UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended~~December~~March 31, ~~2017~~2020

~~[ ]~~ ☐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~~ þ NO ¨Yes ☑ No ☐

Indicate by check mark whether the registrant has submitted electronically ~~and posted on its corporate Web site, if any,~~ every Interactive Data File required to be submitted ~~and posted~~ pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit ~~and post~~ such files). ~~YES~~ þ NO ¨Yes ☑ No ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, 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. ~~(Check one):~~



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

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

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Common stock, par value $1.00 per share, outstanding at ~~January 31, 2018: 85,801,778~~April 30, 2020: 86,573,652 shares.

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GLOSSARY OF TERMS

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



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



Regulatory Agencies
CFTC	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
~~2017~~2019 Form 10-K	The Company’s Annual Report on Form 10-K for the year ended September 30, 2019
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.

Table of Contents



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

~~Table of Contents~~



Dth	Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
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)

Table of Contents

~~NEPA~~
	~~National Environmental Policy Act of 1969, as amended~~
NGA	The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.
NYMEX	New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Open Season	A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.

~~Table of Contents~~



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

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INDEX		Page

Part I. Financial Information

Item 1. Financial Statements (Unaudited)		6

a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Six Months Ended ~~December~~March 31, ~~2017~~2020 and ~~2016~~ 2019		6
b. Consolidated Statements of Comprehensive Income – Three and Six Months Ended ~~December~~March 31, ~~2017~~2020 and ~~2016~~ 2019		7
c. Consolidated Balance Sheets – ~~December~~March 31, ~~2017~~2020 and September 30, ~~2017~~2019		8
d. Consolidated Statements of Cash Flows – ~~Three~~Six Months Ended ~~December~~March 31, ~~2017~~2020 and ~~2016~~ 2019		10
e. Notes to Condensed Consolidated Financial Statements		11
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		2533
Item 3. Quantitative and Qualitative Disclosures About Market Risk		4252
Item 4. Controls and Procedures		4253

Part II. Other Information

Item 1. Legal Proceedings		4253
Item 1 A. Risk Factors		4353
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		4556
Item 3. Defaults Upon Senior Securities		•
Item 4. Mine Safety Disclosures		•
Item 5. Other Information		•
Item 6. Exhibits		4657
Signatures		4758

• The Company has nothing to report under this item.

All references to a certain year in this report are to the Company’s fiscal year ended September 30 of that year, unless otherwise noted.

Table of Contents

Part I. Financial Information

Item 1. Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)


	Three Months Ended December 31,						Three Months Ended March 31,						Six Months Ended March 31,
(Thousands of Dollars, Except Per Common Share Amounts)	2017			2016
(Thousands of U.S. Dollars, Except Per Common Share Amounts)							2020			2019			2020			2019
INCOME
Operating Revenues:
Utility and Energy Marketing Revenues	$	225,725		$	207,780		$	282,634		$	357,654		$	510,660		$	629,747
Exploration and Production and Other Revenues	140,450			161,694			156,542			146,467			323,735			310,403
Pipeline and Storage and Gathering Revenues	53,480			53,026			51,919			48,423			100,888			102,641
	419,655			422,500			491,095			552,544			935,283			1,042,791

Operating Expenses:
Purchased Gas	94,034			70,243			118,270			195,037			210,542			333,697
Operation and Maintenance:
Utility and Energy Marketing	51,369			50,422			51,725			48,559			94,981			92,475
Exploration and Production and Other	35,542			30,461			39,959			40,141			76,652			72,936
Pipeline and Storage and Gathering	20,037			22,660			27,305			27,249			53,190			52,182
Property, Franchise and Other Taxes	20,848			20,379			22,743			22,535			45,887			46,540
Depreciation, Depletion and Amortization	55,830			56,196			77,912			65,664			152,830			129,918
Impairment of Oil and Gas Producing Properties							177,761			—			177,761			—
	277,660			250,361			515,675			399,185			811,843			727,748
Operating Income	141,995			172,139
Operating Income (Loss)							(24,580		)	153,359			123,440			315,043
Other Income (Expense):
Interest Income	2,249			1,600
Other Income	1,722			1,614
Other Income (Deductions)							(17,480		)	(5,919		)	(20,520		)	(15,521		)
Interest Expense on Long-Term Debt	(28,087		)	(29,103		)	(25,270		)	(25,273		)	(50,713		)	(50,713		)
Other Interest Expense	(502		)	(910		)	(1,892		)	(1,787		)	(3,443		)	(2,860		)
Income Before Income Taxes	117,377			145,340
Income Tax Expense (Benefit)	(81,277		)	56,432
Income (Loss) Before Income Taxes							(69,222		)	120,380			48,764			245,949
Income Tax Expense							36,846			29,785			68,241			52,693

Net Income Available for Common Stock	198,654			88,908
Net Income (Loss) Available for Common Stock							(106,068		)	90,595			(19,477		)	193,256

EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	851,669			676,361			1,320,592			1,172,334			1,272,601			1,098,900
	1,050,323			765,269			1,214,524			1,262,929			1,253,124			1,292,156

Dividends on Common Stock	(35,590		)	(34,544		)	(37,654		)	(36,678		)	(75,304		)	(73,342		)
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation	—			31,916
Balance at December 31	$	1,014,733		$	762,641
Cumulative Effect of Adoption of Authoritative Guidance for Hedging							—			—			(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

Earnings Per Common Share:
Earnings (Loss) Per Common Share:
Basic:
Net Income Available for Common Stock	$	2.32		$	1.04
Net Income (Loss) Available for Common Stock							$	(1.23	)	$	1.05		$	(0.23	)	$	2.24
Diluted:
Net Income Available for Common Stock	$	2.30		$	1.04
Net Income (Loss) Available for Common Stock							$	(1.23	)	$	1.04		$	(0.23	)	$	2.23
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	85,630,296			85,189,851			86,561,066			86,290,047			86,469,258			86,159,932
Used in Diluted Calculation	86,325,537			85,797,989			86,561,066			86,767,673			86,469,258			86,738,809
Dividends Per Common Share:
Dividends Declared	$	0.415		$	0.405		$	0.435		$	0.425		$	0.870		$	0.850

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)

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

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



	Three Months Ended March 31,						Six Months Ended March 31,
(Thousands of U.S. Dollars)	2020			2019			2020			2019
Net Income (Loss) Available for Common Stock	$	(106,068	)	$	90,595		$	(19,477	)	$	193,256
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
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	(25,034		)	4,739			(32,386		)	24,384
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	—			—			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
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
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
Income Tax Benefit (Expense) on Cumulative Effect of Adoption of Authoritative Guidance for Hedging	—			—			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
Other Comprehensive Income (Loss)	37,233			(25,596		)	33,238			13,464
Comprehensive Income (Loss)	$	(68,835	)	$	64,999		$	13,761		$	206,720

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	December 31, 2017		September 30, 2017		March 31, 2020		September 30, 2019
(Thousands of Dollars)
(Thousands of U.S. Dollars)
ASSETS
Property, Plant and Equipment	$	10,023,252	$	9,945,560	$	11,559,528	$	11,204,838
Less - Accumulated Depreciation, Depletion and Amortization	5,294,211		5,271,486		6,003,658		5,695,328
	4,729,041		4,674,074		5,555,870		5,509,510
Current Assets
Cash and Temporary Cash Investments	166,289		555,530		111,655		20,428
Hedging Collateral Deposits	4,465		1,741		10,728		6,832
Receivables – Net of Allowance for Uncollectible Accounts of $24,511 and $22,526, Respectively	161,029		112,383
Receivables – Net of Allowance for Uncollectible Accounts of $29,627 and $25,788, Respectively					172,011		139,956
Unbilled Revenue	74,790		22,883		44,715		18,758
Gas Stored Underground	24,139		35,689		8,860		36,632
Materials and Supplies - at average cost	35,139		33,926		48,113		40,717
Unrecovered Purchased Gas Costs	7,787		4,623		—		2,246
Other Current Assets	47,914		51,505		100,188		97,054
	521,552		818,280		496,270		362,623

Other Assets
Recoverable Future Taxes	116,792		181,363		115,934		115,197
Unamortized Debt Expense	8,148		1,159		13,151		14,005
Other Regulatory Assets	174,577		174,433		161,800		167,320
Deferred Charges	34,063		30,047		56,855		33,843
Other Investments	123,368		125,265		137,044		144,917
Goodwill	5,476		5,476		5,476		5,476
Prepaid Post-Retirement Benefit Costs	57,054		56,370		71,381		60,517
Fair Value of Derivative Financial Instruments	21,107		36,111		94,797		48,669
Other	754		742		81		80
	541,339		610,966		656,519		590,024

Total Assets	$	5,791,932	$	6,103,320	$	6,708,659	$	6,462,157

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	December 31, 2017			September 30, 2017			March 31, 2020			September 30, 2019
(Thousands of Dollars)
(Thousands of U.S. Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued And Outstanding – 85,760,846 Shares and 85,543,125 Shares, Respectively	$	85,761		$	85,543
Authorized - 200,000,000 Shares; Issued And Outstanding – 86,561,532 Shares and 86,315,287 Shares, Respectively							$	86,562		$	86,315
Paid in Capital	800,348			796,646			835,444			832,264
Earnings Reinvested in the Business	1,014,733			851,669			1,176,870			1,272,601
Accumulated Other Comprehensive Loss	(40,919		)	(30,123		)	(18,917		)	(52,155		)
Total Comprehensive Shareholders’ Equity	1,859,923			1,703,735			2,079,959			2,139,025
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,084,465			2,083,681			2,134,964			2,133,718
Total Capitalization	3,944,388			3,787,416			4,214,923			4,272,743

Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	—			—			230,000			55,200
Current Portion of Long-Term Debt	—			300,000			—			—
Accounts Payable	132,409			126,443			106,938			132,208
Amounts Payable to Customers	251			—			17,213			4,017
Dividends Payable	35,590			35,500			37,654			37,547
Interest Payable on Long-Term Debt	27,962			35,031			18,508			18,508
Customer Advances	18,398			15,701			615			13,044
Customer Security Deposits	22,503			20,372			14,999			16,210
Other Accruals and Current Liabilities	121,596			111,889			150,239			139,600
Fair Value of Derivative Financial Instruments	6,579			1,103			7,652			5,574
	365,288			646,039			583,818			421,908

Deferred Credits
Deferred Income Taxes	453,285			891,287			777,299			653,382
Taxes Refundable to Customers	366,768			95,739			360,331			366,503
Cost of Removal Regulatory Liability	205,554			204,630			224,546			221,699
Other Regulatory Liabilities	118,551			113,716			157,371			142,367
Pension and Other Post-Retirement Liabilities	125,055			149,079			126,959			133,729
Asset Retirement Obligations	106,516			106,395			128,779			127,458
Other Deferred Credits	106,527			109,019			134,633			122,368
	1,482,256			1,669,865			1,909,918			1,767,506
Commitments and Contingencies (Note 6)	—			—
Commitments and Contingencies (Note 8)							—			—

Total Capitalization and Liabilities	$	5,791,932		$	6,103,320		$	6,708,659		$	6,462,157

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)


	Three Months Ended December 31,						Six Months Ended March 31,
(Thousands of Dollars)	2017			2016
(Thousands of U.S. Dollars)							2020			2019
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	198,654		$	88,908
Adjustments to Reconcile Net Income to Net Cash Provided by 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	55,830			56,196			152,830			129,918
Deferred Income Taxes	(94,676		)	44,852			104,883			90,468
Stock-Based Compensation	3,905			2,482			7,580			10,731
Other	3,678			3,607			9,800			7,997
Change in:
Hedging Collateral Deposits	(2,724		)	1,484
Receivables and Unbilled Revenue	(83,357		)	(67,395		)	(58,248		)	(130,377		)
Gas Stored Underground and Materials and Supplies	10,337			10,597			20,086			29,093
Unrecovered Purchased Gas Costs	(3,164		)	(1,257		)	2,246			(1,556		)
Other Current Assets	3,591			9,576			(3,134		)	10,438
Accounts Payable	13,173			18,805			(5,465		)	10,226
Amounts Payable to Customers	251			(16,306		)	13,196			12,069
Customer Advances	2,697			(983		)	(12,429		)	(13,176		)
Customer Security Deposits	2,131			673			(1,211		)	(7,184		)
Other Accruals and Current Liabilities	11,532			5,919			9,076			48,028
Other Assets	(5,275		)	(8,389		)	(10,359		)	(38,686		)
Other Liabilities	(21,775		)	(4,122		)	3,857			(10,410		)
Net Cash Provided by Operating Activities	94,808			144,647			390,992			340,835

INVESTING ACTIVITIES
Capital Expenditures	(142,613		)	(106,053		)	(395,486		)	(386,579		)
Net Proceeds from Sale of Oil and Gas Producing Properties	—			5,759
Other	2,612			(4,297		)	4,167			(2,616		)
Net Cash Used in Investing Activities	(140,001		)	(104,591		)	(391,319		)	(389,195		)

FINANCING ACTIVITIES
Reduction of Long-Term Debt	(307,047		)	—
Changes in Notes Payable to Banks and Commercial Paper							174,800			—
Dividends Paid on Common Stock	(35,500		)	(34,473		)	(75,197		)	(73,197		)
Net Proceeds from Issuance (Repurchase) of Common Stock	(1,501		)	938
Net Cash Used in Financing Activities	(344,048		)	(33,535		)
Net Increase (Decrease) in Cash and Temporary Cash Investments	(389,241		)	6,521

Cash and Temporary Cash Investments at October 1	555,530			129,972
Cash and Temporary Cash Investments at December 31	$	166,289		$	136,493
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	$	56,116		$	48,965		$	59,490		$	74,929
Receivable from Sale of Oil and Gas Producing Properties	$	17,310		$	20,795

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 -– Summary of Significant Accounting Policies

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

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

Earnings for Interim Periods. The Company, in its opinion, has included all adjustments (which consist of only normally recurring adjustments, unless otherwise disclosed in this Form 10-Q) that are necessary for a fair statement of the results of operations for the reported periods. The consolidated financial statements and notes thereto, included herein, should be read in conjunction with the financial statements and notes for the years ended September 30, ~~2017~~2019, ~~2016~~2018 and ~~2015~~2017 that are included in the Company's ~~2017~~2019 Form 10-K. The consolidated financial statements for the year ended September 30, ~~2018~~2020 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.

The earnings for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2020 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, ~~2018~~2020. Most of the business of both the Utility segment and ~~Energy Marketing segments~~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 ~~Energy Marketing segments,~~in the Company's NFR operations, earnings during the winter months normally represent a substantial part of the earnings that those ~~segments~~businesses are expected to achieve for the entire fiscal year. The Company’s business segments are discussed more fully in Note ~~7 –~~9 — Business Segment Information.

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



	Six Months Ended March 31, 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~~. This~~ on the Consolidated Balance Sheets. Hedging Collateral Deposits is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. 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 other specific information about customer accounts. 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 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

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on the extent and duration of the pandemic crisis. To date, the Company has not experienced any discernible change in the rate at which its customers pay their bills.

Gas Stored Underground. In the Utility segment, gas stored underground is carried at lower of cost or net realizable value, on a LIFO method. Gas stored underground normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to ~~$1.7~~$24.0 million at ~~December~~March 31, ~~2017,~~2020, is reduced to ~~zero~~0 by September 30 of each year as the inventory is replenished.

Property, Plant and Equipment. In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Company's capitalized costs relating to oil and gas producing activities, net of accumulated depreciation, depletion and amortization, were $1.6 billion and $1.7 billion at March 31, 2020 and September 30, 2019, respectively.

Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. Such costs amounted to ~~$77.1~~$74.8 million and ~~$80.9~~$53.5 million at ~~December~~March 31, ~~2017~~2020 and September 30, ~~2017,~~2019, 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

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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 ~~natural~~ gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. ~~At December 31, 2017, the ceiling exceeded the~~The book value of the oil and gas properties ~~by approximately $334.6 million.~~exceeded the ceiling at March 31, 2020. As such, the Company recognized a pre-tax impairment charge of $177.8 million for the quarter ended March 31, 2020. Deferred income tax benefits of $48.5 million related to the impairment charge were also recognized for the quarter ended March 31, 2020. In adjusting estimated future cash flows for hedging under the ceiling test at ~~December~~March 31, ~~2017,~~2020, estimated future net cash flows were increased by ~~$18.0~~$32.7 million.

~~On December 1, 2015, Seneca~~The principal assets of the Utility, Pipeline and ~~IOG - CRV Marcellus, LLC (IOG), an affiliate~~Storage and Gathering segments, consisting primarily of ~~IOG Capital, LP, and funds managed by affiliates~~gas plant in service, are recorded at the historical cost when originally devoted to service. In light of ~~Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate~~COVID-19, government mandates have resulted in the ~~development~~shut-down of ~~certain oil~~a significant number of businesses in the Company’s service territories and ~~gas interests owned by Seneca~~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 ~~Elk, McKean~~turn lead to a decrease in fair value and ~~Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension~~result in a potential impairment of the ~~joint development agreement. Under~~recorded value of such assets. While there were no indications of any conditions that could result in impairments at March 31, 2020, management will continue to monitor the ~~terms~~situation on a quarterly basis.

