)	$	513,286
Over the Counter No Cost Collars – Gas	—		270,453		—		—		270,453
Foreign Currency Contracts	—		2,048		—		(128)		1,920
Total	$	—	$	789,965	$	—	$	(4,306)	$	785,659

Total Net Assets/(Liabilities)	$	179,539	$	(776,484)	$	—	$	—	$	(596,945)

(1)Netting Adjustments represent the ~~counter swaps combines gas~~impact of legally-enforceable master netting arrangements that allow the Company to net gain and ~~oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements~~loss positions held with the ~~Company.~~

Recurring Fair Value Measures At fair value as of December 31, 2017
(Thousands of Dollars) Level 1 Level 2 Level 3
Netting Adjustments⁽¹⁾

Total⁽¹⁾
Assets:

Cash Equivalents – Money Market Mutual Funds $ 132,231
$ —
$ —
$ —
$ 132,231
Derivative Financial Instruments:

Commodity Futures Contracts – Gas 1,374
—
—
(1,374 ) —
Over the Counter Swaps – Gas and Oil —
30,853
—
(10,312 ) 20,541
Foreign Currency Contracts —
1,232
—
(666 ) 566
Other Investments:

Balanced Equity Mutual Fund 36,979
—
—
—
36,979
Fixed Income Mutual Fund 44,232
—
—
—
44,232
Common Stock – Financial Services Industry 3,239
—
—
—
3,239
Hedging Collateral Deposits 4,465
—
—
—
4,465
Total $ 222,520
$ 32,085
$ —
$ (12,352 ) $ 242,253

Liabilities:

Derivative Financial Instruments:

Commodity Futures Contracts – Gas $ 2,190
$ —
$ —
$ (1,374 ) $ 816
Over the Counter Swaps – Gas and Oil —
16,312
—
(10,312 ) 6,000
Foreign Currency Contracts —
429
—
(666 ) (237 )
Total $ 2,190
$ 16,741
$ —
$ (12,352 ) $ 6,579
Total Net Assets/(Liabilities) $ 220,330
$ 15,344
$ —
$ —
$ 235,674
same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

Recurring Fair Value Measures At fair value as of September 30, 2017
(Thousands of Dollars)    Level 1 Level 2 Level 3
Netting Adjustments⁽¹⁾

Total⁽¹⁾
Assets:

Cash Equivalents – Money Market Mutual Funds $ 527,978
$ —
$ —
$ —
$ 527,978
Derivative Financial Instruments:

Commodity Futures Contracts – Gas 1,483
—
—
(963 ) 520
Over the Counter Swaps – Gas and Oil —
38,977
—
(4,206 ) 34,771
Foreign Currency Contracts —
1,227
—
(407 ) 820
Other Investments:

Balanced Equity Mutual Fund 37,033
—
—
—
37,033
Fixed Income Mutual Fund 45,727
—
—
—
45,727
Common Stock – Financial Services Industry 3,150
—
—
—
3,150
Hedging Collateral Deposits 1,741
—
—
—
1,741
Total                                            $ 617,112
$ 40,204
$ —
$ (5,576 ) $ 651,740

Liabilities:

Derivative Financial Instruments:

Commodity Futures Contracts – Gas $ 963
$ —
$ —
$ (963 ) $ —
Over the Counter Swaps – Gas and Oil —
5,309
—
(4,206 ) 1,103
     Foreign Currency Contracts —
407
—
(407 ) —
Total $ 963
$ 5,716
$ —
$ (5,576 ) $ 1,103
Total Net Assets/(Liabilities) $ 616,149
$ 34,488
$ —
$ —
$ 650,637


⁽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.

~~Table of Contents~~

Derivative Financial Instruments

At December 31, 2017 and September 30, 2017, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used in the Company’s Energy Marketing segment. Hedging collateral deposits were $4.5 million at December 31, 2017 and $1.7 million at September 30, 2017, which were associated with these futures contracts and have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at ~~December~~March 31, ~~2017~~2023 and September 30, ~~2017 consist of~~2022 include natural gas price swap agreements, ~~used in the Company’s Exploration and Production and Energy Marketing segments, crude oil price swap agreements used in the Company’s Exploration and Production segment~~natural gas no cost collars, and foreign currency contracts, all of which are used in the ~~Company's~~ Company’s

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Exploration and Production segment. ~~The derivative financial instruments~~Hedging collateral deposits of $91.7 million at September 30, 2022, which were associated with the price swap agreements, no cost collars and foreign currency contracts, have been reported in Level ~~2 at December 31, 2017 also include basis hedge swap agreements used in the Company's Energy Marketing segment.~~1. The fair value of the Level 2 price swap agreements and no cost collars is based on an internal ~~discounted~~ cash flow model that uses observable inputs (i.e. ~~LIBOR~~SOFR based discount rates for the price swap agreements and basis differential information, if applicable, at active natural gas and crude oil 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 ~~accounting rules~~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~~March 31, ~~2017~~,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 March 31, 2023 also includes the contingent consideration associated with the sale of the Exploration and Production segment's California assets on June 30, 2022, which is discussed at Note 2 – Asset Acquisitions and Divestitures and at Note 5 – Financial Instruments. 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~~March 31, ~~2017~~2023 and ~~December~~March 31, ~~2016,~~2022, there were no assets or liabilities measured at fair value and classified as Level 3. ~~For the quarters ended~~ ~~December 31, 2017~~ ~~and~~ ~~December 31, 2016, no transfers in or out of Level 1 or Level 2 occurred.~~

Note 35 – 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, 2017 September 30, 2017
Carrying Amount Fair Value Carrying Amount Fair Value
Long-Term Debt $ 2,084,465
$ 2,214,839
$ 2,383,681
$ 2,523,639


	March 31, 2023				September 30, 2022
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,085,235	$	1,951,250	$	2,632,409	$	2,453,209

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/LIBOR~~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 March 31, 2023		At September 30, 2022

Life Insurance Contracts	$	42,745	$	42,171
Equity Mutual Fund	15,924		19,506
Fixed Income Mutual Fund	15,949		33,348

	$	74,618	$	95,025

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Investments in life insurance contracts are stated at their cash surrender values or net present ~~value as discussed below.~~value. Investments in an equity mutual fund and a fixed income mutual fund ~~and the stock of an insurance company (marketable equity securities), as discussed below,~~ are stated at fair value based on quoted market ~~prices.~~

~~Other investments include cash surrender values of insurance contracts (net present value~~prices with changes in the case of split-dollar collateral assignment arrangements) and marketable equity and fixed income securities. The values of the insurance contracts amounted to $38.9 million at December 31, 2017 and $39.4 million at September 30, 2017. The fair value of the equity mutual fund was $37.0 million at both December 31, 2017 and September 30, 2017. The gross unrealized gain on this equity mutual fund was $9.5 million at December 31, 2017 and $9.9 million at September 30, 2017. A sale of sharesrecognized in ~~the equity mutual fund during~~

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the quarter ended December 31, 2017 resulted in $1.5 million of cash proceeds and a realized gain of $0.4 million. The fair value of the fixed income mutual fund was $44.2 million at December 31, 2017 and $45.7 million at September 30, 2017. The gross unrealized loss on this fixed income mutual fund was $0.2 million at December 31, 2017 and was less than $0.1 million at September 30, 2017. A sale of shares in the fixed income mutual fund during the quarter ended December 31, 2017 resulted in $1.5 million of cash proceeds and a realized loss of less than $0.1 million. The fair value of the stock of an insurance company was $3.2 million at both December 31, 2017 and September 30, 2017. The gross unrealized gain on this stock was $2.3 million at December 31, 2017 and $2.2 million at September 30, 2017.net income. The insurance contracts and ~~marketable~~ equity ~~and fixed income securities~~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, as discussed in Note 11 – Regulatory Matters, 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 as well as the Energy Marketing~~ segment. The Company enters into ~~futures contracts~~over-the-counter no cost collar and ~~over-the-counter~~ swap agreements ~~for natural gas and crude oil~~ to manage the price risk associated with forecasted sales of ~~gas and oil.~~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 Company also enters into futures contracts and swaps, which are accounted for as cash flow hedges, to manage the price risk associated with forecasted gas purchases. The Company enters into futures contracts and swaps to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in value of natural gas held in storage. These instruments are accounted for as fair value hedges. The duration of the Company’s ~~combined~~ cash flow ~~and fair value commodity~~ hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 8 years. ~~The Exploration and Production segment holds~~

On June 30, 2022, the ~~majority~~Company completed the sale of Seneca’s California assets. Under the terms of the ~~Company’s~~purchase and sale agreement, the Company can 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 Company has determined that this contingent consideration meets the definition of a derivative ~~financial instruments.~~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 $5.9 million and $8.2 million at March 31, 2023 and September 30, 2022, respectively. A $2.5 million mark-to-market adjustment was recorded during the quarter ended March 31, 2023. A $2.3 million mark-to-market adjustment was recorded during the six months ended March 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~~March 31, ~~2017~~2023 and September 30, ~~2017. Substantially all of the derivative financial instruments reported on those line items relate to commodity contracts and a small portion relates to foreign currency forward contracts.~~2022.

Cash Flow Hedges

For derivative financial instruments that are designated and qualify as a cash flow hedge, ~~the effective portion of~~ 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. ~~Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.~~

As of ~~December~~March 31, ~~2017~~,2023, the Company had ~~the following~~462.9 Bcf of natural gas commodity derivative contracts (swaps and ~~futures contracts) outstanding:~~no cost collars) outstanding.



~~Commodity~~	~~Units~~
~~Natural Gas~~	~~99.1~~	~~Bcf (short positions)~~
~~Natural Gas~~	~~1.6~~	~~Bcf (long positions)~~
~~Crude Oil~~	~~3,645,000~~	~~Bbls (short positions)~~

As of ~~December~~March 31, ~~2017,~~2023, the Company was hedging a total of ~~$94.7~~$51.0 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward ~~contracts (long positions).~~contracts.

As of ~~December~~March 31, ~~2017,~~2023, the Company had ~~$17.5~~$1.3 million ~~($10.3 million after tax)~~ of net hedging ~~gains~~losses after taxes included in the accumulated other comprehensive income (loss) balance. It is expected that ~~$5.0~~$37.4 million ~~($3.0 million~~of unrealized gains after ~~tax) of such unrealized gains~~taxes will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged ~~transaction~~transactions are recorded in earnings.

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The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended March 31, 2023 and 2022 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships	Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) for the Three Months Ended March 31,				Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Three Months Ended March 31,
	2023		2022			2023		2022
Commodity Contracts	$	310,623	$	(642,240)	Operating Revenue	$	(18,768)	$	(130,271)

Foreign Currency Contracts	(79)		634		Operating Revenue	(172)		50
Total	$	310,544	$	(641,606)		$	(18,940)	$	(130,221)


The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the	The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the																				The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended December 31, 2017 and 2016 (Thousands of Dollars)
Six Months Ended March 31, 2023 and 2022 (Thousands of Dollars)																					Six Months Ended March 31, 2023 and 2022 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships	Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Three Months Ended December 31,						Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Three Months Ended December 31,						Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Three Months Ended December 31,						Derivatives in Cash Flow Hedging Relationships	Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) for the Six Months Ended March 31,				Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Six Months Ended March 31,
	2017			2016				2017			2016				2017			2016				2023		2022			2023		2022
Commodity Contracts	$	(5,948	)	$	(50,444	)	Operating Revenue	$	12,842		$	31,320		Operating Revenue	$	(433	)	$	(100	)	Commodity Contracts	$	607,743	$	(479,114)	Operating Revenue	$	(177,930)	$	(292,899)
Commodity Contracts	956			(1,536		)	Purchased Gas	196			(460		)	Not Applicable	—			—

Foreign Currency Contracts	(507		)	(521		)	Operation and Maintenance Expense	(490		)	(143		)	Not Applicable	—			—			Foreign Currency Contracts	394		640		Operating Revenue	(351)		90
Total	$	(5,499	)	$	(52,501	)		$	12,548		$	30,717			$	(433	)	$	(100	)	Total	$	608,137	$	(478,474)		$	(178,281)	$	(292,809)

~~Fair Value Hedges~~

The Company utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in the value of certain natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or net realizable value writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of December 31, 2017, the Company’s Energy Marketing segment had fair value hedges covering approximately 21.2 Bcf (20.6 Bcf of fixed price sales commitments and 0.6 Bcf of commitments related to the withdrawal of storage gas). For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.

Derivatives in Fair Value Hedging Relationships Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income
Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income for the
Three Months Ended December 31, 2017
(In Thousands)
Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the
Three Months Ended December 31, 2017
(In Thousands)
Commodity Contracts Operating Revenues $ (1,753 ) $ 1,753
Commodity Contracts Purchased Gas $ 137
$ (137 )
$ (1,616 ) $ 1,616

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

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basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has ~~over-the-counter~~over the-counter swap positions, no cost collars and applicable foreign currency forward contracts with sixteen counterparties of which ~~ten~~eight are in a net gain position. On average, the Company had ~~$2.1~~$4.6 million of credit exposure per counterparty in a gain position at ~~December~~March 31, ~~2017.~~2023. The maximum credit exposure per counterparty in a gain position at ~~December~~March 31, ~~2017~~2023 was ~~$8.1~~$11.1 million. As of ~~December~~March 31, ~~2017,~~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~~March 31, ~~2017, thirteen~~2023, fourteen of the sixteen counterparties to the Company’s outstanding derivative ~~instrument~~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 extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to post or increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative ~~instrument~~financial contracts with a credit-risk contingency feature were in a liability position (or

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if the liability were larger) and/or the Company’s credit rating declined, then ~~additional~~ hedging collateral deposits ~~may~~or an increase to such deposits could be required. At ~~December~~March 31, 2017, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $19.2 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements). At December 31, 2017,2023, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was ~~$4.2~~$7.1 million according to the ~~Company's~~Company’s internal model (discussed in Note ~~2 -~~4 – Fair Value Measurements)~~. For its over-the-counter swap agreements~~, and ~~foreign currency forward contracts,~~ no hedging collateral deposits were required to be posted by the Company at ~~December~~March 31, ~~2017.~~

~~For its exchange traded futures contracts,~~2023. Depending on the movement of commodity prices in the future, it is possible that these liability positions could swing into asset positions, at which point the Company ~~was~~would be exposed to credit risk on its derivative financial instruments. In that case, the Company's counterparties could be required to post ~~$4.5 million in~~ hedging collateral deposits as of December 31, 2017. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts or receives hedging collateral based on open positions and margin requirements it has with its counterparties.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. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account. This is discussed in Note 1 under Hedging Collateral Deposits.

Note ~~4 -~~6 – Income Taxes

The effective tax ~~rate~~rates for the quarters ended ~~December~~March 31, ~~2017~~2023 and ~~December~~March 31, ~~2016 was negative 69.2%~~2022 were 26.2% and ~~38.8%~~25.6%, respectively. The ~~difference is a result of~~effective tax rates for the ~~impact of~~six months ended March 31, 2023 and March 31, 2022 were 25.7% and 25.5%, respectively. During the ~~one-time remeasurement of the deferred income tax liability~~quarter and ~~a lower statutory rate of 24.5% as a result of the 2017 Tax Reform Act (as discussed below).~~

On December 22, 2017, the tax legislation referred to as the “Tax Cuts and Jobs Act” (the 2017 Tax Reform Act) was enacted. The 2017 Tax Reform Act significantly changes the taxation of business entities and includes specific provisions related to rate regulated companies. ~~The more significant changes that impact~~six months ended March 31, 2022, the Company ~~are~~was able to utilize the ~~reduction in~~Enhanced Oil Recovery tax credit, which was not available during the ~~corporate federal income tax rate from 35%~~quarter and six months ended March 31, 2023 due to the sale of its California properties.

On April 14, 2023, the IRS issued guidance that provides a ~~blended 24.5% for fiscal 2018~~safe harbor method of accounting that taxpayers may use to determine whether expenses to repair, maintain, replace, or improve natural gas transmission and ~~21% for fiscal 2019 and beyond. As a fiscal year taxpayer, the~~distribution property must be capitalized. The Company is ~~required~~currently analyzing this guidance to ~~use a blended tax rate for fiscal 2018. In addition, beginning in fiscal 2019,~~determine the corporate alternative minimum tax will be eliminated and there will be enhanced limitations on the deductibility of certain executive compensation. For the rate regulated subsidiaries, the 2017 Tax Reform Act also allows for the continued deductibility of interest expense, the elimination of full expensing for tax purposes of certain property acquired after September 27, 2017 and the continuation of certain rate normalization requirements for accelerated depreciation benefits. The non-rate regulated subsidiaries are allowed full expensing of certain property acquired after September 27, 2017 and have potential ~~limitations on the deductibility of interest expense beginning in fiscal 2019.~~

~~The above changes had a material~~ impact on the financial statements in the quarter ended December 31, 2017. Under GAAP, the tax effects of a change in tax law must be recognized in the period in which the law is enacted, or the quarter ending December 31, 2017 for the 2017 Tax Reform Act. GAAP also requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. The Company’s deferred income taxes were remeasured based upon the new tax rates. For the non-rate regulated activities, the change in deferred income taxes was $111.0 million and was recorded as a reduction to income tax expense. For the rate regulated activities, the reduction instatements.

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Note 7 –Capitalization

~~deferred income taxes~~

Summary of ~~$336.7 million was recorded as a decrease to Recoverable Future Taxes of $65.7 million and an increase to Taxes Refundable to Customers of $271.0 million. The 2017 Tax Reform Act~~Changes in Common Stock Equity


	Common Stock			Paid In Capital		Earnings Reinvested in the Business		Accumulated Other Comprehensive Income (Loss)
	Shares	Amount
	(Thousands, except per share amounts)
Balance at January 1, 2023	91,787	$	91,787	$	1,025,639	$	1,713,176	$	(293,746)
Net Income Available for Common Stock						140,880
Dividends Declared on Common Stock ($0.475 Per Share)						(43,602)

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

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

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

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

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

Balance at January 1, 2022	91,437	$	91,437	$	1,013,821	$	1,281,963	$	(277,026)
Net Income Available for Common Stock						167,328
Dividends Declared on Common Stock ($0.455 Per Share)						(41,608)

Other Comprehensive Loss, Net of Tax								(377,228)
Share-Based Payment Expense (1)				4,692

Common Stock Issued Under Stock and Benefit Plans	12	12		271
Balance at March 31, 2022	91,449	$	91,449	$	1,018,784	$	1,407,683	$	(654,254)

Balance at October 1, 2021	91,182	$	91,182	$	1,017,446	$	1,191,175	$	(513,597)
Net Income Available for Common Stock						299,720
Dividends Declared on Common Stock ($0.91 Per Share)						(83,212)



Other Comprehensive Loss, Net of Tax								(140,657)
Share-Based Payment Expense (1)				9,732

Common Stock Issued (Repurchased) Under Stock and Benefit Plans	267	267		(8,394)
Balance at March 31, 2022	91,449	$	91,449	$	1,018,784	$	1,407,683	$	(654,254)

(1)Paid in Capital includes provisions that stipulate how these excess deferred taxes are to be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred income taxes will be determined by the federal and state regulatory agencies. The Company is awaiting regulatory guidance in the jurisdictions in which it operates.

