National Fuel Gas - 10-Q quarterly report FY2021 Q2

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2021

☐ 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 April 30, 2021: 91,172,701 shares.

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GLOSSARY OF TERMS

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


National Fuel Gas Companies
Company			The Registrant, the Registrant and its subsidiaries or the Registrant’s subsidiaries as appropriate in the context of the disclosure
Distribution Corporation			National Fuel Gas Distribution Corporation
Empire			Empire Pipeline, Inc.
Midstream Company			National Fuel Gas Midstream Company, LLC
National Fuel			National Fuel Gas Company
NFR			National Fuel Resources, Inc.
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
2020 Form 10-K			The Company’s Annual Report on Form 10-K for the year ended September 30, 2020
2017 Tax Reform Act			Tax legislation referred to as the "Tax Cuts and Jobs Act," enacted December 22, 2017.
Bbl			Barrel (of oil)
Bcf			Billion cubic feet (of natural gas)
Bcfe (or Mcfe) – represents Bcf (or Mcf) Equivalent			The total heat value (Btu) of natural gas and oil expressed as a volume of natural gas. The Company uses a conversion formula of 1 barrel of oil = 6 Mcf of natural gas.
Btu			British thermal unit; the amount of heat needed to raise the temperature of one pound of water one degree Fahrenheit
Capital expenditure			Represents additions to property, plant, and equipment, or the amount of money a company spends to buy capital assets or upgrade its existing capital assets.
Cashout revenues			A cash resolution of a gas imbalance whereby a customer (e.g. a marketer) pays for gas the customer receives in excess of amounts delivered into pipeline/storage or distribution systems by the customer’s shipper.
CLCPA			Legislation referred to as the "Climate Leadership & Community Protection Act," enacted by the State of New York on July 18, 2019.
Degree day			A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.

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

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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.
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.
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.

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INDEX						Page

Part I. Financial Information

Item 1. Financial Statements (Unaudited)						6

a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Six Months Ended March 31, 2021 and 2020						6
b. Consolidated Statements of Comprehensive Income – Three and Six Months Ended March 31, 2021 and 2020						7
c. Consolidated Balance Sheets – March 31, 2021 and September 30, 2020						8
d. Consolidated Statements of Cash Flows – Six Months Ended March 31, 2021 and 2020						10
e. Notes to Condensed Consolidated Financial Statements						11
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations						29
Item 3. Quantitative and Qualitative Disclosures About Market Risk						49
Item 4. Controls and Procedures						50

Part II. Other Information

Item 1. Legal Proceedings						50
Item 1 A. Risk Factors						50
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds						53
Item 3. Defaults Upon Senior Securities						•
Item 4. Mine Safety Disclosures						•
Item 5. Other Information						•
Item 6. Exhibits						54
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.

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Part I. Financial Information

Item 1. Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)


	Three Months Ended March 31,				Six Months Ended March 31,
(Thousands of U.S. Dollars, Except Per Common Share Amounts)	2021		2020		2021		2020
INCOME
Operating Revenues:
Utility and Energy Marketing Revenues	$	270,849	$	282,634	$	460,315	$	510,660
Exploration and Production and Other Revenues	220,281		156,542		412,316		323,735
Pipeline and Storage and Gathering Revenues	59,985		51,919		119,644		100,888
	551,115		491,095		992,275		935,283

Operating Expenses:
Purchased Gas	106,661		118,270		158,280		210,542
Operation and Maintenance:
Utility and Energy Marketing	52,058		51,725		96,944		94,981
Exploration and Production and Other	41,895		39,959		83,922		76,652
Pipeline and Storage and Gathering	28,133		27,305		56,231		53,190
Property, Franchise and Other Taxes	23,987		22,743		46,768		45,887
Depreciation, Depletion and Amortization	84,342		77,912		167,462		152,830
Impairment of Oil and Gas Producing Properties	—		177,761		76,152		177,761
	337,076		515,675		685,759		811,843
Gain on Sale of Timber Properties	—		—		51,066		—
Operating Income (Loss)	214,039		(24,580)		357,582		123,440
Other Income (Expense):

Other Income (Deductions)	(10,875)		(17,480)		(13,051)		(20,520)
Interest Expense on Long-Term Debt	(48,820)		(25,270)		(81,076)		(50,713)
Other Interest Expense	(1,698)		(1,892)		(3,618)		(3,443)
Income (Loss) Before Income Taxes	152,646		(69,222)		259,837		48,764
Income Tax Expense	40,210		36,846		69,627		68,241

Net Income (Loss) Available for Common Stock	112,436		(106,068)		190,210		(19,477)

EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	1,028,844		1,320,592		991,630		1,272,601
	1,141,280		1,214,524		1,181,840		1,253,124

Dividends on Common Stock	(40,562)		(37,654)		(81,122)		(75,304)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	—		—		—		(950)



Balance at March 31	$	1,100,718	$	1,176,870	$	1,100,718	$	1,176,870

Earnings (Loss) Per Common Share:
Basic:
Net Income (Loss) Available for Common Stock	$	1.23	$	(1.23)	$	2.09	$	(0.23)
Diluted:
Net Income (Loss) Available for Common Stock	$	1.23	$	(1.23)	$	2.08	$	(0.23)
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	91,163,291		86,561,066		91,084,620		86,469,258
Used in Diluted Calculation	91,645,679		86,561,066		91,581,918		86,469,258
Dividends Per Common Share:
Dividends Declared	$	0.445	$	0.435	$	0.890	$	0.870

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)


	Three Months Ended March 31,				Six Months Ended March 31,
(Thousands of U.S. Dollars)	2021		2020		2021		2020
Net Income (Loss) Available for Common Stock	$	112,436	$	(106,068)	$	190,210	$	(19,477)
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(34,373)		76,304		13,648		76,799
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	3,666		(25,034)		3,977		(32,386)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	—		—		—		1,313

Other Comprehensive Income (Loss), Before Tax	(30,707)		51,270		17,625		45,726
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(9,470)		20,854		3,760		20,974
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	1,010		(6,817)		1,096		(8,849)
Income Tax Benefit (Expense) on Cumulative Effect of Adoption of Authoritative Guidance for Hedging	—		—		—		363


Income Taxes – Net	(8,460)		14,037		4,856		12,488
Other Comprehensive Income (Loss)	(22,247)		37,233		12,769		33,238
Comprehensive Income (Loss)	$	90,189	$	(68,835)	$	202,979	$	13,761

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	March 31, 2021		September 30, 2020
(Thousands of U.S. Dollars)
ASSETS
Property, Plant and Equipment	$	12,648,604	$	12,351,852
Less - Accumulated Depreciation, Depletion and Amortization	6,572,534		6,353,785
	6,076,070		5,998,067
Assets Held for Sale, Net	—		53,424
Current Assets
Cash and Temporary Cash Investments	80,467		20,541

Receivables – Net of Allowance for Uncollectible Accounts of $30,128 and $22,810, Respectively	229,479		143,583
Unbilled Revenue	32,685		17,302
Gas Stored Underground	5,745		33,338
Materials, Supplies and Emission Allowances	52,212		51,877
Unrecovered Purchased Gas Costs	479		—
Other Current Assets	56,117		47,557
	457,184		314,198

Other Assets
Recoverable Future Taxes	117,300		118,310
Unamortized Debt Expense	11,443		12,297
Other Regulatory Assets	147,099		156,106
Deferred Charges	60,454		67,131
Other Investments	147,421		154,502
Goodwill	5,476		5,476
Prepaid Post-Retirement Benefit Costs	89,101		76,035
Fair Value of Derivative Financial Instruments	4,104		9,308
Other	—		81
	582,398		599,246

Total Assets	$	7,115,652	$	6,964,935

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	March 31, 2021		September 30, 2020
(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 – 91,163,797 Shares and 90,954,696 Shares, Respectively	$	91,164	$	90,955
Paid in Capital	1,009,075		1,004,158
Earnings Reinvested in the Business	1,100,718		991,630
Accumulated Other Comprehensive Loss	(101,988)		(114,757)
Total Comprehensive Shareholders’ Equity	2,098,969		1,971,986
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,627,033		2,629,576
Total Capitalization	4,726,002		4,601,562

Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	—		30,000

Accounts Payable	107,305		134,126
Amounts Payable to Customers	19,768		10,788
Dividends Payable	40,562		40,475
Interest Payable on Long-Term Debt	17,663		27,521
Customer Advances	—		15,319
Customer Security Deposits	19,503		17,199
Other Accruals and Current Liabilities	176,940		140,176
Fair Value of Derivative Financial Instruments	21,231		43,969
	402,972		459,573

Deferred Credits
Deferred Income Taxes	763,441		696,054
Taxes Refundable to Customers	355,375		357,508

Cost of Removal Regulatory Liability	237,867		230,079
Other Regulatory Liabilities	177,685		161,573
Pension and Other Post-Retirement Liabilities	118,804		127,181
Asset Retirement Obligations	192,127		192,228
Other Deferred Credits	141,379		139,177
	1,986,678		1,903,800
Commitments and Contingencies (Note 8)	—		—

Total Capitalization and Liabilities	$	7,115,652	$	6,964,935

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)


	Six Months Ended March 31,
(Thousands of U.S. Dollars)	2021		2020
OPERATING ACTIVITIES
Net Income (Loss) Available for Common Stock	$	190,210	$	(19,477)
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:
Gain on Sale of Timber Properties	(51,066)		—
Impairment of Oil and Gas Producing Properties	76,152		177,761
Depreciation, Depletion and Amortization	167,462		152,830
Deferred Income Taxes	61,408		104,883

Premium Paid on Early Redemption of Debt	15,715		—
Stock-Based Compensation	8,657		7,580
Other	6,742		9,800
Change in:
Receivables and Unbilled Revenue	(101,159)		(58,248)
Gas Stored Underground and Materials, Supplies and Emission Allowances	27,258		20,086
Unrecovered Purchased Gas Costs	(479)		2,246
Other Current Assets	(8,447)		(3,134)
Accounts Payable	8,613		(5,465)
Amounts Payable to Customers	8,980		13,196
Customer Advances	(15,319)		(12,429)
Customer Security Deposits	2,304		(1,211)
Other Accruals and Current Liabilities	9,058		9,076
Other Assets	11,039		(10,359)
Other Liabilities	5		3,857
Net Cash Provided by Operating Activities	417,133		390,992

INVESTING ACTIVITIES
Capital Expenditures	(338,867)		(395,486)

Net Proceeds from Sale of Timber Properties	104,582		—

Other	12,095		4,167
Net Cash Used in Investing Activities	(222,190)		(391,319)

FINANCING ACTIVITIES
Changes in Notes Payable to Banks and Commercial Paper	(30,000)		174,800

Net Proceeds from Issuance of Long-Term Debt	495,267		—
Reduction of Long-Term Debt	(515,715)		—
Dividends Paid on Common Stock	(81,035)		(75,197)
Net Repurchases of Common Stock	(3,534)		(4,153)
Net Cash Provided by (Used in) Financing Activities	(135,017)		95,450
Net Increase in Cash, Cash Equivalents, and Restricted Cash	59,926		95,123
Cash, Cash Equivalents, and Restricted Cash at October 1	20,541		27,260
Cash, Cash Equivalents, and Restricted Cash at March 31	$	80,467	$	122,383

Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$	68,073	$	59,490

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 – Summary of Significant Accounting Policies

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

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

Earnings for Interim Periods. The Company, in its opinion, has included all adjustments (which consist of only normally recurring adjustments, unless otherwise disclosed in this 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, 2020, 2019 and 2018 that are included in the Company's 2020 Form 10-K. The consolidated financial statements for the year ended September 30, 2021 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.

The earnings for the six months ended March 31, 2021 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2021. 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):


	Six Months Ended March 31, 2021				Six Months Ended March 31, 2020
	Balance at October 1, 2020		Balance at March 31, 2021		Balance at October 1, 2019		Balance at March 31, 2020

Cash and Temporary Cash Investments	$	20,541	$	80,467	$	20,428	$	111,655
Hedging Collateral Deposits	—		—		6,832		10,728
Cash, Cash Equivalents, and Restricted Cash	$	20,541	$	80,467	$	27,260	$	122,383

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 hedging positions. 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 is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic 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. To date, as a result of the COVID-19 pandemic, the Company has started to see modest increases in their receivable balances due to customer non-payments. As a result, the Company has increased the bad debt reserve to account for the higher receivable balances.

Activity in the allowance for uncollectible accounts for the six months ended March 31, 2021 are as follows:

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	Balance at Beginning of Period		Additions Charged to Costs and Expenses		Add: Discounts on Purchased Receivables		Deduct: Net Accounts Receivable Written-Off		Balance at End of Period
Six Months Ended March 31, 2021
Allowance for Uncollectible Accounts	$	22,810	$	11,074	$	737	$	4,493	$	30,128

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 $21.4 million at March 31, 2021, 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:


	At March 31, 2021		At September 30, 2020

Materials and Supplies - at average cost	$	33,532	$	33,859
Emission Allowances	18,680		18,018
	$	52,212	$	51,877

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 at both March 31, 2021 and September 30, 2020.