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

Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss and changes for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2020 and ~~2016,~~2019, 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	)

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

In August 2017, the FASB issued authoritative guidance which changes 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

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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 Outof Accumulated Other Comprehensive Loss. The details about the reclassification adjustments out of accumulated other comprehensive loss for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2020 and ~~2016~~2019 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	Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss												Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended December 31,
	2017			2016
Details About Accumulated Other Comprehensive Loss Components								Three Months Ended March 31,						Six Months Ended March 31,						Affected Line Item in the Statement Where Net Income is Presented
								2020			2019			2020			2019

Commodity Contracts		$12,842			$31,320		Operating Revenues		$23,396			($4,260	)		$30,937			($22,782	)	Operating Revenues
Commodity Contracts	196			(460		)	Purchased Gas	1,909			(280		)	1,911			(1,182		)	Purchased Gas
Foreign Currency Contracts	(490		)	(143		)	Operation and Maintenance Expense	(271		)	(199		)	(462		)	(420		)	Operating Revenues
Gains (Losses) on Securities Available for Sale	430			741			Other Income
	12,978			31,458			Total Before Income Tax	25,034			(4,739		)	32,386			(24,384		)	Total Before Income Tax
	(5,355		)	(13,227		)	Income Tax Expense	(6,817		)	1,328			(8,849		)	6,874			Income Tax Expense
		$7,623			$18,231		Net of Tax		$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):



	At March 31, 2020		At September 30, 2019

Prepayments	$	6,289	$	12,728
Prepaid Property and Other Taxes	23,702		14,361
Federal Income Taxes Receivable	42,385		42,388
State Income Taxes Receivable	3,455		8,579
Fair Values of Firm Commitments	8,775		7,538
Regulatory Assets	15,582		11,460
	$	100,188	$	97,054

At December 31, 2017 At September 30, 2017

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

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



	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 December 31, 2017 At September 30, 2017

Accrued Capital Expenditures $ 28,488
$ 37,382
Regulatory Liabilities 38,920
34,059
Reserve for Gas Replacement 1,739
—
Federal Income Taxes Payable 8,688
1,775
2017 Tax Reform Act Refund 6,000
—
Other 37,761
38,673
$ 121,596
$ 111,889

Earnings Per Common Share. Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company ~~has~~had outstanding ~~are stock options,~~were SARs, restricted stock units and performance shares. ~~For~~As the Company recognized a net loss for both the quarter and six months ended ~~December~~March 31, ~~2017,~~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, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. ~~Stock options,~~ SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were ~~157,603~~159,023 securities and ~~317,686~~175,443 securities excluded as being antidilutive for the ~~quarters~~quarter and six months ended ~~December~~March 31, ~~2017 and December 31, 2016,~~2019, respectively.

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Stock-Based Compensation. The Company granted ~~208,588~~254,608 performance shares during the ~~quarter~~six months ended ~~December~~March 31, ~~2017.~~2020. The weighted average fair value of such performance shares was ~~$50.95~~$43.32 per share for the ~~quarter~~six months ended ~~December~~March 31, ~~2017.~~2020. 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 ~~quarter~~six months ended ~~December~~March 31, ~~2017~~2020 must meet a performance goal related to relative return on capital over ~~the~~a three-year performance ~~cycle of October 1, 2017 to September 30, 2020.~~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 ~~quarter~~six months ended ~~December~~March 31, ~~2017~~2020 must meet a performance goal related to relative total shareholder return over ~~the~~a three-year performance ~~cycle of October 1, 2017 to September 30, 2020.~~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.

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The Company granted ~~89,672 non-performance based~~150,839 nonperformance-based restricted stock units during the ~~quarter~~six months ended ~~December~~March 31, ~~2017.~~2020. The weighted average fair value of such ~~non-performance based~~nonperformance-based restricted stock units was ~~$51.23~~$40.38 per share for the ~~quarter~~six months ended ~~December~~March 31, ~~2017.~~2020. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These ~~non-performance based~~nonperformance-based restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for ~~non-performance based~~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.~~ ~~In May 2014, the FASB issued~~

Note 2 – Revenue from Contracts with Customers

The Company adopted authoritative guidance regarding revenue ~~recognition. The~~recognition on October 1, 2018 using the modified retrospective method of adoption for open contracts as of October 1, 2018. A cumulative effect adjustment to retained earnings was not necessary since no revenue recognition differences were identified when comparing the revenue recognition criteria under the new authoritative guidance ~~provides a single, comprehensive~~to the previous guidance. The Company records revenue ~~recognition model for all contracts with customers~~related to ~~improve comparability.~~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 also records revenue ~~standard contains principles that an entity will apply~~related to ~~determine~~alternative revenue programs in its Utility segment. Revenue related to derivative financial instruments and alternative revenue programs are excluded from the ~~measurement~~scope of ~~revenue and timing of when it is recognized. The original effective date of this~~the new authoritative guidance ~~was as~~since they are accounted for under other existing accounting guidance.

The following tables provide a disaggregation of the Company's ~~first~~revenues for the quarter and six months ended March 31, 2020 and 2019, presented by type of ~~fiscal 2018. However, the FASB has delayed the effective date of the new revenue standard by one year, and the guidance will now be effective as of~~service from each reportable segment. As reported in the Company's ~~first quarter of fiscal 2019. Working towards this implementation date,~~2019 Form 10-K, the Company's NFR operations were previously reported as the Energy Marketing segment, however the Company is ~~currently evaluating~~no longer reporting the ~~guidance~~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.



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

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Six Months Ended March 31, 2020 (Thousands)
Revenues By Type of Service	Exploration and Production		Pipeline and Storage		Gathering		Utility			All Other			Corporate and Intersegment Eliminations			Total Consolidated
Production of Natural Gas	$	220,651	$	—	$	—	$	—		$	—		$	—		$	220,651
Production of Crude Oil	67,931		—		—		—			—			—			67,931
Natural Gas Processing	1,402		—		—		—			—			—			1,402
Natural Gas Gathering 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



Quarter 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	$	121,824		$	—	$	—	$	—		$	—	$	—		$	121,824
Production of Crude Oil	34,878			—		—		—			—		—			34,878
Natural Gas Processing	971			—		—		—			—		—			971
Natural Gas Gathering Services	—			—		29,368		—			—		(29,366		)	2
Natural Gas Transportation Service	—			52,239		—		45,083			—		(19,819		)	77,503
Natural Gas Storage Service	—			19,360		—		—			—		(8,333		)	11,027
Natural Gas Residential Sales	—			—		—		229,254			—		—			229,254
Natural Gas Commercial Sales	—			—		—		34,255			—		—			34,255
Natural Gas Industrial Sales	—			—		—		1,867			—		—			1,867
Natural Gas Marketing	—			—		—		—			58,516		(43		)	58,473
Other	493			740		—		(5,963		)	318		(105		)	(4,517		)
Total Revenues from Contracts with Customers	158,166			72,339		29,368		304,496			58,834		(57,666		)	565,537
Alternative Revenue Programs	—			—		—		(1,466		)	—		—			(1,466		)
Derivative Financial Instruments	(12,064		)	—		—		—			537		—			(11,527		)
Total Revenues	$	146,102		$	72,339	$	29,368	$	303,030		$	59,371	$	(57,666	)	$	552,544

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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 ~~various issues identified by industry based~~following revenue ~~recognition task forces. The Company does not believe that its revenue recognition policies will change materially, although~~amounts in future periods related to “fixed” charges associated with remaining performance obligations for transportation and storage contracts: $92.0 million for the remainder of fiscal 2020; $171.8 million for fiscal 2021; $142.5 million for fiscal 2022; $97.9 million for fiscal 2023; $86.4 million for fiscal 2024; and $361.5 million thereafter.

Note 3 – Leases

On October 1, 2019, the Company ~~is still assessing the impact. The Company will need to enhance its financial statement disclosures to comply with the new authoritative guidance.~~

~~In February 2016, the FASB issued~~adopted authoritative guidance ~~requiring organizations~~regarding lease accounting, which requires entities that lease ~~assets~~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, ~~regardless of whether they are considered to be capital~~including leases orclassified as operating leases. The ~~FASB’s previous~~Company implemented the new standard using the optional transition method and elected to apply the following practical expedients provided in the authoritative ~~guidance required organizations that lease assets to recognize on~~guidance:


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).

Upon adoption, the ~~balance sheet 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

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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 ~~rights~~Company’s operations. Building and ~~obligations created~~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.

Drilling Rigs

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 ~~capital~~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 ~~while excluding operating~~are deemed to be short-term leases ~~from~~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.

Discount Rate

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.

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Oil and Gas Leases

The new authoritative guidance ~~will be effective~~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 ~~first quarter~~total operating lease costs (in thousands):



	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.

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

The ~~Company does~~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 ~~anticipate early adoption and is currently evaluating~~recorded on the ~~provisions of~~Consolidated Balance Sheet.

The following amounts related to operating leases were recorded on the ~~revised guidance.~~

Company’s Consolidated Balance Sheet (in thousands):



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

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

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InFor the six months ended March ~~2016, the FASB issued authoritative guidance simplifying several aspects of the accounting~~31, 2020, cash paid for stock-based compensation. The Company adopted this guidance effective as of October 1, 2016, recognizing a cumulative effect adjustment that increased retained earnings by $31.9 million. The cumulative effect represents the tax benefit of previously unrecognized tax deductionsoperating liabilities, and reported in excess of stock compensation recorded for financial reporting purposes. On a prospective basis, the tax effect of all future differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation will be recognized upon vesting or settlement as income tax expense or benefit in the income statement. From a statement of cash flows ~~perspective, the tax benefits relating to differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation are now included in cash~~ provided by operating activities ~~instead~~on the Company’s Consolidated Statement of ~~cash provided~~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.

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



	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

The ~~changes to~~future minimum operating lease payments as of September 30, 2019, as reported in the ~~statement of cash flows were applied prospectively at~~Company's 2019 Form 10-K, under the ~~time of adoption.~~

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



	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.

Note 24 – Fair Value Measurements

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

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The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of ~~December~~March 31, ~~2017~~2020 and September 30, ~~2017~~2019. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over the counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company.


Recurring Fair Value Measures	At fair value as of December 31, 2017												At fair value as of March 31, 2020
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾			Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾
Assets:
Cash Equivalents – Money Market Mutual Funds	$	132,231	$	—	$	—	$	—		$	132,231		$	95,966	$	—	$	—	$	—		$	95,966
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	1,374		—		—		(1,374		)	—			935		—		—		(935		)	—
Over the Counter Swaps – Gas and Oil	—		30,853		—		(10,312		)	20,541			—		103,068		—		(2,732		)	100,336
Over the Counter No Cost Collars - Gas													—		—		—		(751		)	(751		)
Foreign Currency Contracts	—		1,232		—		(666		)	566			—		—		—		(4,788		)	(4,788		)
Other Investments:
Balanced Equity Mutual Fund	36,979		—		—		—			36,979			31,956		—		—		—			31,956
Fixed Income Mutual Fund	44,232		—		—		—			44,232			63,094		—		—		—			63,094
Common Stock – Financial Services Industry	3,239		—		—		—			3,239			577		—		—		—			577
Hedging Collateral Deposits	4,465		—		—		—			4,465			10,728		—		—		—			10,728
Total	$	222,520	$	32,085	$	—	$	(12,352	)	$	242,253		$	203,256	$	103,068	$	—	$	(9,206	)	$	297,118

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	2,190	$	—	$	—	$	(1,374	)	$	816		$	6,863	$	—	$	—	$	(935	)	$	5,928
Over the Counter Swaps – Gas and Oil	—		16,312		—		(10,312		)	6,000			—		3,398		—		(2,732		)	666
Over the Counter No Cost Collars – Gas													—		970		—		(751		)	219
Foreign Currency Contracts	—		429		—		(666		)	(237		)	—		5,627		—		(4,788		)	839
Total	$	2,190	$	16,741	$	—	$	(12,352	)	$	6,579		$	6,863	$	9,995	$	—	$	(9,206	)	$	7,652
Total Net Assets/(Liabilities)	$	220,330	$	15,344	$	—	$	—		$	235,674		$	196,393	$	93,073	$	—	$	—		$	289,466


Recurring Fair Value Measures	At fair value as of September 30, 2017											At fair value as of September 30, 2019
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾		Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾
Assets:
Cash Equivalents – Money Market Mutual Funds	$	527,978	$	—	$	—	$	—		$	527,978	$	10,521	$	—	$	—	$	—		$	10,521
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	1,483		—		—		(963		)	520		2,055		—		—		(2,055		)	—
Over the Counter Swaps – Gas and Oil	—		38,977		—		(4,206		)	34,771		—		52,076		—		(1,483		)	50,593
Foreign Currency Contracts	—		1,227		—		(407		)	820		—		5		—		(2,052		)	(2,047		)
Other Investments:
Balanced Equity Mutual Fund	37,033		—		—		—			37,033		40,660		—		—		—			40,660
Fixed Income Mutual Fund	45,727		—		—		—			45,727		62,339		—		—		—			62,339
Common Stock – Financial Services Industry	3,150		—		—		—			3,150		844		—		—		—			844
Hedging Collateral Deposits	1,741		—		—		—			1,741		6,832		—		—		—			6,832
Total	$	617,112	$	40,204	$	—	$	(5,576	)	$	651,740	$	123,251	$	52,081	$	—	$	(5,590	)	$	169,742

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	963	$	—	$	—	$	(963	)	$	—	$	7,149	$	—	$	—	$	(2,055	)	$	5,094
Over the Counter Swaps – Gas and Oil	—		5,309		—		(4,206		)	1,103		—		1,671		—		(1,483		)	188
Foreign Currency Contracts	—		407		—		(407		)	—		—		2,344		—		(2,052		)	292
Total	$	963	$	5,716	$	—	$	(5,576	)	$	1,103	$	7,149	$	4,015	$	—	$	(5,590	)	$	5,574
Total Net Assets/(Liabilities)	$	616,149	$	34,488	$	—	$	—		$	650,637	$	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.

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Derivative Financial Instruments

At ~~December~~March 31, ~~2017~~2020 and September 30, ~~2017,~~2019, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used by NFR (included in the ~~Company’s Energy Marketing segment.~~All Other category). Hedging collateral deposits ~~were $4.5~~of $10.7 million ~~at December~~(at March 31, ~~2017~~2020) and ~~$1.7~~$6.8 million at(at September 30, ~~2017,~~2019), which were associated with these futures contracts, ~~and~~ have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at ~~December~~March 31, ~~2017~~2020 and September 30, ~~2017~~2019 consist of natural gas price swap agreements used in the Company’s Exploration and Production segment and ~~Energy Marketing segments,~~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 used in the Company's Exploration and Production segment. The ~~derivative financial instruments reported in Level 2 at December 31, 2017 also include basis hedge swap agreements used in the Company's Energy Marketing 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 for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At ~~December~~March 31, ~~2017~~,2020, 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 ~~December~~March 31, ~~2017~~2020 and ~~December~~March 31, ~~2016,~~2019, there were no0 assets or liabilities measured at fair value and classified as Level 3. For the quarters ended ~~December~~March 31, ~~2017~~2020 and ~~December~~March 31, ~~2016, no~~2019, 0 transfers in or out of Level 1 or Level 2 occurred.

Note 35 – Financial Instruments

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



	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

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

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.

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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

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

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

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the quarter ended December 31, 2017 resulted in $1.5 million of cash proceeds and a realized gain of $0.4 million. The fair value of the fixed income mutual fund was $44.2 million at December 31, 2017 and $45.7 million at September 30, 2017. The gross unrealized loss on this fixed income mutual fund was $0.2 million at December 31, 2017 and was less than $0.1 million at September 30, 2017. A sale of shares in the fixed income mutual fund during the quarter ended December 31, 2017 resulted in $1.5 million of cash proceeds and a realized loss of less than $0.1 million. The fair value of the stock of an insurance company was $3.2 million at both December 31, 2017 and September 30, 2017. The gross unrealized gain on this stock was $2.3 million at December 31, 2017 and $2.2 million at September 30, 2017.net income. The insurance contracts and marketable equity and fixed income securities 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 ~~Energy Marketing segment.~~All Other category). 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 87 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 ~~December~~March 31, ~~2017~~2020 and September 30, ~~2017~~2019. Substantially all of the derivative financial instruments reported on those line items relate to commodity contracts and a small portion relates to foreign currency forward contracts.

Cash Flow Hedges

For derivative instruments that are designated and qualify as a cash flow hedge, ~~the effective portion of~~ the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. ~~Gains~~Prior to October 1, 2019, gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness ~~are~~were recognized in current ~~earnings.~~ 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 ~~December~~March 31, ~~2017~~2020, the Company had the following commodity derivative contracts (swaps, no cost collars and futures contracts) outstanding:



Commodity	Units
Natural Gas	~~99.1~~108.4	Bcf (short positions)
Natural Gas	~~1.6~~17.4	Bcf (long positions)
Crude Oil	~~3,645,000~~2,160,000	Bbls (short positions)

As of ~~December~~March 31, ~~2017,~~2020, the Company was hedging a total of ~~$94.7~~$86.5 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions).

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As of ~~December~~March 31, ~~2017,~~2020, the Company had ~~$17.5~~$93.1 million ($~~10.3~~67.9 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that ~~$5.0~~$80.9 million ($~~3.0~~59.0 million after tax) of ~~such~~ unrealized gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged ~~transaction~~transactions are recorded in earnings.

