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, ~~2020~~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~~) (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, ~~2020: 86,573,652~~2021: 91,172,701 shares.

~~Regulatory Agencies~~
~~CFTC~~Regulatory Agencies
CFTC			Commodity Futures Trading Commission
EPA			United States Environmental Protection Agency
FASB			Financial Accounting Standards Board
FERC			Federal Energy Regulatory Commission
NYDEC			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
~~2019~~2020 Form 10-K			The Company’s Annual Report on Form 10-K for the year ended September 30, ~~2019~~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.



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)



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.

Table of Contents

Part I. Financial Information

Item 1. Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)


	Three Months Ended March 31,						Six Months Ended March 31,							Three Months Ended March 31,				Six Months Ended March 31,
(Thousands of U.S. Dollars, Except Per Common Share Amounts)	2020			2019			2020			2019			(Thousands of U.S. Dollars, Except Per Common Share Amounts)	2021		2020		2021		2020
INCOME													INCOME
Operating Revenues:													Operating Revenues:
Utility and Energy Marketing Revenues	$	282,634		$	357,654		$	510,660		$	629,747		Utility and Energy Marketing Revenues	$	270,849	$	282,634	$	460,315	$	510,660
Exploration and Production and Other Revenues	156,542			146,467			323,735			310,403			Exploration and Production and Other Revenues	220,281		156,542		412,316		323,735
Pipeline and Storage and Gathering Revenues	51,919			48,423			100,888			102,641			Pipeline and Storage and Gathering Revenues	59,985		51,919		119,644		100,888
	491,095			552,544			935,283			1,042,791				551,115		491,095		992,275		935,283

Operating Expenses:													Operating Expenses:
Purchased Gas	118,270			195,037			210,542			333,697			Purchased Gas	106,661		118,270		158,280		210,542
Operation and Maintenance:													Operation and Maintenance:
Utility and Energy Marketing	51,725			48,559			94,981			92,475			Utility and Energy Marketing	52,058		51,725		96,944		94,981
Exploration and Production and Other	39,959			40,141			76,652			72,936			Exploration and Production and Other	41,895		39,959		83,922		76,652
Pipeline and Storage and Gathering	27,305			27,249			53,190			52,182			Pipeline and Storage and Gathering	28,133		27,305		56,231		53,190
Property, Franchise and Other Taxes	22,743			22,535			45,887			46,540			Property, Franchise and Other Taxes	23,987		22,743		46,768		45,887
Depreciation, Depletion and Amortization	77,912			65,664			152,830			129,918			Depreciation, Depletion and Amortization	84,342		77,912		167,462		152,830
Impairment of Oil and Gas Producing Properties	177,761			—			177,761			—			Impairment of Oil and Gas Producing Properties	0		177,761		76,152		177,761
	515,675			399,185			811,843			727,748				337,076		515,675		685,759		811,843
Gain on Sale of Timber Properties													Gain on Sale of Timber Properties	0		0		51,066		0
Operating Income (Loss)	(24,580		)	153,359			123,440			315,043			Operating Income (Loss)	214,039		(24,580)		357,582		123,440
Other Income (Expense):													Other Income (Expense):

Other Income (Deductions)	(17,480		)	(5,919		)	(20,520		)	(15,521		)	Other Income (Deductions)	(10,875)		(17,480)		(13,051)		(20,520)
Interest Expense on Long-Term Debt	(25,270		)	(25,273		)	(50,713		)	(50,713		)	Interest Expense on Long-Term Debt	(48,820)		(25,270)		(81,076)		(50,713)
Other Interest Expense	(1,892		)	(1,787		)	(3,443		)	(2,860		)	Other Interest Expense	(1,698)		(1,892)		(3,618)		(3,443)
Income (Loss) Before Income Taxes	(69,222		)	120,380			48,764			245,949			Income (Loss) Before Income Taxes	152,646		(69,222)		259,837		48,764
Income Tax Expense	36,846			29,785			68,241			52,693			Income Tax Expense	40,210		36,846		69,627		68,241

Net Income (Loss) Available for Common Stock	(106,068		)	90,595			(19,477		)	193,256			Net Income (Loss) Available for Common Stock	112,436		(106,068)		190,210		(19,477)

EARNINGS REINVESTED IN THE BUSINESS													EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	1,320,592			1,172,334			1,272,601			1,098,900			Balance at Beginning of Period	1,028,844		1,320,592		991,630		1,272,601
	1,214,524			1,262,929			1,253,124			1,292,156				1,141,280		1,214,524		1,181,840		1,253,124

Dividends on Common Stock	(37,654		)	(36,678		)	(75,304		)	(73,342		)	Dividends on Common Stock	(40,562)		(37,654)		(81,122)		(75,304)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	—			—			(950		)	—			Cumulative Effect of Adoption of Authoritative Guidance for Hedging	0		0		0		(950)
Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities	—			—			—			7,437
Cumulative Effect of Adoption of Authoritative Guidance for Reclassification of Stranded Tax Effects	—			10,406			—			10,406

Balance at March 31	$	1,176,870		$	1,236,657		$	1,176,870		$	1,236,657		Balance at March 31	$	1,100,718	$	1,176,870	$	1,100,718	$	1,176,870

Earnings (Loss) Per Common Share:													Earnings (Loss) Per Common Share:
Basic:													Basic:
Net Income (Loss) Available for Common Stock	$	(1.23	)	$	1.05		$	(0.23	)	$	2.24		Net Income (Loss) Available for Common Stock	$	1.23	$	(1.23)	$	2.09	$	(0.23)
Diluted:													Diluted:
Net Income (Loss) Available for Common Stock	$	(1.23	)	$	1.04		$	(0.23	)	$	2.23		Net Income (Loss) Available for Common Stock	$	1.23	$	(1.23)	$	2.08	$	(0.23)
Weighted Average Common Shares Outstanding:													Weighted Average Common Shares Outstanding:
Used in Basic Calculation	86,561,066			86,290,047			86,469,258			86,159,932			Used in Basic Calculation	91,163,291		86,561,066		91,084,620		86,469,258
Used in Diluted Calculation	86,561,066			86,767,673			86,469,258			86,738,809			Used in Diluted Calculation	91,645,679		86,561,066		91,581,918		86,469,258
Dividends Per Common Share:													Dividends Per Common Share:
Dividends Declared	$	0.435		$	0.425		$	0.870		$	0.850		Dividends Declared	$	0.445	$	0.435	$	0.890	$	0.870

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)


	Three Months Ended March 31,						Six Months Ended March 31,							Three Months Ended March 31,				Six Months Ended March 31,
(Thousands of U.S. Dollars)	2020			2019			2020			2019			(Thousands of U.S. Dollars)	2021		2020		2021		2020
Net Income (Loss) Available for Common Stock	$	(106,068	)	$	90,595		$	(19,477	)	$	193,256		Net Income (Loss) Available for Common Stock	$	112,436	$	(106,068)	$	190,210	$	(19,477)
Other Comprehensive Income (Loss), Before Tax:													Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	76,304			(26,000		)	76,799			19,390			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	(25,034		)	4,739			(32,386		)	24,384			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			—			Cumulative Effect of Adoption of Authoritative Guidance for Hedging	0		0		0		1,313
Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities to Earnings Reinvested in the Business	—			—			—			(11,738		)

Other Comprehensive Income (Loss), Before Tax	51,270			(21,261		)	45,726			32,036			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	20,854			(7,399		)	20,974			5,593			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	(6,817		)	1,328			(8,849		)	6,874			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 Tax Benefit (Expense) on Cumulative Effect of Adoption of Authoritative Guidance for Hedging	0		0		0		363
Reclassification Adjustment for Income Tax Benefit (Expense) on the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities to Earnings Reinvested in the Business	—			—			—			(4,301		)
Reclassification Adjustment for Stranded Tax Effects Related to the 2017 Tax Reform Act to Earnings Reinvested in the Business	—			10,406			—			10,406

Income Taxes – Net	14,037			4,335			12,488			18,572			Income Taxes – Net	(8,460)		14,037		4,856		12,488
Other Comprehensive Income (Loss)	37,233			(25,596		)	33,238			13,464			Other Comprehensive Income (Loss)	(22,247)		37,233		12,769		33,238
Comprehensive Income (Loss)	$	(68,835	)	$	64,999		$	13,761		$	206,720		Comprehensive Income (Loss)	$	90,189	$	(68,835)	$	202,979	$	13,761

See Notes to Condensed Consolidated Financial Statements

Table of Contents

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	0		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		0
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	0		81
	582,398		599,246

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

March 31,
2020 September 30, 2019
(Thousands of U.S. Dollars)
ASSETS
Property, Plant and Equipment $ 11,559,528
$ 11,204,838
Less - Accumulated Depreciation, Depletion and Amortization 6,003,658
5,695,328
5,555,870
5,509,510
Current Assets

Cash and Temporary Cash Investments 111,655
20,428
Hedging Collateral Deposits 10,728
6,832
Receivables – Net of Allowance for Uncollectible Accounts of $29,627 and $25,788, Respectively 172,011
139,956
Unbilled Revenue 44,715
18,758
Gas Stored Underground 8,860
36,632
Materials and Supplies - at average cost 48,113
40,717
Unrecovered Purchased Gas Costs —
2,246
Other Current Assets 100,188
97,054
496,270
362,623

Other Assets

Recoverable Future Taxes 115,934
115,197
Unamortized Debt Expense 13,151
14,005
Other Regulatory Assets 161,800
167,320
Deferred Charges 56,855
33,843
Other Investments 137,044
144,917
Goodwill 5,476
5,476
Prepaid Post-Retirement Benefit Costs 71,381
60,517
Fair Value of Derivative Financial Instruments 94,797
48,669
Other 81
80
656,519
590,024

Total Assets $ 6,708,659
$ 6,462,157

See Notes to Condensed Consolidated Financial Statements

National Fuel Gas Company

Consolidated Balance Sheets

Authorized - 200,000,000 Shares; Issued And Outstanding – 91,163,797 Shares

and 90,954,696 Shares, Respectively

Authorized - 200,000,000 Shares; Issued And Outstanding – 91,163,797 Shares

and 90,954,696 Shares, Respectively

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)

Six Months Ended
March 31,
(Thousands of U.S. Dollars) 2020 2019
OPERATING ACTIVITIES

Net Income (Loss) Available for Common Stock $ (19,477 ) $ 193,256
Adjustments to Reconcile Net Income (Loss) to Net Cash Provided by Operating Activities:

Impairment of Oil and Gas Producing Properties 177,761
—
Depreciation, Depletion and Amortization 152,830
129,918
Deferred Income Taxes 104,883
90,468
Stock-Based Compensation 7,580
10,731
Other 9,800
7,997
Change in:

Receivables and Unbilled Revenue (58,248 ) (130,377 )
Gas Stored Underground and Materials and Supplies 20,086
29,093
Unrecovered Purchased Gas Costs 2,246
(1,556 )
Other Current Assets (3,134 ) 10,438
Accounts Payable (5,465 ) 10,226
Amounts Payable to Customers 13,196
12,069
Customer Advances (12,429 ) (13,176 )
Customer Security Deposits (1,211 ) (7,184 )
Other Accruals and Current Liabilities 9,076
48,028
Other Assets (10,359 ) (38,686 )
Other Liabilities 3,857
(10,410 )
Net Cash Provided by Operating Activities 390,992
340,835

INVESTING ACTIVITIES

Capital Expenditures (395,486 ) (386,579 )
Other 4,167
(2,616 )
Net Cash Used in Investing Activities (391,319 ) (389,195 )

FINANCING ACTIVITIES

Changes in Notes Payable to Banks and Commercial Paper 174,800
—
Dividends Paid on Common Stock (75,197 ) (73,197 )
Net Repurchases of Common Stock (4,153 ) (8,864 )
Net Cash Provided by (Used in) Financing Activities 95,450
(82,061 )
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash 95,123
(130,421 )
Cash, Cash Equivalents, and Restricted Cash at October 1 27,260
233,047
Cash, Cash Equivalents, and Restricted Cash at March 31 $ 122,383
$ 102,626

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

Non-Cash Capital Expenditures $ 59,490
$ 74,929


	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)		0
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		0
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		0

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		0
Reduction of Long-Term Debt	(515,715)		0
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

Table of Contents

National Fuel Gas Company

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 – Summary of Significant Accounting Policies

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

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

Earnings for Interim Periods. The Company, in its opinion, has included all adjustments (which consist of only normally recurring adjustments, unless otherwise disclosed in this Form 10-Q) that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, 2020, 2019~~, 2018~~ and ~~2017~~2018 that are included in the Company's ~~2019~~2020 Form 10-K. The consolidated financial statements for the year ended September 30, ~~2020~~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, ~~2020~~2021 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, ~~2020~~.2021. Most of the business of ~~both~~ the Utility segment ~~and the Company's NFR operations (included in the All Other category)~~ is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility segment, ~~and in the Company's NFR operations,~~ earnings during the winter months normally represent a substantial part of the earnings that ~~those businesses are~~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	0		0		6,832		10,728
Cash, Cash Equivalents, and Restricted Cash	$	20,541	$	80,467	$	27,260	$	122,383

Six Months Ended
March 31, 2020 Six Months Ended
March 31, 2019
Balance at October 1, 2019 Balance at March 31, 2020 Balance at October 1, 2018 Balance at March 31, 2019

Cash and Temporary Cash Investments $ 20,428
$ 111,655
$ 229,606
$ 100,643
Hedging Collateral Deposits 6,832
10,728
3,441
1,983
Cash, Cash Equivalents, and Restricted Cash $ 27,260
$ 122,383
$ 233,047
$ 102,626

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 ~~and~~of customer accounts, other specific information about customer ~~accounts.~~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. ~~In light~~To date, as a result of the ~~current~~ COVID-19 crisis, government mandates have resulted in the shut-down of a significant number of businesses in the Company’s service territories and many individuals are currently out of work. The financial strains on businesses and individuals could have a significant impact on their ability to pay their bills, which could lead to a significant increase in uncollectible expense for customer receivables, primarily within the Utility segment. While the combination of the current low cost of natural gas service and the steps taken by the federal government to alleviate the financial burden on companies and individuals should act as an offset to the overall economic situation, the Company is anticipating that there will be some level of increase in uncollectible expense depending

~~on the extent and duration of the~~ pandemic, ~~crisis. To date,~~ the Company has ~~not experienced any discernible change~~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 ~~rate at which its customers pay their bills.~~allowance for uncollectible accounts for the six months ended March 31, 2021 are as follows:


	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 ~~$24.0~~$21.4 million at March 31, ~~2020,~~2021, is reduced to 0 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 ~~$1.6~~$1.8 billion ~~and~~ ~~$1.7 billion~~at both March 31, ~~2020~~2021 and September 30, ~~2019, respectively.~~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 ~~$74.8~~$149.2 million and ~~$53.5~~$148.1 million at March 31, ~~2020~~2021 and September 30, ~~2019,~~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 ~~March~~December 31, 2020. As such, the Company recognized a non-cash, pre-tax impairment charge of ~~$177.8~~$76.2 million for the quarter ended ~~March~~December 31, 2020. ~~Deferred~~A deferred income tax ~~benefits~~benefit of ~~$48.5~~$21.0 million related to the non-cash impairment charge ~~were~~was also recognized for the quarter ended ~~March~~December 31, 2020. In adjusting

estimated future cash flows for hedging under the ceiling test at March 31, ~~2020,~~2021, estimated future net cash flows were increased by ~~$32.7~~$127.9 million.

