NATIONAL FUEL GAS CO - Quarter Report: 2022 June (Form 10-Q)

Table of Contents

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 2022

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from____ to_____

Commission File Number 1-3880

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)


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

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

(716) 857-7000

(Registrant's telephone number, including area code)


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

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

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.


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

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

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Common stock, par value $1.00 per share, outstanding at July 31, 2022: 91,475,861 shares.

Table of Contents

GLOSSARY OF TERMS

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


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


Regulatory Agencies
CFTC			Commodity Futures Trading Commission
EPA			United States Environmental Protection Agency
FASB			Financial Accounting Standards Board
FERC			Federal Energy Regulatory Commission
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
PHMSA			Pipeline and Hazardous Materials Safety Administration
SEC			Securities and Exchange Commission


Other
2021 Form 10-K			The Company’s Annual Report on Form 10-K for the year ended September 30, 2021
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.
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.

Table of Contents


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.
Dth			Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
Exchange Act			Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets			Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploration costs			Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
Exploratory well			A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
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.
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			London Interbank Offered Rate
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)
MMBtu			Million British thermal units (heating value of one decatherm of natural gas)
MMcf			Million cubic feet (of natural gas)
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

Table of Contents


Open Season			A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.
Precedent Agreement			An agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called “conditions precedent”) happen, usually within a specified time.
Proved developed reserves			Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped (PUD) reserves			Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make these reserves productive.
Reserves			The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.
Revenue decoupling mechanism			A rate mechanism which adjusts customer rates to render a utility financially indifferent to throughput decreases resulting from conservation.
S&P			Standard & Poor’s Rating Service
SAR			Stock appreciation right
Service agreement			The binding agreement by which the pipeline company agrees to provide service and the shipper agrees to pay for the service.
SOFR			Secured Overnight Financing Rate
Stock acquisitions			Investments in corporations
Utica Shale			A Middle Ordovician-age geological formation lying several thousand feet below the Marcellus Shale in the Appalachian region of the United States, including much of Ohio, Pennsylvania, West Virginia and southern New York.
VEBA			Voluntary Employees’ Beneficiary Association
WNC			Weather normalization clause; 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

Item 1. Financial Statements (Unaudited)						6

a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Nine Months Ended June 30, 2022 and 2021						6
b. Consolidated Statements of Comprehensive Income – Three and Nine Months Ended June 30, 2022 and 2021						7
c. Consolidated Balance Sheets – June 30, 2022 and September 30, 2021						8
d. Consolidated Statements of Cash Flows – Nine Months Ended June 30, 2022 and 2021						10
e. Notes to Condensed Consolidated Financial Statements						11
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations						30
Item 3. Quantitative and Qualitative Disclosures About Market Risk						51
Item 4. Controls and Procedures						51

Part II. Other Information

Item 1. Legal Proceedings						51
Item 1 A. Risk Factors						51
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds						52
Item 3. Defaults Upon Senior Securities						•
Item 4. Mine Safety Disclosures						•
Item 5. Other Information						•
Item 6. Exhibits						53
Signatures						55

• 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 June 30,				Nine Months Ended June 30,
(Thousands of U.S. Dollars, Except Per Common Share Amounts)	2022		2021		2022		2021
INCOME
Operating Revenues:
Utility and Energy Marketing Revenues	$	179,888	$	126,933	$	785,664	$	587,247
Exploration and Production and Other Revenues	252,638		209,618		758,594		621,933
Pipeline and Storage and Gathering Revenues	70,098		57,846		206,642		177,491
	502,624		394,397		1,750,900		1,386,671

Operating Expenses:
Purchased Gas	67,948		18,737		369,168		177,018
Operation and Maintenance:
Utility and Energy Marketing	46,403		42,577		146,523		139,521
Exploration and Production and Other	64,593		43,112		160,016		127,033
Pipeline and Storage and Gathering	33,988		31,239		97,434		87,471
Property, Franchise and Other Taxes	25,874		24,492		78,093		71,259
Depreciation, Depletion and Amortization	95,857		84,170		275,681		251,632
Impairment of Oil and Gas Producing Properties	—		—		—		76,152
	334,663		244,327		1,126,915		930,086
Gain on Sale of Assets	12,736		—		12,736		51,066
Operating Income	180,697		150,070		636,721		507,651
Other Income (Expense):

Other Income (Deductions)	(5,649)		(2,028)		3,291		(15,078)
Interest Expense on Long-Term Debt	(30,091)		(30,220)		(90,300)		(111,296)
Other Interest Expense	(3,882)		(1,012)		(6,561)		(4,630)
Income Before Income Taxes	141,075		116,810		543,151		376,647
Income Tax Expense	32,917		30,335		135,272		99,962

Net Income Available for Common Stock	108,158		86,475		407,879		276,685

EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	1,407,683		1,100,718		1,191,175		991,630
	1,515,841		1,187,193		1,599,054		1,268,315

Dividends on Common Stock	(43,446)		(41,493)		(126,659)		(122,615)




Balance at June 30	$	1,472,395	$	1,145,700	$	1,472,395	$	1,145,700

Earnings Per Common Share:
Basic:
Net Income Available for Common Stock	$	1.18	$	0.95	$	4.46	$	3.04
Diluted:
Net Income Available for Common Stock	$	1.17	$	0.94	$	4.43	$	3.02
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	91,456,265		91,172,683		91,388,417		91,113,973
Used in Diluted Calculation	92,168,518		91,762,898		92,083,560		91,642,849
Dividends Per Common Share:
Dividends Declared	$	0.475	$	0.455	$	1.385	$	1.345

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)


	Three Months Ended June 30,				Nine Months Ended June 30,
(Thousands of U.S. Dollars)	2022		2021		2022		2021
Net Income Available for Common Stock	$	108,158	$	86,475	$	407,879	$	276,685
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(200,084)		(201,498)		(678,558)		(187,850)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	298,371		13,129		591,180		17,106


Other Post-Retirement Adjustment for Regulatory Proceeding	—		—		(7,351)		—
Other Comprehensive Income (Loss), Before Tax	98,287		(188,369)		(94,729)		(170,744)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(54,762)		(55,512)		(185,717)		(51,752)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	81,663		3,617		161,803		4,713



Income Tax Expense (Benefit) Related to Other Post-Retirement Adjustment for Regulatory Proceeding	—		—		(1,544)		—
Income Taxes – Net	26,901		(51,895)		(25,458)		(47,039)
Other Comprehensive Income (Loss)	71,386		(136,474)		(69,271)		(123,705)
Comprehensive Income (Loss)	$	179,544	$	(49,999)	$	338,608	$	152,980

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	June 30, 2022		September 30, 2021
(Thousands of U.S. Dollars)
ASSETS
Property, Plant and Equipment	$	12,299,545	$	13,103,639
Less - Accumulated Depreciation, Depletion and Amortization	5,914,097		6,719,356
	6,385,448		6,384,283

Current Assets
Cash and Temporary Cash Investments	432,576		31,528
Hedging Collateral Deposits	154,470		88,610
Receivables – Net of Allowance for Uncollectible Accounts of $41,983 and $31,639, Respectively	399,033		205,294
Unbilled Revenue	18,525		17,000
Gas Stored Underground	12,336		33,669
Materials, Supplies and Emission Allowances	39,634		53,560
Unrecovered Purchased Gas Costs	32,412		33,128
Other Current Assets	61,359		59,660
	1,150,345		522,449

Other Assets
Recoverable Future Taxes	125,576		121,992
Unamortized Debt Expense	9,308		10,589
Other Regulatory Assets	58,075		60,145
Deferred Charges	77,542		59,939
Other Investments	96,566		149,632
Goodwill	5,476		5,476
Prepaid Pension and Post-Retirement Benefit Costs	187,692		149,151
Fair Value of Derivative Financial Instruments	12,571		—
Other	3,487		1,169
	576,293		558,093

Total Assets	$	8,112,086	$	7,464,825

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	June 30, 2022		September 30, 2021
(Thousands of U.S. Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued And Outstanding – 91,465,569 Shares and 91,181,549 Shares, Respectively	$	91,466	$	91,182
Paid in Capital	1,022,954		1,017,446
Earnings Reinvested in the Business	1,472,395		1,191,175
Accumulated Other Comprehensive Loss	(582,868)		(513,597)
Total Comprehensive Shareholders’ Equity	2,003,947		1,786,206
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,082,463		2,628,687
Total Capitalization	4,086,410		4,414,893

Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	400,000		158,500
Current Portion of Long-Term Debt	549,000		—
Accounts Payable	145,320		171,655
Amounts Payable to Customers	292		21
Dividends Payable	43,446		41,487
Interest Payable on Long-Term Debt	45,017		17,376
Customer Advances	—		17,223
Customer Security Deposits	25,200		19,292
Other Accruals and Current Liabilities	254,383		194,169
Fair Value of Derivative Financial Instruments	703,788		616,410
	2,166,446		1,236,133

Other Liabilities
Deferred Income Taxes	767,207		660,420
Taxes Refundable to Customers	346,577		354,089

Cost of Removal Regulatory Liability	256,092		245,636
Other Regulatory Liabilities	199,094		200,643
Pension and Other Post-Retirement Liabilities	4,732		7,526
Asset Retirement Obligations	152,100		209,639
Other Liabilities	133,428		135,846
	1,859,230		1,813,799
Commitments and Contingencies (Note 8)	—		—

Total Capitalization and Liabilities	$	8,112,086	$	7,464,825

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended June 30,
(Thousands of U.S. Dollars)	2022		2021
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	407,879	$	276,685
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Gain on Sale of Assets	(12,736)		(51,066)
Impairment of Oil and Gas Producing Properties	—		76,152
Depreciation, Depletion and Amortization	275,681		251,632
Deferred Income Taxes	121,150		89,277

Premium Paid on Early Redemption of Debt	—		15,715
Stock-Based Compensation	15,178		12,296
Reduction of Other Post-Retirement Regulatory Liability	(18,533)		—
Other	27,527		7,795
Change in:
Receivables and Unbilled Revenue	(194,832)		(40,733)
Gas Stored Underground and Materials, Supplies and Emission Allowances	24,141		19,024
Unrecovered Purchased Gas Costs	716		—
Other Current Assets	(1,699)		(4,282)
Accounts Payable	19,259		7,474
Amounts Payable to Customers	271		(3,595)
Customer Advances	(17,223)		(15,319)
Customer Security Deposits	5,908		2,073
Other Accruals and Current Liabilities	61,322		23,154
Other Assets	(44,184)		5,839
Other Liabilities	(15,809)		(311)
Net Cash Provided by Operating Activities	654,016		671,810

INVESTING ACTIVITIES
Capital Expenditures	(592,487)		(512,775)
Net Proceeds from Sale of Oil and Gas Producing Properties	254,439		—
Net Proceeds from Sale of Timber Properties	—		104,582

Sale of Fixed Income Mutual Fund Shares in Grantor Trust	30,000		—
Other	13,528		11,223
Net Cash Used in Investing Activities	(294,520)		(396,970)

FINANCING ACTIVITIES
Changes in Notes Payable to Banks and Commercial Paper	241,500		(30,000)

Net Proceeds from Issuance of Long-Term Debt	—		495,267
Reduction of Long-Term Debt	—		(515,715)
Dividends Paid on Common Stock	(124,701)		(121,606)
Net Repurchases of Common Stock	(9,387)		(3,605)
Net Cash Provided by (Used in) Financing Activities	107,412		(175,659)
Net Increase in Cash, Cash Equivalents, and Restricted Cash	466,908		99,181
Cash, Cash Equivalents, and Restricted Cash at October 1	120,138		20,541
Cash, Cash Equivalents, and Restricted Cash at June 30	$	587,046	$	119,722

Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$	74,415	$	81,485
Non-Cash Contingent Consideration for Asset Sale	$	12,571	$	—

See Notes to Condensed Consolidated Financial Statements

Table of Contents

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 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, 2021, 2020 and 2019 that are included in the Company's 2021 Form 10-K. The consolidated financial statements for the year ended September 30, 2022 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.

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

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


	Nine Months Ended June 30, 2022				Nine Months Ended June 30, 2021
	Balance at June 30, 2022		Balance at October 1, 2021		Balance at June 30, 2021		Balance at October 1, 2020

Cash and Temporary Cash Investments	$	432,576	$	31,528	$	118,012	$	20,541
Hedging Collateral Deposits	154,470		88,610		1,710		—
Cash, Cash Equivalents, and Restricted Cash	$	587,046	$	120,138	$	119,722	$	20,541

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

Allowance for Uncollectible Accounts. The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance, the majority of which is in the Utility segment, is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic and regulatory environment. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered.

Table of Contents

Activity in the allowance for uncollectible accounts for the nine months ended June 30, 2022 and 2021 are as follows (in thousands):


	Balance at Beginning of Period		Additions Charged to Costs and Expenses		Discounts on Purchased Receivables		Net Accounts Receivable Written-Off		Balance at End of Period
Nine Months Ended June 30, 2022
Allowance for Uncollectible Accounts	$	31,639	$	12,024	$	1,211	$	(2,891)	$	41,983
Nine Months Ended June 30, 2021
Allowance for Uncollectible Accounts	$	22,810	$	13,375	$	1,097	$	(4,960)	$	32,322

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 $21.8 million at June 30, 2022, is reduced to zero by September 30 of each year as the inventory is replenished.

Materials, Supplies and Emission Allowances. The components of the Company's materials, supplies and emission allowances are as follows (in thousands):


	At June 30, 2022		At September 30, 2021

Materials and Supplies - at average cost	$	39,634	$	34,880
Emission Allowances	—		18,680
	$	39,634	$	53,560

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 $1.8 billion and $1.9 billion at June 30, 2022 and September 30, 2021, 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 $105.5 million and $103.8 million at June 30, 2022 and September 30, 2021, respectively. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.

Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unproved properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter. At June 30, 2022, the ceiling exceeded the book value of the oil and gas properties by approximately $2.4 billion. The estimated future net cash flows were decreased by $757.6 million for hedging under the ceiling test at June 30, 2022.

Table of Contents

The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. There were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at June 30, 2022.

Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss and changes for the nine months ended June 30, 2022 and 2021, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):


	Gains and Losses on Derivative Financial Instruments		Funded Status of the Pension and Other Post-Retirement Benefit Plans		Total
Three Months Ended June 30, 2022
Balance at April 1, 2022	$	(584,812)	$	(69,442)	$	(654,254)
Other Comprehensive Gains and Losses Before Reclassifications	(145,322)		—		(145,322)
Amounts Reclassified From Other Comprehensive Income	216,708		—		216,708

Balance at June 30, 2022	$	(513,426)	$	(69,442)	$	(582,868)
Nine Months Ended June 30, 2022
Balance at October 1, 2021	$	(449,962)	$	(63,635)	$	(513,597)
Other Comprehensive Gains and Losses Before Reclassifications	(492,841)		—		(492,841)
Amounts Reclassified From Other Comprehensive Loss	429,377		—		429,377
Other Post-Retirement Adjustment for Regulatory Proceeding	—		(5,807)		(5,807)

Balance at June 30, 2022	$	(513,426)	$	(69,442)	$	(582,868)
Three Months Ended June 30, 2021
Balance at April 1, 2021	$	(12,096)	$	(89,892)	$	(101,988)
Other Comprehensive Gains and Losses Before Reclassifications	(145,986)		—		(145,986)
Amounts Reclassified From Other Comprehensive Loss	9,512		—		9,512

Balance at June 30, 2021	$	(148,570)	$	(89,892)	$	(238,462)
Nine Months Ended June 30, 2021
Balance at October 1, 2020	$	(24,865)	$	(89,892)	$	(114,757)
Other Comprehensive Gains and Losses Before Reclassifications	(136,098)		—		(136,098)
Amounts Reclassified From Other Comprehensive Loss	12,393		—		12,393



Balance at June 30, 2021	$	(148,570)	$	(89,892)	$	(238,462)

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.”

Table of Contents

Reclassifications Out of Accumulated Other Comprehensive Loss. The details about the reclassification adjustments out of accumulated other comprehensive loss for the nine months ended June 30, 2022 and 2021 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 June 30,		Nine Months Ended June 30,
	2022	2021	2022	2021
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts	($298,372)	($13,281)	($591,271)	($17,351)	Operating Revenues

Foreign Currency Contracts	1	152	91	245	Operating Revenues
	(298,371)	(13,129)	(591,180)	(17,106)	Total Before Income Tax
	81,663	3,617	161,803	4,713	Income Tax Expense
	($216,708)	($9,512)	($429,377)	($12,393)	Net of Tax

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


	At June 30, 2022		At September 30, 2021

Prepayments	$	16,419	$	14,164
Prepaid Property and Other Taxes	11,730		14,788

State Income Taxes Receivable	3,032		1,502

Regulatory Assets	30,178		29,206
	$	61,359	$	59,660

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


	At June 30, 2022		At September 30, 2021

Accrued Capital Expenditures	$	59,849	$	42,541
Regulatory Liabilities	31,959		60,860
Reserve for Gas Replacement	21,775		—
Liability for Royalty and Working Interests	63,755		31,483
Federal Income Taxes Payable	154		154



Non-Qualified Benefit Plan Liability	15,408		15,408
Other	61,483		43,723
	$	254,383	$	194,169

Earnings Per Common Share. Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding were SARs, restricted stock units and performance shares. For the quarter and nine months ended June 30, 2022, 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. SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 873 securities and 6,990 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2022, respectively. There were 334,335 securities and 333,445 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2021, respectively.

Table of Contents

Stock-Based Compensation. The Company granted 195,397 performance shares during the nine months ended June 30, 2022. The weighted average fair value of such performance shares was $65.39 per share for the nine months ended June 30, 2022. Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period.

The performance shares granted during the nine months ended June 30, 2022 include awards that must meet a performance goal related to either relative return on capital over a three-year performance cycle ("ROC performance shares"), methane intensity and greenhouse gas emissions reductions over a three-year performance cycle ("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 period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database. The number of these ROC performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value of the ROC performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award.

The performance goal related to the ESG performance shares over the three-year performance cycle consists of two parts: reductions in the rates of intensity of methane emissions for each of the Company's operating segments, and reduction of the consolidated Company's total greenhouse gas emissions. The Company's Compensation Committee set specific target levels for methane intensity rates and total greenhouse gas emissions, and the performance goal is intended to incentivize and reward performance that helps position the Company to meet or exceed its 2030 methane intensity and greenhouse gas reduction targets. 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 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 128,950 restricted stock units during the nine months ended June 30, 2022. The weighted average fair value of such restricted stock units was $54.10 per share for the nine months ended June 30, 2022. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for 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 must be reduced by the present value of forgone dividends over the vesting term of the award.

Table of Contents

Note 2 – Asset Acquisitions and Divestitures

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. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar 2023 and 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. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. 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.

On December 10, 2020, the Company completed the sale of substantially all timber properties in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme Allegheny Land Company II LLC for net proceeds of $104.6 million. At September 30, 2020, these assets, amounting to $53.4 million, which previously were recorded as Net Property, Plant and Equipment, were presented as Assets Held for Sale, Net on the Consolidated Balance Sheet. These assets were a component of the Company’s All Other category and did not have a major impact on the Company’s operations or financial results. After purchase price adjustments and transaction costs, a gain of $51.1 million was recognized on the sale of these assets. Since the sale did not represent a strategic shift in focus for the Company, the financial results associated with operating these assets as well as the gain on sale have not been reported as discontinued operations.

The sale of the timber properties completed a reverse like-kind exchange pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchange”). On July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from SWEPI LP, a subsidiary of Royal Dutch Shell plc (“Shell”) for total consideration of $506.3 million. The purchase and sale agreement with Shell was structured, in part, as a Reverse 1031 Exchange. In connection with the Reverse 1031 Exchange, the Company, through a subsidiary, assigned the rights to acquire legal title to certain oil and natural gas properties to a Variable Interest Entity ("VIE") formed by an exchange accommodation titleholder. From July 31, 2020 to December 10, 2020, a subsidiary of the Company operated the properties pursuant to a lease agreement with the VIE. As the Company was deemed to be the primary beneficiary of the VIE, the VIE was included in the consolidated financial statements of the Company. Upon completion of the sale of the timber properties on December 10, 2020, the affected properties were conveyed to the Company and the VIE structure was terminated. Refer to Note B – Asset Acquisitions and Divestitures of the Company’s 2021 Form 10-K for additional information concerning the Company’s acquisition of certain upstream assets and midstream gathering assets from Shell.

Table of Contents

Note 3 – Revenue from Contracts with Customers

The following tables provide a disaggregation of the Company's revenues for the quarter and nine months ended June 30, 2022 and 2021, presented by type of service from each reportable segment.


Quarter Ended June 30, 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	$	492,698	$	—	$	—	$	—	$	—	$	—	$	492,698
Production of Crude Oil	58,292		—		—		—		—		—		58,292
Natural Gas Processing	1,016		—		—		—		—		—		1,016
Natural Gas Gathering Service	—		—		55,931		—		—		(53,069)		2,862
Natural Gas Transportation Service	—		74,826		—		22,019		—		(19,173)		77,672
Natural Gas Storage Service	—		21,084		—		—		—		(9,024)		12,060
Natural Gas Residential Sales	—		—		—		138,297		—		—		138,297
Natural Gas Commercial Sales	—		—		—		17,643		—		—		17,643
Natural Gas Industrial Sales	—		—		—		784		—		—		784

Other	(996)		(362)		—		243		—		(175)		(1,290)
Total Revenues from Contracts with Customers	551,010		95,548		55,931		178,986		—		(81,441)		800,034
Alternative Revenue Programs	—		—		—		962		—		—		962
Derivative Financial Instruments	(298,372)		—		—		—		—		—		(298,372)
Total Revenues	$	252,638	$	95,548	$	55,931	$	179,948	$	—	$	(81,441)	$	502,624


Nine Months Ended June 30, 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	$	1,189,940	$	—	$	—	$	—	$	—	$	—	$	1,189,940
Production of Crude Oil	150,276		—		—		—		—		—		150,276
Natural Gas Processing	3,029		—		—		—		—		—		3,029
Natural Gas Gathering Service	—		—		160,759		—		—		(150,696)		10,063
Natural Gas Transportation Service	—		213,766		—		91,276		—		(55,031)		250,011
Natural Gas Storage Service	—		63,334		—		—		—		(27,302)		36,032
Natural Gas Residential Sales	—		—		—		604,336		—		—		604,336
Natural Gas Commercial Sales	—		—		—		84,833		—		—		84,833
Natural Gas Industrial Sales	—		—		—		4,124		—		—		4,124

Other	6,454		2,195		—		(5,903)		6		(468)		2,284
Total Revenues from Contracts with Customers	1,349,699		279,295		160,759		778,666		6		(233,497)		2,334,928
Alternative Revenue Programs	—		—		—		7,243		—		—		7,243
Derivative Financial Instruments	(591,271)		—		—		—		—		—		(591,271)
Total Revenues	$	758,428	$	279,295	$	160,759	$	785,909	$	6	$	(233,497)	$	1,750,900

Table of Contents


Quarter Ended June 30, 2021 (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	$	184,029	$	—	$	—	$	—	$	—	$	—	$	184,029
Production of Crude Oil	37,695		—		—		—		—		—		37,695
Natural Gas Processing	732		—		—		—		—		—		732
Natural Gas Gathering Service	—		—		48,656		—		—		(48,068)		588
Natural Gas Transportation Service	—		63,107		—		20,201		—		(17,786)		65,522
Natural Gas Storage Service	—		20,646		—		—		—		(8,926)		11,720
Natural Gas Residential Sales	—		—		—		93,079		—		—		93,079
Natural Gas Commercial Sales	—		—		—		10,617		—		—		10,617
Natural Gas Industrial Sales	—		—		—		488		—		—		488
Natural Gas Marketing	—		—		—		—		1		(2)		(1)
Other	360		310		—		(437)		—		(84)		149
Total Revenues from Contracts with Customers	222,816		84,063		48,656		123,948		1		(74,866)		404,618
Alternative Revenue Programs	—		—		—		3,060		—		—		3,060
Derivative Financial Instruments	(13,281)		—		—		—		—		—		(13,281)
Total Revenues	$	209,535	$	84,063	$	48,656	$	127,008	$	1	$	(74,866)	$	394,397


Nine Months Ended June 30, 2021 (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	$	539,241	$	—	$	—	$	—	$	—	$	—	$	539,241
Production of Crude Oil	95,783		—		—		—		—		—		95,783
Natural Gas Processing	2,056		—		—		—		—		—		2,056
Natural Gas Gathering Service	—		—		145,927		—		—		(144,317)		1,610
Natural Gas Transportation Service	—		192,580		—		88,736		—		(55,562)		225,754
Natural Gas Storage Service	—		62,394		—		—		—		(26,797)		35,597
Natural Gas Residential Sales	—		—		—		434,728		—		—		434,728
Natural Gas Commercial Sales	—		—		—		56,684		—		—		56,684
Natural Gas Industrial Sales	—		—		—		2,778		—		—		2,778
Natural Gas Marketing	—		—		—		—		651		(22)		629
Other	1,387		3,558		—		(6,568)		545		(291)		(1,369)
Total Revenues from Contracts with Customers	638,467		258,532		145,927		576,358		1,196		(226,989)		1,393,491
Alternative Revenue Programs	—		—		—		10,531		—		—		10,531
Derivative Financial Instruments	(17,351)		—		—		—		—		—		(17,351)
Total Revenues	$	621,116	$	258,532	$	145,927	$	586,889	$	1,196	$	(226,989)	$	1,386,671

The Company records revenue related to its derivative financial instruments in the Exploration and Production segment. The Company also records revenue related to alternative revenue programs in its Utility segment. Revenue related to derivative financial instruments and alternative revenue programs are excluded from the scope of the authoritative guidance regarding revenue recognition since they are accounted for under other existing accounting guidance.

The Company’s Pipeline and Storage segment expects to recognize the following revenue amounts in future periods related to “fixed” charges associated with remaining performance obligations for transportation and storage contracts: $57.8

Table of Contents

million for the remainder of fiscal 2022; $204.7 million for fiscal 2023; $182.5 million for fiscal 2024; $164.1 million for fiscal 2025; $143.1 million for fiscal 2026; and $812.8 million thereafter.

Note 4 – Fair Value Measurements

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

The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of June 30, 2022 and September 30, 2021. 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-the-counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company.