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																																		The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended December 31, 2017 and 2016 (Thousands of Dollars)
Three Months Ended March 31, 2020 and 2019 (Thousands of Dollars)																					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) (Effective Portion) for the Three Months Ended December 31,						Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Three Months Ended December 31,						Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Three Months Ended December 31,						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,
	2017			2016				2017			2016				2017			2016			2020			2019				2020			2019
Commodity Contracts	$	(5,948	)	$	(50,444	)	Operating Revenue	$	12,842		$	31,320		Operating Revenue	$	(433	)	$	(100	)	$	81,108		$	(27,228	)	Operating Revenue	$	23,396		$	(4,260	)
Commodity Contracts	956			(1,536		)	Purchased Gas	196			(460		)	Not Applicable	—			—			(134		)	(54		)	Purchased Gas	1,909			(280		)
Foreign Currency Contracts	(507		)	(521		)	Operation and Maintenance Expense	(490		)	(143		)	Not Applicable	—			—			(4,670		)	1,282			Operating Revenue	(271		)	(199		)
Total	$	(5,499	)	$	(52,501	)		$	12,548		$	30,717			$	(433	)	$	(100	)	$	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	)

Fair Value Hedges

The Company utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments and the decline in the value of certain natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or net realizable value writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of ~~December~~March 31, ~~2017, the Company’s Energy Marketing segment~~2020, NFR had fair value hedges covering approximately ~~21.2~~22.2 Bcf ~~(20.6 Bcf of~~on its fixed price sales ~~commitments and 0.6 Bcf of commitments related to the withdrawal of storage gas).~~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.

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Derivatives in Fair Value Hedging Relationships	Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income	Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income for the Three Months Ended December 31, 2017 (In Thousands)			Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the Three Months Ended December 31, 2017 (In Thousands)			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	$	(1,753	)	$	1,753		Operating Revenues	$	(4,994	)	$	4,994
Commodity Contracts	Purchased Gas	$	137		$	(137	)	Purchased Gas	$	431		$	(431	)
		$	(1,616	)	$	1,616			$	(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

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basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions, no cost collars and applicable foreign currency forward contracts with ~~sixteen~~14 counterparties of which ~~ten~~12 are in a net gain position. On average, the Company had ~~$2.1~~$7.9 million of credit exposure per counterparty in a gain position at ~~December~~March 31, ~~2017.~~2020. The maximum credit exposure per counterparty in a gain position at ~~December~~March 31, ~~2017~~2020 was ~~$8.1~~$17.0 million. As of ~~December~~March 31, ~~2017, no~~2020, 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 ~~December~~March 31, ~~2017, thirteen~~2020, 11 of the ~~sixteen~~14 counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps 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 ~~December~~March 31, ~~2017,~~2020, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was ~~$19.2~~$94.8 million according to the Company’s internal model (discussed in Note 24 — Fair Value Measurements). At ~~December~~March 31, ~~2017,~~2020, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was ~~$4.2~~$1.6 million according to the Company's internal ~~model (discussed in Note 2 - Fair Value Measurements).~~model. For its over-the-counter swap agreements and foreign currency forward contracts, no0 hedging collateral deposits were required to be posted by the Company at ~~December~~March 31, ~~2017.~~ 2020.

For its exchange traded futures contracts, the Company was required to post ~~$4.5~~$10.7 million in hedging collateral deposits as of ~~December~~March 31, ~~2017.~~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. ~~This is discussed in Note 1 under Hedging Collateral Deposits.~~

Note ~~4 -~~6 – Income Taxes

The effective tax ~~rate~~rates for the quarters ended ~~December~~March 31, ~~2017~~2020 and ~~December~~March 31, ~~2016 was~~2019 were negative ~~69.2%~~53.2% and ~~38.8%~~positive 24.7%, respectively. The ~~difference~~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 and March 31, 2019 were 139.9% and 21.4%, respectively. The increase in the tax rate is a result of the ~~impact~~deferred tax valuation allowance, differences

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

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 ~~income~~ tax ~~liability~~assets will not be realized. For the quarter ended 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 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 ~~lower statutory rate~~projected three-year cumulative pre-tax loss primarily due to non-cash impairments of ~~24.5%~~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.

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 ~~result~~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 ~~(as discussed below).~~

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

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

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deferred income taxes of $336.7 million was recorded as a decrease to Recoverable Future Taxes of $65.7 million and an increase to Taxes Refundable to Customers of $271.0 million. The 2017 Tax Reform Act includes provisions that stipulate how these excess deferred taxes are to be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred income taxes will be determined by the federal and state regulatory agencies. The Company is awaiting regulatory guidance in the jurisdictions in which it operates.

~~The 2017 Tax Reform Act also~~ repealed the corporate alternative minimum tax ~~(AMT)~~ and ~~provides~~provided that the Company’s existing AMT credit carryovers ~~are~~were refundable, if not utilized to reduce tax, beginning in fiscal 2019. As of ~~December 31, 2017,~~September 30, 2018, the Company had ~~$92.0~~$85.0 million of AMT credit carryovers that ~~are~~were expected to be ~~utilized or~~ refunded between fiscal ~~2019~~2020 and fiscal ~~2022.~~

The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118) which provides for up to a one year period (the measurement period) in which to complete the required analysis and income tax accounting for the 2017 Tax Reform Act. SAB 118 describes three scenarios associated with a company’s status of accounting for income tax reform: (1) a company is complete with its~~accounting for certain effects of tax reform, (2) a company is able to determine areasonable estimate for certain effects of tax reform and records that estimate as aprovisional amount, or (3) a company is~~2023, if not ~~able to determine a reasonable estimate andtherefore continues to apply the provisions of the taxlaws that were in effect immediately prior to the 2017 Tax Reform Act being enacted.~~

previously utilized. The Company ~~has determined a reasonable estimate~~received the first installment for ~~the measurement~~$42.5 million of ~~the changes~~AMT credit refunds related to fiscal 2019 in deferred income taxes (noted above), which have been reflected as provisional amounts in the December 31, 2017 financial statements. The final determination of the impact of the income tax effects of these items will require additional analysis and further interpretation of the 2017 Tax Reform Act from yet to be issued U.S. Treasury regulations, state income tax guidance, federal and state regulatory guidance and technical corrections.January 2020.

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Note ~~5 -~~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		Paid In Capital			Earnings Reinvested in the Business			Accumulated Other Comprehensive Income (Loss)
	(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⁾	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.

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Common Stock. During the ~~three~~six months ended ~~December~~March 31, ~~2017,~~2020, the Company issued ~~63,082 original issue shares of common stock as a result of SARs exercises, 68,534~~87,135 original issue shares of common stock for restricted stock units that vested and ~~79,079~~231,246 original issue shares of common stock for performance shares that vested. In addition, the Company issued 25,453 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 25,879 original issue shares of common stock for the Company’s 401(k) plans. The Company also issued ~~6,912~~19,133 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 for the directors’ services during the ~~three~~six months ended ~~December~~March 31, ~~2017.~~2020. Holders of ~~stock options, SARs, restricted share~~stock-based compensation awards ~~or restricted stock units~~ will often tender shares of common stock to the Company for payment of ~~option exercise prices and/or~~ applicable withholding taxes. During the ~~three~~six months ended ~~December~~March 31, ~~2017, 51,218~~2020, 91,269 shares of common stock were tendered to the Company for such purposes. The Company considers all shares tendered as cancelled shares restored to the status of authorized but unissued shares, in accordance with New Jersey law.

Current Portion of Long-Term Debt. ~~None~~ NaN of the Company's long-term debt ~~at December~~as of March 31, ~~2017 will mature~~2020 and September 30, 2019 had a maturity date within the following twelve-month period. Current Portion of Long-Term Debt at September 30, 2017 consisted of $300.0 million of 6.50% notes scheduled to mature in April 2018. The Company redeemed these notes on October 18, 2017 for $307.0 million, plus accrued interest. The call premium was recorded to Unamortized Debt Expense on the Consolidated Balance Sheet in October 2017.

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

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

At ~~December~~March 31, ~~2017~~2020, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately ~~$3.0 million. This~~$6.8 million, which includes a $3.7 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. The Company's liability for such clean-up costs has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at ~~December~~March 31, ~~2017.~~2020. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately ~~4 years. The Company~~3 years and is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company.

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Northern Access ~~2016~~ Project. On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access ~~2016~~ project described herein. ~~On April 7, 2017,~~Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received onin January ~~27,~~of 2017). ~~On April 21, 2017, Supply Corporation and Empire filed a Petition for Review in the~~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 ~~NYDEC's Notice~~FERC waiver appeal, described below. While the Company’s initial appeal was pending before the Second Circuit Court of ~~Denial with respect~~Appeals, the FERC issued an Order finding that the NYDEC exceeded the statutory time frame to ~~National Fuel's application for~~take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality ~~Certification,~~Certification. FERC denied rehearing requests associated with its Order and ~~on May 11, 2017,~~FERC's decisions have been appealed and are pending in a separate action before the Second Circuit Court of Appeals. In addition, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. The Company ~~also has pending with FERC a proceeding asserting, among other things, that~~remains committed to the ~~NYDEC exceeded the reasonable and statutory time frames to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification.~~project. In light of these pending legal actions and the ~~Company has not yet determined a target~~need to complete necessary project development activities in advance of construction, the in-service ~~date. As a result of the decision of the NYDEC, Supply Corporation and Empire evaluated the capitalized project costs~~date for impairment as of December 31, 2017 and determined that an impairment charge was not required. The evaluation considered probability weighted scenarios of undiscounted future net cash flows, including a scenario assuming successful resolution with the NYDEC and construction of the pipeline, as well as a scenario where the project does not proceed. Further developments or indicators of an unfavorable resolution could result in the impairment of a significant portion of the project costs, which totaled $75.5 million at December 31, 2017. The project costs are included within Property, Plant and Equipment and Deferred Charges on the Consolidated Balance Sheet.is expected to be no earlier than fiscal 2022.

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

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Note 79 – Business Segment Information

The Company reports financial results for ~~five~~4 segments: Exploration and Production, Pipeline and Storage, Gathering ~~Utility~~ and ~~Energy Marketing.~~Utility. The division of the Company’s operations into reportable segments is based upon a combination of factors including differences in products and services, regulatory environment and geographic factors. 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 ~~2017~~2019 Form 10-K, the Company evaluates segment performance based on income before discontinued operations ~~extraordinary items and cumulative effects of changes in accounting~~ (when applicable). When ~~these items are~~this is not applicable, the Company evaluates performance based on net income. There have not been any changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s ~~2017~~2019 Form 10-K. A listing of segment assets at ~~December~~March 31, ~~2017~~2020 and September 30, ~~2017~~2019 is shown in the tables below.


Quarter Ended December 31, 2017 (Thousands)
Quarter Ended March 31, 2020 (Thousands)										Quarter Ended March 31, 2020 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Energy Marketing	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$139,141	$53,310	$170	$187,089	$38,636	$418,346	$1,096	$213	$419,655	$155,560	$51,919	$—	$250,556	$458,035	$32,925	$135	$491,095
Intersegment Revenues	$—	$21,985	$23,665	$2,182	$126	$47,958	$—	$(47,958)	$—	$—	$27,326	$35,267	$3,937	$66,530	$79	$(66,609)	$—
Segment Profit: Net Income (Loss)	$106,698	$38,462	$45,400	$20,993	$1,046	$212,599	$(719)	$(13,226)	$198,654	$(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	Energy Marketing	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Segment Assets:
At December 31, 2017	$1,420,790	$1,793,848	$589,793	$1,988,758	$72,466	$5,865,655	$77,214	$(150,937)	$5,791,932
At September 30, 2017	$1,407,152	$1,929,788	$580,051	$2,013,123	$60,937	$5,991,051	$76,861	$35,408	$6,103,320
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, 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

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

Note 810 – Retirement Plan and Other Post-Retirement Benefits

Components of Net Periodic Benefit Cost (in thousands):


	Retirement Plan						Other Post-Retirement Benefits						Retirement Plan						Other Post-Retirement Benefits
Three Months Ended December 31,	2017			2016			2017			2016
Three Months Ended March 31,													2020			2019			2020			2019

Service Cost	$	2,480		$	2,992		$	458		$	612		$	2,330		$	2,120		$	402		$	380
Interest Cost	8,252			9,596			3,700			4,752			7,483			9,594			3,228			4,286
Expected Return on Plan Assets	(15,429		)	(14,929		)	(7,871		)	(7,865		)	(15,016		)	(15,591		)	(7,308		)	(7,539		)
Amortization of Prior Service Cost (Credit)	235			264			(107		)	(107		)	182			206			(107		)	(107		)
Amortization of Losses	9,301			10,672			2,639			4,604			9,846			8,024			134			1,490
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾	1,721			535			3,608			1,312			5,519			4,786			8,846			6,565

Net Periodic Benefit Cost	$	6,560		$	9,130		$	2,427		$	3,308		$	10,344		$	9,139		$	5,195		$	5,075




	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⁾	The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.

The components of net periodic benefit cost other than service cost are presented in Other Income (Deductions) on the Consolidated Statements of Income.

Employer Contributions. During the ~~three~~six months ended ~~December~~March 31, ~~2017,~~2020, the Company contributed ~~$27.6~~$19.3 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and ~~$0.7~~$2.1 million to its VEBA trusts for its other post-retirement benefits. In the remainder of ~~2018, the Company may contribute up to $5.0 million to the Retirement Plan. In the remainder of 2018,~~2020, 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, the Company expects its contributions to its VEBA trusts to be in the range of ~~$2.0~~$0.5 million to ~~$3.0~~$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 911– Regulatory Matters

New YorkJurisdiction

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

~~On July 28, 2017, Distribution Corporation filed an appeal with~~

In New York, ~~State Supreme Court, Albany County, seeking review~~on March 13, 2020, the Company agreed to NYPSC Staff’s request that the Company suspend service terminations and disconnections. The Company is anticipating that there will be some level of increase in uncollectible expense depending on the depth and duration of the Order. The appeal contends that portions of the Order should be invalidated because they fail to meet the applicable legal standard for agency decisions. On December 11, 2017, the appeal was transferred to the Supreme Court, Appellate Division, Third Department. The Company cannot predict the outcome of the appealpandemic crisis. It is uncertain at this ~~time.~~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.

~~Table of Contents~~Pennsylvania Jurisdiction

Distribution Corporation’s Pennsylvania jurisdiction delivery rates are being charged to customers in accordance with a rate settlement approved by the PaPUC. The rate settlement does not specify any requirement to file a future rate case.

On ~~December 22, 2017,~~March 26, 2020, the ~~federal Tax Cuts and Jobs Act (the 2017 Tax Reform Act) was enacted into law. On December 29, 2017,~~PaPUC ratified an Emergency Order that established a Service Termination Moratorium intended to continue during the ~~NYPSC issued an order instituting a proceeding~~pendency of Governor Wolf’s March 6, 2020 Proclamation of Disaster Emergency associated with COVID-19. Similar to ~~study the potential effects of the enactment of the 2017 Tax Reform Act on the tax expenses and liabilities of~~ New York, utilities, and the “regulatory treatment of any windfalls resulting from same in order to preserve the benefits for ratepayers.” In its order, the NYPSC stated that the effect of the 2017 Tax Reform Act on utilities’ taxation is likely to be material and complex and that the proceeding was needed to begin the process of addressing the impact on the State’s utilities and ratepayers. The order establishes that the first steps in such process will be soliciting information from its regulated utilities to quantify the impact of the 2017 Tax Reform Act, scheduling a technical conference with the utilities, and the issuance of a NY Department of Public Service Staff (Staff) proposal for accounting and ratemaking treatment of the tax changes. The order further states that once Staff’s proposal is issued, utilities and other interested parties will be invited to comment on Staff’s recommendation. The order also declares that utilities are “put on notice that it is the [NYPSC]’s intent to ensure that net benefits accruing from the Tax Act are preserved for ratepayers, either through deferral accounting or another method, from the first day the Tax Act is put into effect. Utilities acting contrary to this intent do so at their own risk.” The Company cannot predict the outcome of this proceedinguncertain at this ~~time. Refer~~point as to ~~Note 4 - Income Taxes for further discussion of~~whether there would be any regulatory relief with regard to any increase in the ~~2017 Tax Reform Act.~~Utility’s uncollectible expense.

FERC ~~Rate Proceedings~~Jurisdiction

Supply Corporation ~~currently has no active~~filed a Section 4 rate case on ~~file.~~July 31, 2019 proposing rate increases to be effective September 1, 2019. On February 4, 2020, Supply ~~Corporation's~~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 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 income tax rate is increased. If no case has been filed, Supply Corporation must file for rates to be effective February 1, 2025.

Empire's 2019 rate settlement requires a Section 4 rate case filing no later than ~~December 31, 2019.~~

May 1, 2025. Empire ~~currently~~ has no ~~active~~ rate case currently on file. ~~Empire’s current rate settlement requires a rate case filing no later than July 1, 2021.~~

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

OVERVIEW

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

The Company is a diversified energy company engaged principally in the production, gathering, transportation, distribution and marketing of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current development activities are focused primarily in the Marcellus and Utica ~~Shale.~~shales. The common geographic footprint of the Company’s subsidiaries enables them to share management, labor, facilities and support services across various businesses and pursue coordinated projects designed to produce and transport natural gas from the Appalachian basin to markets in Canada and the eastern United States. 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 ~~five~~four business segments.

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

The Company is closely monitoring 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 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 as well as 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 of the work being performed and 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.