The 2017 Tax Reform Act also repealed the corporate alternative minimum tax (AMT) and provides that the Company’s existing AMT credit carryovers are refundable beginning in fiscal 2019. As of December 31, 2017, the Company had $92.0 million of AMT credit carryovers that are expected to be utilized or refunded between fiscal 2019 and fiscal 2022.

The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118) which provides for up to a one year period (the measurement period) in which to complete the required analysis and income tax accounting for the 2017 Tax Reform Act. SAB 118 describes three scenarioscompensation costs associated with ~~a company’s status of accounting for income tax reform: (1) a company~~performance shares and/or restricted stock awards. The expense is ~~complete with itsaccounting for certain effects~~included within Net Income Available For Common Stock, net of tax ~~reform, (2) a company is able to determine areasonable estimate for certain effects of tax reform and records that estimate as aprovisional amount, or (3) a company is not able to determine a reasonable estimate andtherefore continues to apply the provisions of the taxlaws that were in effect immediately prior to the 2017 Tax Reform Act being enacted.~~

The Company has determined a reasonable estimate for the measurement of the changes in deferred income taxes (noted above), which have been reflected as provisional amounts in the December 31, 2017 financial statements. The final determination of the impact of the income tax effects of these items will require additional analysis and further interpretation of the 2017 Tax Reform Act from yet to be issued U.S. Treasury regulations, state income tax guidance, federal and state regulatory guidance and technical corrections.

~~Note 5 -Capitalization~~benefits.

Common Stock. During the ~~three~~six months ended ~~December~~March 31, ~~2017,~~2023, the Company issued ~~63,082~~12,055 original issue shares of common stock as a result of SARs exercises, ~~68,534~~113,531 original issue shares of common stock for restricted stock units that vested and ~~79,079~~278,687 original issue shares of common stock for performance shares that vested. In addition, the Company issued 25,453 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 25,879 original issue shares of common stock for the Company’s 401(k) plans. The Company also issued ~~6,912~~14,680 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, ~~as partial consideration~~including the reinvestment of dividends for certain non-employee directors who elected to defer their shares pursuant to the ~~directors’ services~~dividend reinvestment feature of the Company's Deferred Compensation Plan for Directors and Officers (the "DCP") during the ~~three~~six months ended ~~December~~March 31, ~~2017.~~ 2023. In addition, the Company issued 824 original issue shares of common stock to officers of the Company who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's DCP Plan during the six months ended March 31, 2023.

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Holders of ~~stock options, SARs, restricted share~~stock-based compensation awards ~~or restricted stock units~~ will often tender shares of common stock to the Company for payment of ~~option exercise prices and/or~~ applicable withholding taxes. During the ~~three~~six months ended ~~December~~March 31, ~~2017, 51,218~~2023, 102,761 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 June 30, 2022, the Company entered into a new 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company used the proceeds for general corporate purposes, which included using $150.0 million for the November 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date in March 2023.

Current Portion of Long-Term Debt. None of the Company's long-term debt ~~at December~~as of March 31, ~~2017 will mature~~2023 had a maturity date within the following twelve-month period. The Current Portion of Long-Term Debt at September 30, ~~2017~~2022 consisted of ~~$300.0~~$500.0 million of ~~6.50%~~3.75% notes ~~scheduled to mature in April 2018.~~and $49.0 million of 7.395% notes. The Company redeemed ~~these~~$150.0 million of the 3.75% notes on ~~October 18, 2017 for $307.0~~November 25, 2022 using a portion of the proceeds from short-term borrowings, as discussed above. In March 2023, the Company redeemed the remaining $350.0 million ~~plus accrued interest. The call premium was recorded to Unamortized Debt Expense on~~of the ~~Consolidated Balance Sheet in October 2017.~~3.75% notes as well as the $49.0 million of 7.395% notes.

Note ~~6 -~~8 – Commitments and Contingencies

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

At ~~December~~March 31, ~~2017~~,2023, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately ~~$3.0~~$3.8 million. ~~This estimated~~The Company's liability for such clean-up costs has been recorded in Other ~~Deferred Credits~~Liabilities on the Consolidated Balance Sheet at ~~December~~March 31, ~~2017.~~2023. The Company expects to recover its environmental clean-up costs through rate recovery over a period of ~~approximately 4 years. The Company~~less than one year 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.

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Northern Access ~~2016~~ Project. On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access ~~2016~~ project described herein. ~~On April 7, 2017,~~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 onin January ~~27,~~of 2017). On April 21, 2017, Supply Corporation and Empire filed a Petition for Review in the United States Court of Appeals for the Second Circuit of the NYDEC's Notice of Denial with respect to National Fuel's application for the Water Quality Certification, and on May 11, 2017, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. The Company also has pending withSubsequently, FERC ~~a proceeding asserting, among other things,~~issued an Order finding that the NYDEC exceeded the ~~reasonable and~~ statutory time ~~frames~~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 ~~light~~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 ~~these pending legal actions,~~time from FERC, until December 31, 2024, to construct the project. As of March 31, 2023, the Company has not yet determined a target in-service date. As a result of the decision of the NYDEC, Supply Corporation and Empire evaluated the capitalized project costs for impairment as of December 31, 2017 and determined that an impairment charge was not required. The evaluation considered probability weighted scenarios of undiscounted future net cash flows, including a scenario assuming successful resolution with the NYDEC and construction of the pipeline, as well as a scenario wherespent approximately $55.9 million on the project, ~~does not proceed. Further developments or indicators~~all of ~~an unfavorable resolution could result in the impairment of a significant portion of the project costs,~~ which ~~totaled $75.5 million at December 31, 2017. The project costs are included within Property, Plant and Equipment and Deferred Charges~~is recorded on the ~~Consolidated Balance Sheet.~~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 79 – Business Segment Information

The Company reports financial results for ~~five~~four segments: Exploration and Production, Pipeline and Storage, Gathering ~~Utility~~ and ~~Energy Marketing.~~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.

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The data presented in the tables below reflect financial information for the segments and ~~reconciliations~~reconcile to consolidated amounts. As stated in the ~~2017~~2022 Form 10-K, the Company evaluates segment performance based on income before discontinued operations ~~extraordinary items and cumulative effects of changes in accounting~~ (when applicable). When ~~these items are~~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 ~~2017~~2022 Form 10-K. A listing of segment assets at ~~December~~March 31, ~~2017~~2023 and September 30, ~~2017~~2022 is shown in the tables below.


Quarter Ended March 31, 2023 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$244,552	$64,223	$1,728	$406,758	$717,261	$—	$—	$717,261
Intersegment Revenues	$—	$30,880	$55,253	$358	$86,491	$—	$(86,491)	$—
Segment Profit: Net Income (Loss)	$60,982	$23,858	$24,334	$31,720	$140,894	$(69)	$55	$140,880


Six Months Ended March 31, 2023 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$521,525	$131,844	$4,374	$718,376	$1,376,119	$—	$—	$1,376,119
Intersegment Revenues	$—	$60,915	$109,020	$420	$170,355	$—	$(170,355)	$—
Segment Profit: Net Income (Loss)	$152,174	$53,335	$49,072	$55,537	$310,118	$(350)	$802	$310,570


(Thousands)	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Segment Assets:
At March 31, 2023	$2,489,665	$2,357,852	$882,405	$2,363,918	$8,093,840	$2,105	$(128,703)	$7,967,242
At September 30, 2022	$2,507,541	$2,394,697	$878,796	$2,299,473	$8,080,507	$2,036	$(186,281)	$7,896,262


Quarter Ended March 31, 2022 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$261,593	$67,795	$3,157	$369,092	$701,637	$—	$83	$701,720
Intersegment Revenues	$—	$27,602	$49,447	$110	$77,159	$—	$(77,159)	$—
Segment Profit: Net Income (Loss)	$71,121	$25,470	$22,092	$53,048	$171,731	$—	$(4,403)	$167,328


Six Months Ended March 31, 2022 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$505,791	$129,342	$7,202	$605,776	$1,248,111	$—	$166	$1,248,277
Intersegment Revenues	$—	$54,405	$97,627	$184	$152,216	$6	$(152,222)	$—
Segment Profit: Net Income (Loss)	$133,490	$50,637	$45,229	$75,178	$304,534	$(7)	$(4,807)	$299,720

Quarter Ended December 31, 2017 (Thousands)
Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated
Revenue from External Customers $139,141 $53,310 $170 $187,089 $38,636 $418,346 $1,096 $213 $419,655
Intersegment Revenues $— $21,985 $23,665 $2,182 $126 $47,958 $— $(47,958) $—
Segment Profit: Net Income (Loss) $106,698 $38,462 $45,400 $20,993 $1,046 $212,599 $(719) $(13,226) $198,654

(Thousands) Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated
Segment Assets:
At December 31, 2017 $1,420,790 $1,793,848 $589,793 $1,988,758 $72,466 $5,865,655 $77,214 $(150,937) $5,791,932
At September 30, 2017 $1,407,152 $1,929,788 $580,051 $2,013,123 $60,937 $5,991,051 $76,861 $35,408 $6,103,320

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Quarter Ended December 31, 2016 (Thousands)
Exploration and Production Pipeline and Storage Gathering Utility Energy Marketing Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated
Revenue from External Customers $160,932 $53,000 $26 $170,971 $36,809 $421,738 $554 $208 $422,500
Intersegment Revenues $— $22,155 $27,840 $1,826 $19 $51,840 $— $(51,840) $—
Segment Profit: Net Income (Loss) $35,080 $19,368 $10,981 $21,175 $1,782 $88,386 $(179) $701 $88,908

Note 810 – Retirement Plan and Other Post-Retirement Benefits

Components of Net Periodic Benefit Cost (in thousands):


	Retirement Plan				Other Post-Retirement Benefits
Three Months Ended March 31,	2023		2022		2023		2022

Service Cost	$	1,297	$	2,190	$	147	$	332
Interest Cost	10,629		5,707		3,912		2,267
Expected Return on Plan Assets	(16,648)		(13,074)		(6,403)		(7,340)
Amortization of Prior Service Cost (Credit)	109		134		(107)		(107)

Amortization of (Gains) Losses	(1,920)		6,601		(2,189)		(1,903)
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	5,378		8,418		3,493		4,274

Net Periodic Benefit Cost (Income)	$	(1,155)	$	9,976	$	(1,147)	$	(2,477)


	Retirement Plan						Other Post-Retirement Benefits							Retirement Plan				Other Post-Retirement Benefits
Three Months Ended December 31,	2017			2016			2017			2016
Six Months Ended March 31,													Six Months Ended March 31,	2023		2022		2023		2022

Service Cost	$	2,480		$	2,992		$	458		$	612		Service Cost	$	2,594	$	4,379	$	293	$	664
Interest Cost	8,252			9,596			3,700			4,752			Interest Cost	21,258		11,414		7,824		4,533
Expected Return on Plan Assets	(15,429		)	(14,929		)	(7,871		)	(7,865		)	Expected Return on Plan Assets	(33,297)		(26,147)		(12,806)		(14,680)
Amortization of Prior Service Cost (Credit)	235			264			(107		)	(107		)	Amortization of Prior Service Cost (Credit)	218		268		(214)		(214)
Amortization of Losses	9,301			10,672			2,639			4,604

Amortization of (Gains) Losses													Amortization of (Gains) Losses	(3,840)		13,202		(4,378)		(3,805)
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾	1,721			535			3,608			1,312			Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	10,756		12,838		7,314		10,519

Net Periodic Benefit Cost	$	6,560		$	9,130		$	2,427		$	3,308
Net Periodic Benefit Cost (Income)													Net Periodic Benefit Cost (Income)	$	(2,311)	$	15,954	$	(1,967)	$	(2,983)

(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.


⁽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. ~~During the three months ended December 31, 2017, the~~ The Company ~~contributed $27.6 million~~did not make any contributions to its tax-qualified, noncontributory ~~defined-benefit~~defined benefit retirement plan (Retirement Plan) ~~and $0.7 million to~~or its VEBA trusts for its other post-retirement ~~benefits. In~~benefits during the six months ended March 31, 2023, and does not anticipate making any such contributions during the remainder of 2018, the Company may contribute up to $5.0 million to the Retirement Plan. In the remainder of 2018, the Company expects its contributions to the VEBA trusts to be in the range of $2.0 million to $3.0 million.fiscal 2023.

Note 911– Regulatory Matters

New YorkJurisdiction

~~On April 28, 2016,~~ Distribution ~~Corporation commenced a rate case~~Corporation's current delivery rates in its New York jurisdiction were approved by ~~filing proposed tariff amendments and supporting testimony requesting approval to increase its annual revenues by approximately $41.7 million. Distribution Corporation explained~~the NYPSC in the filing that its request for rate relief was necessitated by a revenue requirement driven primarily by rate base growth, higher operating expense and higher depreciation expense, among other things. On January 23, 2017, the administrative law judge assigned to the proceedingan order issued ~~a recommended decision (RD) in the case. The RD, as revised~~ on January 26, 2017, recommended a rate increase designed to provide additional annual revenues of $8.5 million, an equity ratio, subject to update of 42.3% based on the Company’s equity ratio, and a cost of equity, subject to update of 8.6%. On April 20, 2017 ~~the NYPSC issued an Order adopting some provisions of the RD and modifying or rejecting others. The Order provides for an annual rate increase of $5.9 million. The rate increase became~~with rates becoming effective May 1, 2017. The ~~Order further provides~~order provided for a return on equity of 8.7%, and ~~established an equity ratio of 42.9%. The Order also directs~~directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018.

On The order also authorized the Company to recover approximately $15 million annually for pension and OPEB expenses from customers. Because the Company’s future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July ~~28, 2017,~~2022, Distribution Corporation ~~filed an appeal~~made a filing with ~~New York State Supreme Court, Albany County, seeking review of~~ the ~~Order. The appeal contends that portions of the Order should be invalidated because they fail~~NYPSC to ~~meet the applicable legal standard for agency decisions.~~effectuate a pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022. On ~~December 11, 2017, the appeal was transferred to the Supreme Court, Appellate Division, Third Department. The Company cannot predict the outcome of the appeal at this time.~~

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December 31, 2024, whichever is earlier. With the implementation of this surcredit, Distribution Corporation will no longer be funding the Retirement Plan or its VEBA trusts in its New York jurisdiction.

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 ~~proceeding~~petition with the NYPSC to ~~study~~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 ~~potential effects of~~existing system modernization tracker, effective April 1, 2023. The NYPSC approved the ~~enactment of the 2017 Tax Reform Act~~petition via order dated March 17, 2023 contingent on the ~~tax expenses~~Company not filing a base rate case that would result in new rates becoming effective prior to October 1, 2024.

On January 19, 2023, the NYPSC issued an order in its Effects of COVID-19 on Utility Service (20-M-0266) and ~~liabilities of~~Energy Affordability for Low Income Utility Customers (14-M-0565) proceedings whereby a Phase 2 Utility Arrears Relief Program was authorized. Specifically, the order directed Distribution Corporation and certain other New York utilities to, among other things, address arrears on residential non-energy affordability program (EAP) ratepayer accounts that did not receive a credit under the NYPSC’s Phase 1 program and small commercial ratepayer accounts by issuing a one-time bill credit to such customers to reduce or eliminate accrued arrears through May 1, 2022. The credits shall be processed within 90 days of the ~~“regulatory treatment~~effective date of ~~any windfalls resulting from same~~the order, provided that residential non-EAP customers who had their service disconnected for non-payment in 2022 shall be allowed the opportunity to have their service reinstated in order to ~~preserve~~receive the benefits for ratepayers.” In its order, the NYPSC stated that the effect of the 2017 Tax Reform Act on utilities’ taxation is likely to be material and complex and that the proceeding was needed to begin the process of addressing the impact on the State’s utilities and ratepayers. The order establishes that the first steps in such process will be soliciting information from its regulated utilities to quantify the impact of the 2017 Tax Reform Act, scheduling a technical conference with the utilities, and the issuance of a NY Department of Public Service Staff (Staff) proposal for accounting and ratemaking treatment of the tax changes.credit through June 30, 2023. The order further ~~states that once Staff’s proposal~~directs utilities to suspend residential service terminations for non-payment while arrears credits are applied to accounts through March 1, 2023, or 30 days after credits have been applied, whichever is ~~issued,~~later. The order authorizes the utilities to recover the Phase 2 costs (the arrears credits and ~~other interested parties~~associated carrying charges) through a surcharge. Utilities proposed various offsets to Phase 2 program costs, and Distribution Corporation has proposed certain offsets as part of an uncollectible expense reconciliation proposal. On February 17, 2023, Distribution Corporation made a filing with the NYPSC seeking approval of its uncollectible expense reconciliation mechanism and a determination is pending. Application of the proposed offsets and collection periods will be ~~invited~~determined when the NYPSC rules on the uncollectible expense reconciliation filing.

Pennsylvania Jurisdiction

Distribution Corporation’s current delivery rates in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007. 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 with a proposed effective date of December 27, 2022. On December 8, 2022, the PaPUC issued an order suspending the filing until July 27, 2023 by operation of law unless directed otherwise by the PaPUC. Following discovery, the submission of testimony and an evidentiary hearing, the parties to ~~comment~~the proceeding agreed to a settlement that authorizes, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million as of August 1, 2023. On April 13, 2023, Distribution Corporation filed a joint petition with the PaPUC seeking approval of the settlement on ~~Staff’s recommendation.~~behalf of all active parties to the proceeding. The joint petition is currently pending before the PaPUC.

Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC, Distribution Corporation reduced base rates by $7.7 million in order to stop collecting OPEB expenses from customers. It also ~~declares that utilities are “put on notice that it is~~began to refund to customers overcollected OPEB expenses in the [NYPSC]’s intent to ensure that net benefits accruing from the Tax Act are preserved for ratepayers, either through deferral accounting or another method, from the first day the Tax Act is put into effect. Utilities acting contraryamount of $50.0 million. All matters with respect to this ~~intent do so at their own risk.”~~tariff supplement were finalized on February 24, 2022 with the PaPUC’s approval of an Administrative Law Judge’s Recommended Decision. Concurrent with that decision, the Company discontinued regulatory accounting for OPEB expenses and recorded an $18.5 million adjustment during the quarter ended March 31, 2022 to reduce its regulatory liability for previously deferred OPEB income amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company ~~cannot predict~~also increased customer refunds of overcollected OPEB expenses from $50.0 million to $54.0 million. All refunds specified in the ~~outcome~~tariff supplement are being funded entirely by grantor trust assets held by the Company, most of ~~this proceeding at this time. Refer to Note 4 - Income Taxes for further discussion~~which are included in a fixed income mutual fund that is a component of Other Investments on the ~~2017 Tax Reform Act.~~Company’s Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.

FERC ~~Rate Proceedings~~Jurisdiction

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corporate federal income tax rate is increased. If no case has been filed, Supply ~~Corporation's current~~Corporation must file for rates to be effective February 1, 2025.

Empire’s 2019 rate settlement ~~requires~~provides that Empire must make a rate case filing no later than ~~December 31, 2019.~~May 1, 2025.