Recurring Fair Value Measures	At fair value as of June 30, 2022
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)		Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	406,961	$	—	$	—	$	—	$	406,961
Hedging Collateral Deposits	154,470		—		—		—		154,470
Derivative Financial Instruments:


Over the Counter No Cost Collars – Gas	—		893		—		(893)		—
Contingent Consideration for Asset Sale	—		12,571		—		—		12,571
Foreign Currency Contracts	—		497		—		(497)		—
Other Investments:
Balanced Equity Mutual Fund	20,700		—		—		—		20,700
Fixed Income Mutual Fund	33,936		—		—		—		33,936


Total	$	616,067	$	13,961	$	—	$	(1,390)	$	628,638

Liabilities:
Derivative Financial Instruments:

Over the Counter Swaps – Gas	—		537,456		—		—		537,456
Over the Counter No Cost Collars – Gas	—		167,242		—		(893)		166,349
Foreign Currency Contracts	—		480		—		(497)		(17)
Total	$	—	$	705,178	$	—	$	(1,390)	$	703,788

Total Net Assets/(Liabilities)	$	616,067	$	(691,217)	$	—	$	—	$	(75,150)

Table of Contents


Recurring Fair Value Measures	At fair value as of September 30, 2021
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)		Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	22,269	$	—	$	—	$	—	$	22,269
Hedging Collateral Deposits	88,610		—		—		—		88,610
Derivative Financial Instruments:

Over the Counter Swaps – Gas and Oil	—		1,802		—		(1,802)		—

Foreign Currency Contracts	—		938		—		(938)		—
Other Investments:
Balanced Equity Mutual Fund	34,433		—		—		—		34,433
Fixed Income Mutual Fund	70,639		—		—		—		70,639



Total	$	215,951	$	2,740	$	—	$	(2,740)	$	215,951

Liabilities:
Derivative Financial Instruments:

Over the Counter Swaps – Gas and Oil	—		601,551		—		(1,802)		599,749
Over the Counter No Cost Collars – Gas	—		17,385		—		—		17,385
Foreign Currency Contracts	—		214		—		(938)		(724)
Total	$	—	$	619,150	$	—	$	(2,740)	$	616,410

Total Net Assets/(Liabilities)	$	215,951	$	(616,410)	$	—	$	—	$	(400,459)

(1)Netting Adjustments represent the impact of legally-enforceable master netting arrangements that allow the Company to net gain and loss positions held with the same counterparties. The net asset or net liability for each counterparty is recorded as an asset or liability on the Company’s balance sheet.

Derivative Financial Instruments

The derivative financial instruments reported in Level 2 at June 30, 2022 include natural gas price swap agreements, natural gas no cost collars, and foreign currency contracts, all of which are used in the Company’s Exploration and Production segment. The derivative financial instruments reported in Level 2 at September 30, 2021 consist of the same type of instruments in addition to crude oil price swap agreements. The use of crude oil price swap agreements was discontinued during the quarter ended June 30, 2022 in conjunction with the sale of the Exploration and Production segment's California assets. Hedging collateral deposits of $154.5 million (at June 30, 2022) and $88.6 million (at September 30, 2021), which were associated with the price swap agreements, no cost collars and foreign currency contracts, have been reported in Level 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 based discount rates 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 authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At June 30, 2022, the Company determined that nonperformance risk associated with the price swap agreements, no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

Derivative financial instruments reported in Level 2 at June 30, 2022 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 ICE Brent closing price as of the valuation date, initial and max trigger price, volatility, risk free rate, time of maturity and counterparty risk.

For the quarters ended June 30, 2022 and June 30, 2021, there were no assets or liabilities measured at fair value and classified as Level 3.

Table of Contents

Note 5 – Financial Instruments

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


	June 30, 2022				September 30, 2021
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,631,463	$	2,502,388	$	2,628,687	$	2,898,552

The fair value amounts are not intended to reflect principal amounts that the Company will ultimately be required to pay. Carrying amounts for other financial instruments recorded on the Company’s Consolidated Balance Sheets approximate fair value. The fair value of long-term debt was calculated using observable inputs (U.S. Treasuries for the risk free component and company specific credit spread information – generally obtained from recent trade activity in the debt). As such, the Company considers the debt to be Level 2.

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

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


	At June 30, 2022		At September 30, 2021

Life Insurance Contracts	$	41,930	$	44,560
Equity Mutual Fund	20,700		34,433
Fixed Income Mutual Fund	33,936		70,639

	$	96,566	$	149,632

Investments in life insurance contracts are stated at their cash surrender values or net present value. Investments in an equity mutual fund and a fixed income mutual fund are stated at fair value based on quoted market prices with changes in fair value recognized in net income. The insurance contracts and equity mutual fund are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees. The fixed income mutual fund is primarily an informal funding mechanism for certain regulatory obligations that the Company has to Utility segment customers in its Pennsylvania jurisdiction, 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. The Company enters into over-the-counter no cost collars and over-the-counter swap agreements for natural gas to manage the price risk associated with forecasted sales of natural gas. In addition, the Company also enters into foreign exchange forward contracts to manage the risk of currency fluctuations associated with transportation costs denominated in Canadian currency in the Exploration and Production segment. These instruments are accounted for as cash flow hedges. The duration of the Company’s cash flow hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 9 years.

On June 30, 2022, the Company completed the sale of Seneca’s California assets. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar 2023 and 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 under the authoritative accounting guidance. The fair value of this contingent consideration was estimated to be $12.6 million at June 30, 2022. Future changes in the fair value of this contingent consideration will be marked-to-market each reporting period, with changes in fair value recognized in Other Income (Deductions) on the Consolidated Statement of Income.

Table of Contents

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at June 30, 2022 and September 30, 2021.

Cash Flow Hedges

For derivative financial instruments that are designated and qualify as a cash flow hedge, the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings.

As of June 30, 2022, the Company had 462.3 Bcf of natural gas commodity derivative contracts (swaps and no cost collars) outstanding.

As of June 30, 2022, the Company was hedging a total of $53.4 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

As of June 30, 2022, the Company had $703.8 million ($513.4 million after-tax) of net hedging losses included in the accumulated other comprehensive loss balance. It is expected that $420.1 million ($306.5 million after-tax) of such unrealized losses will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings.


The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended June 30, 2022 and 2021 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships	Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) for the Three Months Ended June 30,				Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Three Months Ended June 30,
	2022		2021			2022			2021
Commodity Contracts	$	(198,827)	$	(202,114)	Operating Revenue	$	(298,372)	(1)	$	(13,281)

Foreign Currency Contracts	(1,257)		616		Operating Revenue	1			152
Total	$	(200,084)	$	(201,498)		$	(298,371)		$	(13,129)


The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Nine Months Ended June 30, 2022 and 2021 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships	Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) for the Nine Months Ended June 30,				Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Nine Months Ended June 30,
	2022		2021			2022			2021
Commodity Contracts	$	(677,942)	$	(191,642)	Operating Revenue	$	(591,271)	(1)	$	(17,351)

Foreign Currency Contracts	(616)		3,792		Operating Revenue	91			245
Total	$	(678,558)	$	(187,850)		$	(591,180)		$	(17,106)

(1)On June 30, 2022, the Company completed the sale of Seneca's California assets. Because of this sale, the Company terminated its remaining crude oil derivative contracts and discontinued hedge accounting for such contracts. A loss of $44.6 million was reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet to Operating Revenues on the Consolidated Statement of Income for the three and nine months ended June 30, 2022. This loss is included in the reported reclassification amounts.

Table of Contents

Credit Risk

The Company has over-the-counter swap positions, no cost collars and applicable foreign currency forward contracts with eighteen counterparties. The majority of the Company’s counterparties are financial institutions and energy traders. As of June 30, 2022, sixteen of the eighteen counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps, over-the-counter no cost collars and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit 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 contracts with a credit-risk contingency feature were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then hedging collateral deposits or an increase to such deposits could be required. At June 30, 2022, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $517.8 million according to the Company’s internal model (discussed in Note 4 – Fair Value Measurements), and the Company posted $154.5 million in hedging collateral deposits. Depending on the movement of commodity prices in the future, it is possible that these liability positions could swing into asset positions, at which point the Company would be exposed to credit risk on its derivative financial instruments. In that case, the Company's counterparties could be required to post hedging collateral deposits.

The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value.

Note 6 – Income Taxes

The effective tax rates for the quarters ended June 30, 2022 and June 30, 2021 were 23.3% and 26.0%, respectively. The effective tax rates for the nine months ended June 30, 2022 and June 30, 2021 were 24.9% and 26.5%, respectively. The decrease in the effective tax rate for both the quarter and nine months ended June 30, 2022 was primarily due to the realization of the Enhanced Oil Recovery credit in fiscal 2022 that was not available during fiscal 2021.

As a result of the sale of the Company's California assets as described in Note 2 – Asset Acquisitions and Divestitures, the remaining deferred tax assets related to the California net operating loss and tax credit carryforwards, which are currently offset with a full valuation allowance, were written off. The deferred tax assets and valuation allowance were written off as the Company determined that there was a remote possibility for use as the Company no longer has California operations. See the table below for the impact to the valuation allowance resulting from the sale (in thousands):


Balance at October 1, 2021	$	57,645
Adjustment Related to Sale of California Assets and Current Year Activity	(28,747)
Balance at June 30, 2022	$	28,898

Subsequent to the end of the third quarter of fiscal 2022, on July 8, 2022, House Bill 1342 was signed into law in Pennsylvania. The law reduces the corporate income tax rate to 8.99% for fiscal 2024. Starting with fiscal 2025, the rate is reduced by 0.5% annually until it reaches 4.99% for fiscal 2032. Due to the reduced state income tax rate, Pennsylvania deferred income taxes will be remeasured using the new rates. The anticipated income tax benefit resulting from the reduced tax rate of approximately $25 million to $30 million will be recorded during the fourth quarter of fiscal 2022.

Table of Contents

Note 7 – Capitalization

Summary of Changes in Common Stock Equity


	Common Stock			Paid In Capital		Earnings Reinvested in the Business		Accumulated Other Comprehensive Income (Loss)
	Shares	Amount
	(Thousands, except per share amounts)
Balance at April 1, 2022	91,449	$	91,449	$	1,018,784	$	1,407,683	$	(654,254)
Net Income Available for Common Stock						108,158
Dividends Declared on Common Stock ($0.475 Per Share)						(43,446)

Other Comprehensive Income, Net of Tax								71,386
Share-Based Payment Expense (1)				4,094

Common Stock Issued Under Stock and Benefit Plans	17	17		76
Balance at June 30, 2022	91,466	$	91,466	$	1,022,954	$	1,472,395	$	(582,868)

Balance at October 1, 2021	91,182	$	91,182	$	1,017,446	$	1,191,175	$	(513,597)
Net Income Available for Common Stock						407,879
Dividends Declared on Common Stock ($1.385 Per Share)						(126,659)

Other Comprehensive Loss, Net of Tax								(69,271)
Share-Based Payment Expense (1)				13,826

Common Stock Issued (Repurchased) Under Stock and Benefit Plans	284	284		(8,318)
Balance at June 30, 2022	91,466	$	91,466	$	1,022,954	$	1,472,395	$	(582,868)

Balance at April 1, 2021	91,164	$	91,164	$	1,009,075	$	1,100,718	$	(101,988)
Net Income Available for Common Stock						86,475
Dividends Declared on Common Stock ($0.455 Per Share)						(41,493)

Other Comprehensive Loss, Net of Tax								(136,474)
Share-Based Payment Expense (1)				3,196

Common Stock Issued Under Stock and Benefit Plans	9	9		432
Balance at June 30, 2021	91,173	$	91,173	$	1,012,703	$	1,145,700	$	(238,462)

Balance at October 1, 2020	90,955	$	90,955	$	1,004,158	$	991,630	$	(114,757)
Net Income Available for Common Stock						276,685
Dividends Declared on Common Stock ($1.345 Per Share)						(122,615)



Other Comprehensive Loss, Net of Tax								(123,705)
Share-Based Payment Expense (1)				10,975

Common Stock Issued (Repurchased) Under Stock and Benefit Plans	218	218		(2,430)
Balance at June 30, 2021	91,173	$	91,173	$	1,012,703	$	1,145,700	$	(238,462)

(1)Paid in Capital includes compensation costs associated with performance shares and/or restricted stock awards. The expense is included within Net Income Available For Common Stock, net of tax benefits.

Common Stock. During the nine months ended June 30, 2022, the Company issued 27,722 original issue shares of common stock as a result of SARs exercises, 123,589 original issue shares of common stock for restricted stock units that vested and 265,607 original issue shares of common stock for performance shares that vested. The Company also issued 21,949 original issue shares of common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, including the reinvestment of dividends for certain non-employee directors who elected to defer their shares pursuant to the dividend reinvestment feature of the Company's Deferred Compensation Plan for Directors and Officers during the nine months ended June 30, 2022. Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes. During the nine months ended June 30, 2022, 154,847 shares of common stock were tendered to the Company for such

Table of Contents

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.

Current Portion of Long-Term Debt. Current Portion of Long-Term Debt at June 30, 2022 consists of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes that mature in March 2023. None of the Company's long-term debt as of September 30, 2021 had a maturity date within the following twelve-month period.

Short-Term Borrowings and Debt Restrictions. On February 28, 2022, the Company entered into a Credit Agreement (as amended from time to time, the "Credit Agreement") with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. The Credit Agreement provides a $1.0 billion unsecured committed revolving credit facility with an initial maturity date of February 26, 2027.

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 modifies the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ending 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 balance sheet.

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. Under the delayed draw mechanism of the 364-Day Credit Agreement, the Company may, through September 28, 2022, make up to three elections to borrow funds under the facility, provided that the Company may extend the period to make such elections to October 28, 2022.

Note 8 – Commitments and Contingencies

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

At June 30, 2022, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.8 million. The Company's liability for such clean-up costs has been recorded in Other Liabilities on the Consolidated Balance Sheet at June 30, 2022. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 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.

Northern Access Project. On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access project described herein. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order and FERC's decisions were appealed. The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project. As of June 30, 2022, the Company has spent approximately $55.8 million on the project, all of which is recorded on the balance sheet.

Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these other matters arising in the normal

Table of Contents

course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.