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 COVID-19 on its supply chains and development projects in this segment. To date, COVID-19 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, 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 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. 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 cost of approximately $145 million. 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. The FM100 Project has a target in-service date in late calendar 2021 and a preliminary cost estimate of approximately $280 million. These and other projects are discussed in more detail in the Capital Resources and Liquidity section that follows.

On February 3, 2017, the Company, in its Pipeline and Storage segment, received FERC approval of a project to move significant prospective Marcellus production from Seneca’s Western Development Area at Clermont to an Empire interconnection with TransCanada Pipeline at Chippawa and an interconnection with Tennessee Gas Pipeline’s 200 Line in East Aurora, New York (“Northern Access ~~2016”~~project”). ~~On April 7, 2017,~~In light of numerous legal actions and the ~~NYDEC issued a Notice~~need to complete necessary project development activities in advance of ~~Denial~~construction, the in-service date for the project is expected to be no earlier than fiscal 2022. For further discussion of the ~~federal Clean Water Act~~Northern Access project, refer to Item 1 at Note 8 — Commitments and Contingencies.

From a rate perspective, Supply Corporation filed a Section ~~401 Water Quality Certification and other state stream and wetland permits for~~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 ~~New York portion~~quarter ended March 31, 2020 by $3.8 million. For further discussion of ~~the project (the Water Quality Certification for the Pennsylvania portion of the project was received on January 27, 2017). On April 21, 2017, the Company appealed the NYDEC's decision with regard~~Supply Corporation's rate matters, refer to the ~~Water Quality Certification to the United States Court of Appeals for the Second Circuit,~~Rate and ~~on May 11, 2017, the Company commenced legal action~~Regulatory Matters section below.

From a legislation perspective, in July 2019, New York State ~~Supreme Court challenging~~enacted legislation known as the ~~NYDEC's actions with regard~~Climate Leadership & Community Protection Act (CLCPA). This climate legislation mandates reducing greenhouse gas emissions to ~~various state permits. The Company also has pending with FERC a proceeding asserting, among other things, that the NYDEC exceeded the reasonable~~60% of 1990 levels by 2030, and ~~statutory time frames~~ to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. The Company remains committed to the project. Approximately $75.5 million in costs have been incurred on this project through December 31, 2017,15% of 1990 levels by 2050, with the ~~costs residing either in Construction Work in Progress,~~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% by 2040. In the near-term, the CLCPA establishes a ~~component~~climate action council and a series of ~~Property, Plant~~advisory panels and ~~Equipment on~~working groups to study how the ~~Consolidated Balance Sheet, or Deferred Charges.~~state will achieve the aggressive emission reduction targets.

Seneca has two downstream Canadian transportation contracts to move incremental volumes associated with the Northern Access 2016 project. One of the contracts has a term expiring on March 31, 2023 with a remaining commitment of approximately $27.1 million (using a 1.2545 Exchange Rate). The other transportation precedent agreement was suspended until the Northern Access 2016 project has received all its necessary permits. Seneca paid $2.4 million associated with this suspension during the quarter ended September 30, 2017 and will be reimbursed this amount if the project is reinstated. As noted above, the Company remains committed to the Northern Access 2016 project. Seneca has mitigated a portion of the current capacity costs through capacity release arrangements.

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

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~~its capital expenditure needs for the remainder of fiscal 2018 and may issue short-term and/or long-term debt during fiscal 2018 as needed.~~

CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's ~~2017~~2019 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. ~~At December 31, 2017, the ceiling exceeded the~~The book value of the oil and gas properties ~~by approximately $334.6 million.~~exceeded the ceiling at March 31, 2020, resulting in an impairment charge of $177.8 million ($129.3 million after-tax). The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended ~~December~~March 31, ~~2017,~~2020, based on posted Midway Sunset prices, was ~~$48.41~~$58.92 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 ~~December~~March 31, ~~2017,~~2020, based on the quoted Henry Hub spot price for natural gas, was ~~$2.98~~$2.30 per MMBtu. (Note – because actual pricing of the Company’s various producing properties varies 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 ~~December~~March 31, ~~2017.~~2020. Pricing differences would include 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 ~~amounts~~additional impairment that the ~~ceiling~~Company would have ~~exceeded the book value of the Company's oil and gas properties~~recorded at ~~December~~March 31, ~~2017 (which would not have resulted in an impairment charge)~~2020 if natural gas prices were $0.25 per MMBtu lower than the average prices used at ~~December~~March 31, ~~2017,~~2020, 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 ~~December~~March 31, ~~2017,~~2020, and the additional impairment that the Company would have recorded at March 31, 2020 if both natural gas prices and crude oil prices were $0.25 per MMBtu and $5 per Bbl lower than the average prices used at ~~December~~March 31, ~~2017~~2020 (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.

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

Excess of Ceiling over Book Value under Sensitivity Analysis	$	188.4	$	295.4	$	149.2
Calculated Impairment under Sensitivity Analysis							$	364.7	$	168.5	$	404.0
Actual Impairment Recorded at March 31, 2020							129.3		129.3		129.3
Additional Impairment							$	235.4	$	39.2	$	274.7

~~It is difficult to predict what factors could lead to future impairments under~~Looking ahead, the SEC's full cost ceiling test. Fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in oil and gas prices have an impact on the amountfirst day of the month Midway Sunset price for crude oil 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 ~~any point~~June 30, 2020 and September 30, 2020, the Company expects to experience ceiling test impairments in ~~time.~~each of these quarters. For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's ~~2017~~2019 Form 10-K.

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

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

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

RESULTS OF OPERATIONS

Earnings

The ~~Company's earnings were $198.7~~Company recorded a loss of $106.1 million for the quarter ended ~~December~~March 31, ~~2017~~2020 compared to earnings of ~~$88.9~~$90.6 million for the quarter ended ~~December~~March 31, ~~2016.~~2019. The ~~increase~~decrease in earnings ~~of $109.8 million~~ is primarily athe result of ~~higher earnings~~a loss recognized 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 and All Other category partially offset these decreases.

The Company recorded a loss of $19.5 million for the six months ended March 31, 2020 compared to earnings of $193.3 million for the six months ended March 31, 2019. The decrease in earnings is primarily the result of a loss recognized in the Exploration and Production segment. Lower earnings in the Utility segment and Pipeline and Storage ~~segment. Lower earnings in the Energy Marketing segment and Utility~~ segment, as well as ~~losses~~a loss in the Corporate category, also contributed to the decrease. Higher earnings in the Gathering segment and All Other ~~categories~~category partially offset these ~~increases.~~ decreases.

The Company's earnings for the quarter and six months ended ~~December~~March 31, ~~2017 include~~2020 included a ~~$111.0~~non-cash $177.8 million ~~remeasurement of accumulated deferred income taxes~~impairment charge ($129.3 million after-tax) recorded during the quarter ended ~~December~~March 31, ~~2017~~2020 for the Exploration and ~~a lower statutory rate~~Production

Table of ~~24.5% as a result of the 2017 Tax Reform Act,~~Contents

segment's oil and gas producing properties, as discussed above. The Company's earnings for the quarter and six months ended March 31, 2020 also included 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.

Earnings (Loss) by Segment


	Three Months Ended December 31,									Three Months Ended March 31,								Six Months Ended March 31,
(Thousands)	2017			2016			Increase (Decrease)			2020			2019		Increase (Decrease)			2020			2019		Increase (Decrease)
Exploration and Production	$	106,698		$	35,080		$	71,618		$	(175,275	)	$	21,873	$	(197,148	)	$	(151,299	)	$	60,087	$	(211,386	)
Pipeline and Storage	38,462			19,368			19,094			22,087			17,749		4,338			40,192			42,851		(2,659		)
Gathering	45,400			10,981			34,419			19,898			12,690		7,208			35,842			26,872		8,970
Utility	20,993			21,175			(182		)	31,499			35,589		(4,090		)	58,082			61,237		(3,155		)
Energy Marketing	1,046			1,782			(736		)
Total Reportable Segments	212,599			88,386			124,213			(101,791		)	87,901		(189,692		)	(17,183		)	191,047		(208,230		)
All Other	(719		)	(179		)	(540		)	1,169			416		753			1,540			499		1,041
Corporate	(13,226		)	701			(13,927		)	(5,446		)	2,278		(7,724		)	(3,834		)	1,710		(5,544		)
Total Consolidated	$	198,654		$	88,908		$	109,746		$	(106,068	)	$	90,595	$	(196,663	)	$	(19,477	)	$	193,256	$	(212,733	)

Exploration and Production

Exploration and Production Operating Revenues


	Three Months Ended December 31,								Three Months Ended March 31,								Six Months Ended March 31,
(Thousands)	2017			2016		Increase (Decrease)			2020		2019			Increase (Decrease)			2020		2019		Increase (Decrease)
Gas (after Hedging)	$	98,115		$	120,564	$	(22,449	)	$	119,139	$	116,962		$	2,177		$	246,377	$	236,712	$	9,665
Oil (after Hedging)	40,214			39,457		757			35,302		34,418			884			73,142		69,682		3,460
Gas Processing Plant	1,065			761		304			714		971			(257		)	1,402		1,945		(543		)
Other	(253		)	150		(403		)	405		(6,249		)	6,654			578		639		(61		)
	$	139,141		$	160,932	$	(21,791	)	$	155,560	$	146,102		$	9,458		$	321,499	$	308,978	$	12,521

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Production Volumes


	Three Months Ended December 31,				Three Months Ended March 31,				Six Months Ended March 31,
	2017	2016	Increase (Decrease)		2020	2019	Increase (Decrease)		2020	2019	Increase (Decrease)
Gas Production (MMcf)
Appalachia	35,414	39,807	(4,393	)	55,638	44,883	10,755		109,922	90,188	19,734
West Coast	695	776	(81	)	479	487	(8	)	966	989	(23	)
Total Production	36,109	40,583	(4,474	)	56,117	45,370	10,747		110,888	91,177	19,711

Oil Production (Mbbl)
Appalachia	1	—	1		1	1	—		2	2	—
West Coast	672	721	(49	)	605	563	42		1,206	1,134	72
Total Production	673	721	(48	)	606	564	42		1,208	1,136	72

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Average Prices


	Three Months Ended December 31,							Three Months Ended March 31,							Six Months Ended March 31,
	2017		2016		Increase (Decrease)			2020		2019		Increase (Decrease)			2020		2019		Increase (Decrease)
Average Gas Price/Mcf
Appalachia	$	2.35	$	2.35	$	—		$	1.77	$	2.65	$	(0.88	)	$	1.97	$	2.79	$	(0.82	)
West Coast	$	5.00	$	4.24	$	0.76		$	4.34	$	6.06	$	(1.72	)	$	4.67	$	6.40	$	(1.73	)
Weighted Average	$	2.40	$	2.39	$	0.01		$	1.80	$	2.69	$	(0.89	)	$	1.99	$	2.83	$	(0.84	)
Weighted Average After Hedging	$	2.72	$	2.97	$	(0.25	)	$	2.12	$	2.58	$	(0.46	)	$	2.22	$	2.60	$	(0.38	)

Average Oil Price/Bbl
Appalachia	$	43.85	N/M		N/M			$	55.90	$	47.54	$	8.36		$	55.48	$	55.93	$	(0.45	)
West Coast	$	57.88	$	43.69	$	14.19		$	49.91	$	61.85	$	(11.94	)	$	56.25	$	63.79	$	(7.54	)
Weighted Average	$	57.86	$	43.82	$	14.04		$	49.92	$	61.82	$	(11.90	)	$	56.25	$	63.78	$	(7.53	)
Weighted Average After Hedging	$	59.79	$	54.71	$	5.08		$	58.23	$	61.01	$	(2.78	)	$	60.57	$	61.36	$	(0.79	)

~~N/M - Not Meaningful~~

~~2017~~2020 Compared with ~~2016~~2019

Operating revenues for the Exploration and Production segment ~~decreased $21.8~~increased $9.5 million for the quarter ended ~~December~~March 31, ~~2017~~2020 as compared with the quarter ended ~~December~~March 31, ~~2016.~~2019. Gas production revenue after hedging ~~decreased $22.4~~increased $2.2 million ~~primarily~~ due to a ~~decrease~~10.7 Bcf increase in gas production, ~~coupled with~~which was largely offset by the impact of a ~~$0.25~~$0.46 per Mcf decrease in the weighted average price of gas after hedging. The ~~decrease~~increase in gas production was ~~primarily~~largely due to ~~natural declines from Marcellus wells in the Eastern Development Area. This was partially offset by production increases in the Western Development Area from~~ new Marcellus and Utica wells ~~coupled with a decrease~~completed and connected to sales in ~~price-related curtailments~~the Western and Eastern Development Areas in the Appalachian region during the quarter ended ~~December~~March 31, ~~2017~~2020 as compared towith the quarter ended ~~December~~March 31, ~~2016. This decrease~~2019. Oil production revenue after hedging increased $0.9 million due to ~~operating revenues was partially offset by an~~a 42 Mbbl increase in oil production, ~~revenue after hedging~~which was largely offset by the impact of ~~$0.8 million. The increase in oil production revenue was due to~~ a ~~$5.08~~$2.78 per Bbl ~~increase~~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 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 decrease in ~~crude~~the weighted average price of gas after hedging. 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. The~~production, which was offset by the impact of a $0.79 per Bbl decrease in ~~crude~~the weighted average price of oil after hedging. The increase in oil production was largely due to higher production in the West Coast region was largely due to the lagging current year impact of decreased steam operations and well workover activity at its North Midway Sunset field in prior years (due to lower crude oil prices) coupled with oil production losses due to temporary shut-in production in Ventura County, California in response to the wildfires occurring in fiscal 2018. During the quarter ended December 31, 2017, there was an increase in steam operations and well workover activity versus the quarter ended December 31, 2016, which will stimulate future crude oil production.region.

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The Exploration and Production segment's ~~earnings~~loss for the quarter ended ~~December~~March 31, ~~2017 were $106.7~~2020 was $175.3 million, ~~an increase~~a decrease of ~~$71.6~~$197.2 million when compared with earnings of ~~$35.1~~$21.9 million for the quarter ended ~~December~~March 31, ~~2016.~~2019. The loss can be attributed to an impairment of oil and gas properties ($129.3 million), as discussed above, recognition of a deferred tax valuation allowance ($60.5 million), lower natural gas prices after hedging ($20.2 million), lower oil prices after hedging ($1.3 million), higher depletion expense ($7.3 million), an increase in lease operating and transportation expenses ($4.6 million) and a higher effective income tax rate ($1.6 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 primarily

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the result of increased gathering and transportation costs in the Appalachian region due to increased production. A higher effective tax rate was largely driven by the prior year impact of the Enhanced Oil Recovery tax credit which is not available in the current year. These were partially offset by higher natural gas production ($21.9 million), higher oil production ($2.0 million) and the impact of mark-to-market adjustments related to oil hedge ineffectiveness recorded in the prior year quarter ($5.3 million).

The Exploration and Production segment's loss for the six months ended March 31, 2020 was $151.3 million, a decrease of $211.4 million when compared with earnings of $60.1 million for the six months ended March 31, 2019. The loss was primarily ~~reflects~~attributable to an impairment of oil and gas properties ($129.3 million), as discussed above, recognition of a deferred tax valuation allowance ($60.5 million) also discussed above, lower natural gas prices after hedging ($32.8 million), lower oil prices after hedging ($0.8 million), higher lease operating and transportation expenses ($11.1 million), higher other operating expenses ($1.0 million), higher depletion expense ($14.8 million), a higher effective tax rate ($3.0 million) and the impact of a remeasurement of the segment's accumulated deferred income taxes ~~($77.3 million) combined with~~in the ~~current period earnings impact of the change~~prior quarter that did not recur in ~~federal tax rate from 35% to a blended rate of 24.5% for~~ fiscal ~~2018 on current income taxes~~2020 ($~~4.1~~1.0 million)~~, both of which were~~. The increase in lease operating and transportation expenses was primarily the result of increased gathering and transportation costs in the 2017 Tax Reform Act. It also reflects higher crude oil prices after hedging ($2.2 million), lower depletion expense ($1.1 million) and lower income tax expense, excluding the impact of the 2017 Tax Reform Act ($3.9 million). The decrease in depletion expense wasAppalachian region due to ~~a decrease in production coupled with an~~increased production. The increase in reserves (an increase in reserves lowers the per mcf/barrel depletion rate) partially offset by an increase in capitalized costs. The decrease in income tax expense, excluding the impact of the 2017 Tax Reform Act,other operating expenses was largely due to an increase in the ~~enhanced oil recovery tax~~purchased gas emissions credit ~~related to Seneca's California properties coupled with a decrease~~ in ~~state income taxes as a result of lower pre-tax net income for~~ the Exploration and Production segment. These factors, which contributed to increased earnings during the quarter ended December 31, 2017 compared to the quarter ended December 31, 2016, were partially offset by lower natural gas prices after hedging ($6.0 million), lower natural gas production ($8.6 million), lower crude oil production ($1.7 million)West Coast region and higher ~~other operating expenses ($0.6 million).~~personnel costs. The increase in ~~other operating expenses~~depletion expense was primarily due to an increase in ~~personnel costs.~~production, as well as a higher depletion rate. A higher effective tax rate was largely driven by the prior year impact of the Enhanced Oil Recovery tax credit which is not available in the current year. These were partially offset by higher natural gas production ($40.4 million) and higher oil production ($3.5 million).