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 $149.2 million and $148.1 million at March 31, 2021 and September 30, 2020, 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 unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent non-cash impairment is required to be charged to earnings in that quarter. At March 31, 2021, the ceiling exceeded the book value of the oil and gas properties by approximately $145.4 million. The book value of the oil and gas properties exceeded the ceiling at December 31, 2020. As such, the Company recognized a non-cash, pre-tax impairment charge of $76.2 million for the quarter ended December 31, 2020. A deferred income tax benefit of $21.0 million related to the non-cash impairment charge was also recognized for the quarter ended December 31, 2020. In adjusting

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estimated future cash flows for hedging under the ceiling test at March 31, 2021, estimated future net cash flows were increased by $127.9 million.

The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. Despite the economic conditions arising from the COVID-19 pandemic, there were no indications of any impairments to property, plant and equipment in the Utility, Pipeline and Storage and Gathering segments at March 31, 2021. Management will continue to monitor the situation on a quarterly basis.

Accumulated Other Comprehensive Income (Loss). The components of Accumulated Other Comprehensive Income (Loss) and changes for the six months ended March 31, 2021 and 2020, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):


	Gains and Losses on Derivative Financial Instruments		Funded Status of the Pension and Other Post-Retirement Benefit Plans		Total
Three Months Ended March 31, 2021
Balance at January 1, 2021	$	10,151	$	(89,892)	$	(79,741)
Other Comprehensive Gains and Losses Before Reclassifications	(24,903)		—		(24,903)
Amounts Reclassified From Other Comprehensive Income (Loss)	2,656		—		2,656
Balance at March 31, 2021	$	(12,096)	$	(89,892)	$	(101,988)
Six Months Ended March 31, 2021
Balance at October 1, 2020	$	(24,865)	$	(89,892)	$	(114,757)
Other Comprehensive Gains and Losses Before Reclassifications	9,888		—		9,888
Amounts Reclassified From Other Comprehensive Income (Loss)	2,881		—		2,881

Balance at March 31, 2021	$	(12,096)	$	(89,892)	$	(101,988)
Three Months Ended March 31, 2020
Balance at January 1, 2020	$	30,680	$	(86,830)	$	(56,150)
Other Comprehensive Gains and Losses Before Reclassifications	55,450		—		55,450
Amounts Reclassified From Other Comprehensive Income (Loss)	(18,217)		—		(18,217)

Balance at March 31, 2020	$	67,913	$	(86,830)	$	(18,917)
Six Months Ended March 31, 2020
Balance at October 1, 2019	$	34,675	$	(86,830)	$	(52,155)
Other Comprehensive Gains and Losses Before Reclassifications	55,825		—		55,825
Amounts Reclassified From Other Comprehensive Income (Loss)	(23,537)		—		(23,537)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	950		—		950


Balance at March 31, 2020	$	67,913	$	(86,830)	$	(18,917)

In August 2017, the FASB issued authoritative guidance which changed the financial reporting of hedging relationships to better portray the economic results of an entity's risk management activities and to simplify the application of hedge accounting. The Company adopted this authoritative guidance effective October 1, 2019, recognizing a cumulative effect adjustment that decreased retained earnings by $1.0 million and increased accumulated other comprehensive income by the same amount.

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Reclassifications Out of Accumulated Other Comprehensive Income (Loss). The details about the reclassification adjustments out of accumulated other comprehensive income (loss) for the six months ended March 31, 2021 and 2020 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):


Details About Accumulated Other Comprehensive Income (Loss) Components	Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss)				Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended March 31,		Six Months Ended March 31,
	2021	2020	2021	2020
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts	($3,761)	$23,396	($4,071)	$30,937	Operating Revenues
Commodity Contracts	—	1,909	—	1,911	Purchased Gas
Foreign Currency Contracts	95	(271)	94	(462)	Operating Revenues
	(3,666)	25,034	(3,977)	32,386	Total Before Income Tax
	1,010	(6,817)	1,096	(8,849)	Income Tax Expense
	($2,656)	$18,217	($2,881)	$23,537	Net of Tax

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


	At March 31, 2021		At September 30, 2020

Prepayments	$	7,692	$	12,851
Prepaid Property and Other Taxes	23,373		14,269

State Income Taxes Receivable	—		3,828

Regulatory Assets	25,052		16,609
	$	56,117	$	47,557

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


	At March 31, 2021		At September 30, 2020

Accrued Capital Expenditures	$	49,526	$	33,344
Regulatory Liabilities	34,832		44,890
Reserve for Gas Replacement	21,432		—
Liability for Royalty and Working Interests	22,475		15,665




Non-Qualified Benefit Plan Liability	14,460		14,460
Other	34,215		31,817
	$	176,940	$	140,176

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 six months ended March 31, 2021, 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 334,945 securities excluded as being antidilutive for both the quarter and six months ended March 31, 2021. As the Company recognized a net

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loss for both the quarter and six months ended March 31, 2020, the aforementioned potentially dilutive securities, amounting to 310,015 and 406,748 securities, were not recognized in the diluted earnings per share calculation for the quarter and six months ended March 31, 2020, respectively.

Stock-Based Compensation. The Company granted 309,470 performance shares during the six months ended March 31, 2021. The weighted average fair value of such performance shares was $39.19 per share for the six months ended March 31, 2021. Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period.

Half of the performance shares granted during the six months ended March 31, 2021 must meet a performance goal related to relative return on capital over a three-year performance cycle. The performance goal over the 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 performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value of these performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award. The other half of the performance shares granted during the six months ended March 31, 2021 must meet a performance goal related to relative total shareholder return over a three-year performance cycle. The performance goal over the performance cycle is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group. Three-year total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these total shareholder return performance shares ("TSR performance shares") that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value price at the date of grant for the TSR performance shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the present value of forgone dividends over the vesting term of the award. This price is multiplied by the number of TSR performance shares awarded, the result of which is recorded as compensation expense over the vesting term of the award.

The Company granted 172,513 restricted stock units during the six months ended March 31, 2021. The weighted average fair value of such restricted stock units was $37.98 per share for the six months ended March 31, 2021. 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.

New Authoritative Accounting and Financial Reporting Guidance. On October 1, 2020, the Company adopted authoritative guidance regarding the measurement of credit losses on financial assets measured at amortized cost. The new guidance requires financial assets measured at amortized cost to be presented at the net amount expected to be collected, which means that companies are required to recognize an allowance for credit losses for the difference between the amortized cost basis of the financial asset and the amount expected to be collected over the contractual life of the asset. Prior to adoption, the Company analyzed its financial assets measured at amortized cost, primarily trade receivables. The adoption of this guidance did not have a material impact to the Company’s financial statements.

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Note 2 – Asset Acquisitions and Divestitures

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. The 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 2020 Form 10-K for additional information concerning the Company’s acquisition of certain upstream assets and midstream gathering assets from Shell.

Note 3 – Revenue from Contracts with Customers

The following tables provide a disaggregation of the Company's revenues for the quarter and six months ended March 31, 2021 and 2020, presented by type of service from each reportable segment.


Quarter Ended March 31, 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	$	188,769	$	—	$	—	$	—	$	—	$	—	$	188,769
Production of Crude Oil	33,589		—		—		—		—		—		33,589
Natural Gas Processing	772		—		—		—		—		—		772
Natural Gas Gathering Service	—		—		50,262		—		—		(49,591)		671
Natural Gas Transportation Service	—		64,648		—		39,514		—		(18,187)		85,975
Natural Gas Storage Service	—		21,231		—		—		—		(9,108)		12,123
Natural Gas Residential Sales	—		—		—		203,768		—		—		203,768
Natural Gas Commercial Sales	—		—		—		28,872		—		—		28,872
Natural Gas Industrial Sales	—		—		—		1,368		—		—		1,368
Natural Gas Marketing	—		—		—		—		66		(1)		65
Other	818		825		—		(4,519)		(1)		(97)		(2,974)
Total Revenues from Contracts with Customers	223,948		86,704		50,262		269,003		65		(76,984)		552,998
Alternative Revenue Programs	—		—		—		1,878		—		—		1,878
Derivative Financial Instruments	(3,761)		—		—		—		—		—		(3,761)
Total Revenues	$	220,187	$	86,704	$	50,262	$	270,881	$	65	$	(76,984)	$	551,115

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Six Months Ended March 31, 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	$	355,212	$	—	$	—	$	—	$	—	$	—	$	355,212
Production of Crude Oil	58,088		—		—		—		—		—		58,088
Natural Gas Processing	1,324		—		—		—		—		—		1,324
Natural Gas Gathering Service	—		—		97,270		—		—		(96,249)		1,021
Natural Gas Transportation Service	—		129,473		—		68,535		—		(37,777)		160,231
Natural Gas Storage Service	—		41,748		—		—		—		(17,871)		23,877
Natural Gas Residential Sales	—		—		—		341,649		—		—		341,649
Natural Gas Commercial Sales	—		—		—		46,067		—		—		46,067
Natural Gas Industrial Sales	—		—		—		2,290		—		—		2,290
Natural Gas Marketing	—		—		—		—		650		(20)		630
Other	1,029		3,248		—		(6,131)		545		(205)		(1,514)
Total Revenues from Contracts with Customers	415,653		174,469		97,270		452,410		1,195		(152,122)		988,875
Alternative Revenue Programs	—		—		—		7,471		—		—		7,471
Derivative Financial Instruments	(4,071)		—		—		—		—		—		(4,071)
Total Revenues	$	411,582	$	174,469	$	97,270	$	459,881	$	1,195	$	(152,122)	$	992,275


Quarter Ended March 31, 2020 (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	$	100,777	$	—	$	—	$	—	$	—	$	—	$	100,777
Production of Crude Oil	30,268		—		—		—		—		—		30,268
Natural Gas Processing	714		—		—		—		—		—		714
Natural Gas Gathering Service	—		—		35,267		—		—		(35,267)		—
Natural Gas Transportation Service	—		58,454		—		39,832		—		(21,976)		76,310
Natural Gas Storage Service	—		20,524		—		—		—		(9,087)		11,437
Natural Gas Residential Sales	—		—		—		185,323		—		—		185,323
Natural Gas Commercial Sales	—		—		—		27,296		—		—		27,296
Natural Gas Industrial Sales	—		—		—		1,144		—		—		1,144
Natural Gas Marketing	—		—		—		—		36,404		(79)		36,325
Other	405		267		—		(3,524)		851		(65)		(2,066)
Total Revenues from Contracts with Customers	132,164		79,245		35,267		250,071		37,255		(66,474)		467,528
Alternative Revenue Programs	—		—		—		4,422		—		—		4,422
Derivative Financial Instruments	23,396		—		—		—		(4,251)		—		19,145
Total Revenues	$	155,560	$	79,245	$	35,267	$	254,493	$	33,004	$	(66,474)	$	491,095

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Six Months Ended March 31, 2020 (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	$	220,651	$	—	$	—	$	—	$	—	$	—	$	220,651
Production of Crude Oil	67,931		—		—		—		—		—		67,931
Natural Gas Processing	1,402		—		—		—		—		—		1,402
Natural Gas Gathering Service	—		—		70,055		—		—		(70,055)		—
Natural Gas Transportation Service	—		111,906		—		72,640		—		(38,963)		145,583
Natural Gas Storage Service	—		38,950		—		—		—		(17,079)		21,871
Natural Gas Residential Sales	—		—		—		329,693		—		—		329,693
Natural Gas Commercial Sales	—		—		—		46,137		—		—		46,137
Natural Gas Industrial Sales	—		—		—		2,413		—		—		2,413
Natural Gas Marketing	—		—		—		—		70,513		(256)		70,257
Other	578		609		—		(6,848)		1,971		(118)		(3,808)
Total Revenues from Contracts with Customers	290,562		151,465		70,055		444,035		72,484		(126,471)		902,130
Alternative Revenue Programs	—		—		—		7,283		—		—		7,283
Derivative Financial Instruments	30,937		—		—		—		(5,067)		—		25,870
Total Revenues	$	321,499	$	151,465	$	70,055	$	451,318	$	67,417	$	(126,471)	$	935,283

The Company records revenue related to its derivative financial instruments in the Exploration and Production segment as well as in its NFR operations (included in the All Other category). The Company discontinued use of derivative financial instruments in its NFR operations upon completing the sale of its commercial and industrial contracts and certain other assets on August 1, 2020. The Company has been winding down its NFR operations since August 1, 2020 which has resulted in a significant reduction in natural gas marketing revenues as shown in the tables above. 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: $94.6 million for the remainder of fiscal 2021; $179.7 million for fiscal 2022; $144.5 million for fiscal 2023; $124.3 million for fiscal 2024; $117.0 million for fiscal 2025; and $517.5 million thereafter.