Note 9 – Business Segment Information

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

The data presented in the tables below reflect financial information for the segments and reconcile to consolidated amounts. As stated in the 2021 Form 10-K, the Company evaluates segment performance based on income before discontinued operations (when applicable). When this is not applicable, the Company evaluates performance based on net income. There have not been any changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s 2021 Form 10-K. A listing of segment assets at June 30, 2022 and September 30, 2021 is shown in the tables below.


Quarter Ended June 30, 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	$252,638	$67,236	$2,862	$179,888	$502,624	$—	$—	$502,624
Intersegment Revenues	$—	$28,312	$53,069	$60	$81,441	$—	$(81,441)	$—
Segment Profit: Net Income (Loss)	$56,497	$26,599	$24,658	$4,622	$112,376	$—	$(4,218)	$108,158


Nine Months Ended June 30, 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	$758,428	$196,579	$10,063	$785,664	$1,750,734	$—	$166	$1,750,900
Intersegment Revenues	$—	$82,716	$150,696	$245	$233,657	$6	$(233,663)	$—
Segment Profit: Net Income (Loss)	$189,987	$77,236	$69,887	$79,800	$416,910	$(7)	$(9,024)	$407,879


(Thousands)	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Segment Assets:
At June 30, 2022	$2,716,219	$2,371,621	$870,204	$2,247,229	$8,205,273	$235	$(93,422)	$8,112,086
At September 30, 2021	$2,286,058	$2,296,030	$837,729	$2,148,267	$7,568,084	$4,146	$(107,405)	$7,464,825


Quarter Ended June 30, 2021 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$209,535	$57,258	$588	$126,934	$394,315	$(1)	$83	$394,397
Intersegment Revenues	$—	$26,805	$48,068	$74	$74,947	$2	$(74,949)	$—
Segment Profit: Net Income (Loss)	$39,015	$21,948	$20,427	$4,841	$86,231	$1,039	$(795)	$86,475

Table of Contents


Nine Months Ended June 30, 2021 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$621,116	$175,881	$1,610	$586,618	$1,385,225	$1,174	$272	$1,386,671
Intersegment Revenues	$—	$82,651	$144,317	$271	$227,239	$22	$(227,261)	$—
Segment Profit: Net Income	$46,213	$71,060	$61,677	$59,922	$238,872	$37,617	$196	$276,685

Note 10 – Retirement Plan and Other Post-Retirement Benefits

Components of Net Periodic Benefit Cost (in thousands):


	Retirement Plan				Other Post-Retirement Benefits
Three Months Ended June 30,	2022		2021		2022		2021

Service Cost	$	2,190	$	2,466	$	332	$	400
Interest Cost	5,707		5,422		2,267		2,326
Expected Return on Plan Assets	(13,074)		(14,537)		(7,340)		(7,241)
Amortization of Prior Service Cost (Credit)	134		158		(107)		(107)

Amortization of (Gains) Losses	6,601		9,203		(1,903)		212
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	3,470		2,772		5,351		6,639

Net Periodic Benefit Cost (Income)	$	5,028	$	5,484	$	(1,400)	$	2,229



	Retirement Plan				Other Post-Retirement Benefits
Nine Months Ended June 30,	2022		2021		2022		2021

Service Cost	$	6,568	$	7,399	$	996	$	1,202
Interest Cost	17,121		16,265		6,800		6,977
Expected Return on Plan Assets	(39,221)		(43,611)		(22,020)		(21,723)
Amortization of Prior Service Cost (Credit)	403		473		(321)		(321)

Amortization of (Gains) Losses	19,803		27,610		(5,708)		636
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	16,308		14,194		15,870		22,942

Net Periodic Benefit Cost (Income)	$	20,982	$	22,330	$	(4,383)	$	9,713

(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 nine months ended June 30, 2022, the Company contributed $19.3 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $2.7 million to its VEBA trusts for its other post-retirement benefits. In the remainder of 2022, the Company expects to contribute approximately $1.1 million to the Retirement Plan. In the remainder of 2022, the Company expects to contribute approximately $0.2 million to its VEBA trusts.

Table of Contents

Note 11 – Regulatory Matters

New York Jurisdiction

Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017. The order provided for a return on equity of 8.7%, and directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018.

On 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). The extension is contingent on the Company not filing a base rate case that would result in new rates becoming effective prior to April 1, 2023.

In response to the novel coronavirus (COVID-19) pandemic, various legislative actions and NYPSC Staff requests resulted in the Company suspending service terminations and disconnections. All legislative prohibitions have expired and the Company has agreed to refrain from terminating residential customers (1) with a pending application for arrears payments through the Emergency Rental Assistance Program administered by the Office of Temporary Disability and (2) participating in the Company’s Statewide Low Income Program (EAP) through September 1, 2022.

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. The rate settlement does not specify any requirement to file a future rate case.

On July 22, 2021, Distribution Corporation filed a supplement to its current Pennsylvania tariff proposing to reduce base rates effective October 1, 2021 by $7.7 million in order to stop collecting other post-employment benefit (“OPEB”) expenses from customers, to begin to refund to customers overcollected OPEB expenses in the amount of $50.0 million, to suspend all regulatory accounting for OPEB expenses and record the cumulative amount of OPEB income previously deferred as a regulatory liability, and to make certain other adjustments to further reduce Distribution Corporation’s regulatory liability associated with OPEB expenses. The PaPUC issued an order approving this tariff supplement on September 15, 2021 and new rates went into effect on October 1, 2021. On September 21, 2021, a complaint was filed in the proceeding. While new rates, including associated refunds, went into effect on October 1, 2021, the Company decided to wait for resolution of the complaint before suspending regulatory accounting for OPEB expenses and recording the cumulative amount of OPEB income previously deferred as a regulatory liability in its consolidated financial statements. The PaPUC assigned the matter to an Administrative Law Judge who, on January 6, 2022, issued a Recommended Decision approving a settlement reached by parties to the complaint proceeding. Under the terms of the settlement, customer refunds of overcollected OPEB expenses increased from $50.0 million to $54.0 million. The Recommended Decision was approved by the PaPUC on February 24, 2022. Accordingly, the Company suspended regulatory accounting for OPEB expenses at that time 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 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.

FERC Jurisdiction

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 may file an NGA general Section 4 rate case to change rates if the corporate federal income tax rate is increased. If no case has been filed, Supply Corporation must file for rates to be effective February 1, 2025.

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

Table of Contents

Note 12 – Leases

In October 2021, the Company executed two lease contracts for drilling rig services in Pennsylvania with lease terms of greater than one year. The first of the new lease contracts commenced in December 2021 with estimated lease payments of $8.4 million over the lease term, and the second commenced in January 2022 with estimated lease payments of $11.9 million over the lease term. Both leases have been recognized on the Consolidated Balance Sheet at June 30, 2022. A right-of-use operating lease asset of $12.6 million is recorded in Deferred Charges for both leases with the current portion of the operating lease liability ($12.4 million) recorded in Other Accruals and Current Liabilities and the noncurrent portion of the operating lease liability ($0.2 million) recorded in Other Liabilities.

Table of Contents

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 and distribution of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current development activities are focused primarily in the Marcellus and Utica shales. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian basin to markets in the eastern United States and Canada. The Company's efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas customers in the Appalachian basin. The Company reports financial results for four business segments. For a discussion of the Company's earnings, refer to the Results of Operations section below.

On 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 cash and contingent consideration valued at $12.6 million at closing. Under the terms of the purchase and sale agreement, the Company can receive up to three annual contingent payments between calendar 2023 and 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. The Company pursued this sale given the strong commodity price environment and the Company’s strategic focus in the Appalachian Basin. 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.

The Company has continued to pursue development projects to expand its Pipeline and Storage segment. One project on Supply Corporation's system, referred to as the FM100 Project, upgraded a 1950’s era pipeline in northwestern Pennsylvania and created approximately 330,000 Dth per day of additional transportation capacity in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County, Pennsylvania to the Transcontinental Gas Pipe Line Company, LLC ("Transco") system at Leidy, Pennsylvania. Construction activities on the expansion portion of the FM100 Project are complete and the project was placed in service in December 2021. This project is expected to provide incremental annual transportation revenues of approximately $50 million. The FM100 Project is discussed in more detail in the Capital Resources and Liquidity section that follows. For further discussion of the Pipeline and Storage segment's revenues and earnings, refer to the Results of Operations section below.

Seneca’s 330,000 Dth per day of incremental pipeline capacity on the Leidy South Project, which is the companion project to the Company's FM100 Project, went in service in December 2021. The incremental pipeline capacity from this project and associated gathering system development by Midstream Company allows Seneca to increase its production and reach premium Transco Zone 6 (Non-New York) markets.

On February 28, 2022, the Company entered into the Credit Agreement with a syndicate of twelve banks. The Credit Agreement replaced the previous Fourth Amended and Restated Credit Agreement and a previous 364-Day Credit Agreement. The Credit Agreement provides a $1.0 billion unsecured committed revolving credit facility with an initial 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. Under the delayed draw mechanism of the 364-Day Credit Agreement, the Company may, through September 28, 2022, make up to three elections to borrow funds under the facility, provided that the Company may extend the period to make such elections to October 28, 2022.

Table of Contents

From a financing perspective, the Company expects to use the proceeds from the sale of the Company's California assets, cash on hand and cash from operations, as well as short-term borrowings, to meet its financing needs for fiscal 2022.

The Company is closely monitoring and responding to developments related to COVID-19 and is taking steps to limit operational impacts and the potential exposure for our workforce and customers. Refer to Risk Factors in Part I, Item 1A, Risk Factors, under Operational Risks in the Company's 2021 Form 10-K for a more complete discussion of the risks to the Company associated with the COVID-19 pandemic.

CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2021 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 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 June 30, 2022, the ceiling exceeded the book value of the oil and gas properties by approximately $2.4 billion. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended June 30, 2022, based on the quoted Henry Hub spot price for natural gas, was $5.13 per MMBtu. (Note: Because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Henry Hub price, which is only indicative of 12-month average prices for the twelve months ended June 30, 2022. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) In regard to the sensitivity of the ceiling test calculation to commodity price changes, if natural gas prices were $0.25 per MMBtu lower than the average prices used at June 30, 2022 in the ceiling test calculation, the ceiling would have exceeded the book value of the Company's oil and gas properties by approximately $2.1 billion (after-tax), which would not have resulted in an impairment charge. This calculated amount is based solely on price changes and does not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

It is difficult to predict what factors could lead to future non-cash impairments under the SEC's full cost ceiling test. Fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in 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 2021 Form 10-K.

RESULTS OF OPERATIONS

Earnings

The Company's earnings were $108.2 million for the quarter ended June 30, 2022 compared to earnings of $86.5 million for the quarter ended June 30, 2021. The increase in earnings of $21.7 million is primarily the result of higher earnings in the Exploration and Production segment, Pipeline and Storage segment and Gathering segment. Lower earnings in the Utility segment and a higher loss in the Corporate category partially offset these increases.

The Company's earnings were $407.9 million for the nine months ended June 30, 2022 compared to earnings of $276.7 million for the nine months ended June 30, 2021. The increase in earnings of $131.2 million is primarily the result of higher earnings in all reportable segments, partially offset by losses in the Corporate and All Other categories.

Table of Contents

The Company's earnings for the quarter and nine months ended June 30, 2022 include the impact of several items in the Company's Exploration and Production segment related to the completion of the sale of Seneca’s California assets, as discussed above. The Company recorded a gain on the sale of these assets of $12.7 million ($9.5 million after-tax) related to a portion of the sales price that was applied to assets that were not subject to the full cost method of accounting. The Company also recorded a loss of $44.6 million ($33.3 million after-tax) related to the termination of its remaining crude oil derivative contracts as a result of the sale. In addition, the Company incurred transaction and severance costs of $9.7 million ($7.2 million after-tax) related to the California asset sale. The Company's earnings for the nine months ended June 30, 2022 include the reduction of an OPEB regulatory liability that increased earnings by $18.5 million ($14.6 million after-tax) recorded during the quarter ended March 31, 2022 in the Utility segment in accordance with a regulatory proceeding in Distribution Corporation's Pennsylvania service territory. The Company's earnings for the nine months ended June 30, 2021 included a non-cash impairment charge of $76.2 million ($55.2 million after-tax) recorded during the quarter ended December 31, 2020 for the Exploration and Production segment's oil and gas producing properties. The Company's earnings for the nine months ended June 30, 2021 also included a gain recognized on the sale of timber properties of $51.1 million ($37.0 million after-tax) recorded during the quarter ended December 31, 2020 in the Company's All Other category. 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.