Pipeline and Storage

Pipeline and Storage Operating Revenues


	Three Months Ended December 31,							Three Months Ended March 31,							Six Months Ended March 31,
(Thousands)	2017		2016		Increase (Decrease)			2020		2019		Increase (Decrease)			2020		2019		Increase (Decrease)
Firm Transportation	$	56,756	$	56,749	$	7		$	58,240	$	51,864	$	6,376		$	111,431	$	107,579	$	3,852
Interruptible Transportation	340		646		(306		)	214		375		(161		)	475		796		(321		)
	57,096		57,395		(299		)	58,454		52,239		6,215			111,906		108,375		3,531
Firm Storage Service	17,839		17,273		566			20,523		19,360		1,163			38,944		38,288		656
Interruptible Storage Service	19		12		7			1		—		1			6		1		5
Other	341		475		(134		)	267		740		(473		)	609		2,744		(2,135		)
	$	75,295	$	75,155	$	140		$	79,245	$	72,339	$	6,906		$	151,465	$	149,408	$	2,057

Pipeline and Storage Throughput


	Three Months Ended December 31,				Three Months Ended March 31,				Six Months Ended March 31,
(MMcf)	2017	2016	Increase (Decrease)		2020	2019	Increase (Decrease)		2020	2019	Increase (Decrease)
Firm Transportation	206,701	190,781	15,920		195,799	199,620	(3,821	)	404,447	391,523	12,924
Interruptible Transportation	882	3,046	(2,164	)	531	750	(219	)	1,244	1,665	(421	)
	207,583	193,827	13,756		196,330	200,370	(4,040	)	405,691	393,188	12,503

~~2017~~2020 Compared with ~~2016~~2019

Operating revenues for the Pipeline and Storage segment ~~remained relatively flat~~increased $6.9 million for the quarter ended ~~December~~March 31, ~~2017~~2020 as compared with the quarter ended ~~December~~March 31, ~~2016. An~~2019. 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 million. The increase in transportation and storage revenues was primarily attributable 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. The settlement remains subject to FERC approval. New demand charges for transportation service from Supply Corporation's Line ~~D Expansion,~~N to Monaca Project, which was placed in service on November 1, ~~2017, and an~~2019, also contributed to the increase in ~~both~~ transportation ~~and~~revenues. The increase in storage revenues ~~due to Supply Corporation's greenhouse gas and pipeline safety surcharge effective November 1, 2017, were largely~~was partially offset by a decline in transportation revenues due partially to an additional 2% reduction in Supply Corporation's rates effective November 1, 2016, which was required by the rate case settlement approved by FERC on November 13, 2015, and a decline in demand charges for ~~transportation services~~Supply Corporation's storage service as a result of the termination of a temporary contract ~~terminations.~~that was acquired in relation to the fiscal 2018 acquisition of the remaining interest in a jointly owned storage field.

Table of Contents

Operating revenues for the Pipeline and Storage segment increased $2.1 million for the six months ended March 31, 2020 as compared with the six months ended March 31, 2019. The increase in operating revenues was primarily due to an increase in transportation revenues of $3.5 million combined with an increase in storage revenues of $0.7 million, partially offset by a decrease in other revenues of $2.1 million. The increase in transportation and storage revenues was primarily 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 increase in Empire's transportation rates effective January 1, 2019 in accordance with Empire's rate case settlement, which was approved 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 a decrease in transportation revenues attributable to an Empire system transportation contract termination in December 2018. The increase in storage revenues due to the increase in Supply Corporation's rates from the 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. The decrease in other revenues was primarily due to proceeds received by Supply Corporation in the first quarter of fiscal 2019 related to a contract termination as a result of a shipper's bankruptcy that did not recur during fiscal 2020.

Transportation volume for the quarter ended ~~December~~March 31, ~~2017 increased~~2020 decreased by ~~13.8~~4.0 Bcf from the prior ~~year’s quarter.~~year's quarter, primarily a reflection of weather that was warmer than the prior year. For the six months ended March 31, 2020, transportation volume increased by 12.5 Bcf from the prior year's six-month period ended March 31, 2019. The increase in transportation volume for the ~~quarter~~six-month period primarily reflects ~~the impact of the Line D Expansion project being placed~~an increase in ~~service combined with colder weather quarter over quarter.~~capacity utilization by certain contract shippers, partially offset by a decrease in volume from warmer weather. 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.

~~Table of Contents~~

The Pipeline and Storage segment’s earnings for the quarter ended ~~December~~March 31, ~~2017~~2020 were ~~$38.5~~$22.1 million, an increase of ~~$19.1~~$4.4 million when compared with earnings of ~~$19.4~~$17.7 million for the quarter ended ~~December~~March 31, ~~2016.~~2019. The increase in earnings was primarily due to ~~lower income tax expense ($17.6 million)~~the earnings impact of higher operating revenues of $5.5 million, as discussed above, combined with ~~lower operating expenses ($1.9 million) and~~ a decrease in ~~interest expense~~operating expenses ($~~0.3~~0.7 million). Income tax expense was lower due to the remeasurement of accumulated deferred income taxes ($14.1 million) combined with the current period earnings impact of the change in federal tax rate from 35% to a blended rate of 24.5% for fiscal 2018 ($3.5 million), both a result of the 2017 Tax Reform Act. The decrease in operating expenses primarily reflects lower ~~pension~~compressor and ~~other post-retirement benefit~~facility maintenance costs, ~~combined with a decrease~~partially offset by an increase in ~~the reserve for preliminary project~~pipeline integrity costs. ~~The decrease in interest expense was largely due to lower intercompany long-term borrowing interest rates for the Pipeline and Storage segment.~~ These earnings increases were ~~slightly~~partially offset by an increase in depreciation expense ($~~0.6~~1.6 million) due to ~~incremental depreciation expense related to expansion projects that were placed~~an increase in ~~service within the last year combined with the non-recurrence of a reduction to depreciation expense recorded in the quarter ended December 31, 2016 to reflect a reduction in~~Supply Corporation's depreciation rates ~~retroactive to July 1, 2016 in accordance~~associated with ~~Empire's~~its rate case ~~settlement. The FERC issued an order approving the~~ settlement ~~on December 13, 2016.~~in principle mentioned above.

~~Looking ahead, the~~The Pipeline and Storage ~~segment expects transportation revenues~~segment’s earnings for the six months ended March 31, 2020 were $40.2 million, a decrease of $2.7 million when compared with earnings of $42.9 million for the six months ended March 31, 2019. The decrease in earnings was primarily due to ~~be negatively impacted in fiscal 2019 in an amount up to approximately $14 million~~higher depreciation expense ($2.0 million), higher property taxes ($1.2 million), and higher income tax expense ($2.5 million), as well as a ~~result~~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. The increase in property taxes was due to the scheduled phase-out of antax incentives in certain jurisdictions along the Empire system, ~~transportation contract reaching its termination date~~as well as higher town, county and school taxes due to an increase in ~~December 2018. Management does not expect~~assessed values from new projects placed in service. Income tax expense was higher due to ~~renew~~permanent differences related to stock compensation activity. The decrease in other income was primarily due to higher non-service pension and post-retirement benefit costs in the ~~contract at existing rates given~~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 ~~change~~decrease in ~~market dynamics.~~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.

Gathering

Gathering Operating Revenues


	Three Months Ended December 31,							Three Months Ended March 31,							Six Months Ended March 31,
(Thousands)	2017		2016		Increase (Decrease)			2020		2019		Increase (Decrease)			2020		2019		Increase (Decrease)
Gathering	$	23,802	$	27,840	$	(4,038	)
Gathering Revenues								$	35,267	$	29,366	$	5,901		$	70,055	$	59,056	$	10,999
Processing and Other Revenues	33		26		7			—		2		(2		)	—		2		(2		)
	$	23,835	$	27,866	$	(4,031	)	$	35,267	$	29,368	$	5,899		$	70,055	$	59,058	$	10,997

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Gathering Volume

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



	Three Months Ended March 31,			Six Months Ended March 31,
	2020	2019	Increase (Decrease)	2020	2019	Increase (Decrease)
Gathered Volume - (MMcf)	65,134	54,157	10,977	129,526	108,845	20,681

~~2017~~2020 Compared with ~~2016~~2019

Operating revenues for the Gathering segment ~~decreased $4.0~~increased $5.9 million for the quarter ended ~~December~~March 31, ~~2017~~2020 as compared with the quarter ended ~~December~~March 31, ~~2016, which~~2019. The increase was ~~driven by a 7.4~~primarily due to an 11.0 Bcf ~~decrease in gathered volume. The overall decrease~~net increase in gathered volume resulting from a 6.5 Bcf, 4.4 Bcf and 1.2 Bcf increase in volume on Midstream Company's Trout Run, Clermont and Wellsboro gathering systems, respectively, offset by a 1.1 Bcf decline in volume on its Covington gathering system. The net increase in gathered volume can be attributed to the increase in Seneca's gross natural gas production in the Appalachian region.

Operating revenues for the Gathering segment increased $11.0 million for the six months ended March 31, 2020 as compared with the six months ended March 31, 2019. This increase was primarily due to a ~~5.2~~20.7 Bcf net increase in gathered volume resulting from a 10.5 Bcf, 7.8 Bcf and 5.1 Bcf increase in gathered volume on its Trout Run, Clermont and Wellsboro gathering systems, respectively. These increases were partially offset by a 2.7 Bcf decrease in gathered volume on ~~Midstream Corporation’s Trout Run Gathering System (Trout Run), a 2.0~~the Covington gathering system. The 20.7 Bcf decrease in gathered volume on Midstream Corporation's Covington Gathering System (Covington), a 0.6 Bcf decrease in gathered volume on Midstream Corporation's Wellsboro Gathering System (Wellsboro), and a 0.1 Bcf decrease in gathered volumes spread across numerous Midstream systems. These decreases were partially offset by a 0.5 Bcfnet increase in gathered volume ~~on Midstream Corporation's Clermont Gathering System (Clermont). The decreases in~~can be attributed to the ~~aforementioned volumes were largely due to a decrease~~net increase in Seneca's ~~production.~~natural gas production for the six months ended March 31, 2020 compared to the six months ended March 31, 2019.

The Gathering segment’s earnings for the quarter ended ~~December~~March 31, ~~2017~~2020 were ~~$45.4~~$19.9 million, an increase of ~~$34.4~~$7.2 million when compared with earnings of ~~$11.0~~$12.7 million for the quarter ended ~~December~~March 31, ~~2016.~~2019. The increase in earnings was mainly due to the higher gathering revenues discussed above ($4.7 million) and the positive earnings impact ($3.8 million) as a result of the Gathering segment's recognition of an income tax benefit that was recorded as an offset to the valuation allowance described above in the Exploration and Production segment. This offset is a result of the Gathering and Exploration and Production segments’ subsidiaries filing a combined state tax return. 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 to earnings were partially offset by higher operating expenses ($0.8 million) and higher depreciation expense ($0.5 million). The increase in operating expenses was due largely to increased preventative maintenance and overhaul activities at Covington and Trout Run compressor stations during the quarter ended March 31, 2020. The increase in depreciation expense was due to an increase in the average gross property, plant and equipment assets in service as compared to the prior year.

The Gathering segment’s earnings for the six months ended March 31, 2020 were $35.8 million, an increase of $8.9 million when compared with earnings of $26.9 million for the six months ended March 31, 2019. The increase in earnings was mainly due to the impact of higher gathering revenues discussed above ($8.7 million) and lower interest expense ($0.3 million). Additionally, the ~~2017 Tax Reform Act, which led~~Gathering segment's earnings were positively impacted ($3.8 million) as a result of the Gathering segment's recognition of an income tax benefit that was recorded as an offset to the ~~remeasurement of accumulated deferred taxes ($34.9 million)~~valuation allowance established in the Exploration and ~~the impact of the tax rate change on current income tax ($1.5 million).~~Production segment, as discussed above. These earnings increases were partially offset by ~~lower~~higher operating expenses ($2.0 million), higher depreciation expense ($0.8 million), higher income tax expense ($0.2 million) and the impact of a nonrecurring income tax benefit recorded in the prior year quarter to adjust the remeasurement of deferred income taxes resulting from the 2017 Tax Reform Act ($0.5 million). The increase in operating expenses was largely due to the completion of compressor unit overhauls on Covington and Trout Run gathering ~~revenue ($2.6 million), as discussed above.~~system compressor stations during the current year. The increase in depreciation expense was due to higher plant balances at the Trout Run, Clermont and Wellsboro gathering systems.

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Utility

Utility Operating Revenues


	Three Months Ended December 31,								Three Months Ended March 31,									Six Months Ended March 31,
(Thousands)	2017			2016		Increase (Decrease)			2020			2019			Increase (Decrease)			2020			2019			Increase (Decrease)
Retail Sales Revenues:
Residential	$	134,739		$	116,387	$	18,352		$	187,932		$	228,061		$	(40,129	)	$	333,547		$	393,394		$	(59,847	)
Commercial	19,633			15,979		3,654			26,213			32,682			(6,469		)	45,874			55,424			(9,550		)
Industrial	872			517		355			1,162			1,867			(705		)	2,429			3,360			(931		)
	155,244			132,883		22,361			215,307			262,610			(47,303		)	381,850			452,178			(70,328		)
Transportation	36,309			36,661		(352		)	42,710			46,383			(3,673		)	76,316			82,333			(6,017		)
Off-System Sales	41			627		(586		)
Other	(2,323		)	2,626		(4,949		)	(3,524		)	(5,963		)	2,439			(6,848		)	(8,824		)	1,976
	$	189,271		$	172,797	$	16,474		$	254,493		$	303,030		$	(48,537	)	$	451,318		$	525,687		$	(74,369	)

Utility Throughput


	Three Months Ended December 31,				Three Months Ended March 31,				Six Months Ended March 31,
(MMcf)	2017	2016	Increase (Decrease)		2020	2019	Increase (Decrease)		2020	2019	Increase (Decrease)
Retail Sales:
Residential	17,847	15,764	2,083		26,155	30,906	(4,751	)	45,631	50,686	(5,055	)
Commercial	2,596	2,299	297		4,033	4,712	(679	)	6,846	7,558	(712	)
Industrial	144	77	67		183	284	(101	)	400	488	(88	)
	20,587	18,140	2,447		30,371	35,902	(5,531	)	52,877	58,732	(5,855	)
Transportation	21,427	19,565	1,862		25,157	28,928	(3,771	)	45,712	51,198	(5,486	)
Off-System Sales	22	173	(151	)
	42,036	37,878	4,158		55,528	64,830	(9,302	)	98,589	109,930	(11,341	)

Degree Days

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



Three Months Ended March 31,				Percent Colder (Warmer) Than
Three Months Ended March 31,	Normal	2020	2019	Normal⁽¹⁾		Prior Year⁽¹⁾
Buffalo, NY	3,326	2,738	3,372	(17.7	)%	(18.8	)%
Erie, PA	3,142	2,555	3,096	(18.7	)%	(17.5	)%
Six Months Ended March 31,
Buffalo, NY	5,579	4,970	5,697	(10.9	)%	(12.8	)%
Erie, PA	5,186	4,461	5,126	(14.0	)%	(13.0	)%


⁽¹⁾	Percents compare actual ~~2017~~2020 degree days to normal degree days and actual ~~2017~~2020 degree days to actual ~~2016~~2019 degree days.

~~2017~~2020 Compared with ~~2016~~2019

Operating revenues for the Utility segment ~~increased $16.5~~decreased $48.5 million for the quarter ended ~~December~~March 31, ~~2017~~2020 as compared with the quarter ended ~~December~~March 31, ~~2016.~~2019. The ~~increase largely~~decrease primarily resulted from a ~~$22.4~~$47.3 million ~~increase~~decrease in retail gas sales revenue and a $3.7 million decrease in transportation revenues. The ~~increase~~reduction in retail gas sales revenue was largely due to a ~~result of higher volumes (due to colder weather) and an increase~~decrease in the cost of gas sold (per Mcf). coupled with lower throughput due to warmer weather. The increase in operating revenues was partially offset by a $0.4 million decrease in transportation revenues, a $4.9 million decrease in other revenues and a $0.6 million decrease in off-system sales (due to lower volumes). The $0.4 million decreasedecline in transportation revenues was primarily due to a 3.8 Bcf decrease in transportation throughput due to warmer weather and the ~~impact~~migration of ~~regulatory adjustments, which more than~~residential transportation customers to retail. These decreases were partially offset ~~the impact of larger volumes and colder weather. The $4.9~~by a $2.4 million ~~decrease~~increase in other revenues, ~~was~~ largely due to ana 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. Due to profit sharing with retail customers,~~Act ($1.7 million) and the ~~margins related to off-system sales are minimal.~~impact of regulatory adjustments ($0.9 million).

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Operating revenues for the Utility segment decreased $74.4 million for the six months ended March 31, 2020 as compared with the six months ended March 31, 2019. The decrease largely resulted from a $70.3 million decrease in retail gas sales revenue and a $6.0 million decrease in transportation revenues. The reduction 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 the current income tax benefits resulting from the 2017 Tax Reform Act ($1.8 million).