~~Empire currently has no active rate case on file. Empire’s current rate settlement requires a rate case filing no later than July 1, 2021.~~

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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, ~~distribution~~storage and ~~marketing~~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 ~~Shale.~~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 ~~Canada and~~ the eastern United ~~States.~~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 ~~producers~~customers in the Appalachian basin. The Company ~~also develops and produces oil reserves, primarily in California. The Company~~ reports financial results for ~~five~~four business segments.

For the quarter ended December 31, 2017 compared to the quarter ended December 31, 2016, the Company experienced an increase in earnings of $109.8 million. On December 22, 2017, the tax legislation referred to as the “Tax Cuts and Jobs Act” (the 2017 Tax Reform Act) was enacted. The 2017 Tax Reform Act significantly changes the taxation of business entities and includes specific provisions related to rate regulated companies. The more significant changes that impact the Company are the reduction in the corporate federal income tax rate from 35% to a blended 24.5% for fiscal 2018 and 21% for fiscal 2019 and beyond. As a fiscal year taxpayer, the Company is required to use a blended tax rate for fiscal 2018. As a result of the 2017 Tax Reform Act, the effective tax rate for the three months ended December 31, 2017 (negative 69.2%) reflects the impact of a one-time remeasurementdiscussion of the Company's accumulated deferred income tax liability, a $111.0 million reduction to income tax expense. The effective tax rate also reflects a lower statutory rate of 24.5%. Without the one-time remeasurement of the Company's accumulated deferred income tax liability, the effective tax rate would have been 25.3%. For further discussion of the impact of the 2017 Tax Reform Act to the Company, refer to Item 1 at Note 4 — Income Taxes. For further discussion of the Company’s earnings, refer to the Results of Operations section below.

On ~~February 3, 2017,~~June 30, 2022, the Company completed the sale of Seneca’s California assets to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in ~~its Pipeline~~cash and ~~Storage segment, received FERC approval of a project to move significant prospective Marcellus production from Seneca’s Western Development Area~~contingent consideration valued at ~~Clermont to an Empire interconnection with TransCanada Pipeline~~$12.6 million at ~~Chippawa~~closing. The Company pursued this sale given the strong commodity price environment and ~~an interconnection with Tennessee Gas Pipeline’s 200 Line~~the Company's strategic focus in ~~East Aurora, New York (“Northern Access 2016”). On April 7, 2017,~~ the ~~NYDEC issued a Notice of Denial~~Appalachian Basin. Under the terms of the ~~federal Clean Water Act Section 401 Water Quality Certification~~purchase and ~~other state stream~~sale agreement, the Company can receive up to three annual contingent payments between calendar year 2023 and ~~wetland permits~~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 sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances.

On June 30, 2022, the Company entered into a new 364-Day Credit Agreement (the "364-Day Credit Agreement") with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company is using the proceeds for general corporate purposes, which included using $150.0 million for the ~~New York portion~~November 2022 redemption of the project (the Water Quality Certification for the Pennsylvania portion of the project was received on January 27, 2017). On April 21, 2017, the Company appealed the NYDEC's decision with regard to the Water Quality Certification to the United States Court of Appeals for the Second Circuit, and on May 11, 2017, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. The Company also has pending with FERC a proceeding asserting, among other things, that the NYDEC exceeded the reasonable and statutory time frames to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. The Company remains committed to the project. Approximately $75.5 million in costs have been incurred on this project through December 31, 2017, with the costs residing either in Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet, or Deferred Charges.

Seneca has two downstream Canadian transportation contracts to move incremental volumes associated with the Northern Access 2016 project. One of the contracts has a term expiring on March 31, 2023 with a remaining commitment of approximately $27.1 million (using a 1.2545 Exchange Rate). The other transportation precedent agreement was suspended until the Northern Access 2016 project has received all its necessary permits. Seneca paid $2.4 million associated with this suspension during the quarter ended September 30, 2017 and will be reimbursed this amount if the project is reinstated. As noted above, the Company remains committed to the Northern Access 2016 project. Seneca has mitigated a portion of the ~~current capacity costs through capacity release arrangements.~~Company's outstanding long-term debt with a maturity date in March 2023. In March 2023, the Company utilized short-term borrowings and cash on hand to redeem the remaining long-term debt that had maturity dates in March 2023, which included $350.0 million of 3.75% notes and $49.0 million of 7.395% notes.

From a financing perspective, ~~in September 2017,~~ the Company issued $300.0 million of 3.95% notes due in September 2027. The proceeds of the debt issuance were used for the October 2017 redemption of $300.0 million of the Company's 6.50% notes that were scheduled to mature in April 2018. The Company expects to use cash on hand, ~~and~~ cash from operations, and short-term or long-term borrowings, as needed, to meet

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its ~~capital expenditure~~financing needs for the remainder of fiscal ~~2018~~2023. The Company continues to evaluate these financing needs and ~~may issue short-term~~options to meet them. Given the current economic conditions, which include continued inflationary pressures and rising interest rates, the cost and/or ~~long-term debt during fiscal 2018~~availability of capital may be impacted, but the Company continues to expect to meet its financing needs as ~~needed.~~discussed above.

Recent turmoil with certain financial institutions has created uncertainty in the economy. While the Company has not been directly impacted, it continues to closely monitor any potential future impacts on the business. The Company has a diverse group of twelve banks that participate in its multi-year and 364-day credit facilities. All of these banks have solid investment grade credit ratings. Additionally, the Company regularly reviews the credit quality of its hedging counterparties, those that provide credit support for customers, and any other material counterparties, and has not identified any material risks as a result of the current economic uncertainty.

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CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's ~~2017~~2022 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 June 30, 2022 sale of the Company's California oil and natural gas properties. That sale is discussed in more detail in Item 1 at Note 2 - Asset Acquisitions and Divestitures. In accordance with ~~this~~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~~March 31, ~~2017,~~2023, the ceiling exceeded the book value of the oil and gas properties by approximately $334.6 million. The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended December 31, 2017, based on posted Midway Sunset prices, was $48.41 per Bbl.$2.7 billion. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended ~~December~~March 31, ~~2017,~~2023, based on the quoted Henry Hub spot price for natural gas, was ~~$2.98~~$5.96 per MMBtu. ~~(Note – because~~(Note: Because actual pricing of the Company’s ~~various~~ producing properties ~~varies~~vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the ~~Midway Sunset and~~ HenryHub ~~prices,~~price, which ~~are~~is only indicative of ~~the~~ 12-month average prices for the twelve months ended ~~December~~March 31, ~~2017. Pricing differences would include~~2023. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) ~~The following table illustrates~~In regard to the sensitivity of the ceiling test calculation to commodity price changes, ~~specifically showing~~if natural gas prices were $0.25 per MMBtu lower than the ~~amounts~~average prices used at March 31, 2023 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's oil and gas properties ~~at December 31, 2017 (which~~by approximately $2.4 billion (after-tax), which would not have resulted in an impairment charge) if natural gas prices were $0.25 per MMBtu lower than the average prices used at December 31, 2017, if crude oil prices were $5 per Bbl lower than the average prices used at December 31, 2017, and if both natural gas prices and crude oil prices were $0.25 per MMBtu and $5 per Bbl lower than the average prices used at December 31, 2017 (all amounts are presented after-tax). Thesecharge. This calculated ~~amounts are~~amount is based solely on price changes and dodoes not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

Ceiling Testing Sensitivity to Commodity Price Changes
(Millions)
$0.25/MMBtu
Decrease in
Natural Gas Prices

$5.00/Bbl
Decrease in
Crude Oil Prices

$0.25/MMBtu
Decrease in
Natural Gas Prices
and $5.00/Bbl
Decrease in
Crude Oil Prices

Excess of Ceiling over Book Value under Sensitivity Analysis $ 188.4
$ 295.4
$ 149.2

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 ~~oil and~~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 ~~2017~~2022 Form 10-K.

~~2017 Tax Reform Act.~~ On December 22, 2017, the tax legislation referred to as the “Tax Cuts and Jobs Act” (the 2017 Tax Reform Act) was enacted. The 2017 Tax Reform Act significantly changes the taxation of business entities and includes specific provisions related to rate regulated companies. The more significant changes that impact the Company are the reduction in the corporate federal income tax rate from 35% to a blended 24.5% for fiscal 2018 and 21% for fiscal 2019 and beyond. As a fiscal year taxpayer, the Company is required to use a blended tax rate for fiscal 2018. In addition, beginning in fiscal 2019, the corporate alternative minimum tax will be eliminated and there will be enhanced limitations on the deductibility of certain executive compensation. For the rate regulated subsidiaries, the 2017 Tax Reform Act also allows for the continued deductibility of interest expense, the elimination of full expensing for tax purposes of certain property acquired after September 27, 2017 and the continuation of certain rate normalization requirements for accelerated depreciation benefits. The Company's non-rate regulated subsidiaries are allowed

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~~full expensing of certain property acquired after September 27, 2017 and have potential limitations on the deductibility of interest expense beginning in fiscal 2019.~~

The Company has determined a reasonable estimate under SAB 118 for the measurement of the changes in deferred income taxes in the December 31, 2017 financial statements. The final determination of the impact of the income tax effects of these items will require additional analysis and further interpretation of the 2017 Tax Reform Act from yet to be issued U.S. Treasury regulations, state income tax guidance, federal and state regulatory guidance and technical corrections. For further discussion of the impact of the 2017 Tax Reform Act to the Company, refer to Item 1 at Note 4 — Income Taxes.

RESULTS OF OPERATIONS

Earnings

The Company's earnings were ~~$198.7~~$140.9 million for the quarter ended ~~December~~March 31, ~~2017~~2023 compared to earnings of ~~$88.9~~$167.3 million for the quarter ended ~~December~~March 31, ~~2016.~~2022. The decrease in earnings of $26.4 million is primarily the result of lower earnings in the Exploration and Production segment, Pipeline and Storage segment and Utility segment. Higher earnings in the Gathering segment and the Corporate category partially offset these decreases.

The Company's earnings were $310.6 million for the six months ended March 31, 2023 compared to earnings of $299.7 million for the six months ended March 31, 2022. The increase in earnings of ~~$109.8~~$10.9 million is primarily athe result of higher earnings in the Exploration and Production segment, Pipeline and Storage segment, Gathering segment and ~~Pipeline and Storage segment.~~Corporate category. Lower earnings in the ~~Energy Marketing~~Utility segment and ~~Utility segment, as well as losses~~a loss in the ~~Corporate and~~ All Other ~~categories~~category partially offset these increases.

The Company's earnings for the quarter and six months ended ~~December~~March 31, ~~2017~~2022 include the reduction of an OPEB regulatory liability that increased Utility segment earnings by $18.5 million ($14.6 million after-tax) in accordance with a $111.0 million remeasurement of accumulated deferred income taxes recorded during the quarter ended December 31, 2017 and a lower statutory rate of 24.5% as a result of the 2017 Tax Reform Act, as discussed above.regulatory proceeding in Distribution Corporation's Pennsylvania service territory. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in ~~the~~ earnings discussions are after-tax amounts, unless otherwise noted.

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Earnings (Loss) by Segment


	Three Months Ended December 31,										Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2017			2016			Increase (Decrease)			(Thousands)	2023		2022		Increase (Decrease)		2023		2022		Increase (Decrease)
Exploration and Production	$	106,698		$	35,080		$	71,618		Exploration and Production	$	60,982	$	71,121	$	(10,139)	$	152,174	$	133,490	$	18,684
Pipeline and Storage	38,462			19,368			19,094			Pipeline and Storage	23,858		25,470		(1,612)		53,335		50,637		2,698
Gathering	45,400			10,981			34,419			Gathering	24,334		22,092		2,242		49,072		45,229		3,843
Utility	20,993			21,175			(182		)	Utility	31,720		53,048		(21,328)		55,537		75,178		(19,641)
Energy Marketing	1,046			1,782			(736		)
Total Reportable Segments	212,599			88,386			124,213			Total Reportable Segments	140,894		171,731		(30,837)		310,118		304,534		5,584
All Other	(719		)	(179		)	(540		)	All Other	(69)		—		(69)		(350)		(7)		(343)
Corporate	(13,226		)	701			(13,927		)	Corporate	55		(4,403)		4,458		802		(4,807)		5,609
Total Consolidated	$	198,654		$	88,908		$	109,746		Total Consolidated	$	140,880	$	167,328	$	(26,448)	$	310,570	$	299,720	$	10,850

Exploration and Production

Exploration and Production Operating Revenues


	Three Months Ended December 31,									Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2017			2016		Increase (Decrease)			(Thousands)	2023		2022		Increase (Decrease)		2023		2022		Increase (Decrease)
Gas (after Hedging)	$	98,115		$	120,564	$	(22,449	)	Gas (after Hedging)	$	241,002	$	218,486	$	22,516	$	514,199	$	424,287	$	89,912
Oil (after Hedging)	40,214			39,457		757			Oil (after Hedging)	526		36,817		(36,291)		1,154		72,040		(70,886)
Gas Processing Plant	1,065			761		304			Gas Processing Plant	209		985		(776)		583		2,013		(1,430)
Other	(253		)	150		(403		)	Other	2,815		5,305		(2,490)		5,589		7,451		(1,862)
	$	139,141		$	160,932	$	(21,791	)		$	244,552	$	261,593	$	(17,041)	$	521,525	$	505,791	$	15,734

Production Volumes


	Three Months Ended March 31,			Six Months Ended March 31,
	2023	2022	Increase (Decrease)	2023	2022	Increase (Decrease)
Gas Production (MMcf)
Appalachia	93,241	83,565	9,676	183,815	164,954	18,861
West Coast	—	397	(397)	—	805	(805)
Total Production	93,241	83,962	9,279	183,815	165,759	18,056

Oil Production (Mbbl)
Appalachia	7	1	6	15	1	14
West Coast	—	522	(522)	—	1,070	(1,070)
Total Production	7	523	(516)	15	1,071	(1,056)

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~~Production Volumes~~

Three Months Ended
December 31,
2017 2016 Increase (Decrease)
Gas Production (MMcf)

Appalachia 35,414
39,807
(4,393 )
West Coast 695
776
(81 )
Total Production 36,109
40,583
(4,474 )

Oil Production (Mbbl)

Appalachia 1
—
1
West Coast 672
721
(49 )
Total Production 673
721
(48 )

Average Prices


	Three Months Ended March 31,						Six Months Ended March 31,
	2023		2022		Increase (Decrease)		2023		2022		Increase (Decrease)
Average Gas Price/Mcf
Appalachia	$	2.79	$	3.97	$	(1.18)	$	3.77	$	4.18	$	(0.41)
West Coast	N/M		$	10.04	N/M		N/M		$	9.91	N/M
Weighted Average	$	2.79	$	4.00	$	(1.21)	$	3.77	$	4.21	$	(0.44)
Weighted Average After Hedging	$	2.58	$	2.60	$	(0.02)	$	2.80	$	2.56	$	0.24

Average Oil Price/Bbl
Appalachia	$	74.12	$	78.32	$	(4.20)	$	78.25	$	75.38	$	2.87
West Coast	N/M		$	94.95	N/M		N/M		$	85.93	N/M
Weighted Average	$	74.12	$	94.93	$	(20.81)	$	78.25	$	85.93	$	(7.68)
Weighted Average After Hedging	$	74.12	$	70.45	$	3.67	$	78.25	$	67.30	$	10.95

Three Months Ended
December 31,
2017 2016 Increase (Decrease)
Average Gas Price/Mcf
Appalachia $ 2.35
$ 2.35
$ —
West Coast $ 5.00
$ 4.24
$ 0.76
Weighted Average $ 2.40
$ 2.39
$ 0.01
Weighted Average After Hedging $ 2.72
$ 2.97
$ (0.25 )

Average Oil Price/Bbl
Appalachia $ 43.85
N/M
N/M
West Coast $ 57.88
$ 43.69
$ 14.19
Weighted Average $ 57.86
$ 43.82
$ 14.04
Weighted Average After Hedging $ 59.79
$ 54.71
$ 5.08

N/M - Not Meaningful (as a result of the sale of Seneca's West Coast assets in June 2022)

~~2017~~2023 Compared with ~~2016~~2022

Operating revenues for the Exploration and Production segment decreased ~~$21.8~~$17.0 million for the quarter ended ~~December~~March 31, ~~2017~~2023 as compared with the quarter ended ~~December~~March 31, ~~2016.~~2022. Gas production revenue after hedging ~~decreased $22.4~~increased $22.5 million ~~primarily~~ due to the impact of a ~~decrease~~9.3 Bcf increase in natural gas production, ~~coupled with~~offset by a ~~$0.25~~$0.02 per Mcf decrease in the weighted average price of natural gas after hedging. ~~The decrease in~~Natural gas production ~~was primarily~~increased largely due to ~~natural declines from Marcellus wells in the Eastern Development Area. This was partially offset by~~additional production ~~increases in the Western Development Area~~ from new Marcellus and Utica wells ~~coupled with a~~in the Appalachian region. Oil production revenue after hedging decreased $36.3 million due to the sale of the Exploration and Production segment's California assets on June 30, 2022. In addition, other revenue decreased $2.5 million and gas processing plant revenue decreased $0.8 million. The decrease in ~~price-related curtailments~~other revenue was attributed to higher temporary capacity releases during the quarter ended ~~December~~March 31, ~~2017~~2022 when compared to the quarter ended ~~December~~March 31, ~~2016. This~~2023. The decrease in gas processing plant revenue was mainly attributed to ~~operating~~the sale of the California assets.

Operating revenues ~~was partially offset by an increase in oil~~for the Exploration and Production segment increased $15.7 million for the six months ended March 31, 2023 as compared with the six months ended March 31, 2022. Gas production revenue after hedging increased $89.9 million due to the impact of ~~$0.8 million. The~~an 18.1 Bcf increase in ~~oil~~natural gas production ~~revenue was due to~~combined with a ~~$5.08~~$0.24 per ~~Bbl~~Mcf increase in the weighted average price of ~~oil~~natural gas after ~~hedging, which was largely offset by a decrease~~hedging. The increase in ~~crude oil production. The decrease in crude oil~~natural gas production ~~in the West Coast region~~ was largely due to additional production from new Marcellus and Utica wells in the ~~lagging current year impact of~~Appalachian region during the six months ended March 31, 2023 as compared with the six months ended March 31, 2022. Oil production revenue after hedging decreased ~~steam operations and well workover activity at its North Midway Sunset field in prior years (due to lower crude oil prices) coupled with oil production losses~~$70.9 million due to the sale of the California assets. In addition, other revenue decreased $1.9 million and gas processing plant revenue decreased $1.4 million. The decrease in other revenue was attributed to higher temporary ~~shut-in production in Ventura County, California in response~~capacity releases during the six months ended March 31, 2022 when compared to the ~~wildfires occurring~~six months ended March 31, 2023, combined with a decrease in ~~fiscal 2018. During~~operating revenue from this segment's water treatment plants. The decrease in gas processing plant revenue was mainly attributed to the ~~quarter ended December 31, 2017, there was an increase in steam operations and well workover activity versus~~sale of the ~~quarter ended December 31, 2016, which will stimulate future crude oil production.~~California assets.