The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas ~~plant in service,~~distribution pipelines, transmission pipelines, storage facilities, gathering lines and compressor stations, are recorded at historical cost. Despite the ~~historical cost when originally devoted to service. In light of~~economic conditions arising from the COVID-19 government mandates have resulted in the shut-down of a significant number of businesses in the Company’s service territories and many individuals are currently out of work. It is possible that the extent and duration of this crisis could reduce projected cash flows associated with the use of these assets, which could in turn lead to a decrease in fair value and result in a potential impairment of the recorded value of such assets. Whilepandemic, there were no indications of any ~~conditions that could result~~impairments to property, plant and equipment in ~~impairments~~the Utility, Pipeline and Storage and Gathering segments at March 31, ~~2020, management~~2021. Management will continue to monitor the situation on a quarterly basis.

Accumulated Other Comprehensive ~~Loss.~~Income (Loss). The components of Accumulated Other Comprehensive ~~Loss~~Income (Loss) and changes for the six months ended March 31, ~~2020~~2021 and ~~2019,~~2020, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):

Gains and Losses on Derivative Financial Instruments Gains and Losses on Securities Available for Sale Funded Status of the Pension and Other Post-Retirement Benefit Plans Total
Three Months Ended 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 )
Three Months Ended March 31, 2019
Balance at January 1, 2019 $ 17,886
$ —
$ (46,576 ) $ (28,690 )
Other Comprehensive Gains and Losses Before Reclassifications (18,601 ) —
—
(18,601 )
Amounts Reclassified From Other Comprehensive Income (Loss) 3,411
—
—
3,411
Reclassification of Stranded Tax Effects Related to the 2017 Tax Reform Act 1,866
—
(12,272 ) (10,406 )
Balance at March 31, 2019 $ 4,562
$ —
$ (58,848 ) $ (54,286 )
Six Months Ended March 31, 2019
Balance at October 1, 2018 $ (28,611 ) $ 7,437
$ (46,576 ) $ (67,750 )
Other Comprehensive Gains and Losses Before Reclassifications 13,797
—
—
13,797
Amounts Reclassified From Other Comprehensive Income (Loss) 17,510
—
—
17,510
Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities —
(7,437 ) —
(7,437 )
Reclassification of Stranded Tax Effects Related to the 2017 Tax Reform Act 1,866
—
(12,272 ) (10,406 )
Balance at March 31, 2019 $ 4,562
$ —
$ (58,848 ) $ (54,286 )

In August 2017, the FASB issued authoritative guidance which ~~changes~~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.

In January 2016, the FASB issued authoritative guidance regarding the recognition and measurement of financial assets and liabilities. The authoritative guidance primarily affects the accounting for equity investments and the presentation and disclosure

requirements for financial instruments. All equity investments in unconsolidated entities will be measured at fair value through earnings rather than through accumulated other comprehensive income. The Company adopted this authoritative guidance effective October 1, 2018 and, as called for by the modified retrospective method of adoption, recorded a cumulative effect adjustment during the quarter ended December 31, 2018 to increase retained earnings by $7.4 million and decrease accumulated other comprehensive income by the same amount.

In February 2018, the FASB issued authoritative guidance that allows an entity to elect a reclassification from accumulated other comprehensive income to retained earnings for stranded tax effects resulting from the 2017 Tax Reform Act and requires certain disclosures about stranded tax effects. The Company adopted this authoritative guidance effective January 1, 2019 and recorded a cumulative effect adjustment related to deferred income taxes associated with hedging activities and pension and post-retirement benefit obligations for the quarter ended March 31, 2019 to increase retained earnings by $10.4 million and decrease accumulated other comprehensive income by the same amount.

Reclassifications Out of Accumulated Other Comprehensive ~~Loss.~~Income (Loss). The details about the reclassification adjustments out of accumulated other comprehensive ~~loss~~income (loss) for the six months ended March 31, ~~2020~~2021 and ~~2019~~2020 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):

Details About Accumulated Other Comprehensive Loss Components Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss Affected Line Item in the Statement Where Net Income is Presented
Three Months Ended March 31, Six Months Ended March 31,
2020 2019 2020 2019
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
     Commodity Contracts
$23,396

($4,260 )
$30,937

($22,782 ) Operating Revenues
     Commodity Contracts 1,909
(280 ) 1,911
(1,182 ) Purchased Gas
     Foreign Currency Contracts (271 ) (199 ) (462 ) (420 ) Operating Revenues
25,034
(4,739 ) 32,386
(24,384 ) Total Before Income Tax
(6,817 ) 1,328
(8,849 ) 6,874
Income Tax Expense

$18,217

($3,411 )
$23,537

($17,510 ) Net of Tax

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

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

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. ~~As the Company recognized a net loss for both~~For the quarter and six months ended March 31, 2020, the aforementioned 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. For 2019,2021, 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 ~~159,023 securities and 175,443~~334,945 securities excluded as being antidilutive for both the quarter and six months ended March 31, 2021. As the Company recognized a net

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, ~~2019,~~2020, respectively.

Stock-Based Compensation. The Company granted ~~254,608~~309,470 performance shares during the six months ended March 31, ~~2020.~~2021. The weighted average fair value of such performance shares was ~~$43.32~~$39.19 per share for the six months ended March 31, ~~2020.~~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, ~~2020~~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, ~~2020~~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 ~~150,839 nonperformance-based~~172,513 restricted stock units during the six months ended March 31, ~~2020.~~2021. The weighted average fair value of such ~~nonperformance-based~~ restricted stock units was ~~$40.38~~$37.98 per share for the six months ended March 31, ~~2020.~~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 ~~nonperformance-based~~ restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for ~~nonperformance-based~~ restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units 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.

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 23 – Revenue from Contracts with Customers

The ~~Company adopted authoritative guidance regarding revenue recognition on October 1, 2018 using~~following tables provide a disaggregation of the ~~modified retrospective method~~Company's revenues for the quarter and six months ended March 31, 2021 and 2020, presented by type of ~~adoption for open contracts as~~service from each reportable segment.


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	$	0	$	0	$	0	$	0	$	0	$	355,212
Production of Crude Oil	58,088		0		0		0		0		0		58,088
Natural Gas Processing	1,324		0		0		0		0		0		1,324
Natural Gas Gathering Service	0		0		97,270		0		0		(96,249)		1,021
Natural Gas Transportation Service	0		129,473		0		68,535		0		(37,777)		160,231
Natural Gas Storage Service	0		41,748		0		0		0		(17,871)		23,877
Natural Gas Residential Sales	0		0		0		341,649		0		0		341,649
Natural Gas Commercial Sales	0		0		0		46,067		0		0		46,067
Natural Gas Industrial Sales	0		0		0		2,290		0		0		2,290
Natural Gas Marketing	0		0		0		0		650		(20)		630
Other	1,029		3,248		0		(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	0		0		0		7,471		0		0		7,471
Derivative Financial Instruments	(4,071)		0		0		0		0		0		(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	$	0	$	0	$	0	$	0	$	0	$	100,777
Production of Crude Oil	30,268		0		0		0		0		0		30,268
Natural Gas Processing	714		0		0		0		0		0		714
Natural Gas Gathering Service	0		0		35,267		0		0		(35,267)		0
Natural Gas Transportation Service	0		58,454		0		39,832		0		(21,976)		76,310
Natural Gas Storage Service	0		20,524		0		0		0		(9,087)		11,437
Natural Gas Residential Sales	0		0		0		185,323		0		0		185,323
Natural Gas Commercial Sales	0		0		0		27,296		0		0		27,296
Natural Gas Industrial Sales	0		0		0		1,144		0		0		1,144
Natural Gas Marketing	0		0		0		0		36,404		(79)		36,325
Other	405		267		0		(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	0		0		0		4,422		0		0		4,422
Derivative Financial Instruments	23,396		0		0		0		(4,251)		0		19,145
Total Revenues	$	155,560	$	79,245	$	35,267	$	254,493	$	33,004	$	(66,474)	$	491,095


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	$	0	$	0	$	0	$	0	$	0	$	220,651
Production of Crude Oil	67,931		0		0		0		0		0		67,931
Natural Gas Processing	1,402		0		0		0		0		0		1,402
Natural Gas Gathering Service	0		0		70,055		0		0		(70,055)		0
Natural Gas Transportation Service	0		111,906		0		72,640		0		(38,963)		145,583
Natural Gas Storage Service	0		38,950		0		0		0		(17,079)		21,871
Natural Gas Residential Sales	0		0		0		329,693		—		0		329,693
Natural Gas Commercial Sales	0		0		0		46,137		0		0		46,137
Natural Gas Industrial Sales	0		0		0		2,413		0		0		2,413
Natural Gas Marketing	0		0		0		0		70,513		(256)		70,257
Other	578		609		0		(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	0		0		0		7,283		0		0		7,283
Derivative Financial Instruments	30,937		0		0		0		(5,067)		0		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 ~~new~~ authoritative guidance regarding revenue recognition since they are accounted for under other existing accounting guidance.

The following tables provide a disaggregation of the Company's revenues for the quarter and six months ended March 31, 2020 and 2019, presented by type of service from each reportable segment. As reported in the Company's 2019 Form 10-K, the Company's NFR operations were previously reported as the Energy Marketing segment, however the Company is no longer reporting the energy marketing operations as a separate reportable segment. Prior year disaggregation of revenue information shown below has been restated to reflect this change in presentation.

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 Services —
—
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

Six Months Ended March 31, 2019 (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 $ 257,735
$ —
$ —
$ —
$ —
$ —
$ 257,735
Production of Crude Oil 72,433
—
—
—
—
—
72,433
Natural Gas Processing 1,945
—
—
—
—
—
1,945
Natural Gas Gathering Services —
—
59,058
—
—
(59,056 ) 2
Natural Gas Transportation Service —
108,375
—
80,714
—
(36,884 ) 152,205
Natural Gas Storage Service —
38,289
—
—
—
(16,306 ) 21,983
Natural Gas Residential Sales —
—
—
396,121
—
—
396,121
Natural Gas Commercial Sales —
—
—
56,301
—
—
56,301
Natural Gas Industrial Sales —
—
—
3,368
—
—
3,368
Natural Gas Marketing —
—
—
—
107,803
(375 ) 107,428
Other 876
2,744
—
(8,824 ) 1,325
(510 ) (4,389 )
Total Revenues from Contracts with Customers 332,989
149,408
59,058
527,680
109,128
(113,131 ) 1,065,132
Alternative Revenue Programs —
—
—
(1,993 ) —
—
(1,993 )
Derivative Financial Instruments (24,011 ) —
—
—
3,663
—
(20,348 )
Total Revenues $ 308,978
$ 149,408
$ 59,058
$ 525,687
$ 112,791
$ (113,131 ) $ 1,042,791

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: ~~$92.0~~$94.6 million for the remainder of fiscal ~~2020; $171.8 million for fiscal~~ 2021; ~~$142.5~~$179.7 million for fiscal 2022; ~~$97.9~~$144.5 million for fiscal 2023; ~~$86.4~~$124.3 million for fiscal 2024; $117.0 million for fiscal 2025; and ~~$361.5~~$517.5 million thereafter.

~~Note 3 – Leases~~

On October 1, 2019, the Company adopted authoritative guidance regarding lease accounting, which requires entities that lease the use of property, plant and equipment to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, including leases classified as operating leases. The Company implemented the new standard using the optional transition method and elected to apply the following practical expedients provided in the authoritative guidance:

Upon adoption, the Company increased assets and liabilities on its Consolidated Balance Sheet by $19.7 million. The adoption did not result in a cumulative effect adjustment to earnings reinvested in the business or have a material impact on the Company’s Consolidated Statement of Income or Consolidated Statement of Cash Flows. Comparative periods, including disclosures relating to those periods, were not restated.

~~Nature of Leases~~

The Company primarily leases building space and drilling rigs, and on a limited basis compressor equipment and other miscellaneous assets. The Company determines if an arrangement is a lease at the inception of the arrangement. To the extent that an arrangement represents a lease, the Company classifies that lease as an operating or a finance lease in accordance with the

authoritative guidance. As of March 31, 2020 the Company did not have any finance leases. Aside from a sublease of office space at the Company’s corporate headquarters, the Company does not have any material arrangements where the Company is the lessor.

~~Buildings and Property~~

The Company enters into building and property rental agreements with third parties for office space, certain field locations and other properties used in the Company’s operations. Building and property leases include the Company’s corporate headquarters in Williamsville, New York, and Exploration and Production segment offices in Houston, Texas, and Pittsburgh, Pennsylvania. The primary non-cancelable terms of the Company’s building and property leases range from three months to ten years. Most building leases include one or more options to renew, generally at the Company’s sole discretion, with renewal terms that can extend the lease terms from one year to fourteen years. Renewal options are included in the lease term if they are reasonably certain to be exercised. The agreements do not contain any material restrictive covenants.

In March 2020, the Company entered into a lease agreement that has not yet commenced. This lease agreement is a building and property lease for a term of ten years expected to commence in June 2021. Total estimated base rent payments over the lease term are approximately $8.4 million. There is also an option to extend the term of the lease for one additional period of eighteen months.

The Company enters into contracts for drilling rig services with third party contractors to support Seneca’s development activities in Pennsylvania and California. Seneca’s drilling rig arrangements are structured with a non-cancelable primary term of one year or less. Upon mutual agreement with the contractor, Seneca has the option to extend the contract with amended terms and conditions, including a renegotiated day rate fee.

The Company has strategically entered into shorter-term drilling rig arrangements to allow for operational and financial flexibility to respond to changes in its operating and economic environment. The Company uses discretion in choosing to extend or not extend drilling rig contracts on a rig by rig basis depending on market and operating conditions present at the time the contract expires, including prices for natural gas and oil.

Due to these considerations, the Company concluded that it is not reasonably certain that it will elect to extend any of its drilling rig arrangements beyond their primary non-cancelable terms of one year or less. Consequently, the Company’s drilling rig leases are deemed to be short-term leases subject to the exemption for balance sheet recognition. These costs are capitalized as part of oil and natural gas properties on the Consolidated Balance Sheet when incurred.

~~Significant Judgments~~

~~Lease Identification~~

The Company uses judgment when determining whether or not an arrangement is or contains a lease. A contract is or contains a lease if the contract conveys the right to use an explicitly or implicitly identified asset that is physically distinct and the Company has the right to control the use of the identified asset for a period of time. When determining right of control, the Company evaluates whether it directs the use of the asset and obtains substantially all of the economic benefits from the use of the asset.