Earnings (Loss) by Segment


	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2022		2021		Increase (Decrease)		2022		2021		Increase (Decrease)
Exploration and Production	$	56,497	$	39,015	$	17,482	$	189,987	$	46,213	$	143,774
Pipeline and Storage	26,599		21,948		4,651		77,236		71,060		6,176
Gathering	24,658		20,427		4,231		69,887		61,677		8,210
Utility	4,622		4,841		(219)		79,800		59,922		19,878
Total Reportable Segments	112,376		86,231		26,145		416,910		238,872		178,038
All Other	—		1,039		(1,039)		(7)		37,617		(37,624)
Corporate	(4,218)		(795)		(3,423)		(9,024)		196		(9,220)
Total Consolidated	$	108,158	$	86,475	$	21,683	$	407,879	$	276,685	$	131,194

Exploration and Production

Exploration and Production Operating Revenues


	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2022		2021		Increase (Decrease)		2022		2021		Increase (Decrease)
Gas (after Hedging)	$	256,383	$	175,378	$	81,005	$	680,670	$	524,417	$	156,253
Oil (after Hedging) (1)	40,867		33,065		7,802		112,907		93,256		19,651
Gas Processing Plant	1,016		732		284		3,029		2,056		973
Other	(45,628)		360		(45,988)		(38,178)		1,387		(39,565)
	$	252,638	$	209,535	$	43,103	$	758,428	$	621,116	$	137,312

Table of Contents

Production Volumes


	Three Months Ended June 30,			Nine Months Ended June 30,
	2022	2021	Increase (Decrease)	2022	2021	Increase (Decrease)
Gas Production (MMcf)
Appalachia	88,888	79,314	9,574	253,842	236,429	17,413
West Coast	405	431	(26)	1,210	1,300	(90)
Total Production	89,293	79,745	9,548	255,052	237,729	17,323

Oil Production (Mbbl)
Appalachia	7	1	6	8	2	6
West Coast	519	557	(38)	1,589	1,681	(92)
Total Production	526	558	(32)	1,597	1,683	(86)

Average Prices


	Three Months Ended June 30,						Nine Months Ended June 30,
	2022		2021		Increase (Decrease)		2022		2021		Increase (Decrease)
Average Gas Price/Mcf
Appalachia	$	5.50	$	2.29	$	3.21	$	4.64	$	2.25	$	2.39
West Coast	$	10.29	$	5.36	$	4.93	$	10.04	$	5.83	$	4.21
Weighted Average	$	5.52	$	2.31	$	3.21	$	4.67	$	2.27	$	2.40
Weighted Average After Hedging	$	2.87	$	2.20	$	0.67	$	2.67	$	2.21	$	0.46

Average Oil Price/Bbl
Appalachia	$	108.47	$	42.09	$	66.38	$	104.83	$	43.13	$	61.70
West Coast	$	110.79	$	67.55	$	43.24	$	94.06	$	56.92	$	37.14
Weighted Average	$	110.76	$	67.52	$	43.24	$	94.11	$	56.90	$	37.21
Weighted Average After Hedging (1)	$	77.65	$	59.22	$	18.43	$	70.71	$	55.40	$	15.31

(1)Oil revenue and weighted average oil price after hedging for the three months and nine months ended June 30, 2022 excludes a loss on discontinuance of crude oil cash flow hedges of $44,632. This loss is presented in other revenue in the table above.

2022 Compared with 2021

Operating revenues for the Exploration and Production segment increased $43.1 million for the quarter ended June 30, 2022 as compared with the quarter ended June 30, 2021. Gas production revenue after hedging increased $81.0 million due to the impact of a 9.5 Bcf increase in natural gas production, together with a $0.67 per Mcf increase in the weighted average price of natural gas after hedging. Natural gas production increased largely due to additional production from new Marcellus and Utica wells in the Appalachian region. Oil production revenue after hedging increased $7.8 million due to an increase in the weighted average price of oil after hedging of $18.43 per Bbl, partially offset by the impact of a 32 Mbbl decrease in oil production. The decrease in oil production was largely due to natural production declines. These amounts were partially offset by a decrease in other revenue of $46.0 million. The decrease in other revenue is primarily attributed to a loss on discontinuance of crude oil cash flow hedges combined with royalty shut-in payments made in accordance with lease agreements.

Operating revenues for the Exploration and Production segment increased $137.3 million for the nine months ended June 30, 2022 as compared with the nine months ended June 30, 2021. Gas production revenue after hedging increased $156.3 million due to the impact of a 17.3 Bcf increase in natural gas production combined with a $0.46 per Mcf increase in the weighted average price of natural gas after hedging. The increase in natural gas production was largely due to additional production from new Marcellus and Utica wells in the Appalachian region during the nine months ended June 30, 2022 as

Table of Contents

compared with the nine months ended June 30, 2021. Oil production revenue after hedging increased $19.7 million due to a $15.31 per Bbl increase in the weighted average price of oil after hedging, offset by the impact of an 86 Mbbl decrease in oil production. The decrease in oil production was largely due to natural production declines. These amounts were partially offset by a decrease in other revenue of $39.6 million. The decrease in other revenue was primarily attributed to a loss on discontinuance of crude oil cash flow hedges combined with royalty shut-in payments made in accordance with lease agreements. These were partially offset by a temporary capacity release for a small portion of this segment's Leidy South transportation contract and operating revenue from Highland Field Services water treatment plants acquired at the end of fiscal 2021.

The Exploration and Production segment's earnings for the quarter ended June 30, 2022 were $56.5 million, an increase of $17.5 million when compared with earnings of $39.0 million for the quarter ended June 30, 2021. The increase in earnings was due to higher natural gas production ($16.6 million), higher natural gas prices after hedging ($47.4 million), higher oil prices after hedging ($7.7 million), lower income tax expense ($3.3 million) and a gain that was recognized on the sale of Seneca's California non-full cost pool assets ($9.5 million), as discussed above. The positive earnings impact of these items was partially offset by lower oil production ($1.5 million), higher lease operating and transportation expenses ($10.1 million), higher depletion expense ($7.3 million), higher other operating expenses ($4.8 million) and higher interest expense ($2.0 million). Finally, the Company also had a loss related to discontinuance of its crude oil cash flow hedges ($33.3 million) and had transaction and severance costs ($7.2 million), all of which were driven by the sale of its California assets. The increase in lease operating and transportation expenses was primarily the result of higher gathering and transportation costs in the Appalachian region due to increased production combined with higher steam fuel costs, utilities and contract labor in the West Coast region. The increase in depletion expense was primarily due to the net increase in production combined with a $0.04 per Mcf increase in the depletion rate. The increase in other operating expenses was primarily attributed to the accrual of estimated abandonment costs related to certain offshore Gulf of Mexico wells that were formally owned by the Company. Several years ago, Seneca sold those wells to an operator that has since gone bankrupt, and, as a result of the bankruptcy, the cost of abandoning the wells will likely revert back to Seneca. The increase in interest expense can largely be attributed to a higher average amount of intercompany short-term borrowings outstanding combined with a higher average interest rate on such borrowings.

The Exploration and Production segment's earnings for the nine months ended June 30, 2022 were $190.0 million, an increase of $143.8 million when compared with earnings of $46.2 million for the nine months ended June 30, 2021. The increase in earnings was primarily attributable to an impairment of oil and gas properties ($55.2 million) recorded during the nine months ended June 30, 2021, higher natural gas production ($30.2 million), higher natural gas prices after hedging ($93.3 million), higher oil prices after hedging ($19.3 million), higher other revenue ($4.0 million), lower interest expense ($3.2 million), lower income tax expense ($3.8 million) and a gain that was recognized on the sale of Seneca's California non-full cost pool assets ($9.5 million). The Exploration and Production segment also recognized a loss in March 2021 ($10.7 million) for its share of the premium paid by the Company to redeem $500 million of the Company’s 4.90% notes that were scheduled to mature in December 2021. These increases in earnings were partially offset by lower oil production ($3.8 million), higher lease operating and transportation expenses ($17.3 million), higher depletion expense ($14.1 million), higher other operating expenses ($7.8 million) and higher other taxes ($3.1 million). Finally, the Company also had a loss related to discontinuance of its crude oil cash flow hedges ($33.3 million) and also had transaction and severance costs ($7.2 million), all of which were driven by the sale of its California assets. The decrease in interest expense can largely be attributed to a lower average amount of intercompany long-term borrowings outstanding combined with a lower average interest rate on such borrowings. The increase in lease operating and transportation expenses was primarily the result of higher gathering and transportation costs in the Appalachian region due to increased production combined with higher steam fuel costs, well workover costs and contract labor in the West Coast region. The increase in depletion expense was primarily due to the net increase in production combined with a $0.03 per Mcf increase in the depletion rate. The increase in other operating expenses was primarily attributed to the accrual of estimated abandonment costs related to certain offshore Gulf of Mexico wells formally owned by the Company, as discussed above. In addition, the increase in other operating expenses was also attributed to an increase in operating costs associated with the Highland Field Services water treatment plants acquired at the end of fiscal 2021. The increase in other taxes was mainly attributed to increased Impact Fees in the Appalachian region as a result of an increase in natural gas prices. The Impact Fees are calculated annually based on calendar year NYMEX natural gas prices.

Table of Contents

Pipeline and Storage

Pipeline and Storage Operating Revenues


	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2022		2021		Increase (Decrease)		2022		2021		Increase (Decrease)
Firm Transportation	$	74,384	$	62,886	$	11,498	$	212,468	$	191,889	$	20,579
Interruptible Transportation	442		221		221		1,298		691		607
	74,826		63,107		11,719		213,766		192,580		21,186
Firm Storage Service	21,084		20,646		438		63,334		62,351		983
Interruptible Storage Service	—		—		—		—		43		(43)
Other	(362)		310		(672)		2,195		3,558		(1,363)
	$	95,548	$	84,063	$	11,485	$	279,295	$	258,532	$	20,763

Pipeline and Storage Throughput


	Three Months Ended June 30,			Nine Months Ended June 30,
(MMcf)	2022	2021	Increase (Decrease)	2022	2021	Increase (Decrease)
Firm Transportation	175,868	174,224	1,644	601,491	586,748	14,743
Interruptible Transportation	206	181	25	1,726	1,205	521
	176,074	174,405	1,669	603,217	587,953	15,264

2022 Compared with 2021

Operating revenues for the Pipeline and Storage segment increased $11.5 million for the quarter ended June 30, 2022 as compared with the quarter ended June 30, 2021. The increase in operating revenues was primarily due to increases in transportation revenues of $11.7 million and storage revenues of $0.4 million, partially offset by a decrease in other revenue of $0.7 million. The increase in transportation revenues was primarily attributable to new demand charges for transportation service from the expansion portion of Supply Corporation's FM100 Project, which was placed into service in December 2021. This increase from the FM100 Project includes the impact of a negotiated revenue step-up to Period 2 Rates that went into effect April 1, 2022 as specified in Supply Corporation's 2020 rate case settlement. The increase in storage revenues was mainly due to the Period 2 Rates that went into effect April 1, 2022 related to the FM100 Project, as discussed above, as well as an increase in a surcharge for Pipeline Safety and Greenhouse Gas Regulatory Costs (PS/GHG Regulatory Costs) that went into effect in November 2020 associated with Supply Corporation's 2020 rate case settlement. The decrease in other revenue primarily reflects lower electric surcharge true-up revenues. Revenues collected through the electric surcharge mechanism are completely offset by electric power costs recorded in operation and maintenance expense.

Operating revenues for the Pipeline and Storage segment increased $20.8 million for the nine months ended June 30, 2022 as compared with the nine months ended June 30, 2021. The increase in operating revenues was primarily due to increases in transportation revenues of $21.2 million and storage revenues of $1.0 million, partially offset by a decrease in other revenues of $1.4 million. The increase in transportation revenues was primarily attributable to new demand charges for transportation service from Supply Corporation's FM100 Project being placed into service as mentioned above, which includes the impact of a negotiated revenue step-up to Period 2 Rates that went into effect April 1, 2022, also mentioned above. This increase was partially offset by a decline in revenues associated with miscellaneous contract terminations and revisions. In addition, the PS/GHG Regulatory Costs surcharge that went into effect in November 2020 associated with Supply Corporation’s 2020 rate case settlement also contributed to the increase in transportation revenues and was primarily responsible for the increase in storage revenues. The decrease in other revenue primarily reflects the non-recurrence of revenue associated with a contract buyout that occurred during the quarter ended December 31, 2020, combined with lower electric surcharge true-up revenues, partially offset by higher cashout revenues. Cashout revenues are completely offset by purchased gas expense.

Transportation volume for the quarter ended June 30, 2022 increased by 1.7 Bcf from the prior year's quarter ended June 30, 2021. For the nine months ended June 30, 2022, transportation volume increased by 15.3 Bcf from the prior year's

Table of Contents

nine-month period ended June 30, 2021. The increase in transportation volume for both the quarter and nine months ended June 30, 2022 primarily reflects an increase in volume from the FM100 Project, which was brought online in December 2021, as well as an increase in short-term contracts. These were partially offset by lower capacity utilization with certain contract shippers. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

The Pipeline and Storage segment’s earnings for the quarter ended June 30, 2022 were $26.6 million, an increase of $4.7 million when compared with earnings of $21.9 million for the quarter ended June 30, 2021. The increase in earnings was primarily due to the earnings impact of higher operating revenues of $9.1 million, as discussed above. These earnings increases were partially offset by an increases in operating expenses ($1.4 million), depreciation expense ($1.4 million), and income tax expense ($0.7 million). The increase in operating expenses was primarily due to higher personnel costs, vehicle fuel costs and compressor station maintenance costs. This was partially offset by lower power costs related to Empire's electric motor drive compressor station. The electric power costs are offset by an equal amount of revenue, as discussed above. The increase in depreciation expense was primarily due to incremental depreciation from Supply Corporation's FM100 Project going into service in December 2021. The increase in income tax expense was mainly attributable to higher state income taxes due to higher pre-tax earnings.

The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2022 were $77.2 million, an increase of $6.1 million when compared with earnings of $71.1 million for the nine months ended June 30, 2021. The increase in earnings was primarily due to the earnings impact of higher operating revenues of $16.4 million, as discussed above, combined with an increase in other income ($0.7 million). The increase in other income was mainly due to higher non-service pension and post-retirement benefit income partially offset by a decrease in the allowance for funds used during construction (equity component) as a result of the FM100 Project being placed in service in December 2021. These earnings increases were partially offset by increases in operating expenses ($5.9 million), depreciation expense ($2.9 million) and property taxes ($0.8 million). The increase in operating expenses was primarily due to a decrease in the reserve for preliminary project costs recorded during the nine months ended June 30, 2021 that did not recur this fiscal year, as well as an increase in personnel costs and vehicle fuel costs. This was partially offset by lower power costs related to Empire's electric motor driven compressor station. The Pipeline and Storage segment also experienced higher purchased gas costs ($0.9 million), largely related to Empire's natural gas-driven compressor stations. The electric power costs and purchased gas costs are offset by an equal amount of 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 property taxes was primarily due to school taxes related to the Empire North project's Farmington compressor station that were assessed since the project went into service.