Note 4 – Fair Value Measurements

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

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The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of March 31, 2021 and September 30, 2020. 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 March 31, 2021
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)		Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	66,759	$	—	$	—	$	—	$	66,759
Derivative Financial Instruments:

Over the Counter Swaps – Gas and Oil	—		18,805		—		(14,768)		4,037
Over the Counter No Cost Collars – Gas	—		—		—		(118)		(118)
Foreign Currency Contracts	—		1,437		—		(1,252)		185
Other Investments:
Balanced Equity Mutual Fund	32,993		—		—		—		32,993
Fixed Income Mutual Fund	70,133		—		—		—		70,133
Common Stock – Financial Services Industry	988		—		—		—		988


Total	$	170,873	$	20,242	$	—	$	(16,138)	$	174,977

Liabilities:
Derivative Financial Instruments:

Over the Counter Swaps – Gas and Oil	—		35,809		—		(14,768)		21,041
Over the Counter No Cost Collars – Gas	—		1,488		—		(118)		1,370
Foreign Currency Contracts	—		72		—		(1,252)		(1,180)
Total	$	—	$	37,369	$	—	$	(16,138)	$	21,231

Total Net Assets/(Liabilities)	$	170,873	$	(17,127)	$	—	$	—	$	153,746


Recurring Fair Value Measures	At fair value as of September 30, 2020
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments(1)		Total(1)
Assets:
Cash Equivalents – Money Market Mutual Funds	$	12,285	$	—	$	—	$	—	$	12,285
Derivative Financial Instruments:

Over the Counter Swaps – Gas and Oil	—		36,418		—		(26,400)		10,018
Over the Counter No Cost Collars – Gas	—		—		—		(720)		(720)
Foreign Currency Contracts	—		259		—		(338)		(79)
Other Investments:
Balanced Equity Mutual Fund	39,618		—		—		—		39,618
Fixed Income Mutual Fund	72,253		—		—		—		72,253
Common Stock – Financial Services Industry	639		—		—		—		639


Total	$	124,795	$	36,677	$	—	$	(27,458)	$	134,014

Liabilities:
Derivative Financial Instruments:

Over the Counter Swaps – Gas and Oil	—		61,280		—		(26,400)		34,880
Over the Counter No Cost Collars – Gas	—		8,171		—		(720)		7,451
Foreign Currency Contracts	—		1,976		—		(338)		1,638
Total	$	—	$	71,427	$	—	$	(27,458)	$	43,969

Total Net Assets/(Liabilities)	$	124,795	$	(34,750)	$	—	$	—	$	90,045

(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.

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Derivative Financial Instruments

The derivative financial instruments reported in Level 2 at March 31, 2021 and September 30, 2020 consist of natural gas price swap agreements, natural gas no cost collars, crude oil price swap agreements, and foreign currency contracts, all of which are used in the Company’s Exploration and Production segment. The fair value of the Level 2 price swap agreements and no cost collars is based on an internal, 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 March 31, 2021, the Company determined that nonperformance risk 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 the quarters ended March 31, 2021 and March 31, 2020, there were no assets or liabilities measured at fair value and classified as Level 3.

Note 5 – Financial Instruments

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


	March 31, 2021				September 30, 2020
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,627,033	$	2,869,081	$	2,629,576	$	2,778,556

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

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

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


	At March 31, 2021		At September 30, 2020

Life Insurance Contracts	$	43,307	$	41,992
Equity Mutual Fund	32,993		39,618
Fixed Income Mutual Fund	70,133		72,253
Marketable Equity Securities	988		639
	$	147,421	$	154,502

Investments in life insurance contracts are stated at their cash surrender values or net present value. Investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (marketable equity securities) are stated

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at fair value based on quoted market prices with changes in fair value recognized in net income. The insurance contracts and marketable equity and fixed income securities are primarily informal funding mechanisms 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 and crude oil to manage the price risk associated with forecasted sales of gas and oil. 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 10 years.

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at March 31, 2021 and September 30, 2020. Substantially all of the derivative financial instruments reported on those line items relate to commodity contracts and a small portion relates to foreign currency forward contracts.

Cash Flow Hedges

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

As of March 31, 2021, the Company had the following commodity derivative contracts (swaps and no cost collars) outstanding:


Commodity	Units
Natural Gas	253.3	Bcf

Crude Oil	2,082,000	Bbls

As of March 31, 2021, the Company was hedging a total of $69.4 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts.

As of March 31, 2021, the Company had $17.1 million ($12.1 million after-tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that $28.2 million ($19.9 million after-tax) of 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 March 31, 2021 and 2020 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships	Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) for the Three Months Ended March 31,				Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Three Months Ended March 31,
	2021		2020			2021		2020
Commodity Contracts	$	(35,123)	$	81,108	Operating Revenue	$	(3,761)	$	23,396
Commodity Contracts	—		(134)		Purchased Gas	—		1,909
Foreign Currency Contracts	750		(4,670)		Operating Revenue	95		(271)
Total	$	(34,373)	$	76,304		$	(3,666)	$	25,034

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The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Six Months Ended March 31, 2021 and 2020 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships	Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) for the Six Months Ended March 31,				Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Six Months Ended March 31,
	2021		2020			2021		2020
Commodity Contracts	$	10,472	$	79,553	Operating Revenue	$	(4,071)	$	30,937
Commodity Contracts	—		997		Purchased Gas	—		1,911
Foreign Currency Contracts	3,176		(3,751)		Operating Revenue	94		(462)
Total	$	13,648	$	76,799		$	(3,977)	$	32,386

Credit Risk

The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions, no cost collars and applicable foreign currency forward contracts with fifteen counterparties of which five are in a net gain position. On average, the Company had $0.8 million of credit exposure per counterparty in a gain position at March 31, 2021. The maximum credit exposure per counterparty in a gain position at March 31, 2021 was $1.6 million. As of March 31, 2021, no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral.

As of March 31, 2021, thirteen of the fifteen 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 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 were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required. At March 31, 2021, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $1.5 million according to the Company’s internal model (discussed in Note 4 – Fair Value Measurements). At March 31, 2021, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $21.2 million according to the Company's internal model. For its over-the-counter swap agreements and foreign currency forward contracts, no hedging collateral deposits were required to be posted by the Company at March 31, 2021.

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 March 31, 2021 and March 31, 2020 were 26.3% and negative 53.2%, respectively. The effective tax rates for the six months ended March 31, 2021 and March 31, 2020 were 26.8% and 139.9%, respectively. The change in the tax rate is primarily the result of a valuation allowance initially established in the quarter ended March 31, 2020, discussed below.

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A valuation allowance for deferred tax assets, including net operating losses and tax credits, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. The Company continually assesses the realizability of its deferred tax assets, including factors such as future taxable income, reversal of existing temporary differences, and tax planning strategies. The Company considers both positive and negative evidence related to the likelihood of the realization of the deferred tax assets. As of March 31, 2020, the Company recorded a valuation allowance against certain state deferred tax assets in the amount of $56.8 million based on its conclusion, considering all available objective evidence and the Company’s history of subsidiary state tax losses, that it was more likely than not that the deferred tax assets would not be realized. The valuation allowance increased to $63.9 million as of March 31, 2021 as a result of certain state net operating loss and tax credit activity. Changes in judgment regarding future realization of these deferred tax assets may result in a reversal of all or a portion of the valuation allowance. The Company will continue to re-assess this position each quarter.

On March 27, 2020, the “Coronavirus Aid, Relief and Economic Security (CARES) Act” was signed into law. The CARES Act, among other things, includes provisions relating to alternative minimum tax (AMT) credit refunds, refundable payroll tax credits, deferment of employer side social security payments, net operating loss carryback periods, and modifications to the net interest deduction limitation. The 2017 Tax Reform Act had repealed the corporate AMT and provided that the Company’s existing AMT credit carryovers were refundable over a four year period. As of September 30, 2018, the Company had $85.0 million of AMT credit carryovers. The Company received the first installment for $42.5 million of AMT credit refunds related to fiscal 2019 in January 2020 and filed for the acceleration of the remaining AMT credit refunds of $42.5 million, which were received in June 2020.

On December 27, 2020, the “Consolidated Appropriations Act, 2021 (CAA)” was signed into law. The CAA clarifies and expands the Paycheck Protection Program loans and the Employee Retention Credit as well as several other tax provisions first outlined in the CARES Act. The CAA is currently being evaluated, however, the Company does not anticipate a material impact as a result of this legislation. On March 11, 2021, the “American Rescue Plan Act of 2021” was signed into law. The Company is still evaluating the impacts of this legislation but does not anticipate a material impact as a result of this legislation.

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Note 7 – Capitalization

Summary of Changes in Common Stock Equity


	Common Stock			Paid In Capital		Earnings Reinvested in the Business		Accumulated Other Comprehensive Income (Loss)
	Shares	Amount
	(Thousands, except per share amounts)
Balance at January 1, 2021	91,153	$	91,153	$	1,004,369	$	1,028,844	$	(79,741)
Net Income Available for Common Stock						112,436
Dividends Declared on Common Stock ($0.445 Per Share)						(40,562)

Other Comprehensive Loss, Net of Tax								(22,247)
Share-Based Payment Expense (1)				4,283

Common Stock Issued Under Stock and Benefit Plans	11	11		423
Balance at March 31, 2021	91,164	$	91,164	$	1,009,075	$	1,100,718	$	(101,988)

Balance at October 1, 2020	90,955	$	90,955	$	1,004,158	$	991,630	$	(114,757)
Net Income Available for Common Stock						190,210
Dividends Declared on Common Stock ($0.89 Per Share)						(81,122)

Other Comprehensive Income, Net of Tax								12,769
Share-Based Payment Expense (1)				7,779

Common Stock Issued (Repurchased) Under Stock and Benefit Plans	209	209		(2,862)
Balance at March 31, 2021	91,164	$	91,164	$	1,009,075	$	1,100,718	$	(101,988)

Balance at January 1, 2020	86,552	$	86,552	$	831,146	$	1,320,592	$	(56,150)
Net Income (Loss) Available for Common Stock						(106,068)
Dividends Declared on Common Stock ($0.435 Per Share)						(37,654)


Other Comprehensive Income, Net of Tax								37,233
Share-Based Payment Expense (1)				3,876
Common Stock Issued Under Stock and Benefit Plans	10	10		422
Balance at March 31, 2020	86,562	$	86,562	$	835,444	$	1,176,870	$	(18,917)

Balance at October 1, 2019	86,315	$	86,315	$	832,264	$	1,272,601	$	(52,155)
Net Income (Loss) Available for Common Stock						(19,477)
Dividends Declared on Common Stock ($0.87 Per Share)						(75,304)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging						(950)


Other Comprehensive Income, Net of Tax								33,238
Share-Based Payment Expense (1)				6,704
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	247	247		(3,524)
Balance at March 31, 2020	86,562	$	86,562	$	835,444	$	1,176,870	$	(18,917)

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

Common Stock. During the six months ended March 31, 2021, the Company issued 105,260 original issue shares of common stock for restricted stock units that vested and 165,161 original issue shares of common stock for performance shares that vested. The Company also issued 21,616 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 Non-Employee Directors Deferred Compensation Plan during the six months ended March 31, 2021. Holders of stock-based compensation awards will often tender shares of common stock to the Company for

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payment of applicable withholding taxes. During the six months ended March 31, 2021, 82,936 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

Current Portion of Long-Term Debt. None of the Company's long-term debt as of March 31, 2021 and September 30, 2020 had a maturity date within the following twelve-month period.

Long-Term Debt. 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%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The proceeds of this debt issuance were used for general corporate purposes, including the redemption of $500.0 million of 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 call premium of $15.7 million was recorded to Interest Expense on Long-Term Debt on the Consolidated Income Statement during the quarter ended March 31, 2021.

Short-Term Borrowings. On February 3, 2021, the Company amended its existing 364-day credit facility agreement. The amendment extends the maturity date of the facility from May 3, 2021 to December 30, 2022, and increases the commitment provided under the facility from $200.0 million to $250.0 million of unsecured committed revolving credit access. The Company entered into the amendment with a syndicate of twelve banks, all of which are also lenders under the Company's existing $750.0 million multi-year credit facility.

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 March 31, 2021, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $3.3 million, which includes a $0.5 million estimated minimum liability to remediate a former manufactured gas plant site located in New York. In March 2018, the NYDEC issued a Record of Decision for this New York site and the minimum liability reflects the remedy selected in the Record of Decision. Active remedial work at the site has been completed and restoration is currently underway. The Company's liability for such clean-up costs has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at March 31, 2021. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 1 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). The United States Court of Appeals for the Second Circuit (the “Second Circuit Court of Appeals”) held in the Company’s favor in its appeal of this decision, vacating the NYDEC denial and remanding to the NYDEC. The NYDEC subsequently issued a second denial, which the Company has appealed to the Second Circuit Court of Appeals. The court has held this appeal in abeyance pending the outcome of the FERC waiver appeal, described below. While the Company’s initial appeal was pending before the Second Circuit Court of Appeals, the 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. Recently, 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.

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Other. The Company is involved in other litigation and regulatory matters arising in the normal course of business. These other matters may include, for example, negligence claims and tax, regulatory or other governmental audits, inspections, investigations and other proceedings. These matters may involve state and federal taxes, safety, compliance with regulations, rate base, cost of service and purchased gas cost issues, among other things. While these other matters arising in the normal course of business could have a material effect on earnings and cash flows in the period in which they are resolved, an estimate of the possible loss or range of loss, if any, cannot be made at this time.

Note 9 – Business Segment Information

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

The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. As stated in the 2020 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 2020 Form 10-K. A listing of segment assets at March 31, 2021 and September 30, 2020 is shown in the tables below.