The Company uses a discount rate to calculate the present value of lease payments in order to determine lease classification and measurement of the lease asset and liability. In the absence of a rate of interest that is readily determinable in the contract, the Company estimates the incremental borrowing rate (IBR) for each lease. The IBR reflects the rate of interest that the Company would pay on the lease commencement date to borrow an amount equal to the lease payments on a collateralized basis over a similar term in similar economic environments.

~~Firm Transportation and Storage Contracts~~

The Company’s subsidiaries enter into long-term arrangements to both reserve firm transportation capacity on third party pipelines and provide firm transportation and storage services to third party shippers. The Company’s firm capacity contracts with non-affiliated entities do not provide rights to use substantially all of the underlying pipeline or storage asset. As such, the Company has concluded that these arrangements are not leases under the authoritative guidance.

~~Oil and Gas Leases~~

The new authoritative guidance does not apply to leases to explore for or use minerals, oil or natural gas resources, including the right to explore for those natural resources and rights to use the land in which those natural resources are contained. As such, the Company has concluded that its oil and gas exploration and production leases and gas storage leases are not leases under the authoritative guidance.

~~Amounts Recognized in the Financial Statements~~

Operating lease costs, excluding those relating to short-term drilling rig leases that are capitalized as part of oil and natural gas properties under full cost pool accounting, are presented in Operations and Maintenance expense on the Consolidated Statement of Income. The following table summarizes the components of the Company’s total operating lease costs (in thousands):

Variable Lease Expense ⁽¹⁾

Short-Term Lease Expense⁽²⁾

Short-Term Lease Costs Recorded to Property, Plant and Equipment ⁽³⁾

Right-of-use assets and lease liabilities are recognized at the commencement date of a leasing arrangement based on the present value of lease payments over the lease term. As of March 31, 2020, the weighted average remaining lease term was 8.6 years and the weighted average discount rate was 3.50%.

The Company’s right-of-use operating lease assets are reflected as Deferred Charges on the Consolidated Balance Sheet. The corresponding operating lease liabilities are reflected in Other Accruals and Current Liabilities (current) and Other Deferred Credits (noncurrent). Short-term leases that have a lease term of one year or less are not recorded on the Consolidated Balance Sheet.

~~The following amounts related to operating leases were recorded on the Company’s Consolidated Balance Sheet (in thousands):~~

For the six months ended March 31, 2020, cash paid for operating liabilities, and reported in cash flows provided by operating activities on the Company’s Consolidated Statement of Cash Flows, was $2.2 million. During the six months ended March 31, 2020, the Company did not record any right-of-use assets in exchange for new lease liabilities.

The following schedule of operating lease liability maturities summarizes the undiscounted lease payments owed by the Company to lessors pursuant to contractual agreements in effect as of March 31, 2020 (in thousands):

~~The future minimum operating lease payments as of September 30, 2019, as reported in the Company's 2019 Form 10-K, under the prior authoritative guidance are as follows (in thousands):~~

Note 4 – Fair Value Measurements

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

The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of March 31, ~~2020~~2021 and September 30, ~~2019~~.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~~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.

Netting Adjustments⁽¹⁾

Recurring Fair Value Measures At fair value as of September 30, 2019
(Thousands of Dollars) Level 1 Level 2 Level 3
Netting Adjustments⁽¹⁾

Total⁽¹⁾
Assets:

Cash Equivalents – Money Market Mutual Funds $ 10,521
$ —
$ —
$ —
$ 10,521
Derivative Financial Instruments:

Commodity Futures Contracts – Gas 2,055
—
—
(2,055 ) —
Over the Counter Swaps – Gas and Oil —
52,076
—
(1,483 ) 50,593
Foreign Currency Contracts —
5
—
(2,052 ) (2,047 )
Other Investments:

Balanced Equity Mutual Fund 40,660
—
—
—
40,660
Fixed Income Mutual Fund 62,339
—
—
—
62,339
Common Stock – Financial Services Industry 844
—
—
—
844
Hedging Collateral Deposits 6,832
—
—
—
6,832
Total $ 123,251
$ 52,081
$ —
$ (5,590 ) $ 169,742

Liabilities:

Derivative Financial Instruments:

Commodity Futures Contracts – Gas $ 7,149
$ —
$ —
$ (2,055 ) $ 5,094
Over the Counter Swaps – Gas and Oil —
1,671
—
(1,483 ) 188
Foreign Currency Contracts —
2,344
—
(2,052 ) 292
Total $ 7,149
$ 4,015
$ —
$ (5,590 ) $ 5,574
Total Net Assets/(Liabilities) $ 116,102
$ 48,066
$ —
$ —
$ 164,168


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

Table of Contents

Derivative Financial Instruments

At March 31, 2020 and September 30, 2019, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used by NFR (included in the All Other category). Hedging collateral deposits of $10.7 million (at March 31, 2020) and $6.8 million (at September 30, 2019), which were associated with these futures contracts, have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at March 31, ~~2020~~2021 and September 30, ~~2019~~2020 consist of natural gas price swap agreements, ~~used in the Company’s Exploration and Production segment and in its NFR operations,~~ natural gas no cost collars, ~~used in the Company's Exploration and Production segment,~~ crude oil price swap agreements, ~~used in the Company’s Exploration and Production segment, basis hedge swap agreements used by NFR~~ and foreign currency contracts, all of which are used in the ~~Company's~~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 ~~accounting rules~~authoritative guidance for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At March 31, ~~2020,~~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, ~~2020~~2021 and March 31, ~~2019,~~2020, there were 0 assets or liabilities measured at fair value and classified as Level 3. ~~For the quarters ended March 31, 2020 and March 31, 2019, 0 transfers in or out of Level 1 or Level 2 occurred.~~

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, 2020 September 30, 2019
Carrying Amount Fair Value Carrying Amount Fair Value
Long-Term Debt $ 2,134,964
$ 1,948,127
$ 2,133,718
$ 2,257,085


	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.

~~Table of Contents~~

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

At March 31, 2020 At September 30, 2019

Life Insurance Contracts $ 41,417
$ 41,074
Equity Mutual Fund 31,956
40,660
Fixed Income Mutual Fund 63,094
62,339
Marketable Equity Securities 577
844
$ 137,044
$ 144,917


	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

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 as well as by NFR (included in the All Other category).~~segment. The Company enters into ~~futures contracts,~~ 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 Company also enters into futures contracts and swaps, which are accounted for as cash flow hedges, to manage the price risk associated with forecasted gas purchases. The Company enters into futures contracts and swaps to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments, and the decline in value of natural gas held in storage. These instruments are accounted for as fair value hedges. The duration of the Company’s ~~combined~~ cash flow ~~and fair value commodity~~ hedges does not typically exceed 5 years while the foreign currency forward contracts do not exceed 710 years. ~~The Exploration and Production segment holds the majority of the Company’s derivative financial instruments.~~

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, ~~2020~~2021 and September 30, ~~2019~~.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.

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. ~~Prior to October 1, 2019, gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment~~

As of ~~effectiveness were recognized in current earnings rather than as a component of other comprehensive income (loss). During the quarter and six months ended~~ March 31, 2019, the Company recorded $6.7 million and $0.2 million , respectively, of hedging ineffectiveness losses that impacted operating revenue. With the October 1, 2019 adoption of the authoritative guidance that changes the financial reporting of hedging relationships and simplifies the application of hedge accounting, derivative instruments that are designated and qualify as a cash flow hedge will no longer have hedge ineffectiveness or a component excluded from the assessment of the effectiveness.

~~As of~~ ~~March 31, 2020~~,2021, the Company had the following commodity derivative contracts (swaps and no cost ~~collars and futures contracts)~~collars) outstanding:



Commodity	Units
Natural Gas	~~108.4~~253.3	Bcf ~~(short positions)~~
~~Natural Gas~~	~~17.4~~		~~Bcf (long positions)~~
Crude Oil	~~2,160,000~~2,082,000	Bbls ~~(short positions)~~

As of March 31, ~~2020,~~2021, the Company was hedging a total of ~~$86.5~~$69.4 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward ~~contracts (long positions).~~contracts.

~~Table of Contents~~

As of March 31, ~~2020,~~2021, the Company had ~~$93.1~~$17.1 million ($~~67.9~~12.1 million ~~after tax)~~after-tax) of net hedging ~~gains~~losses included in the accumulated other comprehensive income (loss) balance. It is expected that ~~$80.9~~$28.2 million ($~~59.0~~19.9 million ~~after tax)~~after-tax) of unrealized ~~gains~~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, 2020 and 2019 (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,
2020 2019 2020 2019
Commodity Contracts $ 81,108
$ (27,228 ) Operating Revenue $ 23,396
$ (4,260 )
Commodity Contracts (134 ) (54 ) Purchased Gas 1,909
(280 )
Foreign Currency Contracts (4,670 ) 1,282
Operating Revenue (271 ) (199 )
Total $ 76,304
$ (26,000 ) $ 25,034
$ (4,739 )


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	0		(134)		Purchased Gas	0		1,909
Foreign Currency Contracts	750		(4,670)		Operating Revenue	95		(271)
Total	$	(34,373)	$	76,304		$	(3,666)	$	25,034

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Six Months Ended March 31, 2020 and 2019 (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,
2020 2019 2020 2019
Commodity Contracts $ 79,553
$ 22,825
Operating Revenue $ 30,937
$ (22,782 )
Commodity Contracts 997
(1,333 ) Purchased Gas 1,911
(1,182 )
Foreign Currency Contracts (3,751 ) (2,102 ) Operating Revenue (462 ) (420 )
Total $ 76,799
$ 19,390
$ 32,386
$ (24,384 )

~~Fair Value Hedges~~

The Company utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments and the decline in the value of certain natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or net realizable value writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of March 31, 2020, NFR had fair value hedges covering approximately 22.2 Bcf on its fixed price sales commitments. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.

Table of Contents


The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the								The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Six Months Ended March 31, 2021 and 2020 (Thousands of Dollars)								Six Months Ended March 31, 2021 and 2020 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships								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
Derivatives in Fair Value Hedging Relationships	Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income	Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income for the Six Months Ended March 31, 2020 (In Thousands)			Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the Six Months Ended March 31, 2020 (In Thousands)
Commodity Contracts	Operating Revenues	$	(4,994	)	$	4,994		Commodity Contracts	$	10,472	$	79,553	Operating Revenue	$	(4,071)	$	30,937
Commodity Contracts	Purchased Gas	$	431		$	(431	)	Commodity Contracts	0		997		Purchased Gas	0		1,911
Foreign Currency Contracts								Foreign Currency Contracts	3,176		(3,751)		Operating Revenue	94		(462)
Total								Total	$	13,648	$	76,799		$	(3,977)	$	32,386
		$	(4,563	)	$	4,563

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 1415 counterparties of which 125 are in a net gain position. On average, the Company had ~~$7.9~~$0.8 million of credit exposure per counterparty in a gain position at March 31, ~~2020.~~2021. The maximum credit exposure per counterparty in a gain position at March 31, ~~2020~~2021 was ~~$17.0~~$1.6 million. As of March 31, ~~2020,~~2021, 0 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, ~~2020, 11~~2021, 13 of the 1415 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, ~~2020,~~2021, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was ~~$94.8~~$1.5 million according to the Company’s internal model (discussed in Note 4 —– Fair Value Measurements). At March 31, ~~2020,~~2021, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was ~~$1.6~~$21.2 million according to the Company's internal model. For its over-the-counter swap agreements and foreign currency forward contracts, 0 hedging collateral deposits were required to be posted by the Company at March 31, ~~2020.~~2021.

For its exchange traded futures contracts, the Company was required to post $10.7 million in hedging collateral deposits as of March 31, 2020. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts or receives hedging collateral based on open positions and margin requirements it has with its counterparties.

The Company’s requirement to post hedging collateral deposits and the Company's right to receive hedging collateral deposits is based on the fair value determined by the Company’s counterparties, which may differ from the Company’s assessment of fair value. Hedging collateral deposits may also include closed derivative positions in which the broker has not cleared the cash from the account to offset the derivative liability. The Company records liabilities related to closed derivative positions in Other Accruals and Current Liabilities on the Consolidated Balance Sheet. These liabilities are relieved when the broker clears the cash from the hedging collateral deposit account.

Note 6 – Income Taxes

The effective tax rates for the quarters ended March 31, ~~2020~~2021 and March 31, ~~2019~~2020 were 26.3% and negative 53.2% ~~and positive 24.7%~~, respectively. ~~The change in the effective tax rate was primarily the result of recording a valuation allowance against certain deferred tax assets, discussed below.~~ The effective tax rates for the six months ended March 31, ~~2020~~2021 and March 31, ~~2019~~2020 were ~~139.9%~~26.8% and ~~21.4%~~139.9%, respectively. The ~~increase~~change in the tax rate is aprimarily the result of ~~the deferred tax~~a valuation allowance ~~differences~~initially established in the quarter ended March 31, 2020, discussed below.

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~~between the book and tax treatment of stock compensation, as well as the elimination of the Enhanced Oil Recovery tax credit in fiscal 2020.~~

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. ~~For~~The Company continually assesses the ~~quarter ended~~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 ~~full~~ valuation allowance against certain state deferred tax assets in the amount of $56.8 million based on its conclusion, considering all available objective evidence ~~(both positive~~ and ~~negative),~~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. ~~A significant item~~The valuation allowance increased to $63.9 million as of ~~objective negative evidence considered was~~March 31, 2021 as a ~~projected three-year cumulative pre-tax~~result of certain state net operating loss ~~primarily due to non-cash impairments of proved natural gas~~ and ~~oil properties due to declining commodity prices.~~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 Company has filed for the acceleration of the remaining AMT credit refunds (under CARES) of $42.5 million, which has been recorded as a current receivable as of March 31, 2020. In addition, the Company is pursuing certain payroll tax related provisions included in the CARES Act.