Gathering

Gathering Operating Revenues


	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2022		2021		Increase (Decrease)		2022		2021		Increase (Decrease)
Gathering Revenues	$	55,931	$	48,656	$	7,275	$	160,759	$	145,927	$	14,832

Gathering Volume


	Three Months Ended June 30,			Nine Months Ended June 30,
	2022	2021	Increase (Decrease)	2022	2021	Increase (Decrease)
Gathered Volume - (MMcf)	109,797	91,817	17,980	314,625	275,283	39,342

2022 Compared with 2021

Operating revenues for the Gathering segment increased $7.3 million for the quarter ended June 30, 2022 as compared with the quarter ended June 30, 2021, which was driven primarily by an 18.0 Bcf increase in gathered volume. The increase in gathered volume can be attributed primarily to an increase in natural gas production on the Covington, Wellsboro, Trout Run and Clermont gathering systems, which recorded increases of 10.7 Bcf, 3.6 Bcf, 2.3 Bcf and 1.4 Bcf, respectively. The increase

Table of Contents

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 $14.8 million for the nine months ended June 30, 2022 as compared with the nine months ended June 30, 2021, which was driven primarily by a 39.3 Bcf increase in gathered volume. Contributors to the increase included the Trout Run, Clermont, Wellsboro and Covington gathering systems, which recorded increases of 16.0 Bcf, 8.7 Bcf, 8.3 Bcf and 6.3 Bcf, respectively. The increase in gathered volume can be attributed to an increase in gross natural gas production in the Appalachian region by producers connected to the aforementioned gathering systems.

The Gathering segment’s earnings for the quarter ended June 30, 2022 were $24.7 million, an increase of $4.3 million when compared with earnings of $20.4 million for the quarter ended June 30, 2021. The increase in earnings was mainly due to higher gathering revenues ($5.7 million) driven by the increase in gathered volume, as discussed above. This increase was partially offset by higher operating expenses ($0.8 million) and income tax expense ($0.3 million). The increase in operating expenses was largely attributable to higher labor and costs for materials, as well as higher outside service costs associated with preventative maintenance overhauls on the Clermont gathering system.

The Gathering segment’s earnings for the nine months ended June 30, 2022 were $69.9 million, an increase of $8.2 million when compared with earnings of $61.7 million for the nine months ended June 30, 2021. The increase in earnings was mainly due to higher gathering revenues ($11.7 million) driven by the increase in gathered volume, as discussed above. Additionally, the Gathering segment's earnings were positively impacted as a result of the Gathering segment's recognition of a loss during the quarter end March 31, 2021 ($0.7 million) for its share of the premium paid by the Company to redeem $500 million of the Company's 4.90% notes that were scheduled to mature in December 2021. The increases were partially offset by higher operating expenses ($2.2 million), depreciation expense ($1.0 million) and income tax expense ($1.0 million). The increase in operating expenses was largely attributable to higher labor costs combined with higher outside service costs associated with preventative maintenance overhauls on the Trout Run and Clermont gathering systems. The increase in depreciation expense was largely due to higher plant balances associated with the Clermont gathering system.

Utility

Utility Operating Revenues


	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands)	2022		2021		Increase (Decrease)		2022		2021		Increase (Decrease)
Retail Sales Revenues:
Residential	$	138,589	$	94,611	$	43,978	$	607,626	$	439,853	$	167,773
Commercial	17,612		10,966		6,646		84,523		57,369		27,154
Industrial	786		497		289		4,135		2,798		1,337
	156,987		106,074		50,913		696,284		500,020		196,264
Transportation	22,718		21,371		1,347		95,528		93,437		2,091

Other	243		(437)		680		(5,903)		(6,568)		665
	$	179,948	$	127,008	$	52,940	$	785,909	$	586,889	$	199,020

Table of Contents

Utility Throughput


	Three Months Ended June 30,			Nine Months Ended June 30,
(MMcf)	2022	2021	Increase (Decrease)	2022	2021	Increase (Decrease)
Retail Sales:
Residential	10,344	9,776	568	59,865	57,241	2,624
Commercial	1,511	1,369	142	8,977	8,206	771
Industrial	74	65	9	466	441	25
	11,929	11,210	719	69,308	65,888	3,420
Transportation	12,936	13,298	(362)	56,274	55,815	459

	24,865	24,508	357	125,582	121,703	3,879

Degree Days


Three Months Ended June 30,				Percent Colder (Warmer) Than
	Normal	2022	2021	Normal(1)		Prior Year(1)
Buffalo, NY	912	797	794	(12.6)	%	0.4	%
Erie, PA	871	741	741	(14.9)	%	—	%
Nine Months Ended June 30,
Buffalo, NY	6,455	5,662	5,693	(12.3)	%	(0.5)	%
Erie, PA	6,023	5,274	5,188	(12.4)	%	1.7	%

(1)Percents compare actual 2022 degree days to normal degree days and actual 2022 degree days to actual 2021 degree days.

2022 Compared with 2021

Operating revenues for the Utility segment increased $52.9 million for the quarter ended June 30, 2022 as compared with the quarter ended June 30, 2021. The increase resulted from a $50.9 million increase in retail gas sales revenue, which was primarily due to a significant increase in the cost of gas sold (per Mcf). Under its purchased gas adjustment clauses in New York and Pennsylvania, Distribution Corporation is not allowed to profit from fluctuations in gas costs. In addition, there was a $1.3 million increase in transportation revenues and a $0.7 million increase in other revenues. The increase in transportation revenues, despite a 0.4 Bcf decrease in transportation throughput, is mainly due to an increase in the system modernization tracker allocation to transportation customers. The increase in other revenues was mainly the result of higher late payment charges billed to customers.

Operating revenues for the Utility segment increased $199.0 million for the nine months ended June 30, 2022 as compared with the nine months ended June 30, 2021. The increase largely resulted from a $196.3 million increase in retail gas sales revenue, which was primarily due to a significant increase in the cost of gas sold (per Mcf). In addition, there was a $2.1 million increase in transportation revenues and a $0.7 million increase in other revenues. The increase in transportation revenues was largely due to an increase in the system modernization tracker allocation to transportation customers as well as a 0.5 Bcf increase in transportation throughput due to slightly colder weather during the nine months ended June 30, 2022. The increase in other revenues was largely due to higher late payment charges billed to customers and higher capacity release revenues.

The Utility segment’s earnings for the quarter ended June 30, 2022 were $4.6 million, a decrease of $0.2 million when compared with earnings of $4.8 million for the quarter ended June 30, 2021. The decrease in earnings was mainly attributable to higher operating expenses ($2.6 million) due to higher personnel costs, largely offset by the impact of a system modernization tracker in New York ($1.3 million). In addition, the net effect of changes resulting from the conclusion of a regulatory proceeding by the PaPUC in February 2022, resulted in a decrease to base rates related to the elimination of OPEB expenses in Pennsylvania ($1.1 million), which was more than offset by a decrease in non-service post-retirement benefit costs ($2.6 million) as Distribution Corporation's Pennsylvania service territory recognized OPEB income during the quarter ended June 30, 2022, compared to the prior year when it recognized OPEB expenses to match against the OPEB amounts collected in base rates.

Table of Contents

The impact of weather variations on earnings in the Utility segment's New York rate jurisdiction is mitigated by that 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 New York customers. For the quarter ended June 30, 2022, the WNC increased earnings by approximately $0.6 million, as the weather was warmer than normal. For the quarter ended June 30, 2021, the WNC increased earnings by approximately $1.3 million, as the weather was warmer than normal.

The Utility segment’s earnings for the nine months ended June 30, 2022 were $79.8 million, an increase of $19.9 million when compared with earnings of $59.9 million for the nine months ended June 30, 2021. The increase is primarily attributable to the conclusion of the regulatory proceeding by the PaPUC in February 2022, which resulted in a reduction in an OPEB-related regulatory liability that increased earnings ($14.6 million). The regulatory proceeding also reduced base rates in Pennsylvania, which reduced earnings for the nine-month period ($5.9 million). With the elimination of OPEB expenses in customer rates, earnings benefited from a decrease in non-service post-retirement benefit costs ($10.3 million) as Distribution Corporation's Pennsylvania service territory recognized OPEB income during the nine months ended June 30, 2022 compared to the prior year period when it recognized OPEB expenses to match against the OPEB amounts collected in base rates. Additional details related to the regulatory proceeding are discussed in the Rate Matters section below and in Item 1 at Note 11 – Regulatory Matters.

The impact of a system modernization tracker in New York ($3.7 million) and higher usage and the impact of weather on customer margins ($3.2 million) also contributed to the increase in earnings when comparing the nine months ended June 30, 2022 to the nine months ended June 30, 2021. These increases were partially offset by higher operating expenses ($4.5 million), which were primarily the result of higher personnel costs partially offset by a decrease in the allowance for uncollectible accounts, and the impact of regulatory true-up adjustments ($1.0 million). The decrease in the allowance for uncollectible accounts is related to the COVID-19 pandemic as the Company recorded incremental expense due to the potential for customer non-payment, given the economic environment, during 2021.

For the nine months ended June 30, 2022, the WNC increased earnings by approximately $4.8 million, as the weather was warmer than normal. For the nine months ended June 30, 2021, the WNC increased earnings by approximately $4.5 million, as the weather was warmer than normal.

Corporate and All Other

2022 Compared with 2021

Corporate and All Other operations had a loss of $4.2 million for the quarter ended June 30, 2022, a decrease of $4.4 million when compared with earnings of $0.2 million for the quarter ended June 30, 2021. The decrease in earnings was primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the quarter ended June 30, 2022, the Company recorded unrealized losses of $2.7 million. During the quarter ended June 30, 2021, the Company recorded unrealized gains of $0.8 million.

For the nine months ended June 30, 2022, Corporate and All Other operations had a loss of $9.0 million, a decrease of $46.8 million when compared with earnings of $37.8 million for the nine months ended June 30, 2021. The decrease in earnings was primarily attributable to the non-recurrence of a $51.1 million gain ($37.0 million gain after-tax) on sale of timber properties recorded by Seneca’s Northeast Division during the nine months ended June 30, 2021. The decrease can also be attributed to unrealized losses on investments in equity securities of $8.0 million during the nine months ended June 30, 2022 compared to unrealized gains on investments in equity securities of $0.5 million during the nine months ended June 30, 2021.

Other Income (Deductions)

Net other deductions on the Consolidated Statement of Income was $5.6 million for the quarter ended June 30, 2022, compared to net other deductions of $2.0 million for the quarter ended June 30, 2021. This change is primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the quarter ended June 30, 2022, the Company recorded pre-tax unrealized losses of $3.9 million. During the quarter ended June 30, 2021, the Company recorded pre-tax unrealized gains of $1.1 million and pre-tax realized gains of $0.7 million. Other income (deductions) was also impacted by the change in cash surrender value of life insurance policies, with the change in value for the quarter ended June 30, 2022 decreasing $0.7 million from the change in value for the quarter ended June 30, 2021, as well as a decrease in allowance for funds used during construction (equity component) of $1.2 million. This was partially offset by a decrease in

Table of Contents

non-service pension and post-retirement benefit costs of $3.7 million for the quarter ended June 30, 2022 compared to the quarter ended June 30, 2021. As discussed above in the Utility, this is largely related to the February 2022 conclusion of the regulatory proceeding in Distribution Corporation's Pennsylvania service territory that addressed Distribution Corporation's recovery of OPEB expenses.

Net other income on the Consolidated Statement of Income was $3.3 million for the nine months ended June 30, 2022, compared to net other deductions of $15.1 million for the nine months ended June 30, 2021. This change is primarily attributable to non-service pension and post-retirement benefit income of $4.5 million for the nine months ended June 30, 2022 compared to non-service pension and post-retirement benefit costs of $28.1 million for the nine months ended June 30, 2021. This is largely related to the February 2022 conclusion of a regulatory proceeding, as discussed in the previous paragraph. This was partially offset by changes in realized and unrealized gains and losses on investments in equity securities. During the nine months ended June 30, 2022, the Company recorded pre-tax realized gains of $4.4 million and pre-tax unrealized losses of $11.8 million. During the nine months ended June 30, 2021, the Company recorded pre-tax realized gains of $4.0 million and pre-tax unrealized gains of $0.6 million. Other income (deductions) was also impacted by the change in cash surrender value of life insurance policies, with the change in value for the nine months ended June 30, 2022 decreasing $1.6 million from the change in value for the nine months ended June 30, 2021, as well as a decrease in allowance for funds used during construction (equity component) of $0.6 million.

Interest Expense on Long-Term Debt

Interest expense on long-term debt on the Consolidated Statement of Income was relatively flat for the quarter ended June 30, 2022 as compared to the quarter ended June 30, 2021. For the nine months ended June 30, 2022, interest expense on long-term debt decreased $21.0 million as compared with the nine months ended June 30, 2021. The Company redeemed $500.0 million of 4.90% notes in March 2021 and paid an early redemption premium of $15.7 million that was recorded as interest expense on long-term debt. The remaining decrease is due largely to a lower weighted average interest rate on long-term debt, stemming from the Company's issuance of $500.0 million of 2.95% notes in February 2021, which replaced $500.0 million of 4.90% notes that were retired in March 2021.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary sources of cash during the nine-month period ended June 30, 2022 consisted of cash provided by operating activities, net proceeds from short-term borrowings, proceeds from the sale of a fixed income mutual fund in a grantor trust and net proceeds from the sale of oil and gas producing properties. The Company’s primary sources of cash during the nine-month period ended June 30, 2021 consisted of cash provided by operating activities, net proceeds from the sale of timber properties and net proceeds from the issuance of long-term debt.