Quarter Ended March 31, 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	$220,187	$59,314	$671	$270,784	$550,956	$64	$95	$551,115
Intersegment Revenues	$—	$27,390	$49,591	$97	$77,078	$1	$(77,079)	$—
Segment Profit: Net Income (Loss)	$36,822	$24,928	$20,700	$32,044	$114,494	$(983)	$(1,075)	$112,436


Six Months Ended March 31, 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	$411,582	$118,623	$1,021	$459,684	$990,910	$1,175	$190	$992,275
Intersegment Revenues	$—	$55,846	$96,249	$197	$152,292	$20	$(152,312)	$—
Segment Profit: Net Income	$7,199	$49,112	$41,250	$55,081	$152,642	$36,577	$991	$190,210


(Thousands)	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Segment Assets:
At March 31, 2021	$2,023,147	$2,240,140	$855,507	$2,151,304	$7,270,098	$27,391	$(181,837)	$7,115,652
At September 30, 2020	$1,979,028	$2,204,971	$945,199	$2,067,852	$7,197,050	$113,571	$(345,686)	$6,964,935


Quarter Ended March 31, 2020 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$155,560	$51,919	$—	$250,556	$458,035	$32,925	$135	$491,095
Intersegment Revenues	$—	$27,326	$35,267	$3,937	$66,530	$79	$(66,609)	$—
Segment Profit: Net Income (Loss)	$(175,275)	$22,087	$19,898	$31,499	$(101,791)	$1,169	$(5,446)	$(106,068)

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Six Months Ended March 31, 2020 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$321,499	$100,888	$—	$445,465	$867,852	$67,161	$270	$935,283
Intersegment Revenues	$—	$50,577	$70,055	$5,853	$126,485	$256	$(126,741)	$—
Segment Profit: Net Income (Loss)	$(151,299)	$40,192	$35,842	$58,082	$(17,183)	$1,540	$(3,834)	$(19,477)

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 March 31,	2021		2020		2021		2020

Service Cost	$	2,466	$	2,330	$	400	$	402
Interest Cost	5,422		7,483		2,326		3,228
Expected Return on Plan Assets	(14,537)		(15,016)		(7,241)		(7,308)
Amortization of Prior Service Cost (Credit)	158		182		(107)		(107)

Amortization of Losses	9,203		9,846		212		134
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	7,710		5,519		9,451		8,846

Net Periodic Benefit Cost	$	10,422	$	10,344	$	5,041	$	5,195



	Retirement Plan				Other Post-Retirement Benefits
Six Months Ended March 31,	2021		2020		2021		2020

Service Cost	$	4,932	$	4,659	$	801	$	804
Interest Cost	10,843		14,965		4,652		6,457
Expected Return on Plan Assets	(29,074)		(30,032)		(14,482)		(14,616)
Amortization of Prior Service Cost (Credit)	316		365		(214)		(214)

Amortization of Losses	18,407		19,692		424		267
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	11,422		7,047		16,303		15,094

Net Periodic Benefit Cost	$	16,846	$	16,696	$	7,484	$	7,792

(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 six months ended March 31, 2021, the Company contributed $14.6 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $2.1 million to its VEBA trusts for its other post-retirement benefits. In the remainder of 2021, the Company expects its contributions to the Retirement Plan to be in the range of $5.0 million to $10.0 million. In the remainder of 2021, the Company expects its contributions to its VEBA trusts to be in the range of $0.5 million to $1.0 million.

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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%. The order also directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018.

In New York, on March 13, 2020, in response to the COVID-19 pandemic, the Company agreed to NYPSC Staff’s request that the Company suspend service terminations and disconnections. Thereafter, on June 17, 2020, New York enacted a new law that prohibits utilities from terminating or disconnecting services to any residential customer for non-payment for the duration of the state disaster emergency. In addition, the law prohibits residential terminations for non-payment for a period of 180 days running from the end of the state disaster emergency for customers that have experienced a change in financial circumstances due to the COVID-19 state of emergency. Governor Cuomo, through the issuance of executive orders, has extended the declaration of the state disaster emergency through May 25, 2021. Although the state disaster emergency declaration continues, the above-enumerated law reached its sunset on March 31, 2021. Legislation purporting to extend the moratorium is pending, and all of the major utilities have notified NYPSC Staff that they have no immediate plans to resume residential disconnections given the proposed legislation. The duration of the aforementioned suspension in New York and its related impact on the Company is uncertain. The Company is anticipating that customer non-payment may increase given higher natural gas usage and the resulting increase in costs for customers. It is uncertain at this point as to whether there would be any regulatory relief for utilities with regard to an increase in costs associated with the COVID-19 pandemic, but it is one of many issues currently being considered in a generic NYPSC proceeding entitled “Proceeding on Motion of the Commission Regarding the Effects of COVID-19 on Utility Service” (Case No. 20-M-0266). Correspondence from NYPSC Staff has recommended that utilities rely on existing avenues of relief for these costs, and has identified additional, more stringent requirements that must be met to achieve relief.

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 March 26, 2020, the PaPUC ratified an Emergency Order that established a Service Termination Moratorium intended to continue during the pendency of Governor Wolf’s March 6, 2020 Proclamation of Disaster Emergency associated with the COVID-19 pandemic. On May 13, 2020, the Company (and other Pennsylvania local distribution companies) received a Secretarial Letter from the PaPUC regarding COVID-19 pandemic cost tracking and regulatory assets. The Secretarial Letter directs utilities to track “extraordinary, nonrecurring incremental COVID-19 related expenses” so the Commission can understand the impact of these expenses on the utilities’ finances. It also authorizes the creation of a utility regulatory asset, but only for incremental uncollectible expenses incurred above those embedded in rates (and incurred since the issuance of the Emergency Order). The Company currently does not anticipate a need to create a regulatory asset for these expenses. On October 8, 2020, the Commission issued an order ending the moratorium effective November 9, 2020, imposing a list of enhanced customer protections that expired on March 31, 2021. On March 11, 2021, the Commission adopted an order confirming that effective April 1, 2021, the utility service termination moratorium would be lifted and utilities would be authorized to return to the regular collections process with certain modifications to customer payment arrangements. The October and March orders expanded the aforementioned potential utility regulatory asset to include all incremental COVID-19 related expenses incurred above those embedded in rates resulting from directives contained in the orders. The Company continues to monitor this item for potential deferral opportunity.

FERC Jurisdiction

Supply Corporation’s rate settlement, approved June 1, 2020, 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. Supply has no rate case currently on file.

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

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Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations

OVERVIEW

Please note that this overview is a high-level summary of items that are discussed in greater detail in subsequent sections of this report.

The Company is a diversified energy company engaged principally in the production, gathering, transportation 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 also develops and produces oil reserves, primarily in California. The Company reports financial results for four business segments. For a discussion of the Company's earnings, refer to the Results of Operations section below.

The Company is closely monitoring and responding to developments related to the novel coronavirus (COVID-19) and is taking steps to limit operational impacts and the potential exposure for our workforce and customers. Refer to Risk Factors in Item 1A of this Form 10-Q as well as Part I, Item 1A, Risk Factors, under Operational Risks in the Company's 2020 Form 10-K for a more complete discussion of the risks to the Company associated with the COVID-19 pandemic.

The Company continues to pursue development projects to expand its Pipeline and Storage segment. The Company is monitoring the impacts of the COVID-19 pandemic on its supply chains and development projects in this segment. To date, the COVID-19 pandemic has not had a material impact on the target in-service dates of these development projects. However, the unpredictable extent and duration of the pandemic, and the government imposition of certain significant restrictions associated therewith, could delay receipt of necessary equipment or delay construction. The Company will continue to monitor this rapidly evolving situation and mitigate where possible. One project on Empire’s system, referred to as the Empire North Project, which allows for the transportation of 205,000 Dth per day of additional shale supplies from interconnections in Tioga County, Pennsylvania, to the TC Energy pipeline, and the Tennessee Gas Pipeline L.L.C. (TGP) 200 Line, was placed in-service during the fourth quarter of fiscal 2020. Another project on Supply Corporation’s system, referred to as the FM100 Project, will upgrade a 1950’s era pipeline in northwestern Pennsylvania and create 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 system at Leidy, Pennsylvania. Construction activities for the FM100 Project are fully in progress. The FM100 Project has a target in-service date of late calendar 2021 and a preliminary cost estimate of approximately $280 million. This project is discussed in more detail in the Capital Resources and Liquidity section that follows.

In advance of the expected late calendar 2021 online date for Seneca’s 330,000 Dth per day of incremental capacity on the Leidy South Project, which is the companion project to the Company's FM100 Project, the Company's Exploration and Production segment added a second horizontal drilling rig in the Appalachian region in January 2021. Production from the first pad that will be drilled in connection with this additional activity is expected in early fiscal 2022, with this incremental production reaching Transco Zone 6 markets during the winter heating season.

From a legislative perspective, in July 2019, New York State enacted legislation known as the Climate Leadership & Community Protection Act (CLCPA). This climate legislation 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 legislation also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% with zero emissions generation by 2040. The CLCPA established a climate action council and a series of advisory panels and working groups to study how the state will achieve the aggressive emission reduction targets. Thus far, the only regulations promulgated in connection with the CLCPA are greenhouse gas limits established by the NYDEC on December 30, 2020. For further discussion of the CLCPA, refer to the Environmental Matters section below.

The Company uses the full cost method of accounting for determining the book value of its oil and natural gas properties in the Exploration and Production segment and that book value is subject to a quarterly ceiling test. This is discussed in more detail in the Critical Accounting Estimates section that follows. In addition to the significant non-cash impairment charges under the ceiling test that the Company recorded during fiscal 2020, the Company recorded a non-cash impairment

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charge under the ceiling test for the six months ended March 31, 2021 of $76.2 million ($55.2 million after-tax), which was recorded during the quarter ended December 31, 2020. Please refer to the Critical Accounting Estimates section below for a sensitivity analysis concerning commodity price changes.

From a financing perspective, on February 24, 2021, the Company issued $500.0 million of 2.95% notes due March 1, 2031. The proceeds of the debt issuance were used for general corporate purposes, including the redemption of $500.0 million of 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.

On February 3, 2021, the Company amended its existing 364-day credit facility agreement. The amendment extends the maturity date of the facility from May 3, 2021 to December 30, 2022, and increases the commitment provided under the facility from $200.0 million to $250.0 million of unsecured committed revolving credit access. The Company entered into the amendment with a syndicate of twelve banks, all of which are also lenders under the Company's existing $750.0 million multi-year credit facility.

The sale of timber properties discussed above, combined with cash on hand, cash from operations and short-term borrowings, are expected to meet the Company’s financing needs for fiscal 2021.

CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2020 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. In accordance with this methodology, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company's oil and gas reserves based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s oil and gas properties at the balance sheet date. The present value of future revenues is calculated using a 10% discount factor. If the book value of the oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling. At March 31, 2021, the ceiling exceeded the book value of the oil and gas properties by approximately $145.4 million. The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended March 31, 2021, based on posted Midway Sunset prices, was $38.19 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended March 31, 2021, based on the quoted Henry Hub spot price for natural gas, was $2.16 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 Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for the twelve months ended March 31, 2021. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the amount the ceiling would have exceeded the book value of the Company's oil and gas properties at March 31, 2021 if crude oil prices were $5 per Bbl lower than the average prices used at March 31, 2021, as well as showing the impairment that the Company would have recorded at March 31, 2021 if natural gas prices were $0.25 per MMBtu lower than the average prices used at March 31, 2021, and the impairment that the Company would have recorded at March 31, 2021 if both natural gas prices and crude oil prices were $0.25 per MMBtu and $5 per Bbl lower than the average prices used at March 31, 2021 (all amounts are presented after-tax). These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.

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Ceiling Testing Sensitivity to Commodity Price Changes
(Millions)	$0.25/MMBtu Decrease in Natural Gas Prices		$5.00/Bbl Decrease in Crude Oil Prices		$0.25/MMBtu Decrease in Natural Gas Prices and $5.00/Bbl Decrease in Crude Oil Prices
Excess of Ceiling over Book Value under Sensitivity Analysis	$	—	$	114.0	$	—
Calculated Impairment under Sensitivity Analysis	$	123.6	$	—	$	154.9

It is difficult to predict what factors could lead to future non-cash impairments under the SEC's full cost ceiling test. Fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in oil and 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 2020 Form 10-K.

RESULTS OF OPERATIONS

Earnings

The Company's earnings were $112.4 million for the quarter ended March 31, 2021 compared to a loss of $106.1 million for the quarter ended March 31, 2020. The increase in earnings of $218.5 million is primarily the result of higher earnings in the Exploration and Production segment, Pipeline and Storage segment, Gathering segment and Utility segment, as well as a lower loss in the Corporate category. A loss in the All Other category provided a small offset to these increases.

The Company's earnings were $190.2 million for the six months ended March 31, 2021 compared to a loss of $19.5 million for the six months ended March 31, 2020. The increase in earnings of $209.7 million is primarily the result of higher earnings in the Exploration and Production segment, Pipeline and Storage segment, Gathering segment and Corporate and All Other categories. Lower earnings in the Utility segment partially offset these increases.