~~Prior to the CARES Act, the~~ 2017 Tax Reform Act had repealed the corporate ~~alternative minimum tax~~AMT and provided that the Company’s existing AMT credit carryovers were refundable ~~if not utilized to reduce tax, beginning in fiscal 2019.~~over a four year period. As of September 30, 2018, the Company had $85.0 million of AMT credit ~~carryovers that were expected to be refunded between fiscal 2020 and fiscal 2023, if not previously utilized.~~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)

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, 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 (Repurchased) 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 )

Balance at January 1, 2019 86,271
$ 86,271
$ 817,076
$ 1,172,334
$ (28,690 )
Net Income Available for Common Stock 90,595

Dividends Declared on Common Stock ($0.425 Per Share) (36,678 )
Cumulative Effect of Adoption of Authoritative Guidance for Reclassification of Stranded Tax Effects 10,406

Other Comprehensive Loss, Net of Tax (25,596 )
Share-Based Payment Expense ⁽¹⁾
5,038

Common Stock Issued (Repurchased) Under Stock and Benefit Plans 30
30
(277 )
Balance at March 31, 2019 86,301
$ 86,301
$ 821,837
$ 1,236,657
$ (54,286 )

Balance at October 1, 2018 85,957
$ 85,957
$ 820,223
$ 1,098,900
$ (67,750 )
Net Income Available for Common Stock �� 193,256

Dividends Declared on Common Stock ($0.85 Per Share) (73,342 )
Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities 7,437

Cumulative Effect of Adoption of Authoritative Guidance for Reclassification of Stranded Tax Effects 10,406

Other Comprehensive Income, Net of Tax 13,464
Share-Based Payment Expense ⁽¹⁾
9,955

Common Stock Issued (Repurchased) Under Stock and Benefit Plans 344
344
(8,341 )
Balance at March 31, 2019 86,301
$ 86,301
$ 821,837
$ 1,236,657
$ (54,286 )


(1)⁽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.~~

~~Table~~ of ~~Contents~~tax benefits.

Common Stock. During the six months ended March 31, ~~2020,~~2021, the Company issued ~~87,135~~105,260 original issue shares of common stock for restricted stock units that vested and ~~231,246~~165,161 original issue shares of common stock for performance shares that vested. The Company also issued ~~19,133~~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, ~~as partial consideration~~including the reinvestment of dividends for certain non-employee directors who elected to defer their shares pursuant to the ~~directors’ services~~dividend reinvestment feature of the Company's Non-Employee Directors Deferred Compensation Plan during the six months ended March 31, ~~2020.~~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, ~~2020, 91,269~~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. NaN of the Company's long-term debt as of March 31, ~~2020~~2021 and September 30, ~~2019~~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, ~~2020~~,2021, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately ~~$6.8~~$3.3 million, which includes a ~~$3.7~~$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, ~~2020.~~2021. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately ~~3 years~~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 ~~have been appealed and are pending in a separate action before~~were appealed. Recently, the Second Circuit Court of ~~Appeals.~~Appeals issued an order upholding the FERC waiver orders. In addition, in the ~~Company commenced legal action in New York State Supreme Court~~Company's state court litigation challenging the NYDEC's actions with regard to various state ~~permits.~~permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project. In light of these pending legal actions and the need to complete necessary project development activities in advance of construction, the in-service date for the project is expected to be no earlier than fiscal 2022.

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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 4 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. ~~As reported in the Company's 2019 Form 10-K, the Company previously reported financial results for five business segments: Exploration and Production, Pipeline and~~

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Storage, Gathering, Utility and Energy Marketing. However, management made the decision to eliminate the Energy Marketing segment as a reportable segment based on the fact that the energy marketing operations do not meet any of the quantitative thresholds specified by authoritative guidance related to segment reporting. Furthermore, from a qualitative standpoint, management’s focus has changed regarding the energy marketing operations, and management no longer considers the energy marketing operations to be integral to the overall operations of the Company. As a result of this change in focus and the fact that the energy marketing operations cannot be aggregated into one of the other four reportable business segments, the energy marketing operations have been included in the All Other category in the disclosures that follow. Prior year segment information shown below has been restated to reflect this change in presentation.

The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. As stated in the ~~2019~~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 ~~2019~~2020 Form 10-K. A listing of segment assets at March 31, ~~2020~~2021 and September 30, ~~2019~~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	$0	$27,390	$49,591	$97	$77,078	$1	$(77,079)	$0
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	$0	$55,846	$96,249	$197	$152,292	$20	$(152,312)	$0
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	$0	$250,556	$458,035	$32,925	$135	$491,095
Intersegment Revenues	$0	$27,326	$35,267	$3,937	$66,530	$79	$(66,609)	$0
Segment Profit: Net Income (Loss)	$(175,275)	$22,087	$19,898	$31,499	$(101,791)	$1,169	$(5,446)	$(106,068)

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)

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)

(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, 2020 $2,014,520 $1,916,849 $576,589 $2,049,424 $6,557,382 $134,926 $16,351 $6,708,659
At September 30, 2019 $1,972,776 $1,893,514 $547,995 $1,991,338 $6,405,623 $122,241 $(65,707) $6,462,157

Quarter Ended March 31, 2019 (Thousands)
Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated
Revenue from External Customers $146,102 $48,421 $2 $298,636 $493,161 $59,328 $55 $552,544
Intersegment Revenues $— $23,918 $29,366 $4,394 $57,678 $43 $(57,721) $—
Segment Profit: Net Income $21,873 $17,749 $12,690 $35,589 $87,901 $416 $2,278 $90,595

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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	$0	$445,465	$867,852	$67,161	$270	$935,283
Intersegment Revenues	$0	$50,577	$70,055	$5,853	$126,485	$256	$(126,741)	$0
Segment Profit: Net Income (Loss)	$(151,299)	$40,192	$35,842	$58,082	$(17,183)	$1,540	$(3,834)	$(19,477)

Six Months Ended March 31, 2019 (Thousands)
Exploration and Production Pipeline and Storage Gathering Utility Total Reportable Segments All Other Corporate and Intersegment Eliminations Total Consolidated
Revenue from External Customers $308,978 $102,639 $2 $518,647 $930,266 $112,416 $109 $1,042,791
Intersegment Revenues $— $46,769 $59,056 $7,040 $112,865 $375 $(113,240) $—
Segment Profit: Net Income $60,087 $42,851 $26,872 $61,237 $191,047 $499 $1,710 $193,256

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							Retirement Plan				Other Post-Retirement Benefits
Three Months Ended March 31,	2020			2019			2020			2019
Six Months Ended March 31,													Six Months Ended March 31,	2021		2020		2021		2020

Service Cost	$	2,330		$	2,120		$	402		$	380		Service Cost	$	4,932	$	4,659	$	801	$	804
Interest Cost	7,483			9,594			3,228			4,286			Interest Cost	10,843		14,965		4,652		6,457
Expected Return on Plan Assets	(15,016		)	(15,591		)	(7,308		)	(7,539		)	Expected Return on Plan Assets	(29,074)		(30,032)		(14,482)		(14,616)
Amortization of Prior Service Cost (Credit)	182			206			(107		)	(107		)	Amortization of Prior Service Cost (Credit)	316		365		(214)		(214)

Amortization of Losses	9,846			8,024			134			1,490			Amortization of Losses	18,407		19,692		424		267
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) ⁽¹⁾	5,519			4,786			8,846			6,565			Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) (1)	11,422		7,047		16,303		15,094

Net Periodic Benefit Cost	$	10,344		$	9,139		$	5,195		$	5,075		Net Periodic Benefit Cost	$	16,846	$	16,696	$	7,484	$	7,792

Retirement Plan Other Post-Retirement Benefits
Six Months Ended March 31, 2020 2019 2020 2019

Service Cost $ 4,659
$ 4,241
$ 804
$ 760
Interest Cost 14,965
19,189
6,457
8,572
Expected Return on Plan Assets (30,032 ) (31,184 ) (14,616 ) (15,078 )
Amortization of Prior Service Cost (Credit) 365
413
(214 ) (214 )
Amortization of Losses 19,692
16,048
267
2,980
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) ⁽¹⁾
7,047
5,604
15,094
10,536

Net Periodic Benefit Cost $ 16,696
$ 14,311
$ 7,792
$ 7,556


⁽¹⁾(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 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, ~~2020,~~2021, the Company contributed ~~$19.3~~$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 ~~2020,~~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 ~~2020,~~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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The market turbulence resulting from COVID-19 has not had a significant impact to the plan assets or funded status of the Retirement Plan or VEBA trusts at this time. The Company will continue to monitor the performance of its Retirement Plan and VEBA trusts during the pandemic crisis to determine if funding requirements will need to increase during the remainder of 2020.

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 ~~there will be some level of~~customer non-payment may increase given higher natural gas usage and the resulting increase in ~~uncollectible expense depending on the depth and duration of the pandemic crisis.~~costs for customers. It is uncertain at this point as to whether there would be any regulatory relief for ~~the Utility segment~~utilities with regard to an increase in costs associated with the COVID-19 pandemic, ~~crisis.~~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 ~~delivery rates are being charged to customers in accordance with a rate settlement~~were approved by the ~~PaPUC.~~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 ~~COVID-19. Similar~~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 ~~New York, it is uncertain at this point as~~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 ~~whether there~~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 ~~any~~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 ~~relief with regard~~asset to ~~any increase~~include all incremental COVID-19 related expenses incurred above those embedded in rates resulting from directives contained in the ~~Utility’s uncollectible expense.~~orders. The Company continues to monitor this item for potential deferral opportunity.

FERC Jurisdiction

Supply Corporation filed a Section 4 rate case on July 31, 2019 proposing rate increases to be effective September 1, 2019. On February 4, 2020, Supply Corporation and the parties in the case reached a settlement in principle (the Settlement) to resolve the rate case. Supply Corporation’s ~~subsequent motion to put in place Interim Settlement Rates effective February~~rate settlement, approved June 1, 2020, was approved by FERC’s Chief Administrative Law Judge on February 21, 2020. The Settlement was filed with FERC on March 13, 2020 and on April 20, 2020 the presiding Administrative Law Judge certified the Settlement to FERC for approval. The “black box” settlement provides for new rates (Period 1 and Period 2 Rates). The Period 1 Rates, the Interim Settlement Rates, are estimated to increase Supply Corporation’s revenues on a yearly basis by approximately $35.5 million, assuming current contract levels. After Period 2 Rates are implemented, which will be the later of April 1, 2022, or the in-service of Supply Corporation’s FM-100 Modernization Project, Supply Corporation’s yearly revenues will have increased by an additional approximately $15.0 million. As well, the Settlement provides for increased depreciation rates and the right to track pipeline safety and greenhouse costs that result from future costs incurred for new rules and the PHMSA Mega Rule. Under the terms of the Settlement, Supply Corporation will also undertake certain actions for its customers, including convening regular customer meetings to address system operations. Under the Settlement, 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~~ Empire’s 2019 rate settlement ~~requires~~provides that Empire must make a ~~Section 4~~ rate case filing no later than May 1, 2025. ~~Empire has no rate case currently on file.~~

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

OVERVIEW

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

The Company is a diversified energy company engaged principally in the production, gathering, transportation ~~distribution~~ and ~~marketing~~distribution of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current development activities are focused primarily in the Marcellus and Utica shales. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian basin to markets in ~~Canada and~~ the eastern United ~~States.~~States and Canada. The Company's efforts in this regard are not limited to affiliated projects. The Company has also been designing and building pipeline projects for the transportation of natural gas for non-affiliated natural gas ~~producers and other~~ 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. ~~In accordance with government mandates, a significant portion~~Refer to Risk Factors in Item 1A of ~~the Company’s workforce is working remotely from home where possible. Steps have been taken to protect those employees that are required to work in the field~~this Form 10-Q as well as Part I, Item 1A, Risk Factors, under Operational Risks in the ~~Company’s customers. These steps include increased cleaning and sanitation of equipment and buildings, the use of safety masks, gloves and goggles as appropriate, given the nature~~Company's 2020 Form 10-K for a more complete discussion of the ~~work being performed and~~risks to the level of contact with customers and co-workers, and requiring employees to maintain social distancing at work. The extent and duration of the pandemic crisis will determine how significant the additional costs associated with combating COVID-19 will be. In addition to measures to protect our workforce and customers, the Company has also taken proactive steps to ensure business continuity and the safe operation of our businesses. The Company is actively managing our supply chains, contractor work, counterparties and customer service functions and has had no material issues occur to date. The length of the pandemic crisis will also impact other aspects of the Company’s operations, the most significant of which will be the future level of the Company’s revenue stream from all segments of the business as significant numbers of commercial and industrial customers have been forced to shut down operations based on government mandates. The financial strains on businesses and individuals could have a significant impact on their ability to pay their bills, which could lead to a significant increase in uncollectible expense for customer receivables, primarily within the Utility segment. While the federal government has taken steps to alleviate the financial burden on companies and individuals and no discernible impact has been experienced to date, the Company is anticipating that there will be some level of increase in uncollectible expense depending, once again, on the depth and duration of the pandemic crisis. It is uncertain at this point as to whether there would be any regulatory relief for the Utility segment with regard to an increase in costs associated with the ~~pandemic crisis.~~COVID-19 pandemic.

One of the steps taken by the federal government to help companies during the pandemic crisis was the passage of the CARES Act on March 27, 2020. 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 Company has filed for the acceleration of the remaining AMT credit refunds (under CARES) of $42.5 million, which has been recorded as a current receivable as of March 31, 2020. In addition, the Company is pursuing certain payroll tax related provisions included in the CARES Act and continues to evaluate other elements of the CARES Act for potential adoption by the Company.

From a financing perspective, despite the unsettled nature of financial markets resulting from the pandemic crisis, the Company has been able to meet its short-term borrowing needs through the use of its committed and uncommitted lines of credit. Before the pandemic crisis began, the Company had expected to use cash on hand, cash from operations and short-term debt to meet its capital expenditure needs for fiscal 2020, while issuing long-term debt during fiscal 2020 if needed. The length of the pandemic crisis is expected to reduce capital spending during the second half of fiscal 2020, which would reduce the Company’s needs for borrowings. However, potential increased costs and lower revenue streams as a result of the pandemic crisis could result in an increased need for borrowings during fiscal 2020. In addition, 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 maturing debt.

The current pandemic crisis has seen a continuation of the low natural gas and oil price environment that existed before the pandemic began, with oil prices being much lower than they were before the crisis. Government mandated shut downs have

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reduced demand for natural gas and oil, contributing to the imbalance between near-term supply and demand that existed prior to the crisis. As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its oil and natural gas properties in the Exploration and Production segment and that book value is subject to a quarterly ceiling test. The Company recorded an impairment under the ceiling test during the quarter ended March 31, 2020 of $177.8 million ($129.3 million after-tax) and it is anticipated that the current low commodity price environment will lead to impairments during the remaining quarters of fiscal 2020 and likely in the first quarter of fiscal 2021 as well. Depending on the magnitude of future impairments, it is possible that the Company’s indenture covenants would restrict the Company's ability to issue additional long-term unsecured indebtedness for a period of time. However, this would not preclude the Company from issuing new indebtedness to replace maturing debt. Please refer to the Critical Accounting Estimates section below for a sensitivity analysis concerning commodity price changes.

Given the current low commodity price environment, the Company's Exploration and Production segment moved from a 3-rig development program to a 2-rig development program in the Appalachian region in January 2020, and intends to move to a single-rig development program during the second half of fiscal 2020. While this will result in lower capital spending in this segment, Seneca still anticipates an increase in natural gas production when comparing fiscal 2020 to fiscal 2019.