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The Exploration and Production segment's earnings for the quarter ended ~~December~~March 31, ~~2017~~2023 were ~~$106.7~~$61.0 million, ~~an increase~~a decrease of ~~$71.6~~$10.1 million when compared with earnings of ~~$35.1~~$71.1 million for the quarter ended ~~December~~March 31, 2016. The increase in earnings primarily reflects the remeasurement of accumulated deferred income taxes ($77.3 million) combined with the current period earnings impact of the change in federal tax rate from 35% to a blended rate of 24.5% for fiscal 2018 on current income taxes ($4.1 million), both of which were the result of the 2017 Tax Reform Act. It also reflects higher crude oil prices after hedging ($2.2 million), lower depletion expense ($1.1 million) and lower income tax expense, excluding the impact of the 2017 Tax Reform Act ($3.9 million).2022. The decrease in ~~depletion expense~~earnings was ~~due~~attributed to a decrease in production coupled with an increase in reserves (an increase in reserves lowers the per mcf/barrel depletion rate) partially offset by an increase in capitalized costs. The decrease in income tax expense, excluding the impact of the 2017 Tax Reform Act, was largely due to an increase in the enhanced oil recovery tax credit related to Seneca's California properties coupled with a decrease in state income taxes as a result of lower pre-tax net income for the Exploration and Production segment. These factors, which contributed to increased earnings during the quarter ended December 31, 2017 compared to the quarter ended December 31, 2016, were partially offset by lower natural gas prices after hedging ($~~6.0~~1.3 million), lower oil production ($28.7 million), higher depletion expense ($6.4 million) and an unrealized loss on contingent consideration received as part of the California asset sale ($1.8 million). A decrease in other revenue ($2.0 million) and gas processing plant revenue ($0.6 million), both of which are discussed above, also contributed to the decrease in earnings. These decreases were partially offset by higher natural gas production ($~~8.6~~19.1 million), lower ~~crude oil production~~lease operating and transportation expenses ($~~1.7~~5.3 million), lower other operating expenses ($3.2 million), lower other taxes ($1.9 million) and higher other ~~operating expenses~~income ($~~0.6~~1.0 million). The increase in depletion expense was primarily due to the net increase in production combined with a $0.05 per Mcf increase in the depletion rate. The decrease in lease operating and transportation expenses was primarily the result of the sale of the California assets, partially offset by higher gathering and transportation costs combined with higher lease operating expenses in the Appalachian region. The decrease in other operating expenses was primarily attributed to the California asset sale. The decrease in other taxes was primarily

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attributed to both the impact of the sale of Seneca's California assets as well as lower Impact Fees in the Appalachian region. The increase in other income was attributed to higher interest income, as well as non-service pension and post-retirement benefit income in the quarter ended March 31, 2023 compared to non-service pension and post-retirement benefit costs in the quarter ended March 31, 2022.

The Exploration and Production segment's earnings for the six months ended March 31, 2023 were $152.2 million, an increase of $18.7 million when compared with earnings of $133.5 million for the six months ended March 31, 2022. The increase in earnings was primarily attributable to higher natural gas production ($36.5 million) and higher natural gas prices after hedging ($34.5 million) as discussed above. Other factors contributing to the earnings increase included lower lease operating and transportation expenses ($11.3 million), lower other operating expenses ($6.5 million), lower other taxes ($0.9 million) and higher other income ($2.3 million). Partially offsetting these items, the Exploration and Production segment experienced lower oil production ($56.1 million), lower other revenue ($1.5 million) and lower gas processing plant revenue ($1.1 million), all of which are discussed above. Other factors that decreased earnings included higher depletion expense ($11.1 million), higher interest expense ($0.9 million), higher income tax expense ($1.1 million) and an unrealized loss on contingent consideration received as part of the California asset sale ($1.7 million). The decrease in lease operating and transportation expenses was primarily the result of the sale of the California assets, partially offset by higher gathering and transportation costs combined with higher lease operating expenses in the Appalachian region. The decrease in other operating expenses was primarily attributed to the California asset sale. The decrease in other taxes was attributed to the impact of the California asset sale, partially offset by higher Impact Fees in the Appalachian region. The increase in other income was attributed to higher interest income, as well as non-service pension and post-retirement income in the six months ended March 31, 2023 compared to non-service pension and post-retirement benefit costs in the six months ended March 31, 2022. The increase in depletion expense was primarily due to anthe net increase in ~~personnel costs.~~production combined with a $0.04 per Mcf increase in the depletion rate. The increase in interest expense can largely be attributed to a higher average interest rate on intercompany short-term borrowings partially offset by lower interest on intercompany long-term borrowings due to the Company's redemption of $500.0 million of 3.75% notes during the six months ended March 31, 2023. The increase in income tax expense was primarily driven by a prior-year benefit realized from the Enhanced Oil Recovery tax credit, which did not recur in the current year as a result of the sale of the California assets.

Pipeline and Storage

Pipeline and Storage Operating Revenues


	Three Months Ended December 31,								Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2017		2016		Increase (Decrease)			(Thousands)	2023		2022		Increase (Decrease)		2023		2022		Increase (Decrease)
Firm Transportation	$	56,756	$	56,749	$	7		Firm Transportation	$	73,487	$	72,259	$	1,228	$	148,944	$	138,084	$	10,860
Interruptible Transportation	340		646		(306		)	Interruptible Transportation	307		412		(105)		1,052		856		196
	57,096		57,395		(299		)		73,794		72,671		1,123		149,996		138,940		11,056
Firm Storage Service	17,839		17,273		566			Firm Storage Service	21,470		21,451		19		42,754		42,251		503
Interruptible Storage Service	19		12		7			Interruptible Storage Service	—		—		—		2		—		2
Other	341		475		(134		)	Other	(161)		1,275		(1,436)		7		2,556		(2,549)
	$	75,295	$	75,155	$	140			$	95,103	$	95,397	$	(294)	$	192,759	$	183,747	$	9,012

Pipeline and Storage Throughput


	Three Months Ended December 31,					Three Months Ended March 31,			Six Months Ended March 31,
(MMcf)	2017	2016	Increase (Decrease)		(MMcf)	2023	2022	Increase (Decrease)	2023	2022	Increase (Decrease)
Firm Transportation	206,701	190,781	15,920		Firm Transportation	231,081	232,030	(949)	455,705	425,623	30,082
Interruptible Transportation	882	3,046	(2,164	)	Interruptible Transportation	619	752	(133)	1,927	1,520	407
	207,583	193,827	13,756			231,700	232,782	(1,082)	457,632	427,143	30,489

~~2017~~

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2023 Compared with ~~2016~~2022

Operating revenues for the Pipeline and Storage segment ~~remained relatively flat~~decreased $0.3 million for the quarter ended ~~December~~March 31, ~~2017~~2023 as compared with the quarter ended March 31, 2022. The decrease in operating revenues was primarily due to a decrease in other revenue of $1.4 million, partially offset by an increase in transportation revenues of $1.1 million. The decrease in other revenue primarily reflects an adjustment to electric surcharge revenues and lower cashout 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. Cashout revenues are completely offset by purchased gas expense. The increase in transportation revenues was primarily attributable to Period 2 Rates that went into effect April 1, 2022. These Period 2 Rates were a negotiated revenue step-up as part of the FM100 Project that was placed into service in December 2021, as specified in Supply Corporation's 2020 rate case settlement. An increase in short-term contracts also contributed to the increase in transportation revenues. These increases were partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions.

Operating revenues for the Pipeline and Storage segment increased $9.0 million for the six months ended March 31, ~~2016. An~~2023 as compared with the six months ended March 31, 2022. The increase in operating revenues was primarily due to an increase in transportation revenues of $11.1 million and an increase in storage revenues of $0.5 million, partially offset by a decrease in other revenue of $2.5 million. The increase in transportation revenues was primarily attributable to new demand charges for transportation service from Supply Corporation's ~~Line D Expansion,~~FM100 Project, which was placed into service in ~~service on November~~December 2021. The increase from the FM100 Project includes the impact of a negotiated revenue step-up to Period 2 Rates that went into effect April 1, ~~2017, and an~~2022, as mentioned above. An increase in ~~both~~short-term contracts also contributed to the increase in transportation ~~and storage revenues due to Supply Corporation's greenhouse gas and pipeline safety surcharge effective November 1, 2017,~~revenues. These increases were ~~largely~~partially offset by a decline in ~~transportation~~ revenues associated with miscellaneous contract terminations and revisions. The increase in storage revenues was mainly due ~~partially~~ to the Period 2 Rates that went into effect April 1, 2022 related to the FM100 Project, as discussed above, as well as an ~~additional 2% reduction~~increase in ~~Supply Corporation's rates effective November 1, 2016, which was required by the rate case settlement approved by FERC on November 13, 2015, and a decline in demand~~reservation charges for ~~transportation services as a result of contract terminations.~~storage service from several new contracts that went into effect. The decrease in other revenue primarily reflects an adjustment to electric surcharge revenues and lower cashout revenues.

Transportation volume for the quarter ended ~~December~~March 31, ~~2017 increased~~2023 decreased by ~~13.8~~1.1 Bcf from the prior ~~year’s quarter.~~year's quarter ended March 31, 2022. For the six months ended March 31, 2023, transportation volume increased by 30.5 Bcf from the prior year's six-month period ended March 31, 2022. The increase in transportation volume for the ~~quarter~~six-month period primarily reflects an increase in volume from the ~~impact of~~FM100 Project, which was brought online in December 2021, as well as an increase in short-term contracts. These were partially offset by certain contract terminations during the ~~Line D Expansion project being placed in service combined with colder weather quarter over quarter.~~six months ended March 31, 2023. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

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The Pipeline and Storage segment’s earnings for the quarter ended ~~December~~March 31, ~~2017~~2023 were ~~$38.5~~$23.9 million, ~~an increase~~a decrease of ~~$19.1~~$1.6 million when compared with earnings of ~~$19.4~~$25.5 million for the quarter ended ~~December~~March 31, ~~2016.~~2022. The decrease in earnings was primarily due to an increase in operating expenses of $2.2 million, combined with the earnings impact of lower operating revenues of $0.2 million, as discussed above. The increase in operating expenses was primarily due to higher personnel costs, higher pipeline integrity costs and an increase in compressor maintenance costs. This was partially offset by lower power costs related to Empire's electric motor drive compressor station. This reduction in electric power costs is offset by an equal reduction in revenue, as discussed above. These earnings decreases were partially offset by an increase in other income of $0.9 million, which was primarily due to a higher weighted average interest rate on intercompany short-term notes receivables along with higher non-service pension and post-retirement benefit income. This was partially offset by a decrease in the allowance for funds used during construction (equity component) related to an annual adjustment that was recorded during the current quarter.

The Pipeline and Storage segment’s earnings for the six months ended March 31, 2023 were $53.3 million, an increase of $2.7 million when compared with earnings of $50.6 million for the six months ended March 31, 2022. The increase in earnings was primarily due to ~~lower income tax expense ($17.6 million)~~the earnings impact of higher operating revenues of $7.1 million, as discussed above, combined with ~~lower~~an increase in other income ($1.5 million). The increase in other income is primarily due to a higher weighted average interest rate on intercompany short-term notes receivables along with higher non-service pension and post-retirement benefit income. This was partially offset by a decrease in allowance for funds used during construction (equity component) related to the construction of the FM100 Project that was placed into service in December 2021 along with an annual adjustment that was recorded during the current fiscal year. These earnings increases were partially offset by increases in operating expenses ($~~1.9~~3.7 million), depreciation expense ($1.6 million) and interest expense ($0.9 million). The increase in operating expenses was primarily due to higher personnel costs, higher pipeline integrity costs and an increase in compressor maintenance costs. This was partially offset by lower power costs related to Empire's electric motor drive compressor station. This reduction in electric

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power costs is offset by an equal reduction in revenue, as discussed above. The increase in depreciation expense was primarily due to incremental depreciation from the FM100 Project going into service in December 2021. The increase in interest expense was mainly due to higher interest rates on security deposits and intercompany short-term borrowings, partially offset by a decrease in interest ~~expense ($0.3 million). Income tax expense was lower~~on intercompany long-term borrowings due to the ~~remeasurement~~Company's redemption of ~~accumulated deferred income taxes ($14.1 million) combined with~~$500.0 million of 3.75% notes during the current period earnings impact of the change in federal tax rate from 35% to a blended rate of 24.5% for fiscal 2018 ($3.5 million), both a result of the 2017 Tax Reform Act. The decrease in operating expenses primarily reflects lower pension and other post-retirement benefit costs combined with a decrease in the reserve for preliminary project costs. The decrease in interest expense was largely due to lower intercompany long-term borrowing interest rates for the Pipeline and Storage segment. These earnings increases were slightly offset by an increase in depreciation expense ($0.6 million) due to incremental depreciation expense related to expansion projects that were placed in service within the last year combined with the non-recurrence of a reduction to depreciation expense recorded in the quartersix months ended ~~December~~March 31, ~~2016 to reflect a reduction in depreciation rates retroactive to July 1, 2016 in accordance with Empire's rate case settlement. The FERC issued an order approving the settlement on December 13, 2016.~~2023.

Looking ahead, the Pipeline and Storage segment expects transportation revenues to be negatively impacted in fiscal 2019 in an amount up to approximately $14 million as a result of an Empire system transportation contract reaching its termination date in December 2018. Management does not expect to renew the contract at existing rates given a change in market dynamics.

Gathering

Gathering Operating Revenues


	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2023		2022		Increase (Decrease)		2023		2022		Increase (Decrease)
Gathering Revenues	$	56,981	$	52,604	$	4,377	$	113,394	$	104,829	$	8,565

Three Months Ended
December 31,
(Thousands) 2017 2016 Increase (Decrease)
Gathering $ 23,802
$ 27,840
$ (4,038 )
Processing and Other Revenues 33
26
7
$ 23,835
$ 27,866
$ (4,031 )

Gathering Volume

Three Months Ended
December 31,
2017 2016 Increase (Decrease)
Gathered Volume - (MMcf) 43,162
50,569
(7,407 )


	Three Months Ended March 31,			Six Months Ended March 31,
	2023	2022	Increase (Decrease)	2023	2022	Increase (Decrease)
Gathered Volume - (MMcf)	109,344	103,736	5,608	217,371	204,829	12,542

~~2017~~2023 Compared with ~~2016~~2022

Operating revenues for the ~~Gathering~~Gathering segment ~~decreased $4.0~~increased $4.4 million for the quarter ended ~~December~~March 31, ~~2017~~2023 as compared with the quarter ended ~~December~~March 31, ~~2016,~~2022, which was driven primarily by a ~~7.4~~5.6 Bcf ~~decrease~~increase in gathered volume. The ~~overall decrease~~increase in gathered volume ~~was due~~can be attributed primarily to ~~a 5.2~~an increase in natural gas production on the Covington and Clermont gathering systems, which recorded increases of 14.9 Bcf ~~decrease in gathered volume on Midstream Corporation’s Trout Run Gathering System (Trout Run), a 2.0~~and 4.2 Bcf, decrease in gathered volume on Midstream Corporation's Covington Gathering System (Covington), a 0.6 Bcf decrease in gathered volume on Midstream Corporation's Wellsboro Gathering System (Wellsboro), and a 0.1 Bcf decrease in gathered volumes spread across numerous Midstream systems. These decreases wererespectively, partially offset by decreases on the Trout Run and Wellsboro gathering systems, which recorded decreases of 8.6 Bcf and 4.9 Bcf, respectively. The net increase can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.

Operating revenues for the Gathering segment increased $8.6 million for the six months ended March 31, 2023 as compared with the six months ended March 31, 2022, which was driven primarily by a ~~0.5~~12.5 Bcf increase in gathered ~~volume on Midstream Corporation's~~volume. Contributors to the increase included the Covington and Clermont ~~Gathering System (Clermont).~~gathering systems, which recorded increases of 31.1 Bcf and 5.7 Bcf, respectively, partially offset by the Trout Run and Wellsboro gathering systems, which recorded decreases of 18.6 Bcf and 5.7 Bcf, respectively. The ~~decreases~~net increase can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned ~~volumes were largely due to a decrease in Seneca's production.~~gathering systems.

The Gathering segment’s earnings for the quarter ended ~~December~~March 31, ~~2017~~2023 were ~~$45.4~~$24.3 million, an increase of ~~$34.4~~$2.2 million when compared with earnings of ~~$11.0~~$22.1 million for the quarter ended ~~December~~March 31, ~~2016.~~2022. The increase in earnings was mainly due to higher gathering revenues ($3.5 million) driven by the ~~impact of the 2017 Tax Reform Act, which led to the remeasurement of accumulated deferred taxes ($34.9 million) and the impact of the tax rate change on current income tax ($1.5 million).~~increase in gathered volume, as discussed above. These ~~earnings~~ increases were partially offset by ~~lower~~higher operating expenses ($0.9 million) and higher depreciation expense ($0.4 million). The increase in operating expenses was largely attributable to higher leased compression and material costs on the Trout Run and Covington gathering ~~revenue~~systems combined with higher labor costs across all of the gathering systems. The increase in depreciation expense was largely due to higher plant balances associated with the Covington and Clermont gathering systems.

The Gathering segment’s earnings for the six months ended March 31, 2023 were $49.1 million, an increase of $3.9 million when compared with earnings of $45.2 million for the six months ended March 31, 2022. The increase in earnings was mainly due to higher gathering revenues ($~~2.6~~6.8 million), driven by the increase in gathered volume, as discussed above. This increase was partially offset by higher operating expenses ($2.1 million) and higher depreciation expense ($0.7 million). The increase in operating expenses was largely attributable to higher leased compression costs on the Trout Run and Covington gathering systems, higher material costs on the Clermont and Covington gathering systems and higher labor costs across all of the gathering systems. The increase in depreciation expense was largely due to higher plant balances associated with the Covington and Clermont gathering systems.