The Company's earnings for the six months ended March 31, 2021 included a non-cash $76.2 million impairment charge ($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, as discussed above. The Company's earnings for the six months ended March 31, 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, as discussed above. The Company's earnings for the quarter and six months ended March 31, 2020 included a non-cash $177.8 million impairment charge ($129.3 million after-tax) recorded during the quarter ended March 31, 2020 for the Exploration and Production segment's oil and gas producing properties. The Company's earnings for the quarter and six months ended March 31, 2020 also included the establishment of a $56.8 million valuation allowance recorded against certain deferred tax assets. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.

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Earnings (Loss) by Segment


	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2021		2020		Increase (Decrease)		2021		2020		Increase (Decrease)
Exploration and Production	$	36,822	$	(175,275)	$	212,097	$	7,199	$	(151,299)	$	158,498
Pipeline and Storage	24,928		22,087		2,841		49,112		40,192		8,920
Gathering	20,700		19,898		802		41,250		35,842		5,408
Utility	32,044		31,499		545		55,081		58,082		(3,001)
Total Reportable Segments	114,494		(101,791)		216,285		152,642		(17,183)		169,825
All Other	(983)		1,169		(2,152)		36,577		1,540		35,037
Corporate	(1,075)		(5,446)		4,371		991		(3,834)		4,825
Total Consolidated	$	112,436	$	(106,068)	$	218,504	$	190,210	$	(19,477)	$	209,687

Exploration and Production

Exploration and Production Operating Revenues


	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2021		2020		Increase (Decrease)		2021		2020		Increase (Decrease)
Gas (after Hedging)	$	186,530	$	119,139	$	67,391	$	349,038	$	246,377	$	102,661
Oil (after Hedging)	32,067		35,302		(3,235)		60,191		73,142		(12,951)
Gas Processing Plant	772		714		58		1,324		1,402		(78)
Other	818		405		413		1,029		578		451
	$	220,187	$	155,560	$	64,627	$	411,582	$	321,499	$	90,083

Production Volumes


	Three Months Ended March 31,			Six Months Ended March 31,
	2021	2020	Increase (Decrease)	2021	2020	Increase (Decrease)
Gas Production (MMcf)
Appalachia	81,446	55,638	25,808	157,115	109,922	47,193
West Coast	428	479	(51)	869	966	(97)
Total Production	81,874	56,117	25,757	157,984	110,888	47,096

Oil Production (Mbbl)
Appalachia	1	1	—	1	2	(1)
West Coast	561	605	(44)	1,124	1,206	(82)
Total Production	562	606	(44)	1,125	1,208	(83)

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Average Prices


	Three Months Ended March 31,						Six Months Ended March 31,
	2021		2020		Increase (Decrease)		2021		2020		Increase (Decrease)
Average Gas Price/Mcf
Appalachia	$	2.28	$	1.77	$	0.51	$	2.23	$	1.97	$	0.26
West Coast	$	7.14	$	4.34	$	2.80	$	6.07	$	4.67	$	1.40
Weighted Average	$	2.31	$	1.80	$	0.51	$	2.25	$	1.99	$	0.26
Weighted Average After Hedging	$	2.28	$	2.12	$	0.16	$	2.21	$	2.22	$	(0.01)

Average Oil Price/Bbl
Appalachia	$	48.47	$	55.90	$	(7.43)	$	43.83	$	55.48	$	(11.65)
West Coast	$	59.83	$	49.91	$	9.92	$	51.64	$	56.25	$	(4.61)
Weighted Average	$	59.82	$	49.92	$	9.90	$	51.63	$	56.25	$	(4.62)
Weighted Average After Hedging	$	57.11	$	58.23	$	(1.12)	$	53.50	$	60.57	$	(7.07)

2021 Compared with 2020

Operating revenues for the Exploration and Production segment increased $64.6 million for the quarter ended March 31, 2021 as compared with the quarter ended March 31, 2020. Gas production revenue after hedging increased $67.4 million due to the impact of a 25.8 Bcf increase in natural gas production, together with a $0.16 per Mcf increase in the weighted average price of natural gas after hedging. Natural gas production increased largely due to additional production from the Company's fourth quarter fiscal 2020 acquisition of Appalachian upstream assets from Shell coupled with new Marcellus and Utica wells in the Appalachian region. Oil production revenue after hedging decreased $3.2 million due to a $1.12 per Bbl decrease in the weighted average price of oil after hedging, combined with the impact of a 44 Mbbl decrease in oil production. The decrease in oil production was largely due to natural production declines as a result of lower activity in response to decreased crude oil prices.

Operating revenues for the Exploration and Production segment increased $90.1 million for the six months ended March 31, 2021 as compared with the six months ended March 31, 2020. Gas production revenue after hedging increased $102.7 million due to the impact of a 47.1 Bcf increase in gas production which was partially offset by a $0.01 per Mcf decrease in the weighted average price of gas after hedging. The increase in gas production was largely due to additional production from the Company's fourth quarter fiscal 2020 acquisition of Appalachian upstream assets from Shell coupled with new Marcellus and Utica wells in the Appalachian region during the six months ended March 31, 2021 as compared with the six months ended March 31, 2020. Oil production revenue after hedging decreased $13.0 million due to a $7.07 per Bbl decrease in the weighted average price of oil after hedging, coupled with the impact of an 83 Mbbl decrease in oil production. The decrease in oil production was largely due to natural production declines as a result of lower activity in response to decreased crude oil prices.

The Exploration and Production segment's earnings for the quarter ended March 31, 2021 were $36.8 million, an increase of $212.1 million when compared with a loss of $175.3 million for the quarter ended March 31, 2020. The increase in earnings was due to a quarter ended March 31, 2020 non-cash impairment of oil and gas properties ($129.3 million), higher natural gas production ($43.2 million), higher natural gas prices after hedging ($10.0 million) and a deferred tax valuation allowance established during the quarter ended March 31, 2020 as discussed more completely in Item 1 at Note 6 — Income Taxes ($60.5 million). The earnings impact of these items was partially offset by lower oil production ($2.1 million), lower oil prices after hedging ($0.5 million), higher lease operating and transportation expenses ($12.1 million), higher depletion expense ($0.8 million), higher other operating expenses ($0.7 million), higher interest expense ($1.0 million) and a higher effective tax rate ($2.4 million). The increase in lease operating and transportation expenses was largely attributed to higher natural gas production. The increase in depletion expense was primarily due to the net increase in production offset by a $0.22 per Mcf decrease in the depletion rate due to prior period non-cash ceiling test impairments coupled with the impact of the asset acquisition from Shell. The increase in interest expense was primarily driven by additional intercompany long-term borrowings from the Company’s long-term debt issuance in June 2020. Finally, the Exploration and Production segment 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.

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The Exploration and Production segment's earnings for the six months ended March 31, 2021 were $7.2 million, an increase of $158.5 million when compared with a loss of $151.3 million for the six months ended March 31, 2020. The increase in earnings was primarily attributable to a decrease in impairments of oil and gas properties ($129.3 million during the six months ended March 31, 2020 compared to $55.2 million during the six months ended March 31, 2021), higher natural gas production ($82.7 million) and a deferred tax valuation allowance established during the quarter ended March 31, 2020 as discussed more completely in Item 1 at Note 6 — Income Taxes ($60.5 million). These increases in earnings were partially offset by lower natural gas prices after hedging ($1.6 million), lower oil production ($4.0 million), lower oil prices after hedging ($6.3 million), higher lease operating and transportation expenses ($23.7 million), higher depletion expense ($1.7 million), higher other operating expenses ($2.5 million), higher interest expense of ($2.1 million) and a higher effective tax rate ($5.6 million). The increase in lease operating and transportation expenses was primarily the result of increased gathering and transportation costs in the Appalachian region due to increased production. The increase in depletion expense was primarily due to the net increase in production offset by a $0.20 per Mcf decrease in the depletion rate due to prior period non-cash ceiling test impairments coupled with the impact of the asset acquisition from Shell. The increase in other operating expense was largely attributed to higher plug and abandonment accretion expense, employee compensation and personnel costs. The increase in interest expense was primarily driven by additional intercompany long-term borrowings from the Company’s long-term debt issuance in June 2020. Finally, the Exploration and Production segment 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.

Pipeline and Storage

Pipeline and Storage Operating Revenues


	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2021		2020		Increase (Decrease)		2021		2020		Increase (Decrease)
Firm Transportation	$	64,405	$	58,240	$	6,165	$	129,004	$	111,431	$	17,573
Interruptible Transportation	243		214		29		469		475		(6)
	64,648		58,454		6,194		129,473		111,906		17,567
Firm Storage Service	21,220		20,523		697		41,705		38,944		2,761
Interruptible Storage Service	11		1		10		43		6		37
Other	825		267		558		3,248		609		2,639
	$	86,704	$	79,245	$	7,459	$	174,469	$	151,465	$	23,004

Pipeline and Storage Throughput


	Three Months Ended March 31,			Six Months Ended March 31,
(MMcf)	2021	2020	Increase (Decrease)	2021	2020	Increase (Decrease)
Firm Transportation	209,496	195,799	13,697	412,524	404,447	8,077
Interruptible Transportation	435	531	(96)	1,024	1,244	(220)
	209,931	196,330	13,601	413,548	405,691	7,857

2021 Compared with 2020

Operating revenues for the Pipeline and Storage segment increased $7.5 million for the quarter ended March 31, 2021 as compared with the quarter ended March 31, 2020. The increase in operating revenues was primarily due to an increase in transportation revenues of $6.2 million and an increase in storage revenues of $0.7 million. The increase in transportation revenues was partially attributable to new demand charges for transportation service from the Empire North Project, which was placed into service during the fourth quarter of fiscal 2020. Transportation revenues also increased due to an increase in Supply Corporation's transportation rates effective February 1, 2020 in accordance with Supply Corporation's rate case settlement. The settlement was approved by the FERC on June 1, 2020. The increase in transportation revenues was partially offset by the termination of a greenhouse gas (GHG) surcharge associated with Supply Corporation's rate case settlement mentioned above

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and also by contract terminations and restructurings. The increase in storage revenues was primarily attributable to an increase in Supply Corporation's storage rates related to its aforementioned rate case settlement.

Operating revenues for the Pipeline and Storage segment increased $23.0 million for the six months ended March 31, 2021 as compared with the six months ended March 31, 2020. The increase in operating revenues was primarily due to an increase in transportation revenues of $17.6 million, an increase in storage revenues of $2.8 million and an increase in other revenues of $2.6 million. The increase in transportation revenues was primarily due to new demand charges for transportation service from the Empire North Project being placed into service as mentioned above. Transportation revenue also increased due to an increase in Supply Corporation's transportation rates effective February 1, 2020 related to the rate case settlement mentioned above. The increase in transportation revenues was partially offset by the reduction of the GHG surcharge associated with Supply Corporation's rate case settlement mentioned above, and also by contract terminations and restructurings and a decrease in revenues from short-term seasonal contracts. The increase in storage revenues was primarily attributable to an increase in Supply Corporation's storage rates related to its aforementioned rate case settlement. The increase in other revenues was primarily due to proceeds received during the quarter ended December 31, 2020 as a result of a contract buyout.

Transportation volume for the quarter ended March 31, 2021 increased by 13.6 Bcf from the prior year's quarter, primarily due to incremental volume from the Empire North Project, which was brought online on September 15, 2020. For the six months ended March 31, 2021, transportation volume increased by 7.9 Bcf from the prior year's six-month period ended March 31, 2020. The increase in transportation volume for the six-month period primarily reflects an increase in volume from the Empire North Project, partially offset by a decrease in volume from a decline in capacity utilization by certain contract shippers and contract terminations and restructurings. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

The Pipeline and Storage segment’s earnings for the quarter ended March 31, 2021 were $24.9 million, an increase of $2.8 million when compared with earnings of $22.1 million for the quarter ended March 31, 2020. The increase in earnings was primarily due to the earnings impact of higher operating revenues of $5.9 million, as discussed above, along with a decrease in operating expenses ($1.8 million). The decrease in operating expenses was mainly due to a decrease in the reserve for preliminary project costs, partially offset by an increase in operating costs, which were primarily power costs related to Empire's electric motor drive compressor station placed into service as part of the Empire North Project mentioned above, as well as an increase in personnel and technology-related costs. Power costs related to Empire’s electric motor drive compressor station are offset by an equal amount of revenue due to a surcharge mechanism. These earnings increases were partially offset by an increase in depreciation expense ($1.9 million), higher interest expense ($2.7 million) and a decrease in other income ($0.4 million). The increase in depreciation expense was primarily due to an increase in Supply Corporation's depreciation rates associated with its rate case settlement as well as incremental depreciation from the Empire North Project going into service, both mentioned above. The increase in interest expense was primarily due to interest on additional intercompany long-term borrowings associated with the Company's June 2020 debt issuance. The decrease in other income was mainly due to a decrease in allowance for funds used during construction (equity component) as a result of the Empire North Project being placed in service during the fourth quarter of fiscal 2020, partially offset by higher non-service pension and post-retirement benefit costs in the current quarter compared to non-service pension and post-retirement income in the prior year's quarter.