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 ~~outbreak,~~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, ~~would allow~~which allows for the transportation of 205,000 Dth per day of additional shale supplies from interconnections in Tioga County, Pennsylvania, to ~~TransCanada Pipeline,~~the TC Energy pipeline, and the ~~TGP~~Tennessee Gas Pipeline L.L.C. (TGP) 200 ~~Line. Project construction is under way. The Empire North Project has a projected~~Line, was placed in-service ~~date late in~~during the fourth quarter of fiscal ~~2020 and an estimated cost of approximately $145 million.~~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 ~~on Supply Corporation’s system~~ 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 inof late calendar 2021 and a preliminary cost estimate of approximately $280 million. ~~These and other projects are~~This project is discussed in more detail in the Capital Resources and Liquidity section that follows.

~~On February 3, 2017,~~ In advance of the ~~Company, in its Pipeline and Storage segment, received FERC approval~~expected late calendar 2021 online date for Seneca’s 330,000 Dth per day of aincremental capacity on the Leidy South Project, which is the companion project to ~~move significant prospective Marcellus production~~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 ~~Seneca’s Western Development Area at Clermont to an Empire interconnection~~the first pad that will be drilled in connection with TransCanada Pipeline at Chippawa and an interconnection with Tennessee Gas Pipeline’s 200 Line in East Aurora, New York (“Northern Access project”). In light of numerous legal actions and the need to complete necessary project development activities in advance of construction, the in-service date for the projectthis additional activity is expected ~~to be no earlier than~~in early fiscal ~~2022. For further discussion of~~2022, with this incremental production reaching Transco Zone 6 markets during the ~~Northern Access project, refer to Item 1 at Note 8 — Commitments and Contingencies.~~winter heating season.

From a rate perspective, Supply Corporation filed a Section 4 rate case on July 31, 2019. The new rates became effective on February 1, 2020 under a proposed settlement, subject to refund. This increased earnings in the quarter ended March 31, 2020 by $3.8 million. For further discussion of Supply Corporation's rate matters, refer to the Rate and Regulatory Matters section below.

~~From a legislation~~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 ~~to 60% of~~by 40% from 1990 levels by 2030, and ~~to 15% of~~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. ~~In the near-term, the~~The CLCPA ~~establishes~~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.

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). Refer to Note 2 – Asset Acquisitions and Divestitures for additional information concerning this sale.

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 ~~2019~~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,

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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. ~~The~~At March 31, 2021, the ceiling exceeded the book value of the oil and gas properties ~~exceeded the ceiling at March 31, 2020, resulting in an impairment charge of $177.8 million ($129.3 million after-tax).~~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, ~~2020,~~2021, based on posted Midway Sunset prices, was ~~$58.92~~$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, ~~2020,~~2021, based on the quoted Henry Hub spot price for natural gas, was ~~$2.30~~$2.16 per MMBtu. ~~(Note – because~~(Note: Because actual pricing of the Company’s ~~various~~ producing properties ~~varies~~vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Midway Sunset and HenryHub prices, which are only indicative of ~~the~~ 12-month average prices for the twelve months ended March 31, ~~2020. Pricing differences would include~~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 ~~additional~~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, ~~2020~~2021 if natural gas prices were $0.25 per MMBtu lower than the average prices used at March 31, ~~2020,~~2021, and the ~~additional~~ impairment that the Company would have recorded at March 31, ~~2020 if crude oil prices were $5 per Bbl lower than the average prices used at March 31, 2020, and the additional impairment that the Company would have recorded at March 31, 2020~~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, ~~2020~~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	Ceiling Testing Sensitivity to Commodity Price Changes						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		(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							Excess of Ceiling over Book Value under Sensitivity Analysis	$	—	$	114.0	$	—
Calculated Impairment under Sensitivity Analysis	$	364.7	$	168.5	$	404.0	Calculated Impairment under Sensitivity Analysis	$	123.6	$	—	$	154.9
Actual Impairment Recorded at March 31, 2020	129.3		129.3		129.3
Additional Impairment	$	235.4	$	39.2	$	274.7

~~Looking ahead,~~ It is difficult to predict what factors could lead to future non-cash impairments under the ~~first day~~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 ~~month Midway Sunset price for crude oil~~ceiling at any point in April 2020 was $18.62 per Bbl. The first day of the month Henry Hub spot price for natural gas in April 2020 was $1.69 per MMBtu. Given these April prices, the potential that prices could stay at this level in future months, and the expected loss of higher gas and oil prices from the 12-month average that will be used in the ceiling test at June 30, 2020 and September 30, 2020, the Company expects to experience ceiling test impairments in each of these quarters.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 ~~2019~~2020 Form 10-K.

RESULTS OF OPERATIONS

Earnings

The ~~Company recorded~~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 compared to~~2020. The increase in earnings of ~~$90.6~~$218.5 million ~~for the quarter ended March 31, 2019. The decrease in earnings~~ is primarily the result of ~~a loss recognized~~higher earnings in the Exploration and Production ~~segment. Lower earnings in the Utility segment and a loss in the Corporate category also contributed to the decrease. Higher earnings in the Gathering~~ 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 ~~partially~~provided a small offset to these ~~decreases.~~increases.

The ~~Company recorded~~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 compared to~~2020. The increase in earnings of ~~$193.3~~$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, ~~2019. The decrease in earnings is primarily~~2021 included a non-cash $76.2 million impairment charge ($55.2 million after-tax) recorded during the ~~result of a loss recognized in~~quarter ended December 31, 2020 for the Exploration and Production ~~segment. Lower~~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 ~~Utility segment and Pipeline and Storage segment, as well as a loss in the Corporate category, also contributed to the decrease. Higher earnings in the Gathering segment and~~Company's All Other category, ~~partially offset these decreases.~~

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

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segment's oil and gas producing ~~properties, as discussed above.~~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,									Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2020			2019		Increase (Decrease)			2020			2019		Increase (Decrease)			(Thousands)	2021		2020		Increase (Decrease)		2021		2020		Increase (Decrease)
Exploration and Production	$	(175,275	)	$	21,873	$	(197,148	)	$	(151,299	)	$	60,087	$	(211,386	)	Exploration and Production	$	36,822	$	(175,275)	$	212,097	$	7,199	$	(151,299)	$	158,498
Pipeline and Storage	22,087			17,749		4,338			40,192			42,851		(2,659		)	Pipeline and Storage	24,928		22,087		2,841		49,112		40,192		8,920
Gathering	19,898			12,690		7,208			35,842			26,872		8,970			Gathering	20,700		19,898		802		41,250		35,842		5,408
Utility	31,499			35,589		(4,090		)	58,082			61,237		(3,155		)	Utility	32,044		31,499		545		55,081		58,082		(3,001)
Total Reportable Segments	(101,791		)	87,901		(189,692		)	(17,183		)	191,047		(208,230		)	Total Reportable Segments	114,494		(101,791)		216,285		152,642		(17,183)		169,825
All Other	1,169			416		753			1,540			499		1,041			All Other	(983)		1,169		(2,152)		36,577		1,540		35,037
Corporate	(5,446		)	2,278		(7,724		)	(3,834		)	1,710		(5,544		)	Corporate	(1,075)		(5,446)		4,371		991		(3,834)		4,825
Total Consolidated	$	(106,068	)	$	90,595	$	(196,663	)	$	(19,477	)	$	193,256	$	(212,733	)	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,								Three Months Ended March 31,						Six Months Ended March 31,
(Thousands)	2020		2019			Increase (Decrease)			2020		2019		Increase (Decrease)			(Thousands)	2021		2020		Increase (Decrease)		2021		2020		Increase (Decrease)
Gas (after Hedging)	$	119,139	$	116,962		$	2,177		$	246,377	$	236,712	$	9,665		Gas (after Hedging)	$	186,530	$	119,139	$	67,391	$	349,038	$	246,377	$	102,661
Oil (after Hedging)	35,302		34,418			884			73,142		69,682		3,460			Oil (after Hedging)	32,067		35,302		(3,235)		60,191		73,142		(12,951)
Gas Processing Plant	714		971			(257		)	1,402		1,945		(543		)	Gas Processing Plant	772		714		58		1,324		1,402		(78)
Other	405		(6,249		)	6,654			578		639		(61		)	Other	818		405		413		1,029		578		451
	$	155,560	$	146,102		$	9,458		$	321,499	$	308,978	$	12,521			$	220,187	$	155,560	$	64,627	$	411,582	$	321,499	$	90,083

Gas Production (MMcf)

Oil Production (Mbbl)

Three Months Ended
March 31, Six Months Ended
March 31,
2020 2019 Increase (Decrease) 2020 2019 Increase (Decrease)
Gas Production (MMcf)

Appalachia 55,638
44,883
10,755
109,922
90,188
19,734
West Coast 479
487
(8 ) 966
989
(23 )
Total Production 56,117
45,370
10,747
110,888
91,177
19,711

Oil Production (Mbbl)

Appalachia 1
1
—
2
2
—
West Coast 605
563
42
1,206
1,134
72
Total Production 606
564
42
1,208
1,136
72

Three Months Ended
March 31, Six Months Ended
March 31,
2020 2019 Increase (Decrease) 2020 2019 Increase (Decrease)
Average Gas Price/Mcf

Appalachia $ 1.77
$ 2.65
$ (0.88 ) $ 1.97
$ 2.79
$ (0.82 )
West Coast $ 4.34
$ 6.06
$ (1.72 ) $ 4.67
$ 6.40
$ (1.73 )
Weighted Average $ 1.80
$ 2.69
$ (0.89 ) $ 1.99
$ 2.83
$ (0.84 )
Weighted Average After Hedging $ 2.12
$ 2.58
$ (0.46 ) $ 2.22
$ 2.60
$ (0.38 )

Average Oil Price/Bbl

Appalachia $ 55.90
$ 47.54
$ 8.36
$ 55.48
$ 55.93
$ (0.45 )
West Coast $ 49.91
$ 61.85
$ (11.94 ) $ 56.25
$ 63.79
$ (7.54 )
Weighted Average $ 49.92
$ 61.82
$ (11.90 ) $ 56.25
$ 63.78
$ (7.53 )
Weighted Average After Hedging $ 58.23
$ 61.01
$ (2.78 ) $ 60.57
$ 61.36
$ (0.79 )

~~2020~~2021 Compared with ~~2019~~2020

Operating revenues for the Exploration and Production segment increased ~~$9.5~~$64.6 million for the quarter ended March 31, ~~2020~~2021 as compared with the quarter ended March 31, ~~2019.~~2020. Gas production revenue after hedging increased ~~$2.2~~$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 ~~10.7~~$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 ~~largely~~partially offset by ~~the impact of~~ a ~~$0.46~~$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 ~~completed and connected to sales in the Western and Eastern Development Areas~~ in the Appalachian region during the ~~quarter~~six months ended March 31, ~~2020~~2021 as compared with the ~~quarter~~six months ended March 31, ~~2019.~~2020. Oil production revenue after hedging ~~increased $0.9~~decreased $13.0 million due to a ~~42 Mbbl increase in oil production, which was largely offset by the impact of a $2.78~~$7.07 per Bbl decrease in the weighted average price of oil after hedging. The increase in oil production revenue was largely due to higher production in the West Coast region. In addition, other revenue increased $6.7 million primarily due to mark-to-market adjustments related to hedge ineffectiveness on oil hedges recorded in the prior year quarter.

~~Operating revenues for the Exploration and Production segment increased $12.5 million for the six months ended March 31, 2020 as compared~~hedging, coupled with ~~the six months ended March 31, 2019. Gas production revenue after hedging increased $9.7 million due to a 19.7 Bcf increase in gas production which was largely offset by~~ the impact of ~~a $0.38 per Mcf~~an 83 Mbbl decrease in ~~the weighted average price of gas after hedging.~~oil production. The increase in gas production was primarily due to new Marcellus and Utica wells completed and connected to sales in the Western and Eastern Development Areas in the Appalachian region during the six months ended March 31, 2020 as compared with the six months ended March 31, 2019. Oil production revenue after hedging increased $3.5 million due to a 72 Mbbl increase in oil production, which was offset by the impact of a $0.79 per Bbl decrease ~~in the weighted average price of oil after hedging. The increase~~ in oil production was largely due to ~~higher~~natural production declines as a result of lower activity in ~~the West Coast region.~~response to decreased crude oil prices.

The Exploration and Production segment's ~~loss~~earnings for the quarter ended March 31, ~~2020 was $175.3~~2021 were $36.8 million, ~~a decrease~~an increase of ~~$197.2~~$212.1 million when compared with ~~earnings~~a loss of ~~$21.9~~$175.3 million for the quarter ended March 31, ~~2019.~~2020. The ~~loss can be attributed~~increase in earnings was due to ana quarter ended March 31, 2020 non-cash impairment of oil and gas properties ($129.3 million), ~~as discussed above, recognition of~~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 ($60.5 million),. The earnings impact of these items was partially offset by lower ~~natural gas prices after hedging~~oil production ($~~20.2~~2.1 million), lower oil prices after hedging ($~~1.3~~0.5 million), higher lease operating and transportation expenses ($12.1 million), higher depletion expense ($~~7.3~~0.8 million), ~~an increase in lease~~higher other operating ~~and transportation~~ expenses ($~~4.6~~0.7 million), higher interest expense ($1.0 million) and a higher effective ~~income~~ tax rate ($~~1.6~~2.4 million). Regarding the deferred tax valuation allowance, a valuation allowance for deferred tax assets, including net operating losses, 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. During the quarter ended March 31, 2020, the Company recorded a full valuation allowance in the amount of $60.5 million in the Exploration and Production segment against certain state deferred tax assets based on its conclusion, considering all available evidence (both positive and negative), that it was more likely than not that the deferred tax assets would not be realized. A significant item of objective negative evidence considered was a projected three-year cumulative pre-tax loss primarily due to non-cash impairments of proved natural gas and oil properties due to declining commodity prices. 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. 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 ~~result of increased gathering and transportation costs~~net increase in production offset by a $0.22 per Mcf decrease in the ~~Appalachian region~~depletion rate due to ~~increased production. A higher effective tax rate was largely driven by~~prior period non-cash ceiling test impairments coupled with the ~~prior year~~ impact of the ~~Enhanced Oil Recovery tax credit which is not available~~asset acquisition from Shell. The increase in interest expense was primarily driven by additional intercompany long-term borrowings from the ~~current year. These~~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 ~~partially offset by higher natural gas production ($21.9 million), higher oil production ($2.0 million) and the impact~~scheduled to mature in December 2021.