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Utility

Utility Operating Revenues


	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2023		2022		Increase (Decrease)		2023		2022		Increase (Decrease)
Retail Sales Revenues:
Residential	$	320,043	$	286,329	$	33,714	$	565,484	$	469,037	$	96,447
Commercial	47,569		41,668		5,901		82,913		66,910		16,003
Industrial	2,787		2,193		594		4,430		3,350		1,080
	370,399		330,190		40,209		652,827		539,297		113,530
Transportation	38,581		43,159		(4,578)		68,093		72,810		(4,717)

Other	(1,864)		(4,147)		2,283		(2,124)		(6,147)		4,023
	$	407,116	$	369,202	$	37,914	$	718,796	$	605,960	$	112,836

Three Months Ended
December 31,
(Thousands) 2017 2016 Increase (Decrease)
Retail Sales Revenues:
Residential $ 134,739
$ 116,387
$ 18,352
Commercial 19,633
15,979
3,654
Industrial 872
517
355
155,244
132,883
22,361
Transportation 36,309
36,661
(352 )
Off-System Sales 41
627
(586 )
Other (2,323 ) 2,626
(4,949 )
$ 189,271
$ 172,797
$ 16,474

Utility Throughput


	Three Months Ended December 31,					Three Months Ended March 31,			Six Months Ended March 31,
(MMcf)	2017	2016	Increase (Decrease)		(MMcf)	2023	2022	Increase (Decrease)	2023	2022	Increase (Decrease)
Retail Sales:					Retail Sales:
Residential	17,847	15,764	2,083		Residential	27,884	32,026	(4,142)	48,037	49,521	(1,484)
Commercial	2,596	2,299	297		Commercial	4,384	4,923	(539)	7,378	7,466	(88)
Industrial	144	77	67		Industrial	267	268	(1)	418	392	26
	20,587	18,140	2,447			32,535	37,217	(4,682)	55,833	57,379	(1,546)
Transportation	21,427	19,565	1,862		Transportation	22,788	25,745	(2,957)	41,098	43,338	(2,240)
Off-System Sales	22	173	(151	)
	42,036	37,878	4,158
						55,323	62,962	(7,639)	96,931	100,717	(3,786)

Degree Days

Three Months Ended December 31, Percent Colder (Warmer) Than
Normal 2017 2016
Normal⁽¹⁾
Prior Year⁽¹⁾
Buffalo 2,253
2,227
1,966
(1.2 )% 13.3 %
Erie 2,044
2,029
1,750
(0.7 )% 15.9 %


⁽¹⁾	~~Percents compare actual 2017 degree days to normal degree days and actual 2017 degree days to actual 2016 degree days.~~

~~2017 Compared with 2016~~


Three Months Ended March 31,				Percent Colder (Warmer) Than
	Normal	2023	2022	Normal(1)		Prior Year(1)
Buffalo, NY	3,290	2,820	3,161	(14.3)	%	(10.8)	%
Erie, PA	3,108	2,645	2,973	(14.9)	%	(11.0)	%
Six Months Ended March 31,
Buffalo, NY	5,543	4,868	4,865	(12.2)	%	0.1	%
Erie, PA	5,152	4,632	4,533	(10.1)	%	2.2	%

(1)Percents compare actual 2023 degree days to normal degree days and actual 2023 degree days to actual 2022 degree days.

2023 Compared with 2022

Operating revenues for the Utility segment increased ~~$16.5~~$37.9 million for the quarter ended ~~December~~March 31, ~~2017~~2023 as compared with the quarter ended ~~December~~March 31, ~~2016.~~2022. The increase resulted largely from a $40.2 million increase in retail gas sales revenue. This increase primarily reflects an increase in the cost of gas sold (per Mcf), partially offset by a 4.7 Bcf decrease in throughput due to warmer weather and a decrease in base rates. It should be noted that under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is not allowed to profit from fluctuations in gas costs. Purchased gas expense recorded on the consolidated income statement matches the revenues collected from customers. Revenues collected in 2023 reflect not only the current cost of gas but also the collection of previously deferred under collected gas costs. The decrease in base rates is related to a tariff filing approved by the NYPSC, which created a surcredit that temporarily eliminates pension and

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OPEB cost recovery from base rates effective October 1, 2022. Additional details related to the regulatory proceeding are discussed in the Rate Matters section and in Item 1 at Note 11 - Regulatory Matters. In addition to the overall increase in retail gas sales revenue, there was a $2.3 million increase in other revenues. The increase in other revenues is the result of higher capacity release revenues ($1.1 million) and a smaller estimated refund provision from the income tax benefits resulting from the 2017 Tax Reform Act ($1.4 million). Partially offsetting the impact of higher retail gas sales revenue and other revenues, there was a $4.6 million decrease in transportation revenues. The decrease in transportation revenues is mainly attributable to a decrease in base rates, as a result of the NYPSC tariff filing related to pension and OPEB costs discussed above, as well as a 3.0 Bcf decrease in throughput due to warmer weather. The decrease in transportation revenues was partially offset by an increase in the system modernization tracker allocation to transportation customers.

Operating revenues for the Utility segment increased $112.8 million for the six months ended March 31, 2023 as compared with the six months ended March 31, 2022. The increase largely resulted from a ~~$22.4~~$113.5 million increase in retail gas sales revenue and a $4.0 million increase in other revenues, which were partially offset by a $4.7 million decrease in transportation revenues. The increase in retail gas sales revenue was ~~largely~~primarily due to a ~~result of higher volumes (due to colder weather) and an~~considerable increase in the cost of gas sold (per Mcf)~~. The increase in operating revenues was~~ partially offset by a ~~$0.4 million~~ decrease in ~~transportation revenues,~~base rates, as a ~~$4.9 million~~result of the NYPSC tariff filing related to pension and OPEB costs discussed above, as well as a 1.5 Bcf decrease in ~~other revenues and a $0.6 million decrease in off-system sales (due to lower volumes). The $0.4 million decrease in transportation revenues was primarily~~throughput due to ~~the impact of regulatory adjustments, which more than offset the impact of larger volumes and colder~~warmer weather. The ~~$4.9 million decrease~~increase in other revenues was largely due to anhigher capacity release revenues ($1.8 million), a smaller estimated refund provision ~~for~~from the ~~current~~ income tax benefits resulting from the 2017 Tax Reform ~~Act. Due~~Act ($0.9 million), a positive regulatory adjustment ($0.9 million), and higher late payment charges billed to ~~profit sharing with retail~~ customers ($0.5 million). The decrease in transportation revenues was largely due to a 2.2 Bcf decrease in transportation throughput during the ~~margins related~~six months ended March 31, 2023 and the decrease in base rates, as previously mentioned. The decrease in transportation revenues was partially offset by an increase in the system modernization tracker allocation to ~~off-system sales are minimal.~~transportation customers.

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The Utility segment’s earnings for the quarter ended ~~December~~March 31, ~~2017~~2023 were ~~$21.0~~$31.7 million, a decrease of ~~$0.2~~$21.3 million when compared with earnings of ~~$21.2~~$53.0 million for the quarter ended ~~December~~March 31, ~~2016. Higher~~2022. The decrease in earnings ~~associated with~~was primarily attributable to the ~~new rate order issued~~non-recurrence of an adjustment that increased earnings by $14.6 million during the ~~NYPSC effective April 1, 2017~~quarter ended March 31, 2022. The adjustment, which resulted from the conclusion of a proceeding in the Utility's Pennsylvania service territory, recognized the cumulative amount of OPEB income in that jurisdiction that previously had been deferred as a regulatory liability. In addition to the non-recurrence of this transaction, there was a decrease in OPEB income ($~~1.0~~1.7 million) ~~combined with~~in the ~~impact of colder~~Utility's Pennsylvania service territory quarter over quarter. Other factors contributing to the decrease included a decrease in usage due to warmer weather ~~in fiscal 2018 compared to fiscal 2017~~ ($~~1.2~~2.9 million) ~~were partially offset by an increase in operating~~, higher interest expense ($~~0.7~~3.4 million), and ~~the impact of regulatory adjustments~~higher operating expenses ($~~1.2~~1.7 million). The increase in interest expense was largely the result of a higher weighted average interest rate on intercompany short-term borrowings. The increase in operating ~~expense is primarily~~expenses was mainly due to higher ~~amortization~~personnel costs and an increase in the accrual for uncollectible accounts.

An additional decrease of ~~environmental remediation costs that~~$6.3 million resulted from a reduction in the ~~new rate order. The current tax benefit associated with~~New York jurisdiction’s base rates as a result of the ~~2017 Tax Reform Act~~NYPSC tariff filing related to pension and OPEB costs discussed above, which temporarily eliminated the recovery of pension and OPEB expenses effective October 1, 2022. This was ~~completely~~ offset by ~~the aforementioned refund provision.~~a decrease in non-service pension and post-retirement benefit costs ($6.6 million), as Distribution Corporation’s New York service territory ceased recognizing pension and OPEB expenses.

Partially offsetting these decreases, the Utility segment also experienced the positive earnings impact of a system modernization tracker in New York ($1.7 million), interest earned on deferred gas costs ($0.7 million), and lower income tax expense ($0.8 million) when comparing the quarter ended March 31, 2023 to the quarter ended March 31, 2022.

The impact of weather variations on earnings in the Utility ~~segment’s~~segment's New York rate jurisdiction is mitigated by that ~~jurisdiction’s~~jurisdiction's weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, in periods of colder than normal weather, the WNC benefits the Utility ~~segment’s~~segment's New York customers. For the quarter ended ~~December~~March 31, ~~2017,~~2023, the WNC increased earnings by approximately ~~$0.9~~$3.3 million, as the weather was warmer than normal. For the quarter ended ~~December~~March 31, ~~2016,~~2022, the WNC ~~preserved~~increased earnings ~~of $1.3~~by approximately $1.5 million, as the weather was warmer than normal.

The Utility segment’s earnings for the six months ended March 31, 2023 were $55.5 million, a decrease of $19.7 million when compared with earnings of $75.2 million for the six months ended March 31, 2022. The decrease is primarily attributable to the non-recurrence of an adjustment that increased earnings by $14.6 million during the quarter ended March 31, 2022, as discussed above. In addition to the non-recurrence of this transaction, there was a decrease in OPEB income ($1.6 million) in the Utility's Pennsylvania service territory period over period. The reduction in the New York jurisdiction's base rates resulting from the NYPSC tariff filing also discussed above ($10.1 million), higher interest expense primarily due to a

~~Energy Marketing~~

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higher weighted average interest rate on intercompany short-term borrowings ($5.4 million), and higher operating expenses ($4.1 million) resulting from higher personnel costs and an increase in the accrual for uncollectible accounts also contributed to the decrease in earnings.

Given the elimination of pension and OPEB expense in customer rates, earnings benefited from a decrease in non-service pension and OPEB costs ($10.2 million) in Distribution Corporation's New York service territory, as a result of the NYPSC tariff filing, discussed above. In addition, the impact of a system modernization tracker in New York ($2.6 million), higher other operating revenues ($1.7 million), and lower income tax expense ($0.7 million) partially offset the decrease in earnings when comparing the six months ended March 31, 2023, to the six months ended March 31, 2022. Other operating revenues increased largely due to higher capacity release revenues.

For the six months ended March 31, 2023, the WNC increased earnings by approximately $4.2 million, as the weather was warmer than normal. For the six months ended March 31, 2022, the WNC increased earnings by approximately $4.1 million, as the weather was warmer than normal.

Corporate and All Other

~~Energy Marketing Operating Revenues~~

Three Months Ended
December 31,
(Thousands) 2017 2016 Increase (Decrease)
Natural Gas (after Hedging) $ 38,730
$ 36,790
$ 1,940
Other 32
38
(6 )
$ 38,762
$ 36,828
$ 1,934
2023 Compared with 2022

~~Energy Marketing Volume~~

Three Months Ended
December 31,
2017 2016 Increase (Decrease)
Natural Gas – (MMcf) 11,979
11,127
852

~~2017 Compared with 2016~~

~~Operating revenues~~ Corporate and All Other operations had a net loss of less than $0.1 million for the ~~Energy Marketing segment~~quarter ended March 31, 2023, a decrease in net loss of $4.4 million when compared with the quarter ended March 31, 2022. The reduction in net loss was primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the quarter ended March 31, 2023, the Company recorded unrealized gains of $0.8 million. During the quarter ended March 31, 2022, the Company recorded unrealized losses of $1.7 million. Also contributing to the reduction in net loss were changes in cash surrender value of life insurance policies, which increased ~~$1.9~~in value $0.4 million during the current quarter compared to a decrease in value of $0.7 million during the prior-year second quarter.

For the six months ended March 31, 2023, Corporate and All Other operations had earnings of $0.5 million, an increase of $5.3 million when compared with a net loss of $4.8 million for the six months ended March 31, 2022. The increase in earnings was primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the six months ended March 31, 2023, the Company recorded unrealized gains of $1.0 million. During the six months ended March 31, 2022, the Company recorded unrealized losses of $5.3 million. Lower non-service pension and post-retirement benefit costs ($1.0 million) also contributed to the increase in earnings. These changes were partially offset by a decrease in realized gains from sales of investments in equity securities ($2.9 million).

Other Income (Deductions)

Net other income on the Consolidated Statement of Income was $2.9 million for the quarter ended ~~December~~March 31, ~~2017 as~~2023, compared ~~with~~to net other income of $10.0 million for the quarter ended ~~December~~March 31, ~~2016. The increase~~2022. This change is primarily attributable to an $11.2 million decrease in non-service pension and post-retirement benefit income quarter over quarter. This is largely related to lower non-service post-retirement benefit income in the Utility’s Pennsylvania service territory stemming from the conclusion of a rate proceeding in the Utility’s Pennsylvania service territory during the quarter ended March 31, 2022. As a result of that proceeding, a one-time adjustment was recorded to reduce a regulatory liability in that jurisdiction by $18.5 million. This decrease in OPEB income was partially offset by an $8.3 million decrease in non-service pension and post-retirement benefit expense in the Utility’s New York Service territory as a result of a tariff filing that became effective October 1, 2022. Additional details related to the regulatory proceedings are discussed in the Rate Matters section and in Item 1, Note 11 – Regulatory Matters.

Net other income on the Consolidated Statement of Income was $9.2 million for the six months ended March 31, 2023, compared to net other income of $8.9 million for the six months ended March 31, 2022. Higher interest income of $4.6 million contributed to the increase. This was primarily due to an increase in interest on temporary cash investments, increased interest on a larger undercollection of gas ~~sales revenue due to~~costs over the prior year in Distribution Corporation and an increase in ~~volume sold to retail customers~~interest received from hedging collateral deposits in the Exploration and Production segment. Changes in unrealized and realized gains and losses on investments in equity securities also increased other income by $5.1 million period over period. Offsetting these increases, there was a $5.0 million reduction in non-service pension and post-retirement benefit income period over period. As discussed above, the Utility's Pennsylvania service territory recorded a one-time adjustment that resulted in $18.5 million of income during the quarter ended March 31, 2022. The resulting earnings reduction in 2023 was largely offset by a $12.9 million decrease in non-service pension and post-retirement benefit expense in the Utility's New York service territory as a result of ~~colder weather, offset slightly by~~the

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tariff filing that became effective October 1, 2022. Other offsetting factors include a ~~lower average price~~mark-to-market adjustment that reduced the value of ~~natural gas period over period.~~the contingent consideration received from the sale of Seneca's California assets in June 2022 and a $1.9 million reduction in allowance for funds used during construction.

~~The Energy Marketing segment earnings for~~Interest Expense on Long-Term Debt

Interest expense on long-term debt on the ~~quarter ended December 31, 2017 were $1.0 million, a decrease~~Consolidated Statement of ~~$0.8 million when compared with earnings of $1.8~~Income decreased $2.5 million for the quarter ended ~~December~~March 31, ~~2016. This decrease in earnings was primarily attributable~~2023 as compared to lower margin of $0.8 million. The decrease in margin largely reflects a decline in average margin per Mcf primarily due to stronger natural gas prices at local purchase points relative to NYMEX-based sales contracts. The 2017 Tax Reform Act did not have a significant impact on Energy Marketing segment earnings for the quarter ended ~~December~~March 31, ~~2017.~~

~~Corporate and All Other~~

~~2017 Compared with 2016~~

~~Corporate and All Other operations had a loss of $13.9 million for~~2022. For the ~~quarter~~six months ended ~~December~~March 31, 2017, a decrease of $14.4 million when compared with earnings of $0.5 million for the quarter ended December 31, 2016. The earnings decrease for the quarter is primarily attributed to a remeasurement of accumulated deferred taxes under the 2017 Tax Reform Act ($15.1 million). This decrease in earnings was partially offset by higher margins ($0.4 million) from the sale of standing timber by Seneca's land and timber division and the current tax benefit of tax rate changes associated with the 2017 Tax Reform Act ($0.1 million).

~~Table of Contents~~

~~Interest Expense on Long-Term Debt (amounts below are pre-tax amounts)~~

~~Interest~~2023, interest expense on long-term debt decreased ~~$1.0~~$3.0 million ~~for the quarter ended December 31, 2017~~ as compared with the ~~quarter~~six months ended ~~December~~March 31, ~~2016.~~2022. This ~~decrease is~~was primarily due to ~~a decrease in~~ the ~~weighted average interest rate on long-term debt outstanding. The Company issued $300~~March 2023 redemptions of $350.0 million of ~~3.95% notes in September 2017~~the $500.0 million 3.75% note and ~~repaid $300~~the $49.0 million 7.395% note. In addition, $150.0 million of ~~6.5% notes~~the $500.0 million 3.75% note was redeemed in ~~October 2017.~~November 2022, which also contributed to the decrease.

CAPITAL RESOURCES AND LIQUIDITY

~~The Company’s primary source of cash during the three-month period ended December 31, 2017 consisted of cash provided by operating activities.~~ The Company’s primary sources of cash during the ~~three-month~~six-month period ended ~~December~~March 31, ~~2016~~2023 consisted of cash provided by operating activities, proceeds from short-term borrowings and proceeds from the sale of a fixed income mutual fund held in a grantor trust. The Company’s primary sources of cash during the six-month period ended March 31, 2022 consisted of cash provided by operating activities, net proceeds from short-term borrowings, proceeds from the sale of a fixed income mutual fund held in a grantor trust and net proceeds from the sale of oil and gas ~~producing~~ properties.

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 2023, cash provided by operating activities is expected to increase when compared to the same period in 2022 and will be used to fund the Company's capital expenditures. Based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures in 2024. This is expected to provide the Company with the option to consider additional growth investments, further reductions in short-term debt, and increasing the amount of cash flow returned to shareholders, either through increases to the Company’s dividend or via repurchases of common stock. 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 Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.

Because of the seasonal nature of the heating business in the Utility ~~and Energy Marketing segments,~~segment, revenues in ~~these segments~~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 ~~and crude oil~~ as well as changes in production. The Company uses various derivative financial instruments, including price swap agreements and ~~futures contracts~~no cost collars, in an attempt to manage this energy commodity price risk.

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Net cash provided by operating activities totaled ~~$94.8~~$711.2 million for the ~~three~~six months ended ~~December~~March 31, ~~2017, a decrease~~2023, an increase of ~~$49.8~~$285.6 million compared with ~~$144.6~~$425.6 million provided by operating activities for the ~~three~~six months ended ~~December~~March 31, ~~2016.~~2022. The ~~decrease~~increase in cash provided by operating activities primarily reflects ~~lower~~higher cash provided by operating activities in the Exploration and Production ~~and Energy Marketing segments. The decrease in the Exploration and Production~~ segment ~~was~~ primarily due to ~~lower~~higher cash receipts from ~~crude oil and~~ natural gas production ~~primarily a result of lower~~in the Appalachian region and higher realized natural gas prices, and lower production. The decrease in the Energy Marketing segment was primarily a result of higher purchased gas costs and an increase in hedging collateral deposits. Hedging collateral deposits serve as collateral for open positions on exchange-trade futures contracts and over-the-counter swaps.after hedging.