The Utility segment’s earnings for the quarter ended ~~December~~March 31, ~~2017~~2020 were ~~$21.0~~$31.5 million, a decrease of ~~$0.2~~$4.1 million when compared with earnings of ~~$21.2~~$35.6 million for the quarter ended ~~December~~March 31, ~~2016. Higher~~2019. The decrease in earnings ~~associated with the new rate order issued by the NYPSC effective April 1, 2017 ($1.0 million) combined with~~was largely attributable to the impact of ~~colder~~lower usage and weather on customer margins ($3.8 million) and higher operating expenses ($2.9 million), which were largely a result of higher personnel costs and a slightly higher accrual for bad debt expense. Bad debt expense may increase more significantly in ~~fiscal 2018 compared to fiscal 2017 ($1.2 million)~~future quarters depending on the extent and duration of the pandemic crisis. These decreases were ~~partially~~slightly offset by ~~an increase in operating expense~~the positive earnings impact related to a system modernization tracker ($~~0.7~~1.7 million) and the impact of regulatory true-up adjustments ($~~1.2~~0.6 million). The increase in operating expense is primarily due to higher amortization of environmental remediation costs that resulted from the new rate order. The current tax benefit associated with the 2017 Tax Reform Act was completely offset by the aforementioned refund provision.

The impact of weather variations on earnings in the Utility ~~segment’s~~segment's New York rate jurisdiction is mitigated by that ~~jurisdiction’s~~jurisdiction's weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, inthe periods of colder than normal weather, the WNC benefits the Utility ~~segment’s~~segment's New York customers. For the quarter ended ~~December~~March 31, ~~2017,~~2020, the WNC increased earnings by approximately ~~$0.9~~$3.7 million, as the weather was warmer than normal. For the quarter ended ~~December~~March 31, ~~2016,~~2019, the WNC ~~preserved~~increased earnings ~~of $1.3~~by approximately $0.1 million, as the weather was warmer than normal.

~~Energy Marketing~~

~~Energy Marketing Operating Revenues~~

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

~~Energy Marketing Volume~~

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

~~2017 Compared with 2016~~

Operating revenues for the Energy Marketing segment increased $1.9 million for the quarter ended December 31, 2017 as compared with the quarter ended December 31, 2016. The increase was primarily due to an increase in gas sales revenue due to an increase in volume sold to retail customers as a result of colder weather, offset slightly by a lower average price of natural gas period over period.

The ~~Energy Marketing segment~~Utility segment’s earnings for the ~~quarter~~six months ended ~~December~~March 31, ~~2017~~2020 were ~~$1.0~~$58.1 million, a decrease of ~~$0.8~~$3.1 million when compared with earnings of ~~$1.8~~$61.2 million for the ~~quarter~~six months ended ~~December~~March 31, ~~2016. This~~2019. The decrease in earnings was ~~primarily~~largely attributable to the impacts of lower ~~margin~~usage and weather on customer margins ($3.7 million) and higher operating expenses ($2.7 million), which were largely a result of ~~$0.8 million. The decrease in margin largely reflects~~higher personnel costs and a ~~decline in average margin per Mcf primarily due~~slightly higher accrual for bad debt expense, as discussed above. These decreases were slightly offset by the positive earnings impact related to ~~stronger natural gas prices at local purchase points relative to NYMEX-based sales contracts. The 2017 Tax Reform Act did not have a significant~~the system modernization tracker ($2.0 million) and the impact ~~on Energy Marketing segment~~of regulatory true-up adjustments ($1.6 million).

For the six months ended March 31, 2020, the WNC increased earnings ~~for~~by approximately $3.6 million, as the ~~quarter~~weather was warmer than normal. For the six months ended ~~December~~March 31, ~~2017.~~2019, the WNC decreased earnings by approximately $0.7 million, as the weather was colder than normal.

Corporate and All Other

~~2017~~2020 Compared with ~~2016~~2019

Corporate and All Other operations had a loss of ~~$13.9~~$4.3 million for the quarter ended ~~December~~March 31, ~~2017,~~2020, a decrease of ~~$14.4~~$7.0 million when compared with earnings of ~~$0.5~~$2.7 million for the quarter ended ~~December~~March 31, ~~2016.~~2019. The decrease in earnings was primarily attributable 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).

For the six months ended March 31, 2020, Corporate and All Other operations had a loss of $2.3 million, a decrease of $4.5 million when compared with earnings of $2.2 million for the ~~quarter is~~six months ended March 31, 2019. The decrease in earnings was primarily ~~attributed~~attributable to athe impact of the prior year remeasurement of ~~accumulated~~ deferred income taxes under the 2017 Tax Reform Act that lowered income tax expense for the six months ended March 31, 2019 ($~~15.1~~3.5 million), coupled with higher unrealized losses on investments in equity securities recorded during the six months ended March 31, 2020 ($3.1 million) and higher interest expense ($0.7 million). ~~This decrease in~~These negative drivers of earnings ~~was~~were partially offset by the impact of higher other income ($1.0 million) that was driven largely by an increase in realized gains on investments in equity securities sold in the current year, higher energy marketing margins ($~~0.4~~0.9 million) ~~from the sale of standing timber by Seneca's land~~ and ~~timber division and the current tax benefit of tax rate changes associated with the 2017 Tax Reform Act~~lower operating expenses ($~~0.1~~0.7 million).

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

Interest on long-term debt ~~decreased $1.0 million~~was relatively flat for both the quarter and six months ended ~~December~~March 31, ~~2017~~2020, as compared ~~with~~to the quarter and six months ended ~~December~~March 31, ~~2016. This decrease is due to a decrease in~~2019. No new additional debt was issued or repaid during the ~~weighted average~~quarters ended March 31, 2020 and March 31, 2019. In addition, amortization of debt premiums discount and expense and capitalized interest ~~rate on long-term debt outstanding. The Company issued $300 million of 3.95% notes in September 2017 and repaid $300 million of 6.5% notes in October 2017.~~remained comparable year over year.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary ~~source of cash during the three-month period ended December 31, 2017 consisted of cash provided by operating activities. The Company’s primary~~ sources of cash during the ~~three-month~~six-month period ended ~~December~~March 31, ~~2016~~2020 consisted of cash provided by operating activities and net proceeds from ~~sale~~short-term borrowings. The Company's primary source of ~~oil and gas producing properties.~~cash during the six-month period ended March 31, 2019 consisted of cash provided by operating activities.

Operating Cash Flow

Internally generated cash from operating activities consists of net income available for common stock, adjusted for non-cash expenses, non-cash income 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 ~~Energy Marketing segments,~~in the Company's NFR operations (included in the All Other category), revenues in these ~~segments~~businesses 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, no cost collars and futures contracts in an attempt to manage this energy commodity price risk.

Net cash provided by operating activities totaled ~~$94.8~~$391.0 million for the ~~three~~six months ended ~~December~~March 31, ~~2017, a decrease~~2020, an increase of ~~$49.8~~$50.2 million compared with ~~$144.6~~$340.8 million provided by operating activities for the ~~three~~six months ended ~~December~~March 31, ~~2016.~~2019. The ~~decrease~~increase in cash provided by operating activities primarily reflects ~~lower~~higher cash provided by operating activities in the ~~Exploration~~Utility segment and ~~Production~~Corporate and ~~Energy Marketing segments.~~All Other categories. The ~~decrease~~increase in the ~~Exploration and Production~~Utility segment was primarily due to ~~lower cash receipts from crude oil~~the timing of gas cost recovery and ~~natural gas production, primarily a result~~the timing of ~~lower natural gas prices and lower production.~~receivable collections. The ~~decrease~~increase in the ~~Energy Marketing segment~~Corporate and All Other categories was primarily ~~a result~~due to the impact of ~~higher purchased gas costs~~the 2017 Tax Reform Act that repealed the corporate alternative minimum tax and ~~an increase~~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 ~~hedging collateral deposits. Hedging collateral deposits serve as collateral for open positions on exchange-trade futures contracts and over-the-counter swaps.~~January 2020.

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Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled ~~$126.5~~$373.9 million during the ~~three~~six months ended ~~December~~March 31, ~~2017~~2020 and ~~$94.6~~$372.7 million during the ~~three~~six months ended ~~December~~March 31, ~~2016.~~2019. The table below presents these expenditures:


Total Expenditures for Long-Lived Assets
Three Months Ended December 31,	2017			2016			Increase (Decrease)
Six Months Ended March 31,						2020					2019			Increase (Decrease)
(Millions)	2017				2016					Increase (Decrease)
Exploration and Production:
Capital Expenditures	$	74.7	(1)	$	40.7	(2)	$	34.0		$	229.3	(1)	$		262.8		(2)	$	(33.5	)
Pipeline and Storage:
Capital Expenditures	22.3		(1)	25.4		(2)	(3.1		)	82.7		(1)	52.6			(2)	30.1
Gathering:
Capital Expenditures	12.9		(1)	11.3		(2)	1.6			24.9		(1)	21.5			(2)	3.4
Utility:
Capital Expenditures	16.5		(1)	17.1		(2)	(0.6		)	36.6		(1)	35.7			(2)	0.9
All Other:
Capital Expenditures	0.1		(1)	0.1		(2)	—			0.4			0.1				0.3
	$	126.5		$	94.6		$	31.9		$	373.9		$	372.7			$	1.2

(1)

At ~~December~~March 31, ~~2017~~,2020, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include ~~$37.1~~$41.2 million, ~~$10.7~~$9.7 million, ~~$4.7~~$4.4 million and ~~$3.6~~$4.2 million, respectively, of non-cash capital expenditures. At September 30, ~~2017~~,2019, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included ~~$36.5~~$38.0 million, ~~$25.1~~$23.8 million, ~~$3.9~~$6.6 million and ~~$6.7~~$12.7 million, respectively, of non-cash capital expenditures. ~~The capital expenditures for the Exploration and Production segment do not include any proceeds received from the sale of oil and gas assets to IOG under the joint development agreement.~~

(2)

At ~~December~~March 31, ~~2016~~,2019, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included ~~$25.3~~$53.4 million, ~~$8.7~~$10.7 million, ~~$7.9~~$7.4 million and ~~$7.1~~$3.4 million, respectively, of non-cash capital expenditures. At September 30, ~~2016~~,2018, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included ~~$25.2~~$51.3 million, ~~$18.7~~$21.9 million, ~~$5.3~~$6.1 million and ~~$11.2~~$9.5 million, respectively, of non-cash capital expenditures. ~~The capital expenditures for the Exploration and Production segment do not include any proceeds received from the sale of oil and gas assets to IOG under the joint development agreement.~~

Exploration and Production

The Exploration and Production segment capital expenditures for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2020 were primarily well drilling and completion expenditures and included approximately ~~$70.6~~$207.1 million for the Appalachian region (including ~~$58.7~~$73.9 million in the Marcellus Shale area and $126.4 million in the Utica Shale area) and ~~$4.1~~$22.2 million for the West Coast region. These amounts included approximately ~~$40.7~~$144.2 million spent to develop proved undeveloped reserves.

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

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The Exploration and Production segment capital expenditures for the ~~three~~six months ended ~~December~~March 31, ~~2016~~2019 were primarily well drilling and completion expenditures and included approximately ~~$29.8~~$247.6 million for the Appalachian region (including ~~$16.4~~$111.8 million in the Marcellus Shale area and $125.9 million in the Utica Shale area) and ~~$10.9~~$15.2 million for the West Coast region. These amounts included approximately ~~$8.3~~$144.7 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2020 were ~~partially~~primarily for expenditures related to Empire's Empire North Project ($45.5 million), and also included $3.4 million of expenditures related to Supply Corporation's Line N to Monaca Project. Both projects are discussed below. In addition, the Pipeline and Storage segment capital expenditures for the six months ended March 31, 2020 included additions, improvements and replacements to this segment’s transmission and gas storage systems. The Pipeline and Storage capital expenditures for the six months ended March 31, 2019 were primarily for additions, improvements and replacements to this segment’s transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for the ~~three~~six months ended ~~December~~March 31, ~~2017 include~~2019 included expenditures related to Supply Corporation's Line ~~D Expansion~~N to Monaca Project ($~~12.4~~4.1 million)~~, as discussed below. The Pipeline~~ and ~~Storage capital expenditures for the~~ ~~three months endedDecember 31, 2016~~ ~~were mainly for expenditures related to~~Empire's Empire ~~and Supply Corporation's Northern Access 2016~~North Project ($~~13.5~~3.7 million) ~~and Supply Corporation's Line D Expansion Project ($4.2 million) and also included additions, improvements, and replacements to this segment’s transmission and gas storage systems.~~.

In light of the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia — specifically in the Marcellus and Utica Shale producing areas — Supply Corporation and Empire have ~~recently~~ completed and ~~are actively pursuing~~continue to pursue several expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines

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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 and become part of a Transco expansion project ("Leidy South") that will create incremental transportation capacity to Transco Zone 6 markets. Seneca is the anchor shipper on Leidy South, providing Seneca with an outlet to premium markets for its Marcellus and Utica production from both the Clermont-Rich Valley (Western Development Area) and Trout Run-Gamble (Eastern Development Area – Lycoming County) 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 the project. The FM100 Project has a target in-service date in late calendar 2021 and a preliminary cost estimate of approximately $280 million. As of March 31, 2020, approximately $7.2 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.

Supply Corporation and Empire ~~are developing~~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 at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York ~~(“Northern~~(the “Northern Access ~~2016”~~project”). The Northern Access ~~2016~~ project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access ~~2016~~ project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. ~~The preliminary cost estimate for the Northern Access 2016 project is approximately $500 million.~~ Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. On February 3, 2017, the Company received FERC approval of the project. ~~On April 7, 2017,~~Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received onin January ~~27,~~of 2017). ~~On April 21, 2017, the Company appealed the NYDEC's decision with regard to the Water Quality Certification to the~~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 ~~on May 11, 2017,~~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

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FERC's decisions have been appealed and are pending in a separate action before the Second Circuit Court of Appeals. In addition, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. The Company ~~also has pending with FERC a proceeding asserting, among other things, that~~remains committed to the ~~NYDEC exceeded the reasonable and statutory time frames to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification.~~project. In light of these pending legal actions and the ~~Company has not yet determined a target~~need to complete necessary project development activities in advance of construction, the in-service ~~date.~~date for the project is expected to be no earlier than fiscal 2022. The Company ~~remains committed to~~will update the ~~project.~~$500 million preliminary cost estimate when there is further clarity on that date. As of ~~December~~March 31, ~~2017,~~2020, approximately ~~$75.5~~$58.0 million has been spent on the Northern Access ~~2016~~ project, including ~~$21.9~~$23.5 million that has been spent to study the project, for which no reserve has been established. The remaining ~~$53.6~~$34.5 million spent on the project has been capitalized as Construction Work in Progress.

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

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

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

Gathering

The majority of the Gathering segment capital expenditures for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2020 were for the continued ~~buildout~~expansion of Midstream ~~Corporation’s Clermont Gathering System and Midstream Corporation's~~Company’s Trout Run, ~~Gathering System,~~Clermont, and Wellsboro gathering systems, as discussed below. Midstream Company spent $12.0 million, $6.9 million and $6.0 million, respectively, during the six months ended March 31, 2020 on the development of the Trout Run, Clermont and Wellsboro gathering systems. These expenditures were largely attributable to new gathering pipelines and the continued development of centralized station facilities, including increased compression horsepower at the Trout Run gathering system, the first phase of compression at the Wellsboro gathering system, and additional dehydration at the Clermont gathering system.

The majority of the Gathering segment capital expenditures for the ~~three~~six months ended ~~December~~March 31, ~~2016~~2019 were for the ~~construction~~continued expansion of the Trout Run, Clermont ~~Gathering System.~~and Wellsboro gathering systems. Midstream Company spent $6.2 million, $5.5 million and $8.6 million, respectively, during the six months ended March 31, 2019 on the development of the Trout Run, Clermont and Wellsboro gathering systems.

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

NFG Midstream Wellsboro, LLC, a wholly owned subsidiary of ~~December 31, 2017, approximately $285.4 million has been spent on the Clermont Gathering System, including approximately $4.0 million spent during the three months ended December 31, 2017, all~~Midstream Company, continues to develop its Wellsboro gathering system in Tioga County, Pennsylvania. The current system consists of ~~which is included in Property, Plant~~a dehydration and ~~Equipment on the Consolidated Balance Sheet at December 31, 2017.~~metering station and backbone and in-field gathering pipelines.

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

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

Utility

The majority of the Utility segment capital expenditures for the ~~three~~six months ended~~December~~ March 31, ~~2017~~2020 and ~~December~~March 31, ~~2016~~2019 were made for main and service line improvements and replacements, as well as main extensions.

Project Funding

~~The~~Over the past two years, the Company has been financing the Pipeline and Storage segment and Gathering segment projects mentioned above, as well as the Exploration and Production segment and Utility segment capital expenditures, with cash from operations and ~~both short~~short-term debt, as well as with proceeds received from the sale of oil and ~~long-term borrowings. Going forward, while~~gas assets. Before the pandemic crisis began, the Company ~~expects~~had expected to use cash on hand, ~~and~~ cash from operations ~~as the first means of financing these projects, the Company may issue~~and short-term ~~and/or long-term~~ debt ~~as necessary during fiscal 2018~~ to ~~help~~ meet its capital expenditure needs for fiscal 2020, while possibly issuing long-term debt during fiscal 2020 if needed. The length of the pandemic crisis could 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 ~~needs. The level of short-term~~ and long-term borrowings will depend upon the amounts of cash provided by operations, which, in turn, will likely be impacted by natural gas and crude oil prices combined with production from existing wells. other investments, or to refinance maturing debt.