The Exploration and Production segment's ~~loss~~earnings for the six months ended March 31, ~~2020 was $151.3~~2021 were $7.2 million, ~~a decrease~~an increase of ~~$211.4~~$158.5 million when compared with ~~earnings~~a loss of ~~$60.1~~$151.3 million for the six months ended March 31, ~~2019.~~2020. The ~~loss~~increase in earnings was primarily attributable to ~~an impairment~~a decrease in impairments of oil and gas properties ($129.3 ~~million)~~million during the six months ended March 31, 2020 compared to $55.2 million during the six months ended March 31, 2021), ~~as discussed above, recognition of~~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 ($60.5 million) ~~also discussed above,~~. These increases in earnings were partially offset by lower natural gas prices after hedging ($~~32.8~~1.6 million), lower oil production ($4.0 million), lower oil prices after hedging ($~~0.8~~6.3 million), higher lease operating and transportation expenses ($~~11.1~~23.7 million), higher depletion expense ($1.7 million), higher other operating expenses ($~~1.0~~2.5 million), higher ~~depletion~~interest expense of ($~~14.8~~2.1 million), and a higher effective tax rate ($~~3.0 million) and the impact of a remeasurement of the segment's accumulated deferred income taxes in the prior quarter that did not recur in fiscal 2020 ($1.0~~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 ~~other operating expenses was largely due to an increase in the purchased gas emissions credit in the West Coast region and higher personnel costs. The increase in~~ depletion expense was primarily due to anthe net increase in production ~~as well as~~offset by a ~~higher~~$0.20 per Mcf decrease in the depletion ~~rate. A higher effective tax~~ rate ~~was largely driven by~~due to prior period non-cash ceiling test impairments coupled with the ~~prior year~~ impact of the ~~Enhanced Oil Recovery tax credit which is not available~~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 ~~current year. These~~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 ~~partially offset by higher natural gas production ($40.4 million) and higher oil production ($3.5 million).~~scheduled to mature in December 2021.

Pipeline and Storage

Pipeline and Storage Operating Revenues

Pipeline and Storage Throughput

~~2020~~2021 Compared with ~~2019~~2020

Operating revenues for the Pipeline and Storage segment increased ~~$6.9~~$7.5 million for the quarter ended March 31, ~~2020~~2021 as compared with the quarter ended March 31, ~~2019.~~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 ~~$1.2~~$0.7 million. The increase in transportation ~~and storage~~ revenues was ~~primarily~~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 ~~and storage~~ rates effective February 1, 2020 in accordance with Supply Corporation's rate case ~~settlement in principle.~~settlement. The settlement ~~remains subject to~~was approved by the FERC ~~approval. New demand charges for transportation service from Supply Corporation's Line N to Monaca Project, which was placed in service~~ on ~~November~~June 1, ~~2019, also contributed to the~~2020. The increase in transportation ~~revenues.~~revenues was partially offset by the termination of a greenhouse gas (GHG) surcharge associated with Supply Corporation's rate case settlement mentioned above

and also by contract terminations and restructurings. The increase in storage revenues was ~~partially offset by a decline~~primarily attributable to an increase in ~~demand charges for~~ Supply Corporation's storage ~~service as a result of the termination of a temporary contract that was acquired in relation~~rates related to ~~the fiscal 2018 acquisition of the remaining interest in a jointly owned storage field.~~its aforementioned rate case settlement.

Operating revenues for the Pipeline and Storage segment increased ~~$2.1~~$23.0 million for the six months ended March 31, ~~2020~~2021 as compared with the six months ended March 31, ~~2019.~~2020. The increase in operating revenues was primarily due to an increase in transportation revenues of ~~$3.5~~$17.6 million, ~~combined with~~ an increase in storage revenues of ~~$0.7~~$2.8 million ~~partially offset by a decrease~~and an increase in other revenues of ~~$2.1~~$2.6 million. The increase in transportation ~~and storage~~ 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 ~~and storage~~ rates effective February 1, 2020 related to the rate case settlement ~~in principle~~ mentioned above. ~~Transportation revenues also increased due to an~~The increase in ~~Empire's~~ transportation ~~rates effective January 1, 2019 in accordance~~revenues was partially offset by the reduction of the GHG surcharge associated with ~~Empire's~~Supply Corporation's rate case settlement ~~which was approved~~mentioned above, and also by ~~the FERC on May 3, 2019, combined with an increase in demand charges for transportation service from Supply Corporation's Line N to Monaca Project, partially offset by~~contract terminations and restructurings and a decrease in ~~transportation~~ revenues ~~attributable to an Empire system transportation contract termination in December 2018.~~from short-term seasonal contracts. The increase in storage revenues ~~due~~was primarily attributable to ~~the~~an increase in Supply Corporation's storage rates ~~from the~~related to its aforementioned rate case settlement in principle was partially offset by a decline in demand charges from Supply Corporation's storage service as a result of the termination of a temporary contract that was acquired in relation to the fiscal 2018 acquisition of the remaining interest in a jointly owned storage field.settlement. The ~~decrease~~increase in other revenues was primarily due to proceeds received ~~by Supply Corporation in~~during the ~~first~~ quarter ~~of fiscal 2019 related to a contract termination~~ended December 31, 2020 as a result of a ~~shipper's bankruptcy that did not recur during fiscal 2020.~~contract buyout.

Transportation volume for the quarter ended March 31, ~~2020 decreased~~2021 increased by ~~4.0~~13.6 Bcf from the prior year's quarter, primarily ~~a reflection of weather that~~due to incremental volume from the Empire North Project, which was ~~warmer than the prior year.~~brought online on September 15, 2020. For the six months ended March 31, ~~2020,~~2021, transportation volume increased by ~~12.5~~7.9 Bcf from the prior year's six-month period ended March 31, ~~2019.~~2020. The increase in transportation volume for the six-month period primarily reflects an increase in ~~capacity utilization by certain contract shippers,~~volume from the Empire North Project, partially offset by a decrease in volume from ~~warmer weather.~~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, ~~2020~~2021 were ~~$22.1~~$24.9 million, an increase of ~~$4.4~~$2.8 million when compared with earnings of ~~$17.7~~$22.1 million for the quarter ended March 31, ~~2019.~~2020. The increase in earnings was primarily due to the earnings impact of higher operating revenues of ~~$5.5~~$5.9 million, as discussed above, ~~combined~~along with a decrease in operating expenses ($~~0.7~~1.8 million). The decrease in operating expenses ~~primarily reflects lower compressor and facility maintenance~~was mainly due to a decrease in the reserve for preliminary project costs, partially offset by an increase in ~~pipeline integrity~~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 ($~~1.6~~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 ~~in principle~~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, ~~2020~~2021 were ~~$40.2~~$49.1 million, ~~a decrease~~an increase of ~~$2.7~~$8.9 million when compared with earnings of ~~$42.9~~$40.2 million for the six months ended March 31, ~~2019.~~2020. The ~~decrease~~increase in earnings was primarily due to the earnings impact of higher ~~depreciation expense~~operating revenues of $18.2 million, as discussed above, combined with a decrease in operating expenses ($~~2.0~~1.6 million)~~, higher property taxes ($1.2 million),~~ and ~~higher~~lower income tax expense ($~~2.5~~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 ~~in principle.~~as well as incremental depreciation from the Empire North Project going into service, both mentioned above. The increase in ~~property taxes~~interest expense was primarily due to interest on additional intercompany long-term borrowings associated with the scheduled phase-out of tax incentives in certain jurisdictions along the Empire system, as well as higher town, county and school taxes due to an increase in assessed values from new projects placed in service. Income tax expense was higher due to permanent differences related to stock compensation activity.Company's June 2020 debt issuance. The decrease in other income was ~~primarily~~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 six-month period compared to non-service pension and post-retirement income in the six months ended March 31, 2019, partially offset by an increase in allowance for funds used during construction (equity component) related to the construction of the Empire North project. These earnings decreases were partially offset by the earnings impact of higher operating revenues ($1.6 million), as discussed above, and a decrease in operating expenses ($1.3 million). The decrease in operating expenses was primarily due to lower compressor and facility maintenance costs as well as a decrease in personnel and compensation costs, partially offset by an increase in pipeline integrity costs.2020.

Gathering Operating Revenues

Three Months Ended
March 31, Six Months Ended
March 31,
(Thousands) 2020 2019 Increase (Decrease) 2020 2019 Increase (Decrease)
Gathering Revenues $ 35,267
$ 29,366
$ 5,901
$ 70,055
$ 59,056
$ 10,999
Processing and Other Revenues —
2
(2 ) —
2
(2 )
$ 35,267
$ 29,368
$ 5,899
$ 70,055
$ 59,058
$ 10,997

~~2020~~2021 Compared with ~~2019~~2020

Operating revenues for the Gathering segment increased ~~$5.9~~$15.0 million for ~~the~~the quarter ended March 31, ~~2020~~2021 as compared with the quarter ended March 31, ~~2019.~~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 ~~was primarily due~~as the Tioga gathering system (the name given to ~~an 11.0~~the acquired assets) recorded 20.0 Bcf ~~net~~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, ~~resulting from~~the Wellsboro gathering system, which experienced a ~~6.5 Bcf, 4.4 Bcf and 1.2~~3.5 Bcf increase in gathered volume ~~on Midstream Company's~~and the Trout Run ~~Clermont and Wellsboro~~ gathering ~~systems, respectively,~~system, which experienced a 3.2 Bcf increase in gathered volume. These increases were partially offset by a ~~1.1~~0.5 Bcf ~~decline~~decrease in gathered volume ~~on its~~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.~~region, as discussed above.

Operating revenues ~~for~~for the Gathering segment increased ~~$11.0~~$27.2 million for the six months ended March 31, 2021 as compared with the six months ended March 31, 2020, ~~as compared with the six months ended March 31, 2019.~~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 ~~20.7 Bcf net increase in gathered volume resulting from a 10.5 Bcf, 7.8 Bcf and 5.1~~41.0 Bcf increase in gathered ~~volume on its~~volume. Other contributors to the increase included the Clermont, Wellsboro and Trout Run ~~Clermont~~gathering systems, which recorded increases of 7.9 Bcf, 4.4 Bcf and ~~Wellsboro gathering systems,~~2.1 Bcf, respectively. These increases were partially offset by a ~~2.7~~1.5 Bcf decrease in gathered volume on the Covington gathering system. The ~~20.7 Bcf~~ net increase in gathered volume can be attributed to the net increase in Seneca's natural gas production, ~~for the six months ended March 31, 2020 compared to the six months ended March 31, 2019.~~as discussed above.

The Gathering segment’s earnings for the quarter ended March 31, ~~2020~~2021 were ~~$19.9~~$20.7 million, an increase of ~~$7.2~~$0.8 million when compared with earnings of ~~$12.7~~$19.9 million for the quarter ended March 31, ~~2019.~~2020. The increase in earnings was mainly due to ~~the~~ higher gathering revenues ($11.8 million) driven by the increase in gathered volume, as discussed ~~above ($4.7 million) and~~above. Additionally, the ~~positive~~Gathering segment's earnings ~~impact~~were negatively impacted ($3.8 million) as a result of the Gathering segment's recognition of an income tax benefit that was recorded during the quarter ended March 31, 2020 as an offset to the valuation allowance ~~described above~~established in the Exploration and Production segment. This offset is a result of the Gathering and Exploration and Production ~~segments’~~segments' subsidiaries ~~filing a combined~~being included in the same state tax return. Taxable income generated in the Gathering segment is used to offset taxable losses in the Exploration and Production segment, which provided the opportunity to reduce the valuation allowance recorded in the Exploration and Production segment. ~~These increases~~Further, earnings decreased due to ~~earnings were partially offset by~~ higher operating expenses ($~~0.8~~2.5 million), higher depreciation expense ($2.2 million) and higher ~~depreciation~~interest expense ($~~0.5~~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 ~~largely~~ to ~~increased preventative maintenance and overhaul activities at Covington and Trout Run compressor stations during~~higher lease compression expense associated with the ~~quarter ended March 31, 2020.~~Tioga gathering system. The increase in depreciation expense was largely due to anhigher plant balances associated with the Tioga gathering system. The increase in interest expense was primarily driven by additional intercompany long-term borrowings from the ~~average gross property, plant and equipment assets~~Company's long-term debt issuance in ~~service as compared~~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 ~~prior year.~~Company's 4.90% notes that were scheduled to mature in December 2021.

The Gathering segment’s earnings for the six months ended March 31, ~~2020~~2021 were ~~$35.8~~$41.3 million, an increase of ~~$8.9~~$5.5 million when compared with earnings of ~~$26.9~~$35.8 million for the six months ended March 31, ~~2019.~~2020. The increase in earnings was mainly due to the ~~impact of~~ higher gathering revenues ($21.5 million) driven by the increase in gathered volume, as discussed ~~above ($8.7 million) and lower interest expense ($0.3 million).~~above. Additionally, the Gathering segment's earnings were ~~positively~~negatively impacted ($3.8 million) as a result of the Gathering segment's recognition of an income tax benefit that was recorded during the quarter ended March 31, 2020 as an offset to the valuation allowance established in the Exploration and Production ~~segment, as~~segment. This offset is a result of the Gathering and Exploration and Production segments’ subsidiaries filing a combined state tax return (as discussed ~~above. These~~above). Further, earnings ~~increases were partially offset by~~decreased due to higher operating expenses ($~~2.0~~3.9 million), higher depreciation expense ($~~0.8~~4.4 million) and higher interest expense ($3.1 million), ~~higher income tax expense ($0.2 million) and~~with each of these increases primarily being a result of the ~~impact~~acquisition of ~~a nonrecurring income tax benefit recorded in the prior year quarter to adjust the remeasurement of deferred income taxes resulting~~midstream gathering assets from ~~the 2017 Tax Reform Act ($0.5 million).~~Shell on July 31, 2020. The increase in operating expenses was largely due to higher lease compression expense associated with the ~~completion of compressor unit overhauls on Covington and Trout Run~~Tioga gathering ~~system compressor stations during the current year.~~system. The increase in depreciation expense was largely due to higher plant balances atassociated with the ~~Trout Run, Clermont and Wellsboro~~Tioga gathering ~~systems.~~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 Operating Revenues

Three Months Ended
March 31, Six Months Ended
March 31,
(Thousands) 2020 2019 Increase (Decrease) 2020 2019 Increase (Decrease)
Retail Sales Revenues:

Residential $ 187,932
$ 228,061
$ (40,129 ) $ 333,547
$ 393,394
$ (59,847 )
Commercial 26,213
32,682
(6,469 ) 45,874
55,424
(9,550 )
Industrial 1,162
1,867
(705 ) 2,429
3,360
(931 )
215,307
262,610
(47,303 ) 381,850
452,178
(70,328 )
Transportation 42,710
46,383
(3,673 ) 76,316
82,333
(6,017 )
Other (3,524 ) (5,963 ) 2,439
(6,848 ) (8,824 ) 1,976
$ 254,493
$ 303,030
$ (48,537 ) $ 451,318
$ 525,687
$ (74,369 )

~~2020 Compared with 2019~~


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 ~~decreased $48.5~~increased $16.4 million for the quarter ended March 31, ~~2020~~2021 as compared with the quarter ended March 31, ~~2019.~~2020. The ~~decrease~~increase primarily resulted from ~~a $47.3~~an $18.7 million ~~decrease~~increase in retail gas sales ~~revenue and a $3.7 million decrease in transportation revenues.~~revenue. The ~~reduction~~increase in retail gas sales revenue was largely due to a ~~decrease~~modest increase in the cost of gas sold (per Mcf) coupled with ~~lower~~higher throughput due to ~~warmer~~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 ~~3.8~~0.6 Bcf decrease in transportation throughput ~~due~~as residential customers switched from transportation service to ~~warmer weather and the migration of residential transportation customers to retail. These decreases were partially offset by a $2.4 million increase~~retail service. The decrease in other revenues was largely due to ~~a smaller estimated refund provision recorded during the quarter ended March 31, 2020 for the current income tax benefits resulting from the 2017 Tax Reform Act ($1.7 million) and~~ the impact of other regulatory true-up adjustments ($0.9 million).