~~Table of Contents~~

Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled ~~$126.5~~$440.6 million during the ~~three~~six months ended ~~December~~March 31, ~~2017~~2023 and ~~$94.6~~$376.2 million during the ~~three~~six months ended ~~December~~March 31, ~~2016.~~2022. The table below presents these expenditures:


Total Expenditures for Long-Lived Assets										Total Expenditures for Long-Lived Assets
Three Months Ended December 31,	2017			2016			Increase (Decrease)
Six Months Ended March 31,						Six Months Ended March 31,				2023				2022				Increase (Decrease)
(Millions)	2017				2016				Increase (Decrease)			(Millions)
Exploration and Production:							Exploration and Production:
Capital Expenditures	$	74.7	(1)	$	40.7	(2)	$	34.0		Capital Expenditures	$	323.6	(1)		$	274.0	(2)		$	49.6
Pipeline and Storage:										Pipeline and Storage:
Capital Expenditures	22.3		(1)	25.4		(2)	(3.1		)	Capital Expenditures	33.3		(1)		38.5		(2)		(5.2)
Gathering:										Gathering:
Capital Expenditures	12.9		(1)	11.3		(2)	1.6			Capital Expenditures	34.1		(1)		20.0		(2)		14.1
Utility:										Utility:
Capital Expenditures	16.5		(1)	17.1		(2)	(0.6		)	Capital Expenditures	49.2		(1)		43.3		(2)		5.9
All Other:										All Other:
Capital Expenditures	0.1		(1)	0.1		(2)	—			Capital Expenditures	0.4				0.4				—
	$	126.5		$	94.6		$	31.9
											$	440.6			$	376.2			$	64.4

~~(1)~~

At ~~December 31, 2017~~,

(1)At March 31, 2023, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $37.1 million, $10.7 million, $4.7 million and $3.6 million, respectively, of non-cash capital expenditures. At ~~September 30, 2017~~, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $36.5 million, $25.1 million, $3.9 million and $6.7 million, respectively, of non-cash capital expenditures. The capital expenditures for the Exploration and Production segment do not include any proceeds received from the sale of oil and gas assets to IOG under the joint development agreement.

~~(2)~~

At ~~December 31, 2016~~, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $25.3 million, $8.7 million, $7.9 million and $7.1 million, respectively, of non-cash capital expenditures. At ~~September 30, 2016~~, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $25.2 million, $18.7 million, $5.3 million and $11.2 million, respectively, of non-cash capital expenditures. The capital expenditures for the Exploration and Production segment do not include any proceeds received from the sale of oil and gas assets to IOG under the joint development agreement.

Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $56.1 million, $2.2 million, $2.0 million and $4.2 million, respectively, of non-cash capital expenditures. At September 30, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $83.0 million, $15.2 million, $10.7 million and $11.4 million, respectively, of non-cash capital expenditures.

(2)At March 31, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $52.5 million, $3.5 million, $3.4 million and $4.1 million, respectively, of non-cash capital expenditures. At September 30, 2021, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $47.9 million, $39.4 million, $4.8 million and $10.6 million, respectively, of non-cash capital expenditures.

Exploration and Production

The Exploration and Production segment capital expenditures for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2023 were primarily well drilling and completion expenditures in the Appalachian region (including $143.2 million in the Marcellus Shale area and $172.4 million in the Utica Shale area). These amounts included approximately $208.2 million spent to develop proved undeveloped reserves.

The Exploration and Production segment capital expenditures for the six months ended March 31, 2022 were primarily well drilling and completion expenditures and included approximately ~~$70.6~~$258.8 million for the Appalachian region (including ~~$58.7~~$84.8 million in the Marcellus Shale area and $166.8 million in the Utica Shale area) and ~~$4.1~~$15.2 million for the West Coast region. These amounts included approximately ~~$40.7 million spent to develop proved undeveloped reserves.~~

On December 1, 2015, Seneca and IOG - CRV Marcellus, LLC (IOG), an affiliate of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension of the joint development agreement. Under the terms of the extended agreement, Seneca and IOG will jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80% working interest in all of the joint development wells. In total, IOG is expected to fund approximately $305 million for its 80% working interest in the 75 joint development wells. Of this amount, IOG has funded $267.1 million as of December 31, 2017, which includes $163.9 million of cash ($137.3 million in fiscal 2016 and $26.6 million in fiscal 2017) shown as Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statements of Cash Flows for fiscal 2016 and fiscal 2017. Such proceeds from sale represent funding received from IOG for costs previously incurred by Seneca to develop a portion of the 75 joint development wells. A receivable of $17.3 million has been recorded at December 31, 2017 in recognition of additional IOG funding that is due to Seneca for costs incurred by Seneca to develop a portion of the 75 joint development wells. This receivable has been shown as a Non-Cash Investing Activity on the Consolidated Statement of Cash Flows for the quarter ended December 31, 2017. The remainder funded joint development expenditures. For further discussion of the extended joint development agreement, refer to Item 1 at Note 1 - Summary of Significant Accounting Policies under the heading “Property, Plant and Equipment.”

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The Exploration and Production segment capital expenditures for the three months ended December 31, 2016 were primarily well drilling and completion expenditures and included approximately $29.8 million for the Appalachian region (including $16.4 million in the Marcellus Shale area) and $10.9 million for the West Coast region. These amounts included approximately $8.3$93.4 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2023 were ~~partially related to~~primarily for additions, improvements and replacements to this ~~segment’s~~segment's transmission and gas storage ~~systems.~~systems, which included system modernization expenditures that enhance the reliability and safety of the systems and reduce emissions. The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2022 were primarily for expenditures related to Supply Corporation's FM100 Project ($21.0 million). In addition, the Pipeline and Storage segment capital expenditures for the ~~three~~

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six months ended ~~December~~March 31, ~~2017 include expenditures related to Supply Corporation's Line D Expansion Project ($12.4 million), as discussed below. The Pipeline and Storage capital expenditures for the~~ ~~three months endedDecember 31, 2016~~ ~~were mainly for expenditures related to Empire and Supply Corporation's Northern Access 2016 Project ($13.5 million) and Supply Corporation's Line D Expansion Project ($4.2 million) and also~~2022 included additions, improvements and replacements to this segment’s transmission and gas storage systems.

In light of 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 recently completed and are actively pursuing several 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. Preliminary survey and investigation costs for expansion, routine replacement or modernization projects are initially recorded as Deferred Charges on the Consolidated Balance Sheet. Management may reserve for preliminary survey and investigation costs associated with large projects by reducing the Deferred Charges balance and increasing Operation and Maintenance Expense on the Consolidated Statement of Income. If it is determined that it is highly probable that a project for which a reserve has been established will be built, the reserve is reversed. This reversal reduces Operation and Maintenance Expense and reestablishes the original balance in Deferred Charges. The amounts remain in Deferred Charges until such time as capital expenditures for the project have been incurred and activities that are necessary to get the construction project ready for its intended use are in progress. At that point, the balance is transferred from Deferred Charges to Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet.

Supply Corporation and Empire are developing a project which would move significant prospective Marcellus production from Seneca's Western Development Area at Clermont to an Empire interconnection with TransCanada Pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York (“Northern Access 2016”). The Northern Access 2016 project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access 2016 project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. The preliminary cost estimate for the Northern Access 2016 project is approximately $500 million. Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. On February 3, 2017, the Company received FERC approval of the project. On April 7, 2017, 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 on January 27, 2017). On April 21, 2017, the Company appealed the NYDEC's decision with regard to the Water Quality Certification to the United States Court of Appeals for the Second Circuit, and on May 11, 2017, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. The Company also has pending with FERC a proceeding asserting, among other things, that the NYDEC exceeded the reasonable and statutory time frames to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. In light of these pending legal actions, the Company has not yet determined a target in-service date. The Company remains committed to the project. As of December 31, 2017, approximately $75.5 million has been spent on the Northern Access 2016 project, including $21.9 million that has been spent to study the project, for which no reserve has been established. The remaining $53.6 million spent on the project has been capitalized as Construction Work in Progress.

On November 21, 2014, Supply Corporation concluded an Open Season for an expansion of its Line D pipeline (“Line D Expansion”) that is intended to allow growing on-system markets to avail themselves of economical gas supply on the TGP 300 line, at an existing interconnect at Lamont, Pennsylvania, and provide increased capacity into the Erie, Pennsylvania market area. Supply Corporation has executed Service Agreements for a total of 77,500 Dth per day for terms of six to ten years and services began November 1, 2017. The project involves construction of a new 4,140 horsepower Keelor Compressor Station and modifications to the Bowen compressor station at an estimated capital cost of approximately $28.2 million. The project also provides system modernization benefits. As of December 31, 2017, approximately $26.8 million has been spent on the Line D Expansion project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at December 31, 2017.

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Empire concluded an Open Season on November 18, 2015, and has designed a project that would allow for the transportation of 205,000 Dth per day of additional shale supplies from interconnections in Tioga County, Pennsylvania, to TransCanada Pipeline, and the TGP 200 Line (“Empire North Project”). Empire has executed a Precedent Agreement with a foundation shipper for 150,000 Dth per day of transportation capacity and with two other shippers for 35,000 Dth per day and 5,000 Dth per day, respectively. Empire continues to negotiate precedent agreements with other prospective shippers. Empire expects to file a Section 7(c) application with the FERC in the second quarter of fiscal 2018. The Empire North project has a projected in-service date of November 1, 2019 and an estimated capital cost of approximately $140 million to $145 million. As of December 31, 2017, approximately $1.1 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, 2017.

Supply Corporation has entered into a foundation shipper Precedent Agreement to provide incremental natural gas transportation services from Line N to the ethylene cracker facility being constructed by Shell Chemical Appalachia, LLC in Potter Township, Pennsylvania. Supply Corporation has completed an Open Season for the project and has secured incremental firm transportation capacity commitments totaling 133,000 Dth per day on Line N and on the proposed pipeline extension of approximately 4.5 miles from Line N to the facility. The proposed in-service date for this project is as early as July 1, 2019 and capital costs are expected to be $17 million. As of December 31, 2017, approximately $0.5 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, 2017.

Gathering

The majority of the Gathering segment capital expenditures for the ~~three~~six months ended ~~December~~March 31, ~~2017 were for~~2023 included expenditures related to the continued ~~buildout~~expansion of Midstream ~~Corporation’s~~Company's Clermont, ~~Gathering System and Midstream Corporation's~~Covington, Trout Run ~~Gathering System,~~and Wellsboro gathering systems, as discussed below. Midstream Company spent $10.2 million, $10.4 million, $3.8 million and $6.4 million, respectively, during the six months ended March 31, 2023 on the development of the Clermont, Covington, Trout Run, and Wellsboro gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines, as well as the continued development of centralized station facilities, including increased compression horsepower, at the Clermont, Trout Run, and Wellsboro gathering systems. In the Tioga gathering system, which is part of Midstream Covington, expenditures were largely attributable to the expansion of on-pad and centralized station facilities related to bringing new development online.

The majority of the Gathering segment capital expenditures for the ~~three~~six months ended ~~December~~March 31, ~~2016 were for~~2022 included expenditures related to the ~~construction~~continued expansion of Midstream Company's Clermont and Covington gathering systems. Midstream Company spent $8.7 million and $10.6 million, respectively, during the six months ended March 31, 2022 on the development of the Clermont ~~Gathering System.~~

~~NFG Midstream Clermont, LLC, a wholly owned subsidiary~~and Covington gathering systems. These expenditures were largely attributable to the installation of Midstream Corporation, is building an extensive gathering system with compression in the Pennsylvania counties of McKean, Elk and Cameron. The total cost estimate for the continued buildout will be dependent on the nature and timing of the shippers', including Seneca's, long-term plans. As of December 31, 2017, approximately $285.4 million has been spent on the Clermont Gathering System, including approximately $4.0 million spent during the three months ended December 31, 2017, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at December 31, 2017.

NFG Midstream Trout Run, LLC, a wholly owned subsidiary of Midstream Corporation, continues to develop its Trout Run Gathering System in Lycoming County, Pennsylvania. The Trout Run Gathering System was initially placed in service in May 2012. The current system consists of approximately 48 miles of backbone andnew in-field gathering pipelines ~~two compressor stations~~in the Clermont gathering system, as well as the development of new gathering facilities, including new in-field gathering pipelines and ~~a dehydration and metering station. As of December 31, 2017, approximately $183.6 million has been spent on~~station upgrades in the Trout Run Gathering System, including approximately $6.3 million spent during the three months ended December 31, 2017, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at December 31, 2017.Tioga gathering system.

NFG Midstream Wellsboro, LLC, a wholly owned subsidiary of Midstream Corporation, continues to develop its Wellsboro Gathering System in Tioga County, Pennsylvania. As of December 31, 2017, the Company has spent approximately $6.9 million in costs related to this project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at December 31, 2017.Utility

~~Utility~~

The majority of the Utility segment capital expenditures for the ~~three~~six months ended~~December~~ March 31, ~~2017~~2023 and ~~December~~March 31, ~~2016~~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.

Other Investing Activities

In October 2021, the Company sold $30 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 to fund a one-time customer bill credit of $25 million in October 2021 for previously overcollected OPEB expenses and the first year installment of a 5-year pass back of an additional $29 million in previously overcollected OPEB expenses in accordance with new rates that went into effect on October 1, 2021. In October 2022, the Company sold an additional $10 million of fixed income mutual fund shares held in the grantor trust. The proceeds from this sale were used to fund the second year installment of the 5-year pass back of overcollected OPEB expenses as well as ~~main extensions.~~ to diversify a portion of grantor trust investments into lower risk money market mutual fund shares. Please refer to the Rate Matters section that follows for additional discussion of this matter.

In March 2022, the Company completed the sale of certain oil and gas assets located in Tioga County, Pennsylvania effective as of October 1, 2021. The Company received net proceeds of $13.5 million from this sale. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.

On June 30, 2022, the Company completed the sale of Seneca’s California assets, all of which are in the Exploration and Production segment, to Sentinel Peak Resources California LLC for a total sale price of $253.5 million, consisting of $240.9 million in cash and contingent consideration valued at $12.6 million at closing. The fair value of the contingent consideration was $5.9 million at March 31, 2023. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. Under the terms of the purchase and sale agreement, the Company can 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 sale price, which reflected an effective date of April 1, 2022, was reduced for production revenues less expenses that were retained by Seneca from the effective date to the closing date. Under the full cost method of accounting for oil and natural gas properties, $220.7 million of the sale price at closing was accounted for as a reduction of capitalized costs since the disposition did not alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center. The remainder of the sale price ($32.8 million) was applied against assets that are not subject to the full cost method of accounting, with the Company

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recognizing a gain of $12.7 million on the sale of such assets. The majority of this gain related to the sale of emission allowances.

On March 22, 2023, the Company entered into a purchase and sale agreement to acquire certain upstream assets located in Potter and Tioga counties, Pennsylvania from SWN Production Company, LLC effective as of January 1, 2023 for total consideration of $127.0 million, subject to certain purchase price adjustments at closing. These assets are contiguous with existing Company owned upstream assets in Pennsylvania. The Company made a deposit of $12.7 million at the signing of the purchase and sale agreement and intends to finance the remaining acquisition cost using short and/or long-term borrowings. The transaction is expected to close before the end of June 2023.

Project Funding

~~The~~ Over the past two years, the Company has been financing ~~the Pipeline and Storage segment and Gathering segment projects mentioned above, as well as the Exploration and Production segment~~ capital expenditures with cash from operations, short-term debt and ~~both short~~proceeds from the sale of the Company's California assets. During the six months ended March 31, 2023 and ~~long-term borrowings.~~March 31, 2022, capital expenditures were funded with cash from operations and short-term debt. Going forward, ~~while~~ the Company expects to use cash on hand, ~~and~~ cash from operations ~~as the first means of financing these projects, the Company may issue~~and short-term ~~and/~~or long-term ~~debt~~borrowings, as ~~necessary during fiscal 2018~~needed, to ~~help meet its~~finance capital ~~expenditures needs.~~expenditures. The level of short-term ~~and~~and/or long-term borrowings will depend upon the ~~amounts~~amount of cash provided by operations, which, in turn, will likely be most impacted by natural gas production, and ~~crude oil prices combined with production from existing wells.~~ the associated commodity price realizations, as well as the level of hedging collateral deposits 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 ~~oil and~~natural gas properties, quicker 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.~~capacities, regulated utility assets and other opportunities as they may arise. The amounts are also subject to modification for opportunities involving carbon 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 ~~other~~ business segments depends, to a large degree, upon market ~~conditions.~~and regulatory conditions as well as legislative actions.

Financing Cash Flow

~~The Company did not have any consolidated~~ Consolidated short-term debt ~~outstanding~~increased $350.0 million, to a total of $410.0 million, when comparing the balance sheet at ~~December~~March 31, ~~2017 or~~2023 to the balance sheet at September 30, ~~2017, nor was there any~~2022. The maximum amount of short-term debt outstanding during the ~~quarter~~six months ended ~~December~~March 31, ~~2017. The~~2023 was $410.0 million. In addition to cash provided by operating activities, the Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, ~~exploration and development expenditures,~~ 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. For example, during the six months ended March 31, 2023, the Company repaid $549.0 million of long-term debt with maturity dates in March 2023. The Company utilized short-term borrowings and cash on hand to redeem the maturities, resulting in an increase in the short-term debt balance. As of March 31, 2023, the Company had outstanding commercial paper of $160.0 million and short-term notes payable to banks of $250.0 million.

On ~~September 9, 2016,~~February 28, 2022, the Company entered into a ~~Third~~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 ~~(Credit Agreement) with~~and a ~~syndicate of what now numbers 13 banks. This~~previous 364-Day Credit Agreement. The Credit Agreement provides a ~~$750.0 million multi-year~~$1.0 billion unsecured committed revolving credit facility ~~through December 5, 2019.~~with a maturity date of February 26, 2027.

On June 30, 2022, the Company entered into the 364-Day Credit Agreement with a syndicate of five banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional $250.0 million unsecured committed delayed draw term loan credit facility with a maturity date of June 29, 2023. The Company elected to draw $250.0 million under the facility on October 27, 2022. The Company used the proceeds for general corporate purposes, which included using $150.0 million for the November 2022 redemption of a portion of the Company's outstanding long-term debt with a maturity date in March 2023.

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The Company also has ~~a number of individual~~ uncommitted ~~or discretionary~~ lines of credit with ~~certain~~ financial institutions for general corporate purposes. Borrowings under ~~the~~these uncommitted lines of credit ~~are~~would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial ~~institutions~~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 .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 March 31, 2023, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement and 364-Day 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 ~~from October 1, 2017 through December 5, 2019.~~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. The 364-Day Credit Agreement includes the same debt to capitalization covenant and the same exclusions of unrealized gains or losses on derivative financial instruments as the Credit Agreement. At ~~December~~March 31, ~~2017,~~2023, the Company’s debt to capitalization ratio, ~~(as~~as calculated under the ~~facility)~~Credit Agreement and 364-Day Credit Agreement, was ~~.53.~~.45. The constraints specified in the Credit Agreement and 364-Day Credit Agreement would have permitted an additional ~~$1.36~~$3.20 billion in short-term and/or long-term debt to be outstanding ~~(further limited by the indenture covenants discussed below)~~at March 31, 2023 before the Company’s debt to capitalization ratio exceeded .65.

A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity ~~sources, including cash provided by operations.~~sources.