The Pipeline and Storage segment’s earnings for the six months ended March 31, 2021 were $49.1 million, an increase of $8.9 million when compared with earnings of $40.2 million for the six months ended March 31, 2020. The increase in earnings was primarily due to the earnings impact of higher operating revenues of $18.2 million, as discussed above, combined with a decrease in operating expenses ($1.6 million) and lower income tax expense ($0.5 million). The decrease in operating expenses was primarily due to a decrease in the reserve for preliminary project costs, partially offset by an increase in operating costs, which were primarily power costs related to Empire's electric motor drive compressor station, discussed in the previous paragraph, as well as an increase in personnel costs. The decrease in income tax expense was due to passing back excess deferred taxes to rate payers as a result of the 2017 Tax Reform Act per the Supply Corporation rate case settlement, partially offset by permanent differences related to allowance for funds used during construction and stock compensation activity. These earnings increases were partially offset by an increase in depreciation expense ($4.9 million), higher interest expense ($5.5 million), as well as a decrease in other income ($0.9 million). The increase in depreciation expense was due to an increase in Supply Corporation's depreciation rates associated with its rate case settlement as well as incremental depreciation from the Empire North Project going into service, both mentioned above. The increase in interest expense was primarily due to interest on additional intercompany long-term borrowings associated with the Company's June 2020 debt issuance. The decrease in other income was mainly due to a decrease in allowance for funds used during construction (equity component) as a result of the Empire North Project being placed in service during the fourth quarter of fiscal 2020, partially offset by higher non-service

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pension and post-retirement benefit costs in the current six-month period compared to non-service pension and post-retirement income in the six months ended March 31, 2020.

Gathering

Gathering Operating Revenues


	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2021		2020		Increase (Decrease)		2021		2020		Increase (Decrease)
Gathering Revenues	$	50,262	$	35,267	$	14,995	$	97,270	$	70,055	$	27,215

Gathering Volume


	Three Months Ended March 31,			Six Months Ended March 31,
	2021	2020	Increase (Decrease)	2021	2020	Increase (Decrease)
Gathered Volume - (MMcf)	95,121	65,134	29,987	183,466	129,526	53,940

2021 Compared with 2020

Operating revenues for the Gathering segment increased $15.0 million for the quarter ended March 31, 2021 as compared with the quarter ended March 31, 2020, which was driven primarily by a 30.0 Bcf increase in gathered volume. The July 31, 2020 acquisition of midstream gathering assets from Shell was the primary driver of this increase as the Tioga gathering system (the name given to the acquired assets) recorded 20.0 Bcf of gathered volume for the quarter ended March 31, 2021. Other contributors to the increase included the Clermont gathering system, which experienced a 3.8 Bcf increase in gathered volume, the Wellsboro gathering system, which experienced a 3.5 Bcf increase in gathered volume and the Trout Run gathering system, which experienced a 3.2 Bcf increase in gathered volume. These increases were partially offset by a 0.5 Bcf decrease in gathered volume at the Covington gathering system. The net increase in gathered volume can be attributed primarily to the increase in Seneca's gross natural gas production in the Appalachian region, as discussed above.

Operating revenues for the Gathering segment increased $27.2 million for the six months ended March 31, 2021 as compared with the six months ended March 31, 2020, which was driven primarily by a 53.9 Bcf increase in gathered volume. This increase was primarily due to the Tioga gathering system which recorded a 41.0 Bcf increase in gathered volume. Other contributors to the increase included the Clermont, Wellsboro and Trout Run gathering systems, which recorded increases of 7.9 Bcf, 4.4 Bcf and 2.1 Bcf, respectively. These increases were partially offset by a 1.5 Bcf decrease in gathered volume on the Covington gathering system. The net increase in gathered volume can be attributed to the net increase in Seneca's natural gas production, as discussed above.

The Gathering segment’s earnings for the quarter ended March 31, 2021 were $20.7 million, an increase of $0.8 million when compared with earnings of $19.9 million for the quarter ended March 31, 2020. The increase in earnings was mainly due to higher gathering revenues ($11.8 million) driven by the increase in gathered volume, as discussed above. Additionally, the Gathering segment's earnings were negatively impacted ($3.8 million) as a result of the Gathering segment's recognition of an income tax benefit that was recorded during the quarter ended March 31, 2020 as an offset to the valuation allowance established in the Exploration and Production segment. This offset is a result of the Gathering and Exploration and Production segments' subsidiaries being included in the same state tax return. Taxable income generated in the Gathering segment is used to offset taxable losses in the Exploration and Production segment, which provided the opportunity to reduce the valuation allowance recorded in the Exploration and Production segment. Further, earnings decreased due to higher operating expenses ($2.5 million), higher depreciation expense ($2.2 million) and higher interest expense ($1.6 million), with each of these increases primarily being a result of the acquisition of midstream gathering assets from Shell on July 31, 2020. The increase in operating expenses was largely due to higher lease compression expense associated with the Tioga gathering system. The increase in depreciation expense was largely due to higher plant balances associated with the Tioga gathering system. The increase in interest expense was primarily driven by additional intercompany long-term borrowings from the Company's long-term debt issuance in June 2020. Finally, the Gathering segment recognized a loss in March 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.

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The Gathering segment’s earnings for the six months ended March 31, 2021 were $41.3 million, an increase of $5.5 million when compared with earnings of $35.8 million for the six months ended March 31, 2020. The increase in earnings was mainly due to the higher gathering revenues ($21.5 million) driven by the increase in gathered volume, as discussed above. Additionally, the Gathering segment's earnings were negatively impacted ($3.8 million) as a result of the Gathering segment's recognition of an income tax benefit that was recorded during the quarter ended March 31, 2020 as an offset to the valuation allowance established in the Exploration and Production segment. This offset is a result of the Gathering and Exploration and Production segments’ subsidiaries filing a combined state tax return (as discussed above). Further, earnings decreased due to higher operating expenses ($3.9 million), higher depreciation expense ($4.4 million) and higher interest expense ($3.1 million), with each of these increases primarily being a result of the acquisition of midstream gathering assets from Shell on July 31, 2020. The increase in operating expenses was largely due to higher lease compression expense associated with the Tioga gathering system. The increase in depreciation expense was largely due to higher plant balances associated with the Tioga gathering system. The increase in interest expense was primarily driven by additional intercompany long-term borrowings from the Company's long-term debt issuance in June 2020. Finally, the Gathering segment recognized a loss in March 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.

Utility

Utility Operating Revenues


	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2021		2020		Increase (Decrease)		2021		2020		Increase (Decrease)
Retail Sales Revenues:
Residential	$	204,398	$	187,932	$	16,466	$	345,241	$	333,547	$	11,694
Commercial	28,196		26,213		1,983		46,404		45,874		530
Industrial	1,370		1,162		208		2,301		2,429		(128)
	233,964		215,307		18,657		393,946		381,850		12,096
Transportation	41,436		42,710		(1,274)		72,066		76,316		(4,250)

Other	(4,519)		(3,524)		(995)		(6,131)		(6,848)		717
	$	270,881	$	254,493	$	16,388	$	459,881	$	451,318	$	8,563

Utility Throughput


	Three Months Ended March 31,			Six Months Ended March 31,
(MMcf)	2021	2020	Increase (Decrease)	2021	2020	Increase (Decrease)
Retail Sales:
Residential	29,052	26,155	2,897	47,465	45,631	1,834
Commercial	4,309	4,033	276	6,836	6,846	(10)
Industrial	223	183	40	376	400	(24)
	33,584	30,371	3,213	54,677	52,877	1,800
Transportation	24,584	25,157	(573)	42,518	45,712	(3,194)

	58,168	55,528	2,640	97,195	98,589	(1,394)

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Degree Days


Three Months Ended March 31,				Percent Colder (Warmer) Than
	Normal	2021	2020	Normal(1)		Prior Year(1)
Buffalo, NY	3,290	2,978	2,738	(9.5)	%	8.8	%
Erie, PA	3,108	2,750	2,555	(11.5)	%	7.6	%
Six Months Ended March 31,
Buffalo, NY	5,543	4,899	4,970	(11.6)	%	(1.4)	%
Erie, PA	5,152	4,447	4,461	(13.7)	%	(0.3)	%

(1)Percents compare actual 2021 degree days to normal degree days and actual 2021 degree days to actual 2020 degree days.

2021 Compared with 2020

Operating revenues for the Utility segment increased $16.4 million for the quarter ended March 31, 2021 as compared with the quarter ended March 31, 2020. The increase primarily resulted from an $18.7 million increase in retail gas sales revenue. The increase in retail gas sales revenue was largely due to a modest increase in the cost of gas sold (per Mcf) coupled with higher throughput due to colder weather. This increase was partially offset by a $1.3 million decrease in transportation revenues and a $1.0 million decrease in other revenues. The decline in transportation revenues was primarily due to a 0.6 Bcf decrease in transportation throughput as residential customers switched from transportation service to retail service. The decrease in other revenues was largely due to the impact of other regulatory true-up adjustments ($0.9 million).

Operating revenues for the Utility segment increased $8.6 million for the six months ended March 31, 2021 as compared with the six months ended March 31, 2020. The increase largely resulted from a $12.1 million increase in retail gas sales revenue and a $0.7 million increase in other revenues. The increase in retail gas sales revenue was largely a result of the migration of residential transportation customers to retail. The increase in other revenues was largely due to a smaller estimated refund provision recorded during the six months ended March 31, 2021 ($1.2 million), slightly offset by other regulatory true-up adjustments ($0.5 million). These increases were partially offset by a $4.3 million decrease in transportation revenues. The decrease in transportation revenues was primarily due to a 3.2 Bcf decrease in transportation throughput due to the migration of residential transportation customers to retail and slightly warmer weather.

The Utility segment’s earnings for the quarter ended March 31, 2021 were $32.0 million, an increase of $0.5 million when compared with earnings of $31.5 million for the quarter ended March 31, 2020. The increase in earnings was largely attributable to higher usage and weather on customer margins ($1.5 million) and the impact of a system modernization tracker in New York ($1.6 million). These increases were slightly offset by higher regulatory true-up adjustments ($1.2 million) and higher operating expenses ($1.4 million), which were primarily a result of higher personnel costs and an increase to the allowance for uncollectible accounts. The increase to 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 current economic environment.

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 March 31, 2021, the WNC increased earnings by approximately $1.6 million, as the weather was warmer than normal. For the quarter ended March 31, 2020, the WNC increased earnings by approximately $3.7 million, as the weather was warmer than normal.

The Utility segment’s earnings for the six months ended March 31, 2021 were $55.1 million, a decrease of $3.0 million when compared with earnings of $58.1 million for the six months ended March 31, 2020. The decrease in earnings was largely attributable to higher operating expenses ($3.3 million), which were primarily a result of higher personnel costs and an increase to the allowance for uncollectible accounts, both of which are discussed above, higher income tax expense ($1.2 million) and the impact of regulatory true-up adjustments ($1.0 million). These decreases were slightly offset by the positive earnings impact related to the system modernization tracker ($2.5 million) and the impacts of higher usage on customer margins ($0.3 million).

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For the six months ended March 31, 2021, the WNC increased earnings by approximately $3.2 million, as the weather was warmer than normal. For the six months ended March 31, 2020, the WNC increased earnings by approximately $3.6 million, as the weather was warmer than normal.

Corporate and All Other

2021 Compared with 2020

Corporate and All Other operations had a loss of $2.1 million for the quarter ended March 31, 2021, which was $2.2 million lower than the loss of $4.3 million for the quarter ended March 31, 2020. The increase in earnings was primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the quarter ended March 31, 2020, the Company recorded unrealized losses of $4.3 million. During the quarter ended March 31, 2021, the Company recorded unrealized gains of $0.7 million. Offsetting this positive impact, the remaining $2.8 million variation largely represents lower earnings from the Company’s energy marketing operations, which sold its commercial and industrial contracts and certain other assets in August 2020, and its timber operations, which ended with the sale of substantially all timber properties in December 2020.

For the six months ended March 31, 2021, Corporate and All Other operations had earnings of $37.6 million, an increase of $39.9 million when compared with a loss of $2.3 million for the six months ended March 31, 2020. The increase in earnings was primarily attributable to the gain recognized on the sale of timber properties by Seneca's Northeast Division for $51.1 million ($37.0 million after-tax). The increase can also be attributed to changes in unrealized losses on investments in equity securities. During the six months ended March 31, 2020, the Company recorded unrealized losses of $5.1 million. During the six months ended March 31, 2021, the Company recorded unrealized losses of $0.4 million. Offsetting these positive factors, the remaining $1.8 million variation largely represents lower earnings from the Company’s energy marketing operations, which sold its commercial and industrial contracts and certain other assets in August 2020, and its timber operations, which ended with the sale of substantially all timber properties in December 2020. Please refer to Note 2 – Asset Acquisitions and Divestitures in Item 1 for further discussion of the sale of timber properties.