Operating revenues for the Utility segment ~~decreased $74.4~~increased $8.6 million for the six months ended March 31, ~~2020~~2021 as compared with the six months ended March 31, ~~2019.~~2020. The ~~decrease~~increase largely resulted from a ~~$70.3~~$12.1 million ~~decrease~~increase in retail gas sales revenue and a ~~$6.0~~$0.7 million ~~decrease~~increase in ~~transportation~~other revenues. The ~~reduction~~increase in retail gas sales revenue was largely a result of a decrease in the cost of gas sold (per Mcf) coupled with lower throughput due to warmer weather. The decline in transportation revenues was primarily due to a 5.5 Bcf decrease in throughput due to warmer weather and the migration of residential transportation customers to retail. ~~These decreases were partially offset by a $2.0 million increase in other revenues.~~ The increase in other revenues was largely due to a smaller estimated refund provision recorded during the six months ended March 31, ~~2020 for~~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 ~~current income tax benefits resulting from the 2017 Tax Reform Act ($1.8 million).~~migration of residential transportation customers to retail and slightly warmer weather.

The Utility segment’s earnings for the quarter ended March 31, ~~2020~~2021 were ~~$31.5~~$32.0 million, ~~a decrease~~an increase of ~~$4.1~~$0.5 million when compared with earnings of ~~$35.6~~$31.5 million for the quarter ended March 31, ~~2019.~~2020. The ~~decrease~~increase in earnings was largely attributable to ~~the impact of lower~~higher usage and weather on customer margins ($~~3.8~~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 ($1.2 million) and higher operating expenses ($~~2.9~~1.4 million), which were ~~largely~~primarily a result of higher personnel costs and ~~a slightly higher accrual~~an increase to the allowance for ~~bad debt expense. Bad debt expense may~~uncollectible accounts. The increase ~~more significantly in future quarters depending on~~to the ~~extent and duration of the pandemic crisis. These decreases were slightly offset by the positive earnings impact~~allowance for uncollectible accounts is related to ~~a system modernization tracker ($1.7 million) and~~ the ~~impact of regulatory true-up adjustments ($0.6 million).~~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, ~~the~~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. ~~For the quarter ended March 31, 2019, the WNC increased earnings by approximately $0.1 million, as the weather was warmer than normal.~~

The Utility segment’s earnings for the six months ended March 31, ~~2020~~2021 were ~~$58.1~~$55.1 million, a decrease of ~~$3.1~~$3.0 million when compared with earnings of ~~$61.2~~$58.1 million for the six months ended March 31, ~~2019.~~2020. The decrease in earnings was largely attributable to ~~the impacts of lower usage and weather on customer margins ($3.7 million) and~~ higher operating expenses ($~~2.7~~3.3 million), which were ~~largely~~primarily a result of higher personnel costs and ~~a slightly~~an increase to the allowance for uncollectible accounts, both of which are discussed above, higher ~~accrual for bad debt~~income tax expense ~~as discussed above.~~($1.2 million) and the impact of regulatory true-up adjustments ($1.0 million). These decreases were slightly offset by the positive earnings impact related to the system modernization tracker ($~~2.0~~2.5 million) and the ~~impact~~impacts of ~~regulatory true-up adjustments~~higher usage on customer margins ($~~1.6~~0.3 million).

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. ~~For the six months ended March 31, 2019, the WNC decreased earnings by approximately $0.7 million, as the weather was colder than normal.~~

Corporate and All Other

~~2020~~2021 Compared with ~~2019~~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, ~~a decrease~~the Company recorded unrealized losses of ~~$7.0~~$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 ~~when compared~~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 ~~$2.7~~$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, ~~2019. The decrease in earnings was primarily attributable~~2021 as compared to ~~unrealized losses on investments in equity securities recorded during~~ the quarter ended March 31, 2020, compared to unrealized gains recorded during the quarter ended March 31, 2019 ($7.3 million) coupled with higher interest expense ($0.6 million). These negative drivers of earnings were partially offset by the impact of higher energy marking margins ($0.6 million) and lower operating expenses ($0.4 million).

2020. For the six months ended March 31, ~~2020, Corporate and All Other operations had a loss of $2.3~~2021, net other deductions decreased $7.5 million ~~a decrease of $4.5 million when~~as compared ~~with earnings of $2.2 million for~~to the six months ended March 31, ~~2019. The decrease in earnings was~~2020. These decreases are primarily attributable to the impact of the prior year remeasurement of deferred income taxes under the 2017 Tax Reform Act that lowered income tax expense for the six months ended March 31, 2019 ($3.5 million), coupled with higherchanges in unrealized gains and losses on investments in equity ~~securities~~securities. During the quarter ended March 31, 2020, the Company recorded ~~during~~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, ~~($3.1 million) and higher interest expense ($0.7 million). These negative drivers~~the Company recorded pre-tax unrealized losses of ~~earnings were partially offset by~~$6.4 million. During the ~~impact~~six months ended March 31, 2021, the Company recorded pre-tax unrealized losses of higher other income ($1.0 million) that was driven largely by an increase in realized gains on investments in equity securities sold in the current year, higher energy marketing margins ($0.9 million) and lower operating expenses ($0.7 million).$0.5 million.

Interest Expense on Long-Term Debt

Interest expense on long-term debt ~~was relatively flat~~on the Consolidated Statement of Income increased $23.6 million for ~~both~~ the quarter ~~and~~ended March 31, 2021 as compared to the quarter ended March 31, 2020. For the six months ended March 31, ~~2020,~~2021, interest expense on long-term debt increased $30.4 million as compared towith the ~~quarter and~~ six months ended March 31, ~~2019. No new additional~~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 ~~was issued or repaid during~~balance stemming from the ~~quarters ended March 31, 2020 and March 31, 2019. In addition, amortization~~issuance of ~~debt premiums discount and expense and capitalized interest remained comparable year over year.~~$500.0 million of 5.50% notes in June 2020.

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. ~~The Company's primary source~~

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, ~~and in the Company's NFR operations (included in the All Other category),~~ revenues in ~~these businesses~~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, ~~and futures contracts~~ in an attempt to manage this energy commodity price risk.

Net cash provided by operating activities totaled ~~$391.0~~$417.1 million for the six months ended March 31, ~~2020,~~2021, an increase of ~~$50.2~~$26.1 million compared with ~~$340.8~~$391.0 million provided by operating activities for the six months ended March 31, ~~2019.~~2020. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the ~~Utility~~Pipeline and Storage segment, the Exploration and Production segment, and ~~Corporate and All Other categories.~~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 ~~was~~is primarily due to the timing of gas cost recovery and the timing of receivable collections. The increase in the Corporate and All Other categories was primarily due to the impact of the 2017 Tax Reform Act that repealed the corporate alternative minimum tax and provided that the Company's existing AMT credit carryovers were refundable, if not utilized to reduce tax. The first installment of AMT credit refunds were received in January 2020.

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 and $372.7 million during the six months ended March 31, 2019.~~2020. The table below presents these 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 ~~Exploration~~Pipeline and ~~Production~~Storage segment capital expenditures for the six months ended March 31, ~~2019~~2021 were primarily ~~well drilling~~for expenditures related to Supply Corporation's FM100 Project ($60.8 million), which is discussed below. In addition, the Pipeline and ~~completion~~Storage segment capital expenditures ~~and included approximately $247.6 million~~ for the ~~Appalachian region (including $111.8 million in the Marcellus Shale area~~six months ended March 31, 2021 included additions, improvements and ~~$125.9 million in the Utica Shale area)~~replacements to this segment’s transmission and ~~$15.2 million for the West Coast region. These amounts included approximately $144.7 million spent to develop proved undeveloped reserves.~~

~~Pipeline and Storage~~

gas storage systems. The Pipeline and Storage segment capital expenditures for the six months ended March 31, 2020 were primarily for expenditures related to ~~Empire's~~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. ~~Both projects are discussed below.~~ 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. The Pipeline and Storage capital expenditures for the six months ended March 31, 2019 were primarily for additions, improvements and replacements to this segment’s transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for the six months ended March 31, 2019 included expenditures related to Supply Corporation's Line N to Monaca Project ($4.1 million) and Empire's Empire North Project ($3.7 million).

In light of the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia, — specifically in the Marcellus and Utica Shale producing areas, — Supply Corporation and Empire have completed and

continue to pursue ~~several~~ expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines

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

Supply Corporation completed a project to provide incremental natural gas transportation services from Line N to the ethane cracker facility being constructed by Shell Chemical Appalachia, LLC in Potter Township, Pennsylvania ("Line N to Monaca Project"), with transportation service beginning on November 1, 2019. This project involved construction of a 4.5 mile pipeline extension from Line N to the facility and has resulted in Supply Corporation securing incremental firm transportation capacity commitments totaling 133,000 Dth per day on Line N and on the pipeline extension to the facility. Supply Corporation was authorized to pursue the project by FERC under its blanket certificate as of May 30, 2018. As of March 31, 2020, approximately $22.2 million has been spent on the Line N to Monaca Project, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2020.

Empire concluded an Open Season on November 18, 2015, and has designed a project that would allow for the transportation of 205,000 Dth per day of additional shale supplies from interconnections in Tioga County, Pennsylvania, to TransCanada Pipeline, and the TGP 200 Line (“Empire North Project”). This project is fully subscribed under long term agreements and received the FERC Section 7(c) certificate on March 7, 2019. Project construction is under way. The Empire North Project has a projected in-service date late in the fourth quarter of fiscal 2020 and an estimated capital cost of approximately $145 million. As of March 31, 2020, approximately $90.9 million has been capitalized as Construction Work in Progress for this project, including $19.9 million of costs transferred from the Northern Access Project, which is discussed below.

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 ~~the~~an anchor shipper on Leidy South, ~~providing Seneca~~which provides it with an outlet to premium markets ~~for its Marcellus and Utica production~~ from both ~~the Clermont-Rich Valley (Western Development Area)~~its Eastern and ~~Trout Run-Gamble (Eastern Development Area~~ – ~~Lycoming County)~~Western development areas. ~~Supply Corporation filed a Section 7(c) application with the FERC in July 2019. On February 7, 2020, the~~ FERC issued the ~~Environmental Assessment for~~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 ~~project.~~Lease was fully executed on that date. Construction activities are fully in progress. The FM100 Project has a target in-service date inof late calendar 2021 and a preliminary cost estimate of approximately $280 million. As of March 31, ~~2020,~~2021, approximately ~~$7.2~~$67.9 million has been spent on the FM100 Project, including $5.6 million spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet. The remaining $1.6 million spent on the project has been capitalized as Construction Work in ~~Progress.~~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 ~~TransCanada Pipeline~~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 ~~have been appealed and are pending in a separate action before~~were appealed. Recently, the Second Circuit Court of ~~Appeals.~~Appeals issued an order upholding the FERC waiver orders. In addition, in the ~~Company commenced legal action in New York State Supreme Court~~Company's state court litigation challenging the NYDEC's actions with regard to various state ~~permits.~~permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project. In light of these pending legal actions and the need to complete necessary project development activities in advance of construction, the in-service date for the project is expected to be no earlier than fiscal 2022. The Company will update the $500 million preliminary cost estimate and expected in-service date for the project when there is further clarity on ~~that date.~~the pending legal actions. As of March 31, ~~2020,~~2021, approximately ~~$58.0~~$55.6 million has been spent on the Northern Access project, including ~~$23.5~~$24.0 million that has been spent to study the project, for which no reserve has been established. The remaining ~~$34.5~~$31.6 million spent on the project ~~has been capitalized as Construction Work~~is included in ~~Progress.~~Property, Plant and Equipment on the Consolidated Balance Sheet at March 31, 2021.

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,

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


INDEX		Page

Part I. Financial Information

~~INDEX~~	~~Page~~

~~Part I. Financial Information~~

Item 1. Financial Statements (Unaudited)	6

a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Six Months Ended March 31, ~~2020~~2021 and ~~2019~~2020		6
b. Consolidated Statements of Comprehensive Income – Three and Six Months Ended March 31, ~~2020~~2021 and ~~2019~~2020		7
c. Consolidated Balance Sheets – March 31, ~~2020~~2021 and September 30, ~~2019~~2020		8
d. Consolidated Statements of Cash Flows – Six Months Ended March 31, ~~2020~~2021 and ~~2019~~ 2020		10
e. Notes to Condensed Consolidated Financial Statements		11
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		3329
Item 3. Quantitative and Qualitative Disclosures About Market Risk		5249
Item 4. Controls and Procedures		5350

Part II. Other Information

Item 1. Legal Proceedings		5350
Item 1 A. Risk Factors		5350
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		5653
Item 3. Defaults Upon Senior Securities		•
Item 4. Mine Safety Disclosures		•
Item 5. Other Information		•
Item 6. Exhibits		5754
Signatures		5855


	March 31, 2020			September 30, 2019				March 31, 2021		September 30, 2020
(Thousands of U.S. Dollars)							(Thousands of U.S. Dollars)
CAPITALIZATION AND LIABILITIES							CAPITALIZATION AND LIABILITIES
Capitalization:							Capitalization:
Comprehensive Shareholders’ Equity							Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value							Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued And Outstanding – 86,561,532 Shares and 86,315,287 Shares, Respectively	$	86,562		$	86,315
Authorized - 200,000,000 Shares; Issued And Outstanding – 91,163,797 Shares and 90,954,696 Shares, Respectively							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	835,444			832,264			Paid in Capital	1,009,075		1,004,158
Earnings Reinvested in the Business	1,176,870			1,272,601			Earnings Reinvested in the Business	1,100,718		991,630
Accumulated Other Comprehensive Loss	(18,917		)	(52,155		)	Accumulated Other Comprehensive Loss	(101,988)		(114,757)
Total Comprehensive Shareholders’ Equity	2,079,959			2,139,025			Total Comprehensive Shareholders’ Equity	2,098,969		1,971,986
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,134,964			2,133,718			Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,627,033		2,629,576
Total Capitalization	4,214,923			4,272,743			Total Capitalization	4,726,002		4,601,562

Current and Accrued Liabilities							Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	230,000			55,200			Notes Payable to Banks and Commercial Paper	0		30,000
Current Portion of Long-Term Debt	—			—