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The Company continuously evaluates capital expenditures and potential investments in corporations, partnerships, and other business entities. The amounts are subject to modification for opportunities such as the acquisition of attractive oil and gas properties, natural gas storage facilities, natural gas gathering and compression facilities and the expansion of natural gas

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transmission line ~~capacities.~~capacities, regulated utility assets and other opportunities as they may arise. While the majority of capital expenditures in the Utility segment are necessitated by the continued need for replacement and upgrading of mains and service lines, the magnitude of future capital expenditures or other investments in the Company’s other business segments depends, to a large degree, upon market conditions.

Financing Cash Flow

~~The Company did not have any consolidated~~Consolidated short-term debt ~~outstanding~~increased $174.8 million when comparing the balance sheet at ~~December~~March 31, ~~2017 or~~2020 to the balance sheet at September 30, ~~2017, nor was there any~~2019. The maximum amount of short-term debt outstanding during the ~~quarter~~six months ended ~~December~~March 31, ~~2017.~~2020 was $250.0 million. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. During the quarter ended March 31, 2020, the Company issued, under its Credit Agreement (as defined below) and uncommitted lines of credit, short-term notes payable to banks in the amount of $230.0 million. The notes were issued to replace commercial paper borrowings that matured during the quarter and for temporary financing requirements as discussed above. Given the effects on credit markets of COVID-19, access to commercial paper markets became challenging and more expensive beginning in March 2020. As a result, the Company elected to draw on its committed credit facility and uncommitted lines of credit as alternative sources of short-term capital. At March 31, 2020, the Company had outstanding short-term notes payable to banks of $230.0 million. Of this amount, $200.0 million was issued under the Credit Agreement. The Company had no commercial paper outstanding at March 31, 2020.

On ~~September 9, 2016,~~October 25, 2018, the Company entered into a ~~Third~~Fourth Amended and Restated Credit Agreement (Credit Agreement) with a syndicate of ~~what now numbers 13~~12 banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through ~~December 5, 2019.~~October 25, 2023. The Company also has ~~a number of individual~~ uncommitted ~~or discretionary~~ lines of credit with ~~certain~~ financial institutions for general corporate purposes. Borrowings under ~~the~~these uncommitted lines of credit ~~are~~would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial ~~institutions~~institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future.

The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $250 million. During the quarter, ~~from October 1, 2017 through December 5, 2019. At December~~the Company recorded an after-tax ceiling test impairment of $129.3 million. As a result at March 31, ~~2017,~~2020, $64.6 million was added back to the Company's total capitalization for purposes of the facility, and the Company’s debt to capitalization ratio, ~~(as~~as calculated under the ~~facility)~~facility, was ~~.53.~~.52. The constraints specified in the Credit Agreement would have permitted an additional ~~$1.36~~$1.61 billion in short-term and/or long-term debt to be outstanding at March 31, 2020 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65.

During the quarter ended March 31, 2020, the Company was downgraded by S&P to a rating of BBB- with a negative outlook. Combined with current ratings from other credit rating agencies, the downgrade increased the Company's short-term borrowing costs under its Credit Agreement. A further downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources, including cash provided by operations.

The Credit Agreement contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. ~~As of December 31, 2017, the Company did not have any debt outstanding under the Credit Agreement.~~

None of the ~~Company’s~~Company's long-term debt ~~at December~~as of March 31, ~~2017~~2020 and September 30, 2019 had a maturity date within the following twelve-month period. ~~The Current Portion~~

Table of Long-Term Debt at September 30, 2017 consisted of $300.0 million aggregate principal amount of 6.50% notes scheduled to mature in April 2018. The Company redeemed these notes on October 18, 2017 for $307.0 million, plus accrued interest.Contents

The Company’s embedded cost of long-term debt was ~~5.17%~~4.69% at both March 31, 2020 and ~~5.53% at December~~March 31, ~~2017 and December 31, 2016, respectively.~~2019.

The Company's present liquidity position is believed to be adequate to satisfy known demands. Under the Company’s existing indenture covenants at ~~December~~March 31, ~~2017,~~2020, the Company would have been permitted to issue up to a maximum of ~~$654.0~~$719 million in additional long-term indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. ~~The~~However, factors that reduce the Company's ~~present liquidity position is believed to be adequate to satisfy known demands. However, if~~operating income and/or consolidated assets, including impairments (i.e. write-downs) of the ~~Company were to experience a significant loss in the future (for example, as a result of an impairment of~~Company's oil and natural gas ~~properties), it is possible, depending on factors including~~properties, could contribute to the ~~magnitude of the loss, that these~~Company's inability to meet interest coverage or debt-to-assets indenture covenants, which would restrict the Company's ability to issue ~~additional~~ long-term ~~unsecured indebtedness~~debt. In light of impairments of oil and natural gas properties recognized or expected in fiscal 2020 and likely in the first quarter of fiscal 2021, the Company anticipates that it may be precluded from issuing incremental long-term debt for a period of up

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~~to nine calendar months,~~time beginning ~~with the fourth calendar month following the loss. This~~in fiscal 2021. The covenants would not preclude the Company from issuing ~~new indebtedness~~long-term debt to replace maturing ~~debt.~~long-term debt, including the Company's 4.90% notes, in the principal amount of $500 million, maturing in December 2021. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

The Company’s 1974 indenture pursuant to which ~~$98.7~~$99.0 million (or ~~4.7%~~4.6%) of the Company’s long-term debt (as of ~~December~~March 31, ~~2017)~~2020) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

~~OFF-BALANCE SHEET ARRANGEMENTS~~

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

OTHER MATTERS

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

During the ~~three~~six months ended ~~December~~March 31, ~~2017,~~2020, the Company contributed ~~$27.6~~$19.3 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and ~~$0.7~~$2.1 million to its VEBA trusts for its other post-retirement benefits. In the remainder of ~~2018, the Company may contribute up to $5.0 million to the Retirement Plan. In the remainder of 2018,~~2020, 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, the Company expects its contributions to its VEBA trusts to be in the range of ~~$2.0~~$0.5 million to ~~$3.0~~$1.0 million.

The Company, in its Exploration and Production segment, has entered into a $76.2 million contractual obligation related to hydraulic fracturing and other completion services during the quarter ended March 31, 2020. This contractual commitment extends through May 31, 2021.

Market Risk Sensitive Instruments

On July 21, 2010, the Dodd-Frank Act was signed into law. The Dodd-Frank Act includes provisions related to the swaps and over-the-counter derivatives markets that are designed to promote transparency, mitigate systemic risk and protect against market abuse. Although regulators have issued certain regulations, other rules that may impact the Company have yet to be finalized.

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rules that would impose speculative position limits on positions in 28 core physical commodity contracts as well as economically equivalent futures, options and swaps. While the Company does not intend to enter into positions on a speculative basis, such rules could nevertheless impact the ability of the Company to enter into certain derivative hedging transactions with respect to such commodities. If ~~we reduce our~~the Company reduces its use of hedging transactions as a result of final regulations to be issued by the CFTC, ~~our~~ results of operations may become more volatile and ~~our~~ cash flows may be less predictable. There may be other rules developed by the CFTC and other regulators that could impact the Company. While many of those rules place specific conditions on the operations of swap dealers and major swap participants, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs.

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

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The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At ~~December~~March 31, ~~2017,~~2020, 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.

The Company uses various derivative financial instruments as part of the Company’s overall energy commodity price risk management strategy in its Exploration and Production segment and its NFR operations (included in the All Other category). During the quarter ended March 31, 2020, the Company began using no cost collars in its Exploration and Production segment to manage the price risk associated with forecasted sales of gas. The no cost collars are not held for trading purposes.

The following table discloses the notional quantities, the weighted average ceiling price and the weighted average floor price for the no cost collars used by the Company to manage natural gas price risk. The no cost collars provide for the Company to receive monthly payments from (or make payments to) other parties when a variable price falls below an established floor price (the Company receives payment from the counterparty) or exceeds an established ceiling price (the Company pays the counterparty). At March 31, 2020, the Company had not entered into any natural gas no cost collars extending beyond 2022.



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

At March 31, 2020, the Company would have had to pay an aggregate of approximately $1.0 million to terminate the natural gas no cost collars outstanding at that date.

For a complete discussion of all other market risk sensitive instruments used by the Company, refer to ~~"Market~~“Market Risk Sensitive ~~Instruments"~~Instruments” in Item 7 of the ~~Company's 2017~~Company’s 2019 Form 10-K. ~~There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.~~

Rate and Regulatory Matters

Utility Operation

Delivery rates for both the New York and Pennsylvania divisions are regulated by the states’ respective public utility commissions and typically are changed only when approved through a procedure known as a “rate case.” ~~Although the~~The Pennsylvania division does not have a rate case on ~~file, see~~file. See below for a description of the current rate proceedings affecting the New York division. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are

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recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.

New YorkJurisdiction

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

On July 28, 2017, Distribution Corporation filed an appeal with New York State Supreme Court, Albany County, seeking review of the Order. The appeal contends that portions of the Order should be invalidated because they fail to meet the applicable legal standard for agency decisions. On December 11, 2017, the appeal was transferred to the Supreme Court, Appellate Division, Third Department. The Company cannot predict the outcome of the appeal at this time.

On ~~December 22, 2017, the federal Tax Cuts and Jobs Act (the 2017 Tax Reform Act) was enacted into law. On December 29, 2017,~~April 24, 2019, the NYPSC issued an order ~~instituting a proceeding to study~~extending the ~~potential effects~~sunset provision of the ~~enactment~~tracker previously approved by the NYPSC that allows Distribution Corporation to recover increased investment in utility system modernization for one year (until March 31, 2021). The extension is contingent on a one year stay-out of a general rate case filing that would prevent new rates from becoming effective prior to April 1, 2021.

In New York, on March 13, 2020, the Company agreed to NYPSC Staff’s request that the Company suspend service terminations and disconnections. The Company is anticipating that there will be some level of increase in uncollectible expense depending on the depth and duration of the ~~2017 Tax Reform Act on~~pandemic crisis. It is uncertain at this point as to whether there would be any regulatory relief for the ~~tax expenses and liabilities of New York utilities, and the “regulatory treatment of any windfalls resulting from same~~Utility segment with regard to an increase in order to preserve the benefits for ratepayers.” In its order, the NYPSC stated that the effect of the 2017 Tax Reform Act on utilities’ taxation is likely to be material and complex and that the proceeding was needed to begin the process of addressing the impact on the State’s utilities and ratepayers. The order establishes that the first steps in such process will be soliciting information from its regulated utilities to quantify the impact of the 2017 Tax Reform Act, scheduling a technical conferencecosts associated with the utilities, and the issuance of a NY Department of Public Service Staff (Staff) proposal for accounting and ratemaking treatment of the tax changes. The order further states that once Staff’s proposal is issued, utilities and other interested parties will be invited to comment on Staff’s recommendation. The order also declares that utilities are “put on notice that it is the [NYPSC]’s intent to ensure that net benefits accruing from the Tax Act are preserved for ratepayers, either through deferral accounting or another method, from the first day the Tax Act is put into effect. Utilities acting contrary to this intent do so at their own risk.” The Company cannot predict the outcome of this proceeding at this time. Refer to Item 1 at Note 4 - Income Taxes for a further discussion of the 2017 Tax Reform Act.pandemic crisis.

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Pennsylvania Jurisdiction

Distribution Corporation’s ~~current delivery charges in its~~ Pennsylvania jurisdiction ~~were~~delivery rates are being charged to customers in accordance with a rate settlement approved by the PaPUC. The rate settlement does not specify any requirement to file a future rate case.

On March 26, 2020, the PaPUC ~~on November 30, 2006~~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 to New York, it is uncertain at this point as ~~part of a settlement agreement that became effective January 1, 2007.~~to whether there would be any regulatory relief with regard to any increase in the Utility’s uncollectible expense.

Pipeline and Storage

Empire's 2019 rate settlement requires a Section 4 rate case filing no later than ~~December 31, 2019.~~

May 1, 2025. Empire ~~currently~~ has no ~~active~~ rate case currently on file. ~~Empire’s current rate settlement requires a rate case filing no later than July 1, 2021.~~

Environmental Matters

The Company is subject to various federal, state and local laws and regulations relating to the protection of the environment. The Company has established procedures for the ongoing evaluation of its operations to identify potential environmental exposures and comply with regulatory requirements.

For further discussion of the Company's environmental exposures, refer to Item 1 at Note 68 — Commitments and Contingencies under the heading “Environmental Matters.”

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Legislative and regulatory measures to address climate change and greenhouse gas emissions are in various phases of discussion or ~~implementation. In~~implementation in the United ~~States, these~~States. These efforts include legislative proposals and ~~EPA~~new regulations at the state and federal ~~level, actions at the state~~ level, and private party litigation related to greenhouse gas emissions. ~~While the~~The U.S. ~~Congress has from time to time considered legislation aimed at reducing emissions of greenhouse gases,~~ Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA ~~is regulating~~regulates greenhouse gas emissions pursuant to the ~~authority granted to it by the federal~~ Clean Air Act. ~~For example, in April 2012, the~~The regulations implemented by EPA adopted rules which restrict emissions associated with oil and natural gas drilling. The EPA previously adopted final regulations that set methane and volatile organic compound emissions standards for new or modified oil and gas emissions sources. These rules impose more stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. The current administration has issued executive orders to review and potentially roll back many of these burdensome regulations, and, in turn, litigation (not involving the Company) has been instituted to challenge the administration's efforts. The Company must continue to comply with all applicable regulations. ~~In addition, the U.S. Congress has from time to time considered bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases.~~ A number of states have adopted energy strategies or plans with aggressive goals ~~that include~~for the reduction of greenhouse gas emissions. For example, New York’s State Energy Plan includes Reforming the Energy Vision (REV) initiatives which set greenhouse gas emission reduction targets of 40% by 2030 and 80% by 2050. Additionally, the Plan targets that 50% of electric generation must come from renewable energy sources by 2030. Similarly, Pennsylvania has a methane reduction framework ~~for the oil and gas industry which will result in permitting changes~~ with the stated goal of reducing methane emissions from well sites, compressor stations and ~~pipelines. With respect to its operations~~pipelines and is in the process of evaluating cap-and-trade programs (e.g., Regional Greenhouse Gas Initiative). In California, the Company currently complies with California cap-and-trade ~~guidelines,~~rules, which increases the Company's cost of environmental compliance in its Exploration and Production ~~segment operations.~~segment. Legislation or regulation that aims to reduce greenhouse gas emissions could also include emissions limits, reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. Federal, state or local governments may ~~for example,~~ provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. New York State, for example, passed the CLCPA that mandates reducing greenhouse gas emissions to 60% of 1990 levels by 2030, and to 15% of 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The CLCPA also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% by 2040. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets depending on regulatory treatment afforded in the process. These initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements, requiring retrofitting of existing equipment, requiring installation of new equipment, and/or requiring the ~~Company to retrofit existing equipment, install new equipment to reduce emissions from larger facilities and/or~~ purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory ~~approvals with regard to existing~~approvals. Changing market conditions and new ~~facilities, impose additional monitoring~~regulatory requirements, as well as unanticipated or inconsistent application of existing laws and ~~reporting requirements, and reduce demand for oil and natural gas. But legislation~~regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.more years.

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~~New Authoritative Accounting and Financial Reporting Guidance~~

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

Safe Harbor for Forward-Looking Statements

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


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


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


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


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


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


6.3.	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;

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


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


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


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


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


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


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

12.

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


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


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


~~10.~~14.	Other changes in price differentials between similar quantities of natural gas or oil having different quality, heating value, hydrocarbon mix or delivery date;

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~~11.~~15.	The cost and effects of legal and administrative claims against the Company or activist shareholder campaigns to effect changes at the Company;


~~12.~~16.	Uncertainty of oil and gas reserve estimates;


~~13.~~17.	Significant differences between the Company’s projected and actual production levels for natural gas or oil;


~~14.~~18.	Changes in demographic patterns and weather conditions;


~~15.~~19.	Changes in the availability, price or accounting treatment of derivative financial instruments;


~~16.~~20.	Changes in laws, actuarial assumptions, the interest rate environment and the return on plan/trust assets related to the Company’s pension and other post-retirement benefits, which can affect future funding obligations and costs and plan liabilities;


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


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


~~19.~~21.	Economic disruptions or uninsured losses resulting from major accidents, fires, severe weather, natural disasters, terrorist activities or acts of ~~war, cyber attacks or pest infestation;~~war;


~~20.~~22.	Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or


~~21.~~23.	Increasing costs of insurance, changes in coverage and the ability to obtain insurance.

The Company disclaims any obligation to update any forward-looking statements to reflect events or circumstances after the date hereof.

Item 3. Quantitative and Qualitative Disclosures About Market Risk

Refer to the "Market Risk Sensitive Instruments" section in Item 2 – MD&A.

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of ~~December~~March 31, ~~2017.~~ 2020.

Changes in Internal Control Over Financial Reporting

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended ~~December~~March 31, ~~2017~~2020 that have materially affected, or are reasonably likely to materially affect, the Company’s internal control over financial reporting.

Part II. Other Information

Item 1. Legal Proceedings

On ~~September 13, 2017, the PaDEP sent~~January 17, 2020, Seneca signed a ~~draft~~ Consent Assessment of Civil Penalty (CACP) ~~to Seneca,~~with the PaDEP, in relation to an alleged violation identified by the PaDEP in 2011 of the Pennsylvania Oil and Gas Act, as well as PaDEP rules and regulations regarding ~~gas migration relating~~well cementing/casing at a Seneca location. The parties agreed to ~~Seneca’s drilling activities. The~~a penalty amount of ~~the penalty sought by the PaDEP is not material to the Company. The draft CACP~~$125,000.