Other Income (Deductions)

Net other deductions on the Consolidated Statement of Income decreased $6.6 million for the quarter ended March 31, 2021 as compared to the quarter ended March 31, 2020. For the six months ended March 31, 2021, net other deductions decreased $7.5 million as compared to the six months ended March 31, 2020. These decreases are primarily attributable to changes in unrealized gains and losses on investments in equity securities. During the quarter ended March 31, 2020, the Company recorded pre-tax unrealized losses of $5.4 million. During the quarter ended March 31, 2021, the Company recorded pre-tax unrealized gains of $0.8 million. During the six months ended March 31, 2020, the Company recorded pre-tax unrealized losses of $6.4 million. During the six months ended March 31, 2021, the Company recorded pre-tax unrealized losses of $0.5 million.

Interest Expense on Long-Term Debt

Interest expense on long-term debt on the Consolidated Statement of Income increased $23.6 million for the quarter ended March 31, 2021 as compared to the quarter ended March 31, 2020. For the six months ended March 31, 2021, interest expense on long-term debt increased $30.4 million as compared with the six months ended March 31, 2020. The Company redeemed $500.0 million of 4.90% notes on March 11, 2021 and paid a call premium of $15.7 million that was recorded as interest expense on long-term debt. The remaining increase is due largely to a higher average long-term debt balance stemming from the issuance of $500.0 million of 5.50% notes in June 2020.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary sources of cash during the six-month period ended March 31, 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's primary sources of cash during the six-month period ended March 31, 2020 consisted of cash provided by operating activities and net proceeds from short-term borrowings.

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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 and stock-based compensation.

Cash provided by operating activities in the Utility and Pipeline and Storage segments may vary substantially from period to period because of the impact of rate cases. In the Utility segment, supplier refunds, over- or under-recovered purchased gas costs and weather may also significantly impact cash flow. The impact of weather on cash flow is tempered in the Utility segment’s New York rate jurisdiction by its WNC and in the Pipeline and Storage segment by the straight fixed-variable rate design used by Supply Corporation and Empire.

Because of the seasonal nature of the heating business in the Utility 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 and crude oil 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 $417.1 million for the six months ended March 31, 2021, an increase of $26.1 million compared with $391.0 million provided by operating activities for the six months ended March 31, 2020. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Pipeline and Storage segment, the Exploration and Production segment, and the Gathering segment, slightly offset by lower cash provided by operating activities in the Utility segment. The increase in the Pipeline and Storage segment was primarily due to higher cash receipts from transportation and storage service, which largely reflects an increase in Supply Corporation's transportation and storage rates effective February 1, 2020 and an increase in demand charges for transportation services from the Empire North Project that was placed in service during September 2020 and the Line N to Monaca Project that was placed in service in November 2019. The increase in the 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, largely stemming from the July 31, 2020 acquisition of upstream assets and midstream gathering assets from Shell. The decrease in the Utility segment is primarily due to the timing of gas cost recovery and the timing of receivable collections.

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Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $322.4 million during the six months ended March 31, 2021 and $373.9 million during the six months ended March 31, 2020. The table below presents these expenditures:


Total Expenditures for Long-Lived Assets
Six Months Ended March 31,	2021			2020			Increase (Decrease)
(Millions)
Exploration and Production:
Capital Expenditures	$	169.6	(1)	$	229.3	(2)	$	(59.7)
Pipeline and Storage:
Capital Expenditures	91.7		(1)	82.7		(2)	9.0
Gathering:
Capital Expenditures	19.4		(1)	24.9		(2)	(5.5)
Utility:
Capital Expenditures	41.8		(1)	36.6		(2)	5.2
All Other:
Capital Expenditures	0.1			0.4			(0.3)
Eliminations	(0.2)			—			(0.2)
	$	322.4		$	373.9		$	(51.5)

(1)At March 31, 2021, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $44.5 million, $16.0 million, $2.9 million and $4.7 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.

(2)At March 31, 2020, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $41.2 million, $9.7 million, $4.4 million and $4.2 million, respectively, of non-cash capital expenditures. At September 30, 2019, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $38.0 million, $23.8 million, $6.6 million and $12.7 million, respectively, of non-cash capital expenditures.

Exploration and Production

The Exploration and Production segment capital expenditures for the six months ended March 31, 2021 were primarily well drilling and completion expenditures and included approximately $167.1 million for the Appalachian region (including $58.2 million in the Marcellus Shale area and $97.7 million in the Utica Shale area) and $2.5 million for the West Coast region. These amounts included approximately $62.2 million spent to develop proved undeveloped reserves.

The Exploration and Production segment capital expenditures for the six months ended March 31, 2020 were primarily well drilling and completion expenditures and included approximately $207.1 million for the Appalachian region (including $73.9 million in the Marcellus Shale area and $126.4 million in the Utica Shale area) and $22.2 million for the West Coast region. These amounts included approximately $144.2 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2021 were primarily for expenditures related to Supply Corporation's FM100 Project ($60.8 million), which is discussed below. In addition, the Pipeline and Storage segment capital expenditures for the six months ended March 31, 2021 included additions, improvements and replacements to this segment’s transmission and gas storage systems. The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2020 were primarily for expenditures related to the Empire North Project ($45.5 million), and also included $3.4 million of expenditures related to Supply Corporation's Line N to Monaca Project. In addition, the Pipeline and Storage segment capital expenditures for the six months ended March 31, 2020 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

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

Supply Corporation has developed its FM100 Project, which will upgrade a 1950's era pipeline in northwestern Pennsylvania and create 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. A precedent agreement has been executed by Supply Corporation and Transco whereby this additional capacity is expected to be leased by Transco ("Lease") and become part of a Transco expansion project ("Leidy South") that will create incremental transportation capacity to Transco Zone 6 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. FERC issued the Section 7(c) certificate on July 17, 2020 and Supply Corporation accepted it on August 14, 2020. FERC issued a Notice to Proceed on February 22, 2021, and the Lease was fully executed on that date. Construction activities are fully in progress. The FM100 Project has a target in-service date of late calendar 2021 and a preliminary cost estimate of approximately $280 million. As of March 31, 2021, approximately $67.9 million has been capitalized as Construction Work in Progress for this project.

Supply Corporation and Empire have developed a project which would move significant prospective Marcellus 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). The United States Court of Appeals for the Second Circuit (the “Second Circuit Court of Appeals”) held in the Company’s favor in its appeal of this decision, vacating the NYDEC denial and remanding to the NYDEC. The NYDEC subsequently issued a second denial, which the Company has appealed to the Second Circuit Court of Appeals. The court has held this appeal in abeyance pending the outcome of the FERC waiver appeal, described below. While the Company’s initial appeal was pending before the Second Circuit Court of Appeals, the 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. Recently, 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. 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 pending legal actions. As of March 31, 2021, approximately $55.6 million has been spent on the Northern Access project, including $24.0 million that has been spent to study the project, for which no reserve has been established. The remaining $31.6 million spent on the project is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2021.

Gathering

The majority of the Gathering segment capital expenditures for the six months ended March 31, 2021 included expenditures related to the continued expansion of Midstream Company's Clermont and Wellsboro gathering systems, as discussed below. Midstream Company spent $11.6 million and $3.7 million, respectively, during the six months ended March 31, 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,

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including increased compression horsepower at the Clermont and Wellsboro gathering systems and additional dehydration on the Clermont gathering system.

The majority of the Gathering segment capital expenditures for the six months ended March 31, 2020 were for the continued expansion of Midstream Company's Trout Run, Clermont and Wellsboro gathering systems. Midstream Company spent $12.0 million, $6.9 million and $6.0 million, respectively, during the six months ended March 31, 2020 on the development of the Trout Run, Clermont and Wellsboro gathering systems. These expenditures were largely attributable to new gathering pipelines and the continued development of centralized station facilities, including increased compression horsepower at the Trout Run gathering system, the first phase of compression at the Wellsboro gathering system, and additional dehydration at 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 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.

NFG Midstream Trout Run, LLC, a wholly owned subsidiary of Midstream Company, continues to develop its Trout Run gathering system in Lycoming County, Pennsylvania. The Trout Run gathering system was initially placed in service in May 2012. The current system consists of three compressor stations and backbone and in-field gathering pipelines.

Utility

The majority of the Utility segment capital expenditures for the six months ended March 31, 2021 and March 31, 2020 were made for main and service line improvements and replacements that enhance the reliability and safety of the system and reduce emissions. Expenditures were also made for main extensions.

Other Investing Activities

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. 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 2020 Form 10-K for additional information concerning the Company’s acquisition of certain upstream assets and midstream gathering assets from Shell.

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 six months ended March 31, 2021 and March 31, 2020, 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 and short-term borrowings 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 impacted by natural gas and crude oil production and the associated commodity price realizations.

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, 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

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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 decreased $30.0 million when comparing the balance sheet at March 31, 2021 to the balance sheet at September 30, 2020. The maximum amount of short-term debt outstanding during the six months ended March 31, 2021 was $145.8 million. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. At March 31, 2021, the Company did not have any outstanding short-term notes payable to banks or commercial paper outstanding.

The Company maintains $1.0 billion of unsecured committed revolving credit access across two facilities. On October 25, 2018, the Company entered into a Fourth Amended and Restated Credit Agreement ("Credit Agreement") with a syndicate of twelve banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through October 25, 2023. In addition to the Credit Agreement, on February 3, 2021, the Company amended its existing 364-Day Credit Agreement to extend the maturity date thereof from May 3, 2021 to December 30, 2022, and to increase the lenders' commitments thereunder from $200.0 million to $250.0 million, among other changes (as amended, the "Amended 364-Day Credit Agreement"). Twelve banks are parties to the Amended 364-Day Credit Agreement, all of which are also lenders under the Credit Agreement. The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future.

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 $250 million. This provision also applies to the Amended 364-Day Credit Agreement. Since July 1, 2018, the Company recorded non-cash, after-tax ceiling test impairments totaling $381.4 million. As a result, at March 31, 2021, $190.7 million was added back to the Company's total capitalization for purposes of the facility, and the Company’s debt to capitalization ratio, as calculated under the facility, was .53. The constraints specified in both the Credit Agreement and Amended 364-Day Credit Agreement would have permitted an additional $1.62 billion in short-term and/or long-term debt to be outstanding at March 31, 2021 (further limited by the indenture covenants discussed below) 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 and Amended 364-Day Credit Agreement contain a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement and the Amended 364-Day Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity.

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

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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%, if certain change of control events involving a material subsidiary result in a downgrade of the credit rating assigned to the notes below investment grade (or if the credit rating assigned to the notes is subsequently upgraded). The proceeds of this debt issuance were used for general corporate purposes, including the redemption of $500.0 million of 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.

None of the Company's long-term debt as of March 31, 2021 and September 30, 2020 had a maturity date within the following twelve-month period.

The Company’s embedded cost of long-term debt was 4.48% and 4.69% at March 31, 2021 and March 31, 2020, respectively.

Under the Company’s existing indenture covenants at March 31, 2021, the Company would have been permitted to issue up to a maximum of approximately $57.1 million in additional unsubordinated long-term indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace existing debt. The maximum amount of additional long-term indebtedness noted above that would have been permitted to be issued under the indenture covenants at March 31, 2021 was impacted by non-cash impairments of oil and gas properties recognized during fiscal 2020 and the quarter ended December 31, 2020. The Company's present liquidity position is believed to be adequate to satisfy known demands. However, if the Company were to experience a significant loss in the future (for example, as a result of an impairment of oil and gas properties), it is possible, depending on factors including the magnitude of the loss, that these indenture covenants would restrict the Company's ability to issue additional unsubordinated long-term indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. This would not preclude the Company from issuing new indebtedness to replace existing 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 March 31, 2021) 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 six months ended March 31, 2021, the Company contributed $14.6 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $2.1 million to its VEBA trusts for its other post-retirement benefits. In the remainder of 2021, the Company expects its contributions to the Retirement Plan to be in the range of $5.0 million to $10.0 million. In the remainder of 2021, the Company expects its contributions to its VEBA trusts to be in the range of $0.5 million to $1.0 million.

The Company, in its Exploration and Production segment, has extended the term of a contractual obligation related to hydraulic fracturing during the quarter ended December 31, 2020. This extension is valued at approximately $82.3 million and extends the contractual obligation through December 31, 2022.

Market Risk Sensitive Instruments

On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act includes provisions related to the swaps and over-the-counter derivatives markets that are designed to promote transparency, mitigate systemic risk and protect

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against market abuse. Although regulators have issued certain regulations, other rules that may impact the Company have yet to be finalized.

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

Finally, given the additional authority granted to the CFTC on anti-market manipulation, anti-fraud and disruptive trading practices, it is difficult to predict how the evolving enforcement priorities of the CFTC will impact 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.

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 2020 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

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 directed the implementation of an earnings sharing mechanism to be in place beginning on April 1, 2018.

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related impact on the Company is uncertain. The Company is anticipating that customer non-payment may increase given higher natural gas usage and the resulting increase in costs for customers. It is uncertain at this point as to whether there would be any regulatory relief for utilities with regard to an increase in costs associated with the COVID-19 pandemic, but it is one of many issues currently being considered in a generic NYPSC proceeding entitled “Proceeding on Motion of the Commission Regarding the Effects of COVID-19 on Utility Service” (Case No. 20-M-0266). Correspondence from NYPSC Staff has recommended that utilities rely on existing avenues of relief for these costs, and has identified additional, more stringent requirements that must be met to achieve relief.