Accounts Payable	106,938			132,208			Accounts Payable	107,305		134,126
Amounts Payable to Customers	17,213			4,017			Amounts Payable to Customers	19,768		10,788
Dividends Payable	37,654			37,547			Dividends Payable	40,562		40,475
Interest Payable on Long-Term Debt	18,508			18,508			Interest Payable on Long-Term Debt	17,663		27,521
Customer Advances	615			13,044			Customer Advances	0		15,319
Customer Security Deposits	14,999			16,210			Customer Security Deposits	19,503		17,199
Other Accruals and Current Liabilities	150,239			139,600			Other Accruals and Current Liabilities	176,940		140,176
Fair Value of Derivative Financial Instruments	7,652			5,574			Fair Value of Derivative Financial Instruments	21,231		43,969
	583,818			421,908				402,972		459,573

Deferred Credits							Deferred Credits
Deferred Income Taxes	777,299			653,382			Deferred Income Taxes	763,441		696,054
Taxes Refundable to Customers	360,331			366,503			Taxes Refundable to Customers	355,375		357,508

Cost of Removal Regulatory Liability	224,546			221,699			Cost of Removal Regulatory Liability	237,867		230,079
Other Regulatory Liabilities	157,371			142,367			Other Regulatory Liabilities	177,685		161,573
Pension and Other Post-Retirement Liabilities	126,959			133,729			Pension and Other Post-Retirement Liabilities	118,804		127,181
Asset Retirement Obligations	128,779			127,458			Asset Retirement Obligations	192,127		192,228
Other Deferred Credits	134,633			122,368			Other Deferred Credits	141,379		139,177
	1,909,918			1,767,506				1,986,678		1,903,800
Commitments and Contingencies (Note 8)	—			—			Commitments and Contingencies (Note 8)	0		0

Total Capitalization and Liabilities	$	6,708,659		$	6,462,157		Total Capitalization and Liabilities	$	7,115,652	$	6,964,935


	At March 31, 2020		At September 30, 2019			At March 31, 2021		At September 30, 2020

Prepayments	$	6,289	$	12,728	Prepayments	$	7,692	$	12,851
Prepaid Property and Other Taxes	23,702		14,361		Prepaid Property and Other Taxes	23,373		14,269
Federal Income Taxes Receivable	42,385		42,388

State Income Taxes Receivable	3,455		8,579		State Income Taxes Receivable	0		3,828
Fair Values of Firm Commitments	8,775		7,538

Regulatory Assets	15,582		11,460		Regulatory Assets	25,052		16,609
	$	100,188	$	97,054		$	56,117	$	47,557



	At March 31, 2020		At September 30, 2019

Accrued Capital Expenditures	$	31,886	$	33,713
Regulatory Liabilities	45,338		50,332
Reserve for Gas Replacement	23,978		—
Liability for Royalty and Working Interests	13,987		18,057
Non-Qualified Benefit Plan Liability	13,194		13,194
Other	21,856		24,304
	$	150,239	$	139,600


	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		0
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



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



	Six Months Ended March 31, 2020				Six Months Ended March 31, 2019
	Balance at October 1, 2019		Balance at March 31, 2020		Balance at October 1, 2018		Balance at March 31, 2019

Cash and Temporary Cash Investments	$	20,428	$	111,655	$	229,606	$	100,643
Hedging Collateral Deposits	6,832		10,728		3,441		1,983
Cash, Cash Equivalents, and Restricted Cash	$	27,260	$	122,383	$	233,047	$	102,626


	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)		0		(24,903)
Amounts Reclassified From Other Comprehensive Income (Loss)	2,656		0		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		0		9,888
Amounts Reclassified From Other Comprehensive Income (Loss)	2,881		0		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		0		55,450
Amounts Reclassified From Other Comprehensive Income (Loss)	(18,217)		0		(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		0		55,825
Amounts Reclassified From Other Comprehensive Income (Loss)	(23,537)		0		(23,537)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	950		0		950


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



	Gains and Losses on Derivative Financial Instruments			Gains and Losses on Securities Available for Sale			Funded Status of the Pension and Other Post-Retirement Benefit Plans			Total
Three Months Ended 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	)
Three Months Ended March 31, 2019
Balance at January 1, 2019	$	17,886		$	—		$	(46,576	)	$	(28,690	)
Other Comprehensive Gains and Losses Before Reclassifications	(18,601		)	—			—			(18,601		)
Amounts Reclassified From Other Comprehensive Income (Loss)	3,411			—			—			3,411
Reclassification of Stranded Tax Effects Related to the 2017 Tax Reform Act	1,866			—			(12,272		)	(10,406		)
Balance at March 31, 2019	$	4,562		$	—		$	(58,848	)	$	(54,286	)
Six Months Ended March 31, 2019
Balance at October 1, 2018	$	(28,611	)	$	7,437		$	(46,576	)	$	(67,750	)
Other Comprehensive Gains and Losses Before Reclassifications	13,797			—			—			13,797
Amounts Reclassified From Other Comprehensive Income (Loss)	17,510			—			—			17,510
Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities	—			(7,437		)	—			(7,437		)
Reclassification of Stranded Tax Effects Related to the 2017 Tax Reform Act	1,866			—			(12,272		)	(10,406		)
Balance at March 31, 2019	$	4,562		$	—		$	(58,848	)	$	(54,286	)


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	0	1,909	0	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


1.	For contracts that commenced prior to and existed as of October 1, 2019, a package of practical expedients to not reassess whether a contract is or contains a lease, lease classification, and initial direct costs under the new authoritative guidance;


2.	~~An election not to apply the recognition requirements in the new authoritative guidance to short-term leases (a lease that at commencement date has a lease term of one year or less);~~


3.	~~A practical expedient to not reassess certain land easements that existed prior to October 1, 2019 and were not previously accounted for as leases under the prior authoritative guidance; and~~


4.	~~A practical expedient that permits combining lease and non-lease components in a contract and accounting for the combination as a lease (elected by asset-class).~~



	Three Months Ended March 31, 2020			Six Months Ended March 31, 2020

Operating Lease Expense	$	943		1,916
Variable Lease Expense ⁽¹⁾	137			272
Short-Term Lease Expense⁽²⁾	76			140
Sublease Income	(80		)	(161		)
Total Lease Expense	$	1,076		$	2,167

Short-Term Lease Costs Recorded to Property, Plant and Equipment ⁽³⁾	$	6,776		$	14,289


⁽¹⁾	~~Variable lease payments that are not dependent on an index or rate are not included in the lease liability.~~


⁽²⁾	~~Short-term lease costs exclude expenses related to leases with a lease term of one month or less.~~


⁽³⁾	~~Short-term lease costs relating to drilling rig leases that are capitalized as part of oil and natural gas properties under full cost pool accounting.~~



	At March 31, 2020
Assets:
Deferred Charges	$	18,260

Liabilities:
Other Accruals and Current Liabilities	$	3,390
Other Deferred Credits	$	14,870



	At March 31, 2020

2020 (remaining 6 months)	$	1,877
2021	2,868
2022	2,278
2023	2,270
2024	2,237
Thereafter	9,717
Total Lease Payments	21,247
Less: Interest	(2,987		)
Total Lease Liability	$	18,260



	At September 30, 2019

2020 ⁽¹⁾	$	12,356
2021	2,813
2022	2,264
2023	2,270
2024	2,237
Thereafter	9,717
Total Operating Lease Obligations	$	31,657


⁽¹⁾	The future minimum operating lease payment amount for 2020 includes short-term leases, including drilling rigs, that are not included in the schedule of operating lease liability maturities above under the new authoritative guidance.


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	$	0	$	0	$	0	$	66,759
Derivative Financial Instruments:

Over the Counter Swaps – Gas and Oil	0		18,805		0		(14,768)		4,037
Over the Counter No Cost Collars – Gas	0		0		0		(118)		(118)
Foreign Currency Contracts	0		1,437		0		(1,252)		185
Other Investments:
Balanced Equity Mutual Fund	32,993		0		0		0		32,993
Fixed Income Mutual Fund	70,133		0		0		0		70,133
Common Stock – Financial Services Industry	988		0		0		0		988


Total	$	170,873	$	20,242	$	0	$	(16,138)	$	174,977

Liabilities:
Derivative Financial Instruments:

Over the Counter Swaps – Gas and Oil	0		35,809		0		(14,768)		21,041
Over the Counter No Cost Collars – Gas	0		1,488		0		(118)		1,370
Foreign Currency Contracts	0		72		0		(1,252)		(1,180)
Total	$	0	$	37,369	$	0	$	(16,138)	$	21,231

Total Net Assets/(Liabilities)	$	170,873	$	(17,127)	$	0	$	0	$	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	$	0	$	0	$	0	$	12,285
Derivative Financial Instruments:

Over the Counter Swaps – Gas and Oil	0		36,418		0		(26,400)		10,018
Over the Counter No Cost Collars – Gas	0		0		0		(720)		(720)
Foreign Currency Contracts	0		259		0		(338)		(79)
Other Investments:
Balanced Equity Mutual Fund	39,618		0		0		0		39,618
Fixed Income Mutual Fund	72,253		0		0		0		72,253
Common Stock – Financial Services Industry	639		0		0		0		639


Total	$	124,795	$	36,677	$	0	$	(27,458)	$	134,014

Liabilities:
Derivative Financial Instruments:

Over the Counter Swaps – Gas and Oil	0		61,280		0		(26,400)		34,880
Over the Counter No Cost Collars – Gas	0		8,171		0		(720)		7,451
Foreign Currency Contracts	0		1,976		0		(338)		1,638
Total	$	0	$	71,427	$	0	$	(27,458)	$	43,969

Total Net Assets/(Liabilities)	$	124,795	$	(34,750)	$	0	$	0	$	90,045



Recurring Fair Value Measures	At fair value as of March 31, 2020
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾
Assets:
Cash Equivalents – Money Market Mutual Funds	$	95,966	$	—	$	—	$	—		$	95,966
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	935		—		—		(935		)	—
Over the Counter Swaps – Gas and Oil	—		103,068		—		(2,732		)	100,336
Over the Counter No Cost Collars - Gas	—		—		—		(751		)	(751		)
Foreign Currency Contracts	—		—		—		(4,788		)	(4,788		)
Other Investments:
Balanced Equity Mutual Fund	31,956		—		—		—			31,956
Fixed Income Mutual Fund	63,094		—		—		—			63,094
Common Stock – Financial Services Industry	577		—		—		—			577
Hedging Collateral Deposits	10,728		—		—		—			10,728
Total	$	203,256	$	103,068	$	—	$	(9,206	)	$	297,118

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	6,863	$	—	$	—	$	(935	)	$	5,928
Over the Counter Swaps – Gas and Oil	—		3,398		—		(2,732		)	666
Over the Counter No Cost Collars – Gas	—		970		—		(751		)	219
Foreign Currency Contracts	—		5,627		—		(4,788		)	839
Total	$	6,863	$	9,995	$	—	$	(9,206	)	$	7,652
Total Net Assets/(Liabilities)	$	196,393	$	93,073	$	—	$	—		$	289,466



Recurring Fair Value Measures	At fair value as of September 30, 2019
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾
Assets:
Cash Equivalents – Money Market Mutual Funds	$	10,521	$	—	$	—	$	—		$	10,521
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	2,055		—		—		(2,055		)	—
Over the Counter Swaps – Gas and Oil	—		52,076		—		(1,483		)	50,593
Foreign Currency Contracts	—		5		—		(2,052		)	(2,047		)
Other Investments:
Balanced Equity Mutual Fund	40,660		—		—		—			40,660
Fixed Income Mutual Fund	62,339		—		—		—			62,339
Common Stock – Financial Services Industry	844		—		—		—			844
Hedging Collateral Deposits	6,832		—		—		—			6,832
Total	$	123,251	$	52,081	$	—	$	(5,590	)	$	169,742

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	7,149	$	—	$	—	$	(2,055	)	$	5,094
Over the Counter Swaps – Gas and Oil	—		1,671		—		(1,483		)	188
Foreign Currency Contracts	—		2,344		—		(2,052		)	292
Total	$	7,149	$	4,015	$	—	$	(5,590	)	$	5,574
Total Net Assets/(Liabilities)	$	116,102	$	48,066	$	—	$	—		$	164,168



	March 31, 2020				September 30, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,134,964	$	1,948,127	$	2,133,718	$	2,257,085



The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended March 31, 2020 and 2019 (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,
	2020			2019				2020			2019
Commodity Contracts	$	81,108		$	(27,228	)	Operating Revenue	$	23,396		$	(4,260	)
Commodity Contracts	(134		)	(54		)	Purchased Gas	1,909			(280		)
Foreign Currency Contracts	(4,670		)	1,282			Operating Revenue	(271		)	(199		)
Total	$	76,304		$	(26,000	)		$	25,034		$	(4,739	)



The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Six Months Ended March 31, 2020 and 2019 (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,
	2020			2019				2020			2019
Commodity Contracts	$	79,553		$	22,825		Operating Revenue	$	30,937		$	(22,782	)
Commodity Contracts	997			(1,333		)	Purchased Gas	1,911			(1,182		)
Foreign Currency Contracts	(3,751		)	(2,102		)	Operating Revenue	(462		)	(420		)
Total	$	76,799		$	19,390			$	32,386		$	(24,384	)


⁽¹⁾	~~Percents compare actual 2020 degree days to normal degree days and actual 2020 degree days to actual 2019 degree days.~~


Total Expenditures for Long-Lived Assets										Total Expenditures for Long-Lived Assets
Six Months Ended March 31,	2020			2019			Increase (Decrease)			Six Months Ended March 31,	2021			2020			Increase (Decrease)
(Millions)						(Millions)
Exploration and Production:													Exploration and Production:
Capital Expenditures	$	229.3	(1)	$	262.8	(2)	$	(33.5	)	Capital Expenditures	$	169.6	(1)	$	229.3	(2)	$	(59.7)
Pipeline and Storage:										Pipeline and Storage:
Capital Expenditures	82.7		(1)	52.6		(2)	30.1			Capital Expenditures	91.7		(1)	82.7		(2)	9.0
Gathering:										Gathering:
Capital Expenditures	24.9		(1)	21.5		(2)	3.4			Capital Expenditures	19.4		(1)	24.9		(2)	(5.5)
Utility:										Utility:
Capital Expenditures	36.6		(1)	35.7		(2)	0.9			Capital Expenditures	41.8		(1)	36.6		(2)	5.2
All Other:										All Other:
Capital Expenditures	0.4			0.1			0.3			Capital Expenditures	0.1			0.4			(0.3)
Eliminations										Eliminations	(0.2)			—			(0.2)
	$	373.9		$	372.7		$	1.2			$	322.4		$	373.9		$	(51.5)



No Cost Collars
	Expected Maturity Date
	2021		2022		Total

Natural Gas
Notional Quantities (Equivalent Bcf)	13.8		1.2		15.0
Weighted Average Ceiling Price (per Mcf)	$	2.90	$	2.90	$	2.90
Weighted Average Floor Price (per Mcf)	$	2.18	$	2.18	$	2.18


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


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


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