The Credit Agreement ~~contains~~and 364-Day Credit Agreement contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement and 364-Day 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. ~~As of December 31, 2017, the Company did not have any debt outstanding under the Credit Agreement.~~

None of the ~~Company’s~~Company's long-term debt ~~at December~~as of March 31, ~~2017~~2023 had a maturity date within the following twelve-month period. The Current Portion of Long-Term Debt at September 30, ~~2017~~2022 consisted of ~~$300.0~~$500.0 million ~~aggregate principal amount~~ of ~~6.50%~~3.75% notes ~~scheduled to mature~~($150.0 million of which was subsequently paid in ~~April 2018.~~November 2022) and $49.0 million of 7.395% notes, that each had maturity dates in March 2023. The Company ~~redeemed~~utilized short-term borrowings and cash on hand to repay $150.0 million of these ~~notes on October 18, 2017 for $307.0~~maturities in November 2022 and the remaining $399.0 million ~~plus accrued interest.~~in March 2023.

The Company’s embedded cost of long-term debt was ~~5.17%~~4.58% at March 31, 2023 and ~~5.53%~~4.48% at ~~December~~March 31, ~~2017 and December 31, 2016, respectively.~~2022.

Under the Company’s existing indenture covenants at ~~December~~March 31, ~~2017,~~2023, the Company would have been permitted to issue up to a maximum of ~~$654.0 million~~approximately $3.73 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace ~~maturing debt.~~existing debt (further limited by debt to capitalization ratio constraints under the Company's Credit Agreement, as discussed above). The Company's present liquidity position is believed to be adequate to satisfy known demands. ~~However, if~~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 ~~were to experience a significant loss in~~from issuing incremental unsubordinated long-term debt, or significantly limit the ~~future (for example,~~amount of such debt that could be issued. Losses incurred as a result of ~~an impairment~~significant impairments of oil and gas ~~properties), it is possible, depending on factors including~~properties have in the ~~magnitude of the loss, that these~~past resulted in such temporary restrictions. The indenture covenants ~~would restrict the Company's ability to issue additional long-term unsecured indebtedness for a period of up~~

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~~to nine calendar months, beginning with the fourth calendar month following the loss. This~~ would not preclude the Company from issuing new ~~indebtedness~~long-term debt to replace ~~maturing~~existing long-term debt,

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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 ~~$98.7~~$50.0 million (or ~~4.7%~~2.4%) of the Company’s long-term debt (as of ~~December~~March 31, ~~2017)~~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.

~~OFF-BALANCE SHEET ARRANGEMENTS~~

The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Exploration and Production segment and Corporate operations, having a remaining lease commitment of approximately $27.4 million. These leases have been entered into for the use of compressors, drilling rigs, buildings and other items and are accounted for as operating leases.

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.

~~During~~ 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 ~~three months ended~~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, ~~2017,~~2024, to construct the project. The Company ~~contributed $27.6~~will update the $500 million preliminary cost estimate and expected in-service date for the project when there is further clarity on the timing of receipt of necessary regulatory approvals. As of March 31, 2023, approximately $55.9 million has been spent on the Northern Access project, including $24.3 million that has been spent to study the project. The remaining $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2023.

The Company did not make any contributions to its tax-qualified, noncontributory ~~defined-benefit~~defined benefit retirement plan (Retirement Plan) ~~and $0.7 million to~~or its VEBA trusts for its other post-retirement ~~benefits. In~~benefits during the six months ended March 31, 2023, and does not anticipate making any such contributions during the remainder of 2018, the Company may contribute up to $5.0 million to the Retirement Plan. In the remainder of 2018, the Company expects its contributions to the VEBA trusts to be in the range of $2.0 million to $3.0 million.fiscal 2023.

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 ~~issued certain~~adopted several final regulations, other rules that may impact the Company have yet to be finalized.

The CFTC’s Dodd-Frank regulations continue to preserve the ability of non-financial end users to hedge their risks using swaps without being subject to mandatory clearing. In 2015, legislation was enacted to exempt from margin requirements swaps used by non-financial end-users to hedge or mitigate commercial risk. In 2016, the CFTC issued a reproposal to its position limit rules that would impose speculative position limits on positions in 28 core physical commodity contracts as well as economically equivalent futures, options and swaps. While the Company does not intend to enter into positions on a speculative basis, such rules could nevertheless impact the ability of the Company to enter into certain derivative hedging transactions with respect to such commodities. If we reduce our use of hedging transactions as a result of final regulations to be issued by the CFTC, our results of operations may become more volatile and our cash flows may be less predictable. There may be other rules developed Rules adopted by the CFTC and other regulators ~~that~~ could adversely impact the Company. While many of those rules place specific conditions on the operations of swap dealers ~~and major swap participants,~~rather than directly on the Company, concern remains that swap dealers ~~and major swap participants~~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.

~~Finally,~~ 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 ~~additional~~enforcement authority granted to the CFTC on anti-market manipulation, anti-fraud and ~~disruptive~~anti-disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact our business. Should wethe Company violate any laws or regulations applicable to our hedging activities, weit could be subject to CFTC enforcement action and material penalties and sanctions. The Company ~~continues to monitor these enforcement and other regulatory developments, but~~ cannot predict the impact that evolving application of the Dodd-Frank Act may have on its operations.

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The ~~accounting rules~~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~~March 31, ~~2017,~~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~~“Market Risk Sensitive ~~Instruments"~~Instruments” in Item 7 of the ~~Company's 2017~~Company’s 2022 Form 10-K. ~~There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.~~

Rate ~~and Regulatory~~ 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.” ~~Although~~As noted below, the Pennsylvania division ~~does not have~~currently has a rate case on ~~file, see below for a description of the current rate proceedings affecting the New York division.~~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 YorkJurisdiction

On The order also authorized the Company to recover approximately $15 million annually for pension and OPEB expenses from customers. Because the Company's future pension and OPEB costs were projected to be satisfied with existing funds held in reserve, in July ~~28, 2017,~~2022, Distribution Corporation ~~filed an appeal~~made a filing with ~~New York State Supreme Court, Albany County, seeking review of~~ the ~~Order. The appeal contends that portions of the Order should be invalidated because they fail~~NYPSC to ~~meet the applicable legal standard for agency decisions.~~effectuate a pension and OPEB surcredit to customers to offset these amounts being collected in base rates effective October 1, 2022. On ~~December 11, 2017, the appeal was transferred to the Supreme Court, Appellate Division, Third Department. The Company cannot predict the outcome of the appeal at this time.~~

~~On December 22, 2017, the federal Tax Cuts and Jobs Act (the 2017 Tax Reform Act) was enacted into law. On December 29, 2017,~~September 16, 2022, the NYPSC issued an order ~~instituting~~approving the filing. The surcredit will remain in effect until modified by the NYPSC in another proceeding, or until December 31, 2024, whichever is earlier. With the implementation of this surcredit, Distribution Corporation will no longer be funding the Retirement Plan or its VEBA trusts in its New York jurisdiction.

On January 19, 2023, the NYPSC issued an order in its Effects of COVID-19 on Utility Service (20-M-0266) and ~~liabilities of~~Energy Affordability for Low Income Utility Customers (14-M-0565) proceedings whereby a Phase 2 Utility Arrears Relief Program was authorized. Specifically, the order directed Distribution Corporation and certain other New York utilities to, among other things, address arrears on residential non-energy affordability program (EAP) ratepayer accounts that did not receive a credit under the NYPSC’s Phase 1 program and small commercial ratepayer accounts by issuing a one-time bill credit to such customers to reduce or eliminate accrued arrears through May 1, 2022. The credits shall be processed within 90 days of the ~~“regulatory treatment~~effective date of ~~any windfalls resulting from same~~the order, provided that residential non-EAP customers who had their service disconnected for non-payment in 2022 shall be allowed the opportunity to have their service reinstated in order to ~~preserve~~receive the benefits for ratepayers.” In its order, the NYPSC stated that the effect of the 2017 Tax Reform Act on utilities’ taxation is likely to be material and complex and that the proceeding was needed to begin the process of addressing the impact on the State’s utilities and ratepayers. The order establishes that the first steps in such process will be soliciting information from its regulated utilities to quantify the impact of the 2017 Tax Reform Act, scheduling a technical conference with the utilities, and the issuance of a NY Department of Public Service Staff (Staff) proposal for accounting and ratemaking treatment of the tax changes.credit through June 30, 2023. The order further ~~states that once Staff’s proposal~~directs utilities to suspend residential service terminations for non-payment while arrears credits are applied to accounts through March 1, 2023, or 30 days after credits have been applied, whichever is ~~issued,~~later. The order authorizes the utilities to recover the Phase 2 costs (the arrears credits and ~~other interested parties~~associated carrying charges) through a surcharge. Utilities proposed various offsets to Phase 2 program costs, and Distribution Corporation has proposed certain offsets as part of an uncollectible expense reconciliation proposal. On February 17, 2023, Distribution Corporation made a filing with the NYPSC seeking approval of its uncollectible expense reconciliation mechanism and a determination is pending. Application of the proposed offsets and collection periods will be ~~invited to comment~~determined when the NYPSC rules on ~~Staff’s recommendation. The order also declares that utilities are “put on notice that it is~~ the [NYPSC]’s intent to ensure that net benefits accruing from the Tax Act are preserved for ratepayers, either through deferral accounting or another method, from the first day the Tax Act is put into effect. Utilities acting contrary to this intent do so at their own risk.” The Company cannot predict the outcome of this proceeding at this time. Refer to Item 1 at Note 4 - Income Taxes for a further discussion of the 2017 Tax Reform Act.

uncollectible expense reconciliation filing.

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Pennsylvania Jurisdiction

Distribution Corporation’s current delivery ~~charges~~rates in its Pennsylvania jurisdiction were approved by the PaPUC on November 30, 2006 as part of a settlement agreement that became effective January 1, 2007. 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 with a proposed effective date of December 27, 2022. On December 8, 2022, the PaPUC issued an order suspending the filing until July 27, 2023 by operation of law unless directed otherwise by the PaPUC. Following discovery, the submission of testimony and an evidentiary hearing, the parties to the proceeding agreed to a settlement that authorizes, among other things, an increase in Distribution Corporation’s annual base rate operating revenues of $23 million as of August 1, 2023. On April 13, 2023, Distribution Corporation filed a joint petition with the PaPUC seeking approval of the settlement on behalf of all active parties to the proceeding. The joint petition is currently pending before the PaPUC.

Effective October 1, 2021, pursuant to a tariff supplement filed with the PaPUC, Distribution Corporation reduced base rates by $7.7 million in order to stop collecting OPEB expenses from customers. It also began to refund to customers overcollected OPEB expenses in the amount of $50.0 million. All matters with respect to this tariff supplement were finalized on February 24, 2022 with the PaPUC's approval of an Administrative Law Judge's Recommended Decision. Concurrent with that decision, the Company discontinued regulatory accounting for OPEB expenses and recorded an $18.5 million adjustment during the quarter ended March 31, 2022 to reduce its regulatory liability for previously deferred OPEB income amounts through September 30, 2021 and to increase Other Income (Deductions) on the consolidated financial statements by a like amount. The Company also increased customer refunds of overcollected OPEB expenses from $50.0 million to $54.0 million. All refunds specified in the tariff supplement are being funded entirely by grantor trust assets held by the Company, most of which are included in a fixed income mutual fund that is a component of Other Investments on the Company's Consolidated Balance Sheet. With the elimination of OPEB expenses in base rates, Distribution Corporation is no longer funding the grantor trust or its VEBA trusts in its Pennsylvania jurisdiction.

Pipeline and Storage

Supply Corporation’s 2020 rate settlement provides that no party may make a rate filing for new rates to be effective before February 1, 2024, except that Supply Corporation ~~currently has no active~~may file an NGA general Section 4 rate case ~~on file.~~to change rates if the corporate federal income tax rate is increased. If no case has been filed, Supply ~~Corporation's current~~Corporation must file for rates to be effective February 1, 2025.

Empire’s 2019 rate settlement ~~requires~~provides that Empire must make a rate case filing no later than ~~December 31, 2019.~~May 1, 2025.

~~Empire currently has no active rate case on file. Empire’s current rate settlement requires a rate case filing no later than July 1, 2021.~~

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 change as environmental exposures and opportunities change and regulatory updates are issued.

For further discussion of the Company's environmental exposures, refer to Item 1 at Note 68 — 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~~implementation in the United ~~States, these~~States. These efforts include legislation, legislative proposals and ~~EPA~~new regulations at the state and federal ~~level, actions at the state~~ level, and private party litigation related to greenhouse gas emissions. ~~While~~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 ~~U.S. Congress has from time~~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 ~~time considered legislation aimed at reducing~~be applicable to the reported annual methane emissions of ~~greenhouse gases, Congress has not yet passed any federal climate change legislation~~certain oil and ~~we cannot predict when or if Congress will pass such legislation and~~gas facilities, above specified methane intensity thresholds, starting in ~~what form. In~~calendar year 2024. This portion of the ~~absence of such legislation,~~IRA is to be administered by the EPA ~~is regulating~~and potential fees will begin with emissions reported for calendar year 2024. The EPA regulates greenhouse gas

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emissions pursuant to the ~~authority granted to it by the federal~~ Clean Air Act. ~~For example, in April 2012,~~The regulations implemented by the EPA adopted rules which restrict emissions associated with oil and natural gas drilling. The EPA previously adopted final regulations that set methane and volatile organic compound emissions standards for new or modified oil and gas emissions sources. These rules impose more stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. The current administration has issued executive orders to review and potentially roll back many of these regulations, and, in turn, litigation (not involving the Company) has been instituted to challenge the administration's efforts. The Company must continue to comply with all applicable regulations. ~~In addition, the U.S. Congress has from time to time considered bills that would establish~~Additionally, a ~~cap-and-trade program to reduce emissions of greenhouse gases. A~~ number of states have adopted energy strategies or plans with aggressive goals ~~that include~~for the reduction of greenhouse gas emissions. For example, New York’s State Energy Plan includes Reforming the Energy Vision (REV) initiatives which set greenhouse gas emission reduction targets of 40% by 2030 and 80% by 2050. Additionally, the Plan targets that 50% of electric generation must come from renewable energy sources by 2030. Similarly, Pennsylvania has a methane reduction framework ~~for the oil and gas industry which will result in permitting changes~~ with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. ~~With respect~~Pennsylvania's Governor also entered the Commonwealth into a cap-and-trade program known as the Regional Greenhouse Gas Initiative, however, the Commonwealth's participation is currently stayed due to its operations in California, the Company currently complies with California cap-and-trade guidelines, which increases the Company's cost of environmental compliance in its Exploration and Production segment operations. Legislation or regulation that aims to reduce greenhouse gas emissions could also include carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources.ongoing litigation. Federal, state or local governments may ~~for example,~~ 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. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on the promulgation of final regulations and on regulatory treatment afforded in the process. Thus far, the only regulations promulgated in connection with the CLCPA are statewide greenhouse gas emissions limits established by the NYDEC in 6 NYCRR Part 496, effective December 30, 2020. The NYDEC has until January 1, 2024 to issue further rules and regulations implementing the statute and had indicated that it will initiate regulatory proceedings to investigate development of a cap-and-invest program in New York. 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 ~~Company to retrofit existing equipment, install new equipment to reduce emissions from larger facilities and/or~~ purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory ~~approvals with regard to existing~~approvals. Changing market conditions and new ~~facilities, impose additional monitoring~~regulatory requirements, as well as unanticipated or inconsistent application of existing laws and ~~reporting~~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 ~~reduce demand~~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 ~~oil and natural gas. But legislation~~services performed or ~~regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company~~products produced are determined by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisionsmarket factors that are ~~ultimately adopted.~~not necessarily correlated to the underlying costs required to provide the service or product.

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~~New Authoritative Accounting and Financial Reporting Guidance~~

For discussion of the recently issued authoritative accounting and financial reporting guidance, refer to Item 1 at Note 1 — Summary of Significant Accounting Policies under the heading “New Authoritative Accounting and Financial Reporting Guidance.”

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 ~~rules,~~and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:


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


2.	Governmental/regulatory actions, initiatives and proceedings, including those involving rate cases (which address, among other things, target rates of return, rate design and retained natural gas), environmental/safety requirements, affiliate relationships, industry structure, and franchise renewal;


3.	Changes in laws, regulations or judicial interpretations to which the Company is subject, including those involving derivatives, taxes, safety, employment, climate change, other environmental matters, real property, and exploration and production activities such as hydraulic fracturing;


4.	~~Impairments under the SEC’s full cost ceiling test for natural gas and oil reserves;~~


5.	~~Changes in the price of natural gas or oil;~~


6.	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;

Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas and oil reserves, including among others geology, lease availability, title disputes, weather conditions, 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;


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


9.	Changes in price differentials between similar quantities of natural gas or oil 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;


~~10.~~	~~Other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date;~~

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;

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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;


~~11.~~	~~The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;~~


~~12.~~	~~Uncertainty of oil and gas reserve estimates;~~


~~13.~~	~~Significant differences between the Company’s projected and actual production levels for natural gas or oil;~~


~~14.~~	~~Changes in demographic patterns and weather conditions;~~


~~15.~~	~~Changes in the availability, price or accounting treatment of derivative financial instruments;~~


~~16.~~	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;


~~17.~~	~~Changes in economic conditions, including global, national or regional recessions, and their effect on the demand for, and customers’ ability to pay for, the Company’s products and services;~~


~~18.~~	~~The creditworthiness or performance of the Company’s key suppliers, customers and counterparties;~~


~~19.~~	~~Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities, acts of war, cyber attacks or pest infestation;~~


~~20.~~	~~Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or~~


~~21.~~	~~Increasing costs of insurance, changes in coverage and the ability to obtain insurance.~~

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

8.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;

9.Impairments under the SEC’s full cost ceiling test for natural gas reserves;

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

12.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;

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

14.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, 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;

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

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

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

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

19.Uncertainty of natural gas reserve estimates;

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

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

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

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

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

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

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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~~March 31, ~~2017.~~ 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~~March 31, ~~2017~~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

On September 13, 2017, the PaDEP sent a draft Consent Assessment of Civil Penalty (CACP) to Seneca, in relation to an alleged violation of the Pennsylvania Oil and Gas Act, as well as PaDEP rules and regulations regarding gas migration relating to Seneca’s drilling activities. The amount of the penalty sought by the PaDEP is not material to the Company. The draft CACP

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~~alleges a violation identified by the PaDEP in 2011. Seneca disputes the alleged violation and will vigorously defend its position in negotiations with the PaDEP.~~

For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note ~~6 —~~8 – Commitments and Contingencies, and Part I, Item 2 - MD&A of this report under the heading “Other Matters – Environmental Matters.”

For a discussion of certain rate matters involving the NYPSC, refer to Part I, Item 1 of this report at Note ~~9 —~~11 – Regulatory Matters.

Item 1A. Risk Factors

The risk factors in Item 1A of the Company’s ~~2017~~2022 Form 10-K,as updated by Item 1A of Part II of the Company's Quarterly Report on Form 10-Q for the quarter ended December 31, 2022, have not materially changed other than as set forth below. The risk factor presented below supersedes the risk factor having the same caption in the 2017 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2017 Form 10-K.changed.