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.

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 more 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. A number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines and is in the process of evaluating cap-and-trade programs (e.g., Regional Greenhouse Gas Initiative). In California, the Company currently complies with California cap-and-trade rules, which increases the

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Company's cost of environmental compliance in its Exploration and Production segment. On April 23, 2021, California's Governor issued an executive order directing CalGem to stop issuing fracking permits by 2024, which does not have a direct impact on the plans of the Exploration and Production segment as those plans do not involve fracking. The executive order also directed the California Air Resources Board to investigate phasing out oil extraction by 2045, which may result in permitting delays and new legislative action in support of the directive. 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. Federal, state or local governments may provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. The NYPSC, for example, initiated a proceeding to consider climate-related financial disclosures at the utility operating company level, and the NY 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. 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.

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:

1.The length and severity of the recent COVID-19 pandemic, including its impacts across our businesses on demand, operations, global supply chains and liquidity;

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

3.Changes in the price of natural gas or oil;

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

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

6.Financial and economic conditions, including the availability of credit, and occurrences affecting the Company’s ability to obtain financing on acceptable terms for working capital, capital expenditures and other investments,

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including any downgrades in the Company’s credit ratings and changes in interest rates and other capital market conditions;

7.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;

8.Delays or changes in costs or 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;

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

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

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

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

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

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

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

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

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

18.Uncertainty of oil and gas reserve estimates;

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

20.Changes in demographic patterns and weather conditions;

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

22.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;

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

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

25.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.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and 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 March 31, 2021.

Changes in Internal Control Over Financial Reporting

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended March 31, 2021 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 2020 Form 10-K, as amended by Item 1A of Part II of the Company's Form 10-Q for the quarter ended December 31, 2020, have not materially changed other than as set forth below. The risk factors presented below supersede the risk factors having the same caption in the 2020 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2020 Form 10-K and the December 31, 2020 Form 10-Q. The impact of the COVID-19 pandemic may also exacerbate other risks discussed in Item 1A of the Company’s 2020 Form 10-K, any of which could have a material effect on us. This situation is changing rapidly and additional impacts may arise that we are not aware of currently.

The Company is dependent on capital and credit markets to successfully execute its business strategies.

The Company relies upon short-term bank borrowings, commercial paper markets and longer-term capital markets to finance capital requirements not satisfied by cash flow from operations. The Company is dependent on these capital sources to provide capital to its subsidiaries to fund operations, acquire, maintain and develop properties, and execute growth strategies. The availability and cost of credit sources may be cyclical and these capital sources may not remain available to the Company. Continued turmoil in credit markets, due to the ongoing COVID-19 pandemic or otherwise, may make it difficult for the Company to obtain financing on acceptable terms or at all for working capital, capital expenditures and other investments, or to refinance existing debt. These difficulties could adversely affect the Company's growth strategies, operations and financial performance.

The Company's ability to borrow under its credit facilities and commercial paper agreements, and its ability to issue long-term debt under its indentures, depend on the Company's compliance with its obligations under the facilities, agreements and indentures. For example, to issue incremental long-term debt, the Company must meet an interest coverage test under its 1974 indenture. In general, the Company’s operating income, subject to certain adjustments, over a consecutive 12-month period within the 15 months preceding the debt issuance, must be not less than two times the total annual interest charges on the Company’s long-term debt, taking into account the incremental issuance. In addition, the Company must maintain a ratio of long-term debt to consolidated assets (as defined under the 1974 indenture) of not more than 60%. Depending on their

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magnitude, factors that reduce the Company’s operating income and/or consolidated assets, including impairments (i.e., write-downs) of the Company’s oil and natural gas properties, could contribute to the Company’s inability to meet the interest coverage test or debt-to-assets ratio.

In addition, the Company's short-term bank loans and commercial paper are in the form of floating rate debt or debt that may have rates fixed for very short periods of time, resulting in exposure to interest rate fluctuations in the absence of interest rate hedging transactions. The cost of long-term debt, the interest rates on the Company's short-term bank loans and commercial paper and the ability of the Company to issue commercial paper are affected by its credit ratings published by S&P, Moody's Investors Service, Inc. and Fitch Ratings, Inc. 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. On March 27, 2020, the Company was downgraded by S&P to a rating of BBB- with a negative outlook, which S&P revised on June 3, 2020 to a rating of BBB- with a stable outlook. Combined with current ratings from other credit rating agencies, that downgrade increased the Company's short-term borrowing costs under its Credit Agreement. Additionally, $1.1 billion of the Company’s outstanding long-term debt would be subject to an interest rate increase if certain fundamental changes occur that involve a material subsidiary and result in a downgrade of a credit rating assigned to the notes below investment grade. In addition to the $1.1 billion, another $500 million of the Company’s outstanding long-term debt would be subject to an interest rate increase based solely on a downgrade of a credit rating assigned to the notes below investment grade, regardless of any additional fundamental changes. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets.

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

Climate change could create physical risks, which may adversely affect the Company’s operations. Physical risks include changes in weather conditions, which could cause demand for gas to increase or decrease. If there were to be any impacts from climate change to the Company’s operations and financial results, the Company expects that they would likely occur over a long period of time and thus are difficult to quantify with any degree of specificity. Extreme weather events may result in adverse physical effects on portions of the country’s gas infrastructure, which could disrupt the Company’s supply chain and ultimately its operations. Disruption of production activities, and transportation and distribution systems could result in reduced operational efficiency, and customer service interruption.

Climate change, and the laws, regulations and other initiatives to address climate change, may impact the Company’s financial results. On January 20, 2021, the federal administration executed the instrument stating the country's intent to rejoin the Paris Agreement, the international effort to establish emissions reduction goals for signatory countries, thus allowing for the U.S. to reenter the Paris Agreement as an official party thirty days later. 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 recent 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. Recent executive orders from the new 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 development and production of gas and oil, establishment of a carbon tax and/or fee, 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 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 oil and gas industry which has resulted in permitting changes with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. With respect to its operations in California, the Company currently complies with California cap-and-trade guidelines, which increases the Company’s cost of environmental compliance in its Exploration and Production segment operation. In addition, the NYPSC initiated a proceeding to consider climate-related financial disclosures at the utility operating level, and the NY State legislature passed the CLCPA, which created emission reduction and electric generation mandates, and could ultimately impact the Utility segment’s customer base and the Utility segment’s business. The NY State legislature has recently proposed a bill known as the Climate and Community Investment Act, which if enacted as proposed, would impose a fee of $55 per short ton of carbon dioxide equivalent on any carbon-based fuels sold, used or brought into the state, with such fee beginning in 2022 and escalating thereafter. Legislation or regulation that aims to reduce greenhouse gas emissions could

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also include greenhouse gas emissions limits and reporting requirements, carbon taxes and/or similar fees on carbon dioxide or equivalent emissions, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. Additionally, the trend toward increased conservation, 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 7, MD&A under the heading “Environmental Matters” and subheading “Environmental Regulation.”

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.

The Company may be adversely affected by economic conditions and their impact on our suppliers and customers.

Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity, including the effects of the COVID-19 pandemic, could adversely affect the Company’s revenues and cash flows or restrict its future growth. The Company is monitoring and responding to the impacts of the COVID-19 pandemic across its businesses. To date, the COVID-19 pandemic has not had a material impact on the Company. However, the Company cannot predict the extent or duration of the outbreak or whether this rapidly evolving situation will have a material impact on the Company’s workforce, supply chain, operations or financial results, including potential regulatory responses to the financial impacts associated with the COVID-19 pandemic on the Company and its customers. Economic conditions in the Company’s utility service territories, along with legislative and regulatory prohibitions and/or limitations on terminations of service, also impact its collections of accounts receivable. For instance, New York initially enacted legislation that prohibits residential utility terminations for non-payment for the duration of the New York State COVID Disaster Emergency and while such legislation expired March 31, 2021, new proposed legislation, if enacted, would prohibit utility terminations for non-payment for residential and small commercial customers who experienced a change in financial circumstances due to the COVID-19 state of emergency, with such prohibition running for a period of one hundred eighty days after either the New York State COVID-19 state of emergency is lifted or expires or December 31, 2021, whichever is earlier. All of the Company’s segments are exposed to risks associated with the creditworthiness or performance of key suppliers and customers, many of which may be adversely affected by volatile conditions in the financial markets, including volatility caused by the ongoing COVID-19 pandemic. These conditions could result in financial instability or other adverse effects at any of our suppliers or customers. For example, counterparties to the Company’s commodity hedging arrangements or commodity sales contracts might not be able to perform their obligations under these arrangements or contracts. Customers of the Company’s Utility segment may have particular trouble paying their bills during periods of declining economic activity or high commodity prices, potentially resulting in increased bad debt expense and reduced earnings. The PaPUC has directed utilities to track extraordinary, nonrecurring incremental COVID-19 related expenses, and has authorized the creation of a utility regulatory asset but only for incremental COVID-19 related expenses incurred above those embedded in rates resulting from directives contained in certain PaPUC orders, therefore it is unclear at this time to what extent the PaPUC will, and whether the NYPSC will at all, allow rate recovery for COVID-19 pandemic related expenses. Similarly, if reductions were to occur in funding of the federal Low Income Home Energy Assistance Program, bad debt expense could increase and earnings could decrease. In addition, oil and gas exploration and production companies that are customers of the Company’s Pipeline and Storage segment may decide not to renew contracts for the same transportation capacity during periods of reduced production due to persistent low commodity prices. Any of these events could have a material adverse effect on the Company’s results of operations, financial condition and cash flows.

The Company could be adversely affected by the delayed recovery or disallowance of purchased gas costs incurred by the Utility segment.

Tariff rate schedules in each of the Utility segment’s service territories contain purchased gas adjustment clauses which permit Distribution Corporation to file with state regulators for rate adjustments to recover increases in the cost of purchased gas. Assuming those rate adjustments are granted, increases in the cost of purchased gas have no direct impact on profit margins. Distribution Corporation is required to file an accounting reconciliation with the regulators in each of the Utility segment’s service territories regarding the costs of purchased gas. Extreme weather events, variations in seasonal weather, and other events disrupting supply and/or demand could cause the Company to experience unforeseeable and unprecedented increases in the costs of purchased gas. Any prudently incurred gas costs could be subject to deferred recovery if regulators determine such costs are detrimental to customers in the short-term. Furthermore, there is a risk of disallowance of full recovery

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of these costs if regulators determine that Distribution Corporation was imprudent in making its gas purchases. Any material delayed recovery or disallowance of purchased gas costs could have a material adverse effect on cash flow and earnings.

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

On January 4, 2021, the Company issued a total of 10,670 unregistered shares of Company common stock to ten non-employee directors of the Company then serving on the Board of Directors of the Company, consisting of 1,067 shares to each such director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended March 31, 2021. The Company issued an additional 66 shares pursuant to the dividend reinvestment feature of the Company's Non-Employee Directors Deferred Compensation Plan to the six non-employee directors who elected to defer the shares issued for the quarter ended March 31, 2021, consisting of 11 shares to each such director. 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)
Jan. 1 - 31, 2021	13,642	$43.62	—	6,971,019
Feb. 1 - 28, 2021	13,461	$43.19	—	6,971,019
Mar. 1 - 31, 2021	11,848	$48.31	—	6,971,019
Total	38,951	$44.90	—	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 March 31, 2021, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 38,951 shares purchased other than through a publicly announced share repurchase program, 38,802 were purchased for the Company's 401(k) plans and 149 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 repurchase program has no expiration date. The Company has not repurchased any shares since September 17, 2008 and has no plans to make further purchases in the near future.

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Item 6. Exhibits


Exhibit Number						Description of Exhibit
•						Certificate of Amendment of Restated Certificate of Incorporation, as amended, of National Fuel Gas Company (Exhibit 3.1, Form 8-K dated March 16, 2021)

•						Amendment No. 1 to 364-Day Credit Agreement, dated as of February 3, 2021, among the Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (Exhibit 10.1, Form 8-K dated February 4, 2021)

•						Amendment No. 1 to Fourth Amended and Restated Credit Agreement, dated as of February 3, 2021, among the Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (Exhibit 10.2, Form 8-K dated February 4, 2021)

•						Officer's Certificate establishing 2.95% Notes due 2031, dated February 24, 2021 (Exhibit 4.1.1, Form 8-K dated February 24, 2021)

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 March 31, 2021 and 2020.

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 six months ended March 31, 2021 and 2020, (ii) the Consolidated Statements of Comprehensive Income for the three and six months ended March 31, 2021 and 2020, (iii) the Consolidated Balance Sheets at March 31, 2021 and September 30, 2020, (iv) the Consolidated Statements of Cash Flows for the six months ended March 31, 2021 and 2020 and (v) the Notes to Condensed Consolidated Financial Statements.

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

•						Incorporated herein by reference as indicated.

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

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SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the Registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.


NATIONAL FUEL GAS COMPANY
(Registrant)





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





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

Date: May 7, 2021

National Fuel Gas - 10-Q quarterly report FY2021 Q2

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