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 2022, cash provided by operating activities is expected to increase over the amount of cash provided by operating activities when compared to the same period in 2021 and, when combined with cash on hand, will be used to fund the Company's capital expenditures. There are no scheduled repayments of long-term debt in the remainder of 2022. Looking at 2023 through 2024, based on current commodity prices, cash provided by operating activities is expected to exceed capital expenditures in each of those years, which could lead to further capital investments in the business or reductions in short-term borrowings and a net reduction in long-term debt in 2023 while still allowing the Company to meet its dividend requirements. These cash flow projections do not reflect the impact of acquisitions or divestitures that may arise in the future.

Operating Cash Flow

Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income, gains and losses associated with investing and financing activities, and changes in operating assets and liabilities. Non-cash items include depreciation, depletion and amortization, impairment of oil and gas producing properties, deferred income taxes, the reduction of an other post-retirement regulatory liability 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

Table of Contents

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

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

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

Net cash provided by operating activities totaled $654.0 million for the nine months ended June 30, 2022, a decrease of $17.8 million compared with $671.8 million provided by operating activities for the nine months ended June 30, 2021. The decrease in cash provided by operating activities primarily reflects lower cash provided by operating activities in the Utility segment, slightly offset by higher cash provided by operating activities in the Exploration and Production Segment and Gathering Segment. The decrease in the Utility segment is primarily due to lower rates in the Utility segment's Pennsylvania service territory that went into effect October 1, 2021 combined with the timing of gas cost recovery, timing of gas receivables and other regulatory true-ups. The rates that went into effect included a one-time customer bill credit of $25 million in October 2021 for previously overcollected OPEB expenses and the beginning of a 5-year pass back of an additional $29 million in previously overcollected OPEB expenses. Please refer to the Rate Matters section that follows for additional discussion of this matter. The increase in Exploration and Production segment and the Gathering segment was primarily due to higher cash receipts from natural gas production and gathering services in the Appalachian region.

Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $564.2 million during the nine months ended June 30, 2022 and $509.7 million during the nine months ended June 30, 2021. The table below presents these expenditures:


Total Expenditures for Long-Lived Assets
Nine Months Ended June 30,	2022			2021			Increase (Decrease)
(Millions)
Exploration and Production:
Capital Expenditures	$	405.7	(1)	$	263.8	(2)	$	141.9
Pipeline and Storage:
Capital Expenditures	58.2		(1)	155.5		(2)	(97.3)
Gathering:
Capital Expenditures	28.6		(1)	25.6		(2)	3.0
Utility:
Capital Expenditures	71.0		(1)	66.7		(2)	4.3
All Other:
Capital Expenditures	0.7			0.2			0.5
Eliminations	—			(2.1)			2.1
	$	564.2		$	509.7		$	54.5

(1)At June 30, 2022, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $62.0 million, $5.2 million, $2.5 million and $4.7 million, respectively, of non-cash capital expenditures. At September 30, 2021,

Table of Contents

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.

(2)At June 30, 2021, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $49.7 million, $25.8 million, $0.9 million and $5.1 million, respectively, of non-cash capital expenditures. At September 30, 2020, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $45.8 million, $17.3 million, $13.5 million and $10.7 million, respectively, of non-cash capital expenditures.

Exploration and Production

The Exploration and Production segment capital expenditures for the nine months ended June 30, 2022 were primarily well drilling and completion expenditures and included approximately $387.0 million for the Appalachian region (including $123.0 million in the Marcellus Shale area and $253.4 million in the Utica Shale area) and $18.7 million for the West Coast region. These amounts included approximately $130.8 million spent to develop proved undeveloped reserves. The Exploration and Production segment's capital expenditures for fiscal 2022 are expected to be in the range of $525 million to $550 million.

The Exploration and Production segment capital expenditures for the nine months ended June 30, 2021 were primarily well drilling and completion expenditures and included approximately $255.8 million for the Appalachian region (including $79.8 million in the Marcellus Shale area and $155.6 million in the Utica Shale area) and $8.0 million for the West Coast region. These amounts included approximately $68.5 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2022 were primarily for additions, improvements and replacements to this segment's transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2022 included expenditures related to Supply Corporation's FM100 Project ($23.0 million), which is discussed below. The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2021 were primarily for expenditures related to Supply Corporation's FM100 Project ($115.4 million). In addition, the Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2021 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 completed and continue to pursue expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines and to on-system markets, and markets beyond the Supply Corporation and Empire pipeline systems.

Supply Corporation has developed its FM100 Project, which upgraded a 1950's era pipeline in northwestern Pennsylvania and created approximately 330,000 Dth per day of additional transportation capacity in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County to the Transcontinental Gas Pipe Line Company, LLC (“Transco”) system at Leidy, Pennsylvania. Supply Corporation and Transco executed a precedent agreement whereby Transco has leased this additional capacity ("Lease") as part of a Transco expansion project ("Leidy South"), creating incremental transportation capacity to Transco Zone 6 (Non-New York) markets. Seneca is an anchor shipper on Leidy South, which provides it with an outlet to premium markets from both its Eastern and Western development areas. Construction activities on the expansion portion of the FM100 project are complete and the project commenced partial in-service on December 1, 2021, with full in-service on December 19, 2021. Abandonment activities on the project will continue in calendar year 2022. As of June 30, 2022, approximately $209.2 million has been spent on the FM100 project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at June 30, 2022.

Supply Corporation and Empire have developed a project which would move significant prospective Marcellus and Utica production from Seneca's Western Development Area at Clermont to an Empire interconnection with the TC Energy pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York (the “Northern Access project”). The Northern Access project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. On February 3, 2017, the Company received FERC approval of the project. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). Subsequently, FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean

Table of Contents

Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order, and FERC's decisions were appealed. The Second Circuit Court of Appeals issued an order upholding the FERC waiver orders. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project and, on June 29, 2022, received an extension of time from FERC, until December 31, 2024, to construct the project. The Company 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 June 30, 2022, approximately $55.8 million has been spent on the Northern Access project, including $24.2 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 June 30, 2022.

Gathering

The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2022 included expenditures related to the continued expansion of Midstream Company's Clermont and Covington gathering systems, as discussed below. Midstream Company spent $13.4 million and $12.9 million, respectively, during the nine months ended June 30, 2022 on the development of the Clermont and Covington gathering systems. These expenditures were largely attributable to the installation of new in-field gathering pipelines in the Clermont gathering system, as well as the development of new gathering facilities, including new in-field gathering pipelines and station upgrades, in the Tioga gathering system, which is part of Midstream Covington.

The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2021 were for the continued expansion of Midstream Company's Clermont and Wellsboro gathering systems. Midstream Company spent $15.1 million and $3.7 million, respectively, during the nine months ended June 30, 2021 on the development of the Clermont and Wellsboro gathering systems. These expenditures were largely attributable to new Clermont gathering pipelines, as well as the continued development of centralized station facilities, including increased compression horsepower at the Clermont and Wellsboro gathering systems and additional dehydration on the Clermont gathering system.

NFG Midstream Clermont, LLC, a wholly-owned subsidiary of Midstream Company, continues to develop an extensive gathering system with compression in the Pennsylvania counties of McKean, Elk and Cameron. The Clermont gathering system was initially placed in service in July 2014. The current system consists of three compressor stations and backbone and in-field gathering pipelines. The total cost estimate for the continued buildout will be dependent on the nature and timing of Seneca's long-term plans.

NFG Midstream Covington, LLC, a wholly-owned subsidiary of Midstream Company, operates its Covington gathering system as well as the Tioga gathering system acquired from Shell on July 31, 2020, both in Tioga County, Pennsylvania. The current Covington gathering system consists of two compressor stations and backbone and in-field gathering pipelines. The Tioga gathering system consists of 13 compressor stations and backbone and in-field gathering pipelines.

NFG Midstream Wellsboro, LLC, a wholly-owned subsidiary of Midstream Company, continues to develop its Wellsboro gathering system in Tioga County, Pennsylvania. The current system consists of one compressor station and backbone and in-field gathering pipelines.

Utility

The majority of the Utility segment capital expenditures for the nine months ended June 30, 2022 and June 30, 2021 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions. The Utility segment's capital expenditures for fiscal 2022 are expected to be in the range of $100 million to $110 million.

Other Investing Activities

On December 10, 2020, the Company completed the sale of substantially all timber properties in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme Allegheny Land Company II LLC for net proceeds of $104.6 million. After purchase price adjustments and transaction costs, a gain of $51.1 million was recognized on the sale of these assets ($37.0 million after-tax). The sale of the timber properties completed a reverse like-kind exchange pursuant to Section 1031 of the Internal Revenue Code, as amended (“Reverse 1031 Exchange”). On July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from Shell for total consideration of $506.3 million.

Table of Contents

The purchase and sale agreement with Shell was structured, in part, as a Reverse 1031 Exchange. Refer to Item 8, Note B – Asset Acquisitions and Divestitures, of the Company’s 2021 Form 10-K for additional information concerning the Company’s acquisition of certain upstream assets and midstream gathering assets from Shell.

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. 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.

Project Funding

Over the past two years, the Company has been financing capital expenditures with cash from operations, short-term and long-term debt, common stock, and proceeds from the sale of timber properties. During the nine months ended June 30, 2022 and June 30, 2021, capital expenditures were funded with cash from operations and short-term debt. The Company issued long-term debt and common stock in June 2020 to help finance the acquisition of upstream assets and midstream gathering assets from Shell. The financing of the asset acquisition from Shell was completed in December 2020 when the Company completed the sale of substantially all of its timber properties, through the completion of the Reverse 1031 Exchange discussed above. Going forward, the Company expects to use cash on hand, cash from operations, short-term borrowings and proceeds from the sale of the Company's California assets to finance capital expenditures. The level of short-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be most impacted by the timing of gas cost recovery in the Utility segment. It will also depend on natural gas production, and the associated commodity price realizations, as well as the level of hedging collateral deposits in the Exploration and Production segment.

The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, quicker development of existing oil and gas properties, natural gas storage and transmission facilities, natural gas gathering and compression facilities and the expansion of natural gas transmission line capacities, regulated utility assets and other opportunities as they may arise. 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 and regulatory conditions.

Financing Cash Flow

Consolidated short-term debt increased $241.5 million, to a total of $400.0 million, when comparing the balance sheet at June 30, 2022 to the balance sheet at September 30, 2021. The maximum amount of short-term debt outstanding during the nine months ended June 30, 2022 was $675.4 million. In addition to cash provided by operating activities, the Company

Table of Contents

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, 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, elevated commodity prices relative to its existing portfolio of derivative financial instruments led to the Company posting margin of $154.5 million with a number of its derivative counterparties as of June 30, 2022. The maximum amount of margin posted during the nine months ended June 30, 2022 was $464.2 million. The Company's margin deposits are reflected on the balance sheet as a current asset titled Hedging Collateral Deposits. To meet these margin requirements and other near-term cash flow needs, the Company utilized short-term debt in the form of commercial paper and borrowings under its revolving credit facility.

As of June 30, 2022, the Company had short-term notes payable to banks of $400.0 million. The Company did not have any commercial paper outstanding at June 30, 2022. On June 30, 2022, the Company received $240.9 million in proceeds, after customary closing adjustments, related to the sale of the Company's California assets. Subsequent to June 30, 2022, these proceeds were used to reduce the amount of short-term notes payable to banks.

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

The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed .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 June 30, 2022, $190.7 million was added back to the Company's total capitalization for purposes of the calculation under the Credit Agreement. On May 3, 2022, the Company entered into Amendment No. 1 to the Credit Agreement with the same twelve banks under the initial Credit Agreement. The amendment further modifies the definition of consolidated capitalization, for purposes of calculating the debt to capitalization ratio under the Credit Agreement, to exclude, beginning with the quarter ended June 30, 2022, all unrealized gains or losses on commodity-related derivative financial instruments and up to $10 million in unrealized gains or losses on other derivative financial instruments included in Accumulated Other Comprehensive Income (Loss) within Total Comprehensive Shareholders' Equity on the Company's balance sheet. Under the Credit Agreement, such unrealized losses will not negatively affect the calculation of the debt to capitalization ratio, and such unrealized gains will not positively affect the calculation. At June 30, 2022, the Company’s debt to capitalization ratio, as calculated under the Credit Agreement, was .53. The constraints specified in the Credit Agreement would have permitted an additional $1.99 billion in short-term and/or long-term debt to be outstanding at June 30, 2022 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.

The Credit Agreement contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other

Table of Contents

borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.

On February 24, 2021, the Company issued $500.0 million of 2.95% notes due March 1, 2031. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $495.3 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of both a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to adjustment from time to time, with a maximum adjustment of 2.00%, such that the coupon will not exceed 4.95%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes to a rating below investment grade. A downgrade with a resulting increase to the coupon does not preclude the coupon from returning to its original rate if the Company's credit rating is subsequently upgraded. The proceeds of this debt issuance were used for general corporate purposes, including the redemption of $500.0 million of the Company's 4.90% notes on March 11, 2021 that were scheduled to mature in December 2021. The Company redeemed those notes for $515.7 million, plus accrued interest.

The Current Portion of Long-Term Debt at June 30, 2022 consists of $500.0 million of 3.75% notes and $49.0 million of 7.395% notes that mature in March 2023. None of the Company's long-term debt as of September 30, 2021 had a maturity date within the following twelve-month period.

The Company’s embedded cost of long-term debt was 4.48% at both June 30, 2022 and June 30, 2021.