The Company’s need to comply with comprehensive, complex, and the sometimes unpredictable enforcement of government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.

While the Company generally refers to its Utility segment and its Pipeline and Storage segment as its "regulated segments," there are many governmental laws and regulations that have an impact on almost every aspect of the Company's businesses including, but not limited to, tax law, such as the 2017 Tax Reform Act and related regulatory action, and environmental law. Existing statutes and regulations may be revised or reinterpreted and new laws and regulations may be adopted or become applicable to the Company, such as tax legislation, which may increase the Company's costs, require refunds to customers or affect its business in ways that the Company cannot predict. Administrative agencies may apply existing laws and regulations in unanticipated, inconsistent or legally unsupportable ways, making it difficult to develop and complete projects, and harming the economic climate generally. New York State, for example, under the current executive administration, appears intent on imposing unattainable regulatory standards, at least with respect to certain fossil fuel energy infrastructure projects.

In the Company's Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC, the PaPUC and, with respect to certain transactions, the FERC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers, or to the extent Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover increased costs (including costs that may be incurred in connection with governmental investigations or proceedings or mandated infrastructure inspection, maintenance or replacement programs), earnings may decrease.

In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have established competitive markets in which customers may purchase gas commodity from unregulated marketers, in addition to utility companies. Retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation because in both jurisdictions it recovers its cost of service through delivery rates and charges, and not through any mark-up on the gas commodity purchased by its customers. Over the longer run, however, rate design changes resulting from customer migration to marketer service ("unbundling") can expose utilities such as Distribution Corporation to stranded costs and revenue erosion in the absence of compensating rate relief.

Both the NYPSC and the PaPUC have, from time-to-time, instituted proceedings for the purpose of promoting conservation of energy commodities, including natural gas. In New York, Distribution Corporation implemented a Conservation Incentive Program that promotes conservation and efficient use of natural gas by offering customer rebates for the installation of high-efficiency appliances, among other things. The intent of conservation and efficiency programs is to reduce customer usage of natural gas. Under traditional volumetric rates, reduced usage by customers results in decreased revenues to the Utility. To prevent revenue erosion caused by conservation, the NYPSC approved a "revenue decoupling mechanism" that renders Distribution Corporation's New York division financially indifferent to the effects of conservation. In Pennsylvania, the PaPUC has not directed Distribution Corporation to implement a conservation program. If the NYPSC were to revoke the revenue decoupling mechanism in a future proceeding or the PaPUC were to adopt a conservation program without revenue decoupling mechanism or other changes in rate design, reduced customer usage could decrease revenues, forcing Distribution Corporation to file for rate relief. If Distribution Corporation were unable to obtain adequate rate relief, its financial condition, results of operations and cash flows would be adversely affected.

In New York, aggressive generic statewide programs created under the label of efficiency or conservation continue to generate a sizable utility funding requirement for state agencies that administer those programs. Although utilities are authorized to recover the cost of efficiency and conservation program funding through special rates and surcharges, the resulting upward

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pressure on customer rates, coupled with increased assessments and taxes, could affect future tolerance for traditional utility rate increases, especially if natural gas commodity costs were to increase.

The Company is subject to the jurisdiction of the FERC with respect to Supply Corporation, Empire and some transactions performed by other Company subsidiaries, including Seneca, Distribution Corporation and NFR. The FERC, among other things, approves the rates that Supply Corporation and Empire may charge to their natural gas transportation and/or storage customers. Those approved rates also impact the returns that Supply Corporation and Empire may earn on the assets that are dedicated to those operations. Pursuant to the petition of a customer or state commission, or on the FERC's own initiative, the FERC has the authority to investigate whether Supply Corporation's and Empire's rates are still "just and reasonable" as required by the NGA, and if not, to adjust those rates prospectively. If Supply Corporation or Empire is required in a rate proceeding to adjust the rates it charges its natural gas transportation and/or storage customers, or if either Supply Corporation or Empire is unable to obtain approval for rate increases, particularly when necessary to cover increased costs, Supply Corporation's or Empire's earnings may decrease. The FERC also possesses significant penalty authority with respect to violations of the laws and regulations it administers. Supply Corporation, Empire and, to the extent subject to FERC jurisdiction, the Company's other subsidiaries are subject to the FERC's penalty authority. In addition, the FERC exercises jurisdiction over the construction and operation of facilities used in interstate gas transmission. Also, decisions of Canadian regulators such as the National Energy Board and the Ontario Energy Board could affect the viability and profitability of Supply Corporation and Empire projects designed to transport gas between Canada and the U.S.

The Company is also subject to the jurisdiction of the Pipeline and Hazardous Materials Safety Administration (PHMSA). PHMSA issues regulations and conducts evaluations, among other things, that set safety standards for pipelines and underground storage facilities. Compliance with new legislation could increase costs to the Company. Non-compliance with this legislation could result in civil penalties for pipeline safety violations. If as a result of these or similar new laws or regulations the Company incurs material costs that it is unable to recover fully through rates or otherwise offset, the Company's financial condition, results of operations, and cash flows could be adversely affected.

In the Company's Exploration and Production segment, various aspects of Seneca's operations are subject to regulation by, among others, the EPA, the U.S. Fish and Wildlife Service, the U.S. Forestry Service, the Bureau of Land Management, the PaDEP, the Pennsylvania Department of Conservation and Natural Resources, the Division of Oil, Gas and Geothermal Resources of the California Department of Conservation, the California Department of Fish and Wildlife, and in some areas, locally adopted ordinances. Administrative proceedings or increased regulation by these or other agencies could lead to operational delays or restrictions and increased expense for Seneca.

~~The Company has significant transactions involving price hedging of its oil and natural gas production as well as its fixed price purchase and sale commitments.~~

In order to protect itself to some extent against unusual price volatility and to lock in fixed pricing on oil and natural gas production for certain periods of time, the Company’s Exploration and Production segment regularly enters into commodity price derivatives contracts (hedging arrangements) with respect to a portion of its expected production. These contracts may at any time cover as much as approximately 80% of the Company’s expected energy production during the upcoming 12-month period. These contracts reduce exposure to subsequent price drops but can also limit the Company’s ability to benefit from increases in commodity prices. In addition, the Energy Marketing segment enters into certain hedging arrangements, primarily with respect to its fixed price purchase and sales commitments and its gas stored underground.

Under applicable accounting rules currently in effect, the Company’s hedging arrangements are subject to quarterly effectiveness tests. Inherent within those effectiveness tests are assumptions concerning the long-term price differential between different types of crude oil, assumptions concerning the difference between published natural gas price indexes established by pipelines into which hedged natural gas production is delivered and the reference price established in the hedging arrangements, assumptions regarding the levels of production that will be achieved and, with regard to fixed price commitments, assumptions regarding the creditworthiness of certain customers and their forecasted consumption of natural gas. Depending on market conditions for natural gas and crude oil and the levels of production actually achieved, it is possible that certain of those assumptions may change in the future, and, depending on the magnitude of any such changes, it is possible that a portion of the Company’s hedges may no longer be considered highly effective. In that case, gains or losses from the ineffective derivative financial instruments would be marked-to-market on the income statement without regard to an underlying physical transaction. For example, in the Exploration and Production segment, where the Company uses short positions (i.e. positions that pay off in the event of commodity price decline) to hedge forecasted sales, gains would occur to the extent that natural gas and crude oil hedge prices exceed market prices for the Company’s natural gas and crude oil production, and losses would occur to the extent that market prices for the Company’s natural gas and crude oil production exceed hedge prices.

Use of energy commodity price hedges also exposes the Company to the risk of non-performance by a contract counterparty. These parties might not be able to perform their obligations under the hedge arrangements. In addition, the Company enters into certain commodity price hedges that are cleared through the NYMEX or ICE by futures commission merchants. Under

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NYMEX and ICE rules, the Company is required to post collateral in connection with such hedges, with such collateral being held by its futures commission merchants. The Company is exposed to the risk of loss of such collateral from occurrences such as financial failure of its futures commission merchants, or misappropriation or mishandling of clients’ funds or other similar actions by its futures commission merchants. In addition, the Company is exposed to potential hedging ineffectiveness in the event of a failure by one of its futures commission merchants or contract counterparties.

It is the Company’s practice that the use of commodity derivatives contracts comply with various policies in effect in respective business segments. For example, in the Exploration and Production segment, commodity derivatives contracts must be confined to the price hedging of existing and forecast production, and in the Energy Marketing segment, commodity derivatives with respect to fixed price purchase and sales commitments must be matched against commitments reasonably certain to be fulfilled. The Company maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose the Company to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Company’s actual production of oil and natural gas falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.

The Dodd-Frank Act increased federal oversight and regulation of the over-the-counter derivatives markets and certain entities that participate in those markets. The act requires the CFTC, the SEC and various banking regulators to promulgate rules and regulations implementing the act. Although regulators have issued certain regulations, other rules that may be relevant to the Company have yet to be finalized.

The CFTC’s Dodd-Frank regulations continue to preserve the ability of non-financial end users to hedge their risks using swaps without being subject to mandatory clearing. In 2015, legislation was enacted to exempt from margin requirements swaps used by non-financial end users to hedge or mitigate commercial risk. In 2016, the CFTC issued a reproposal to its position limit rules that would impose speculative position limits on positions in 28 core physical commodity contracts as well as economically equivalent futures, options and swaps. While the Company does not intend to enter into positions on a speculative basis, such rules could nevertheless impact the ability of the Company to enter into certain derivative hedging transactions with respect to such commodities. If the Company reduces its use of hedging transactions as a result of final CFTC regulations, the Company’s results of operations may become more volatile and its cash flows may be less predictable. There may be other rules developed by the CFTC and other regulators that could impact the Company. While many of those rules place specific conditions on the operations of swap dealers and major swap participants, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs.

Finally, given the additional authority granted to the CFTC on anti-market manipulation, anti-fraud and disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact the Company’s business. Should the Company violate any laws or regulations applicable to the Company’s hedging activities, the Company could be subject to CFTC enforcement action and material penalties and sanctions.

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

On ~~October 2, 2017,~~January 3, 2023, the Company issued a total of ~~6,912~~7,100 unregistered shares of Company common stock to ~~nine~~ non-employee directors of the Company then serving on the Board of Directors of the Company ~~768~~(or, in the case of non-employee directors who elected to defer receipt of such shares pursuant to ~~each such~~the Company's Deferred Compensation Plan for Directors and Officers (the “DCP”), to the DCP trustee), consisting of 710 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~~March 31, ~~2017~~.2023. The Company issued an additional 350 unregistered shares in the aggregate

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on January 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.

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Issuer Purchases of Equity Securities


Period	Total Number of Shares Purchased (a)	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under Share Repurchase Plans or Programs (b)
Jan. 1 - 31, 2023	11,873	$60.87	—	6,971,019
Feb. 1 - 28, 2023	11,599	$57.53	—	6,971,019
Mar 1 - 31, 2023	11,888	$55.68	—	6,971,019
Total	35,360	$58.03	—	6,971,019

(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 March 31, 2023, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. All of the 35,360 shares purchased other than through a publicly announced share repurchase program were purchased for the Company's 401(k) plans.

(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.

Period
Total Number of Shares Purchased ^(a)
Average Price Paid per Share Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs
Maximum Number of Shares That May Yet Be Purchased Under Share Repurchase Plans or Programs ^(b)
Oct. 1 - 31, 2017 —
N/A — 6,971,019
Nov. 1 - 30, 2017 7,336
$57.83 — 6,971,019
Dec. 1 - 31, 2017 43,882
$57.06 — 6,971,019
Total 51,218
$57.17 — 6,971,019

^(a)

Represents shares of common stock of the Company tendered to the Company by holders of stock options, SARs, restricted stock units or shares of restricted stock for the payment of option exercise prices or applicable withholding taxes. During the quarter ended ~~December 31, 2017, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program.~~


^(b)	In September 2008, the Company’s Board of Directors authorized the repurchase of eight million shares of the Company’s common stock. The repurchase program has no expiration date. The Company has not repurchased any shares since September 17, 2008 and has no plans to make further purchases in the near future.

Item 6. Exhibits


Exhibit Number		Description of Exhibit
10.1		Retirement and Consulting Services Agreement, dated as of March 9, 2023, between National Fuel Gas Distribution Corporation and Karen M. Camiolo.

~~Exhibit~~ ~~Number~~ 31.1		~~Description of Exhibit~~
~~10.1~~	~~Form of Award Notice for Return on Capital Performance Shares under the National Fuel Gas Company 2010 Equity Compensation Plan.~~

~~10.2~~	~~Form of Award Notice for Total Shareholder Return Performance Shares under the National Fuel Gas Company 2010 Equity Compensation Plan.~~

~~10.3~~	~~Form of Award Notice for Restricted Stock Units under the National Fuel Gas Company 2010 Equity Compensation Plan.~~

12	~~Statements regarding Computation of Ratios:~~ ~~Ratio of Earnings to Fixed Charges for the Three Months Ended December 31, 2017 and the Fiscal Years Ended September 30, 2014 through 2017.~~

~~31.1~~	Written statements of Chief Executive Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act.

31.2		Written statements of Principal Financial Officer pursuant to Rule 13a-14(a)/15d-14(a) of the Exchange Act.

32••		Certification furnished pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

99		National Fuel Gas Company Consolidated Statements of Income for the Twelve Months Ended ~~December~~March 31, ~~2017~~2023 and ~~2016.~~2022.

101		Interactive data files submitted pursuant to Regulation ~~S-T:~~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~~six months ended ~~December~~March 31, ~~2017~~2023 and ~~2016,~~2022, (ii) the Consolidated Statements of Comprehensive Income for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2023 and ~~2016,~~2022, (iii) the Consolidated Balance Sheets at ~~December~~March 31, ~~2017~~2023 and September 30, ~~2017,~~2022, (iv) the Consolidated Statements of Cash Flows for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2023 and ~~2016~~2022 and (v) the Notes to Condensed Consolidated Financial Statements.

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



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

•• 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/ ~~D. P. Bauer~~T. J. Silverstein
~~D. P. Bauer~~T. J. Silverstein
Treasurer and Principal Financial Officer





/s/ ~~K. M. Camiolo~~E. G. Mendel
~~K. M. Camiolo~~E. G. Mendel
Controller and Principal Accounting Officer

Date: ~~February 2, 2018~~May 4, 2023



	Gains and Losses on Derivative Financial Instruments			Gains and Losses on Securities Available for Sale			Funded Status of the Pension and Other Post-Retirement Benefit Plans			Total
Three Months Ended December 31, 2017
Balance at October 1, 2017	$	20,801		$	7,562		$	(58,486	)	$	(30,123	)
Other Comprehensive Gains and Losses Before Reclassifications	(3,194		)	21			—			(3,173		)
Amounts Reclassified From Other Comprehensive Loss	(7,351		)	(272		)	—			(7,623		)
Balance at December 31, 2017	$	10,256		$	7,311		$	(58,486	)	$	(40,919	)
Three Months Ended December 31, 2016
Balance at October 1, 2016	$	64,782		$	6,054		$	(76,476	)	$	(5,640	)
Other Comprehensive Gains and Losses Before Reclassifications	(30,449		)	(539		)	—			(30,988		)
Amounts Reclassified From Other Comprehensive Loss	(17,763		)	(468		)	—			(18,231		)
Balance at December 31, 2016	$	16,570		$	5,047		$	(76,476	)	$	(54,859	)



Recurring Fair Value Measures	At fair value as of December 31, 2017
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾
Assets:
Cash Equivalents – Money Market Mutual Funds	$	132,231	$	—	$	—	$	—		$	132,231
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	1,374		—		—		(1,374		)	—
Over the Counter Swaps – Gas and Oil	—		30,853		—		(10,312		)	20,541
Foreign Currency Contracts	—		1,232		—		(666		)	566
Other Investments:
Balanced Equity Mutual Fund	36,979		—		—		—			36,979
Fixed Income Mutual Fund	44,232		—		—		—			44,232
Common Stock – Financial Services Industry	3,239		—		—		—			3,239
Hedging Collateral Deposits	4,465		—		—		—			4,465
Total	$	222,520	$	32,085	$	—	$	(12,352	)	$	242,253

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	2,190	$	—	$	—	$	(1,374	)	$	816
Over the Counter Swaps – Gas and Oil	—		16,312		—		(10,312		)	6,000
Foreign Currency Contracts	—		429		—		(666		)	(237		)
Total	$	2,190	$	16,741	$	—	$	(12,352	)	$	6,579
Total Net Assets/(Liabilities)	$	220,330	$	15,344	$	—	$	—		$	235,674



Recurring Fair Value Measures	At fair value as of September 30, 2017
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾
Assets:
Cash Equivalents – Money Market Mutual Funds	$	527,978	$	—	$	—	$	—		$	527,978
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	1,483		—		—		(963		)	520
Over the Counter Swaps – Gas and Oil	—		38,977		—		(4,206		)	34,771
Foreign Currency Contracts	—		1,227		—		(407		)	820
Other Investments:
Balanced Equity Mutual Fund	37,033		—		—		—			37,033
Fixed Income Mutual Fund	45,727		—		—		—			45,727
Common Stock – Financial Services Industry	3,150		—		—		—			3,150
Hedging Collateral Deposits	1,741		—		—		—			1,741
Total	$	617,112	$	40,204	$	—	$	(5,576	)	$	651,740

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	963	$	—	$	—	$	(963	)	$	—
Over the Counter Swaps – Gas and Oil	—		5,309		—		(4,206		)	1,103
Foreign Currency Contracts	—		407		—		(407		)	—
Total	$	963	$	5,716	$	—	$	(5,576	)	$	1,103
Total Net Assets/(Liabilities)	$	616,149	$	34,488	$	—	$	—		$	650,637



	December 31, 2017				September 30, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,084,465	$	2,214,839	$	2,383,681	$	2,523,639



Derivatives in Fair Value Hedging Relationships	Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income	Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income for the Three Months Ended December 31, 2017 (In Thousands)			Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the Three Months Ended December 31, 2017 (In Thousands)
Commodity Contracts	Operating Revenues	$	(1,753	)	$	1,753
Commodity Contracts	Purchased Gas	$	137		$	(137	)
		$	(1,616	)	$	1,616



Ceiling Testing Sensitivity to Commodity Price Changes
(Millions)	$0.25/MMBtu Decrease in Natural Gas Prices		$5.00/Bbl Decrease in Crude Oil Prices		$0.25/MMBtu Decrease in Natural Gas Prices and $5.00/Bbl Decrease in Crude Oil Prices

Excess of Ceiling over Book Value under Sensitivity Analysis	$	188.4	$	295.4	$	149.2



Period	Total Number of Shares Purchased ^(a)	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under Share Repurchase Plans or Programs ^(b)
Oct. 1 - 31, 2017	—	N/A	—	6,971,019
Nov. 1 - 30, 2017	7,336	$57.83	—	6,971,019
Dec. 1 - 31, 2017	43,882	$57.06	—	6,971,019
Total	51,218	$57.17	—	6,971,019