Under the Company’s existing indenture covenants at June 30, 2022, the Company would have been permitted to issue up to a maximum of approximately $1.89 billion in additional unsubordinated long-term indebtedness at then current market interest rates, in addition to being able to issue new indebtedness to replace existing debt (further limited by 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. It is possible, depending on amounts reported in various income statement and balance sheet line items, that the indenture covenants could, for a period of time, prevent the Company from issuing incremental unsubordinated long-term debt, or significantly limit the amount of such debt that could be issued. Losses incurred as a result of significant impairments of oil and gas properties have in the past resulted in such temporary restrictions. The indenture covenants would not preclude the Company from issuing new long-term debt to replace existing long-term debt, or from issuing additional short-term debt. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

The Company’s 1974 indenture pursuant to which $99.0 million (or 3.7%) of the Company’s long-term debt (as of June 30, 2022) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

OTHER MATTERS

In addition to the legal proceedings disclosed in Part II, Item 1 of this report, the Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations or other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these normal-course matters could have a material effect on earnings and cash flows in the period in which they are resolved, they are not expected to change materially the Company’s present liquidity position, nor are they expected to have a material adverse effect on the financial condition of the Company.

During the nine months ended June 30, 2022, the Company contributed $19.3 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $2.7 million to its VEBA trusts for its other post-retirement benefits. In the remainder of 2022, the Company expects to contribute approximately $1.1 million to its Retirement Plan. In the remainder of 2022, the Company expects to contribute approximately $0.2 million to its VEBA trusts.

Table of Contents

The Company, in its Exploration and Production segment, entered into contractual obligations for the nine months ended June 30, 2022 to spend $67.3 million for hydraulic fracturing services work through June 1, 2024.

Market Risk Sensitive Instruments

On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act required the CFTC, SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation, and includes provisions related to the swaps and over-the-counter derivatives markets that are designed to promote transparency, mitigate systemic risk and protect against market abuse. Although regulators have issued certain regulations, other rules that may impact the Company have yet to be finalized. Rules developed by the CFTC and other regulators 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. Additionally, given the enforcement 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 our business. Should the Company violate any laws or regulations applicable to our hedging activities, it could be subject to CFTC enforcement action and material penalties and sanctions. The Company 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.

The authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At June 30, 2022, the Company determined that nonperformance risk associated with its natural gas price swap agreements, natural gas no cost collars and foreign currency contracts would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

For a complete discussion of all other market risk sensitive instruments used by the Company, refer to “Market Risk Sensitive Instruments” in Item 7 of the Company’s 2021 Form 10-K.

Rate Matters

Utility Operation

Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” Neither the New York or Pennsylvania divisions currently have a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.

New York Jurisdiction

In response to the COVID-19 pandemic, various legislative actions and NYPSC Staff requests resulted in the Company suspending service terminations and disconnections. All legislative prohibitions have expired and the Company has agreed to refrain from terminating residential customers (1) with a pending application for arrears payments through the Emergency Rental Assistance Program administered by the Office of Temporary Disability and (2) participating in the Company’s Statewide Low Income Program (EAP) through September 1, 2022.

Table of Contents

Pennsylvania Jurisdiction

Pipeline and Storage

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

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory requirements. In March 2021, the Company set greenhouse gas reduction targets associated with the Company's utility delivery system. To further our ongoing efforts to lower the Company's emissions profile, in September 2021 the Company also established methane intensity reduction targets at each of its businesses, as well as an absolute greenhouse gas emissions reduction target for the consolidated Company. 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 8 — Commitments and Contingencies under the heading “Environmental Matters.”

Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or implementation in the United States. These efforts include legislation, legislative proposals and new regulations at the state and federal level, and private party litigation related to greenhouse gas emissions. The U.S. Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA regulates greenhouse gas emissions pursuant to the Clean Air Act. The regulations implemented by EPA impose stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. The Company must continue to comply with all applicable regulations. Additionally, other federal regulatory agencies are beginning to address greenhouse gas emissions through changes

Table of Contents

in their regulatory oversight approach and policies. A number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. In New York, 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 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. NYDEC finalized its Part 203 Oil and Gas Sector Rule in March 2022, which establishes monitoring, operational, and reporting requirements with respect to methane and volatile organic compound emissions and significantly increases leak detection and repair (LDAR) inspections, repair and replacement obligations, recordkeeping, reporting, and notification requirements for multiple sources along natural gas metering and regulating stations, transmission pipelines, compressor stations, storage facilities, and gathering lines. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines and is in the process of evaluating cap-and-trade programs (e.g., Regional Greenhouse Gas Initiative). 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. The above-enumerated initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources.

Effects of Inflation

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

Safe Harbor for Forward-Looking Statements

The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new authoritative accounting and reporting guidance, and possible outcomes of litigation or regulatory proceedings, as well as statements that are identified by the use of the words “anticipates,” “estimates,” “expects,” “forecasts,” “intends,” “plans,” “predicts,” “projects,” “believes,” “seeks,” “will,” “may,” and similar expressions, are “forward-looking statements” as defined in the Private Securities Litigation Reform Act of 1995 and accordingly involve risks and uncertainties which could cause actual results or outcomes to differ materially from those expressed in the forward-looking statements. The Company’s expectations, beliefs and projections are expressed in good faith and are believed by the Company to have a reasonable basis, but there can be no assurance that management’s expectations, beliefs or projections will result or be achieved or accomplished. In addition to other factors and matters discussed elsewhere herein, the following are important factors that, in the view of the Company, could cause actual results to differ materially from those discussed in the forward-looking statements:

Table of Contents

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

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

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

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

5.Changes in economic conditions, including inflationary pressures 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.The length and severity of the ongoing COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity;

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

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

11.Increased costs or delays or changes in plans with respect to Company projects or related projects of other companies, including disruptions due to the COVID-19 pandemic, as well as difficulties or delays in obtaining necessary governmental approvals, permits or orders or in obtaining the cooperation of interconnecting facility operators;

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

13.The Company's ability to successfully integrate acquired assets and achieve expected cost synergies;

14.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;

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

16.Factors affecting the Company’s ability to successfully identify, drill for and produce economically viable natural gas 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;

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

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

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

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

21.Uncertainty of gas reserve estimates;

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

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

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

Table of Contents

25.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;

26.Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of war;

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

28.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.

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 June 30, 2022.

Changes in Internal Control Over Financial Reporting

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended June 30, 2022 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

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

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

Item 1A. Risk Factors

The risk factors in Item 1A of the Company’s 2021 Form 10-K have not materially changed other than as set forth below. The risk factors presented below superseded the risk factors having the same caption in the 2021 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2021 Form 10-K.

STRATEGIC RISKS

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

Table of Contents

Climate change, and the laws, regulations and other initiatives to address climate change, may impact the Company’s financial results. In early 2021, the U.S. rejoined the Paris Agreement, the international effort to establish emissions reduction goals for signatory countries. Under the Paris Agreement, signatory countries are expected to submit their nationally determined contributions to curb greenhouse gas emissions and meet the agreed temperature objectives every five years. On April 22, 2021, the federal administration announced the U.S. nationally determined contribution to achieve a fifty to fifty-two percent reduction from 2005 levels in economy-wide net greenhouse gas pollution by 2030. In addition to the federal reentry into the Paris Agreement, state and local governments, non-governmental organizations, and financial institutions have made, and will likely continue to make, more aggressive efforts to reduce emissions and advance the objectives of the Paris Agreement. Executive orders from the federal administration, in addition to federal, state and local legislative and regulatory initiatives proposed or adopted in an attempt to limit the effects of climate change, including greenhouse gas emissions, could have significant impacts on the energy industry including government-imposed limitations, prohibitions or moratoriums on the use and/or production of gas, establishment of a carbon tax and/or methane fee, lack of support for system modernization, as well as accelerated depreciation of assets and/or stranded assets. For example, the U.S. Congress has from time to time considered bills that would establish a cap-and-trade program, methane fee or carbon tax to reduce emissions of greenhouse gases. A number of states have adopted energy strategies or plans with goals that include the reduction of greenhouse gas emissions. For example, Pennsylvania has a methane reduction framework for the natural gas industry which has resulted in permitting changes with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. In addition, the NYPSC initiated a proceeding to consider climate-related financial disclosures at the utility operating level, and in 2019, the New York State legislature passed the CLCPA, which created emission reduction and electric generation mandates, and could ultimately impact the Utility segment’s customer base and business. Pursuant to the CLCPA, New York's Climate Action Council issued for comment a draft scoping plan that includes recommendations to decommission substantial portions of the natural gas system and curtail use of natural gas and natural gas appliances. The New York State legislature, in early 2021, proposed a bill known as the Climate and Community Investment Act, which proposed an escalating fee starting at $55 per short ton of carbon dioxide equivalent on any carbon-based fuels sold, used or brought into the state. That bill did not pass, but it, or something similar to it, may be proposed in the future. Legislation or regulation that aims to reduce greenhouse gas emissions could also include gas bans, greenhouse gas emissions limits and reporting requirements, carbon taxes and/or similar fees on carbon dioxide, methane or equivalent emissions, restrictive permitting, increased efficiency standards requiring system remediation and/or changes in operating practices, and incentives or mandates to conserve energy or use renewable energy sources. NYDEC finalized its Part 203 Oil and Gas Sector Rule in March 2022, which significantly increases leak detection and repair (LDAR) inspections, recordkeeping, reporting, and notification requirements for multiple sources along city gates, transmission pipelines, compressor stations, storage facilities, and gathering lines. Additionally, the trend toward increased energy conservation, change in consumer behaviors, competition from renewable energy sources, and technological advances to address climate change may reduce the demand for natural gas. For further discussion of the risks associated with environmental regulation to address climate change, refer to Item 2, MD&A under the heading “Environmental Matters.”

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

OPERATIONAL RISKS

Disputes with collective bargaining units representing the Company’s workforce, and work stoppage (e.g. strike or lockout), could adversely affect the Company’s operations as well as its financial results.

Approximately half of the Company’s active workforce is represented by collective bargaining units in New York and Pennsylvania. These labor agreements are negotiated periodically, and therefore, the Company is subject to the risk that such agreements may not be able to be renewed on reasonably satisfactory terms, on anticipated timelines, or at all. In connection with the negotiation of such collective bargaining agreements, or in future matters involving collective bargaining units representing the Company’s workforce, the Company could experience, among other things, strikes, work stoppages, slowdowns or lockouts, which could cause a disruption of the Company's operations and have a material adverse effect on the Company's results of operations and financial condition.

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

On April 1, 2022, the Company issued a total of 6,260 unregistered shares of Company common stock to non-employee directors of the Company then serving on the Board of Directors of the Company (or, in the case of non-employee directors who elected to defer receipt of such shares pursuant to the Company's Deferred Compensation Plan for Directors and

Table of Contents

Officers (the “DCP”), to the DCP trustee), consisting of 626 shares per director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan (the “2009 Plan”) as partial consideration for such directors’ services during the quarter ended June 30, 2022. On April 14, 2022, the Company issued to the DCP trustee an additional 210 unregistered shares pursuant to the dividend reinvestment feature of the DCP, consisting of approximately 35 shares for each of the six directors who made a deferral election. These transactions were exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as transactions not involving a public offering.

Issuer Purchases of Equity Securities


Period	Total Number of Shares Purchased (a)	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under Share Repurchase Plans or Programs (b)
Apr. 1 - 30, 2022	9,147	$69.47	—	6,971,019
May 1 - 31, 2022	9,278	$73.20	—	6,971,019
June 1 - 30, 2022	14,101	$71.03	—	6,971,019
Total	32,526	$71.22	—	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 tendered to the Company by holders of stock-based compensation awards for the payment of applicable withholding taxes. During the quarter ended June 30, 2022, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 32,526 shares purchased other than through a publicly announced share repurchase program, 27,178 were purchased for the Company's 401(k) plans and 5,348 were purchased as a result of shares tendered to the Company by holders of stock-based compensation awards.

(b)In September 2008, the Company’s Board of Directors authorized the repurchase of eight million shares of the Company’s common stock. The Company has not repurchased any shares since September 17, 2008. The repurchase program has no expiration date and management would discuss with the Company's Board of Directors any future repurchases under this program.

Item 6. Exhibits


Exhibit Number						Description of Exhibit

•						National Fuel Gas Company By-Laws as amended and restated June 15, 2022 (Exhibit 3.1, Form 8-K dated June 17, 2022).

•						Amendment No. 1 to Credit Agreement, dated as of May 3, 2022, among the Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (Exhibit 10.1, Form 10-Q dated May 6, 2022).

•						364-Day Credit Agreement, dated as of June 30, 2022, among the Company, the Lenders party thereto, and Wells Fargo Bank, National Association, as Administrative Agent (Exhibit 10.1, Form 8-K dated July 1, 2022).

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 June 30, 2022 and 2021.

101						Interactive data files submitted pursuant to Regulation S-T, formatted in Inline XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income and Earnings Reinvested in the Business for the three and nine months ended June 30, 2022 and 2021, (ii) the Consolidated Statements of Comprehensive Income for the three and nine months ended June 30, 2022 and 2021, (iii) the Consolidated Balance Sheets at June 30, 2022 and September 30, 2021, (iv) the Consolidated Statements of Cash Flows for the nine months ended June 30, 2022 and 2021 and (v) the Notes to Condensed Consolidated Financial Statements.

Table of Contents


Exhibit Number						Description of Exhibit

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

•						Incorporated herein by reference as indicated.

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

Table of Contents

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/ K. M. Camiolo
K. M. Camiolo
Treasurer and Principal Financial Officer





/s/ E. G. Mendel
E. G. Mendel
Controller and Principal Accounting Officer

Date: August 5, 2022