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

For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 68 — Commitments and Contingencies, and Part I, Item 2 - MD&A of this report under the heading “Other Matters – Environmental Matters.”

For a discussion of certain rate matters involving the NYPSC, refer to Part I, Item 1 of this report at Note 911 — Regulatory Matters.

Item 1A. Risk Factors

The risk factors in Item 1A of the Company’s ~~2017~~2019 Form 10-K have not materially changed other than as set forth below. The risk ~~factor~~factors presented below ~~supersedes~~supersede the risk ~~factor~~factors having the same caption in the ~~2017~~2019 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the ~~2017~~2019 Form 10-K. The impact of COVID-19 may also exacerbate other risks discussed in Item 1A of the Company’s 2019 Form 10-K, any of which could have a material effect on us. This situation is changing rapidly and additional impacts may arise that we are not aware of currently.

The COVID-19 global pandemic could have a material adverse effect on the Company’s ~~need~~business, results of operations, cash flows and financial condition.

The actual or perceived effects of a widespread public health concern or pandemic, such as COVID-19, could negatively affect our business and results of operations. While to ~~comply with comprehensive, complex,~~date the Company has not experienced any material negative effects as a result of COVID-19, the situation continues to rapidly evolve and ~~the sometimes unpredictable enforcement of government regulations may increase its costs and limit its revenue growth, which may~~could result in ~~reduced earnings.~~

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

~~In the Company's Utility segment, the operations~~

A protracted slowdown of ~~Distribution Corporation are subject to the jurisdiction~~broad sectors of the ~~NYPSC, the PaPUC and, with respect~~economy or significant changes in legislation or regulatory policy to ~~certain transactions, the FERC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also~~address COVID-19 could adversely impact the ~~returns that Distribution Corporation may earn~~Company. Although it is not possible to predict the ultimate impact of COVID-19, including on the ~~assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers,~~Company’s business, results of operations, cash flows or ~~to the extent Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover increased costs (including costs~~financial positions, such impacts that may be ~~incurred~~material include, but are not limited to: (i) a significant reduction in ~~connection~~demand for natural gas; (ii) increased late or uncollectible customer payments; (iii) the inability for the Company’s contractors or suppliers to fulfill their contractual obligations; (iv) significant changes in the Company’s human capital management approach, and increased cybersecurity threats associated with ~~governmental investigations~~work-from-home arrangements; (v) difficulties in obtaining financing on acceptable terms or ~~proceedings~~at all for working capital, capital expenditures

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and other investments, or ~~mandated infrastructure inspection, maintenance~~to refinance maturing debt; and (vi) impacts on natural gas pricing and the potential impairment of the recorded value of certain assets as a result of reduced projected cash flows. To the extent the duration of any of these conditions extends for a longer period of time, the adverse impact will generally be more severe.

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

The Company relies upon short-term bank borrowings, commercial paper markets and longer-term capital markets to finance capital requirements not satisfied by cash flow from operations. The Company is dependent on these capital sources to provide capital to its subsidiaries to fund operations, acquire, maintain and develop properties, and execute growth strategies. The availability and cost of credit sources may be cyclical and these capital sources may not remain available to the Company. For example, given near-term challenges in commodity pricing, a downgrade by S&P in the Company’s credit ratings, and, most prominently, the effects on credit markets of the novel coronavirus (COVID-19), access to commercial paper markets became challenging and more expensive beginning in March 2020. As a result, the Company elected to draw on its committed credit facility and uncommitted lines of credit as alternative sources of short-term capital. Continued turmoil in credit markets, due to the ongoing COVID-19 pandemic or ~~replacement programs)~~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. These difficulties could adversely affect the Company's growth strategies, operations and financial performance.

The Company's ability to borrow under its credit facilities and commercial paper agreements, and its ability to issue long-term debt under its indentures, depend on the Company's compliance with its obligations under the facilities, agreements and indentures. For example, to issue incremental long-term debt, the Company must meet an interest coverage test under its 1974 indenture. In general, the Company’s operating income, subject to certain adjustments, over a consecutive 12-month period within the 15 months preceding the debt issuance, must be not less than two times the total annual interest charges on the Company’s long-term debt, taking into account the incremental issuance. In addition, the Company must maintain a ratio of long-term debt to consolidated assets (as defined under the 1974 indenture) of not more than 60%. Depending on their magnitude, factors that reduce the Company’s operating income and/or consolidated assets, including impairments (i.e., ~~earnings~~write-downs) of the Company’s oil and natural gas properties, could contribute to the Company’s inability to meet the interest coverage test or debt-to-assets ratio. In light of impairments recognized or expected in fiscal 2020 and 2021, the Company anticipates that it may ~~decrease.~~be precluded from issuing incremental long-term debt for a period of time beginning in fiscal 2021. The 1974 indenture would not preclude the Company from issuing long-term debt to replace maturing long-term debt, including the Company’s 4.90% notes, in the principal amount of $500 million, maturing in December 2021.

In addition, the Company's short-term bank loans and commercial paper are in the form of floating rate debt or debt that may have rates fixed for very short periods of time, resulting in exposure to their historical methods of utility regulation, both the PaPUC and NYPSC have established competitive markets in which customers may purchase gas commodity from unregulated marketers, in addition to utility companies. Retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation because in both jurisdictions it recovers its cost of service through delivery rates and charges, and not through any mark-up on the gas commodity purchased by its customers. Over the longer run, however,interest rate ~~design changes resulting from customer migration to marketer service ("unbundling") can expose utilities such as Distribution Corporation to stranded costs and revenue erosion~~fluctuations in the absence of ~~compensating~~interest rate ~~relief.~~

~~Both~~hedging transactions. The cost of long-term debt, the ~~NYPSC~~interest rates on the Company's short-term bank loans and commercial paper and the ~~PaPUC have,~~ability of the Company to issue commercial paper are affected by its debt credit ratings published by S&P, Moody's Investors Service, Inc. and Fitch Ratings. A downgrade in the Company's credit ratings could increase borrowing costs, negatively impact the availability of capital from ~~time-to-time, instituted proceedings for~~banks, commercial paper purchasers and other sources, and require the ~~purpose~~Company’s subsidiaries to post letters of ~~promoting conservation~~credit, cash or other assets as collateral with certain counterparties. During the quarter ended March 31, 2020, the Company was downgraded by S&P to a rating of ~~energy commodities, including natural gas. In New York, Distribution Corporation implemented~~BBB- with a ~~Conservation Incentive Program~~negative outlook. Combined with current ratings from other credit rating agencies, the downgrade increased the Company's short-term borrowing costs under its Credit Agreement. Additionally, $600 million of the Company’s outstanding long-term debt would be subject to an interest rate increase if certain fundamental changes occur that ~~promotes conservation~~involve a material subsidiary and ~~efficient use~~result in a downgrade of ~~natural gas~~the credit ratings assigned to the notes below investment grade. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets.

The Company may be adversely affected by ~~offering customer rebates for the installation~~economic conditions and their impact on our suppliers and customers.

Periods of high-efficiency appliances, among other things. The intent of conservation and efficiency programs is to reduce customer usage of natural gas. Under traditional volumetric rates, reduced usage by customers resultsslowed economic activity generally result in decreased ~~revenues to the Utility. To prevent revenue erosion caused~~energy consumption, particularly by ~~conservation, the NYPSC approved~~industrial and large commercial companies. As a ~~"revenue decoupling mechanism" that renders Distribution Corporation's New York division financially indifferent to~~consequence, national or regional recessions or other downturns in economic activity, including the effects of ~~conservation. In Pennsylvania,~~COVID-19, could adversely affect the PaPUC has not directed Distribution Corporation to implement a conservation program. If the NYPSC were to revoke the revenue decoupling mechanism in a future proceeding or the PaPUC were to adopt a conservation program without revenue decoupling mechanism or other changes in rate design, reduced customer usage could decreaseCompany’s revenues ~~forcing Distribution Corporation to file for rate relief. If Distribution Corporation were unable to obtain adequate rate relief, its financial condition, results of operations~~ and cash flows ~~would~~or restrict its future growth. The Company is monitoring the impacts of COVID-19 across our businesses. To date, COVID-19 has not had a material impact on the Company. However, the Company cannot predict the extent or duration of the outbreak or whether this rapidly evolving situation will have a material impact on the Company’s workforce, supply chain, operations or financial results, including potential regulatory responses to the financial impacts associated with COVID-19 on the Company and its customers. Economic conditions in the Company’s utility service territories and NFR's territories also impact its collections of accounts receivable. All of the Company’s segments are exposed to risks associated with the creditworthiness or performance of key suppliers and customers, many of which may be adversely ~~affected.~~affected by volatile conditions in the financial markets, including volatility caused by the ongoing COVID-19 pandemic. These conditions could result in financial instability or other adverse effects at any of our suppliers or customers. For

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

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

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

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

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

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

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

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

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

~~Table~~contracts. Customers of ~~Contents~~

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

~~It is~~ the Company’s ~~practice that the use~~Utility segment may have particular trouble paying their bills during periods of declining economic activity or high commodity ~~derivatives contracts comply with various policies~~prices, potentially resulting in ~~effect in respective business segments. For example, in the Exploration~~increased bad debt expense and Production segment, commodity derivatives contracts must be confined to the price hedging of existing and forecast production, and in the Energy Marketing segment, commodity derivatives with respect to fixed price purchase and sales commitments must be matched against commitments reasonably certain to be fulfilled. The Company maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades,reduced earnings. Similarly, if ~~they~~reductions were to occur in funding of the federal Low Income Home Energy Assistance Program, bad debt expense could ~~expose the Company to substantial losses to cover positions in its derivatives contracts.~~increase and earnings could decrease. In addition, ~~in the event~~oil and gas exploration and production companies that are customers of the Company’s ~~actual~~Pipeline and Storage segment may decide not to renew contracts for the same transportation capacity during periods of reduced production due to persistent low commodity prices. Any of ~~oil and natural gas falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.~~

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

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

Third party attempts to breach the ~~CFTC~~Company’s network security and other ~~regulators that~~disruptions to information technology systems could impact the ~~Company. While many~~Company’s operations and adversely affect its financial results.

The Company relies on the accuracy, capacity and security of ~~those rules place specific conditions on~~its information technology systems for the operations of ~~swap dealers~~many of its business processes and ~~major swap participants, concern remains that swap dealers~~to comply with regulatory, legal and ~~major swap participants will pass along their increased costs stemming from final rules through higher transaction costs and prices~~tax requirements. While the Company maintains some of its critical information technology systems, the Company is also dependent on third parties to provide important information technology services. The Company’s information technology systems are subject to attempts by others to gain unauthorized access, or to otherwise introduce malicious software. These attempts might be the result of industrial or other ~~direct~~espionage, or ~~indirect costs.~~

~~Finally, given~~actions by hackers seeking to harm the ~~additional authority granted~~Company, its services or customers. These more sophisticated cyber-related attacks, as well as cybersecurity failures resulting from human error, pose a risk to the ~~CFTC on anti-market manipulation, anti-fraud and disruptive trading practices, it is difficult to predict how the evolving enforcement priorities~~security of the ~~CFTC will impact~~Company’s systems and networks and the confidentiality, availability and integrity of the Company’s ~~business. Should~~and its customers’ data. That data may be considered sensitive, confidential, or personal information that is subject to privacy and security laws and regulations. With the global outbreak of COVID-19, the Company ~~violate any laws~~has directed its employees to work remotely, when possible. Cyber criminals may attempt to exploit this increase in digital application use and work-from-home arrangements. In addition, increased use of information technology systems as a result of employees working remotely and other factors may lead to disruptions or ~~regulations applicable~~failures of the Company’s information technology systems. While the Company employs reasonable and appropriate controls to protect data and the Company’s systems, the Company may be vulnerable to material security breaches, information technology system failures, lost or corrupted data, programming errors and employee errors and/or malfeasance that could lead to disruption of the Company’s operations, as well as the unauthorized access, use, disclosure, modification or destruction of the sensitive, confidential or personal information. Furthermore, the Company may have little or no oversight with respect to security measures employed by third-party service providers, which may ultimately prove to be ineffective atcountering threats. Failures of the Company’s information technology systems, whether caused inadvertently or by attempts to breach the Company’s network security may result in disruption of the Company’s business operations and services, delays in production, theft of sensitive and valuable data, damage to our physical systems, and reputational harm. Significant expenditures may be required to remedy such failures or breaches, including restoration of customer service and enhancement of information technology systems. The Company seeks to prevent, detect and investigate these security incidents, but in some cases the Company might be unaware of an incident or its magnitude and effects. In addition to existing risks, the adoption of new technologies may also increase the Company’s exposure to data breaches or the Company’s ability to detect and remediate effects of a breach. The Company has experienced attempts to breach its network security, and although the scope of such incidents is sometimes unknown, they could prove to be material to the Company. Even though insurance coverage is in place for cyber-related risks, if such a breach were to occur, the Company’s ~~hedging~~operations, earnings and financial condition could be adversely affected to the extent not fully covered by such insurance.

Delays or changes in plans or costs with respect to Company projects, including regulatory delays or denials with respect to necessary approvals, permits or orders, could delay or prevent anticipated project completion and may result in asset write-offs and reduced earnings.

Construction of the Pipeline and Storage segment’s planned pipelines and storage facilities, as well as the expansion of existing facilities, is subject to various regulatory, environmental, political, legal, economic and other development risks, including the ability to obtain necessary approvals and permits from regulatory agencies on a timely basis and on acceptable terms, or at all. Existing or potential third party opposition, such as opposition from landowner and environmental groups, which are beyond our control, could materially affect the anticipated construction of a project. In addition, third parties could impede the Gathering segment’s acquisition, expansion or renewal of rights-of-way or land rights on a timely basis and on acceptable terms. The Company is monitoring the impacts of COVID-19 on its construction projects and supply chains. The outbreak, and the government imposition of certain significant restrictions associated therewith, could delay receipt of necessary equipment or delay construction. Any delay in project construction may prevent a planned project from going into service when anticipated, which could cause a delay in the receipt of revenues from those facilities, result in asset write-offs and materially impact operating results or anticipated results. Additionally, delays in pipeline construction projects could impede the Exploration and Production segment's ability to transport its production to premium markets, or to fulfill obligations to sell at contracted delivery points.

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Financial accounting requirements regarding exploration and production activities may affect the Company's profitability.

The Company accounts for its exploration and production activities under the full cost method of accounting. Each quarter, the Company must perform a "ceiling test" calculation, comparing the level of its unamortized investment in oil and gas properties to the present value of the future net revenue projected to be recovered from those properties according to methods prescribed by the SEC. In determining present value, the Company uses a 12-month historical average price for oil and gas (based on first day of the month prices and adjusted for hedging) as well as the SEC mandated discount rate. If, at the end of any quarter, the amount of the unamortized investment exceeds the net present value of the projected future cash flows, such investment may be considered to be "impaired," and the full cost accounting rules require that the investment must be written down to the calculated net present value. Such an instance would require the Company to recognize an immediate expense in that quarter, and its earnings would be reduced. Depending on the magnitude of any decrease in average prices, that charge could be ~~subject~~material. Under the Company's existing indenture covenants, an impairment could restrict the Company's ability to ~~CFTC enforcement action~~issue additional long-term unsecured indebtedness for a period time, beginning with the fourth calendar month following the impairment. For the quarter ended March 31, 2020, the Company recognized a pre-tax impairment charge on its oil and ~~material penalties~~natural gas properties of $177.8 million. It is anticipated that the current low commodity price environment will lead to impairments during the remaining quarters of fiscal 2020 and ~~sanctions.~~likely into the first quarter of fiscal 2021 as well.

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

On ~~October~~January 2, ~~2017,~~2020, the Company issued a total of ~~6,912~~9,370 unregistered shares of Company common stock to ~~nine~~ten non-employee directors of the Company then serving on the Board of Directors of the Company, ~~768~~including 748 shares to Stephen E. Ewing, whose service as a director concluded on March 11, 2020 in accordance with the provisions of the Company’s Corporate Governance Guidelines with respect to director age, and 958 shares to each ~~such~~of the other nine aforementioned non-employee directors. On March 13, 2020, the Company issues 283 unregistered shares of Company common stock to Barbara M. Baumann, who joined the Board on March 11, 2020 as a non-employee director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended ~~December~~March 31, ~~2017~~.2020. These transactions were exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as transactions not involving a public offering.

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Issuer Purchases of Equity Securities

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



Period	Total Number of Shares Purchased ^(a)	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under Share Repurchase Plans or Programs ^(b)
Jan. 1 - 31, 2020	12,040	$44.95	—	6,971,019
Feb. 1 - 29, 2020	13,114	$42.30	—	6,971,019
Mar. 1 - 31, 2020	15,408	$36.57	—	6,971,019
Total	40,562	$40.91	—	6,971,019

^(a)

Represents shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of ~~stock options, SARs, restricted stock units or shares of restricted stock~~stock-based compensation awards for the payment of ~~option exercise prices or~~ applicable withholding taxes. During the quarter ended ~~December~~March 31, ~~2017~~,2020, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program.

Of the 40,562 shares purchased other than through a publicly announced share repurchase program, 40,413 were purchased for the Company’s 401(k) plans and 149 were purchased as a result of shares tendered to the Company by holders of stock-based compensation awards.


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

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Item 6. Exhibits



Exhibit Number		Description of Exhibit
10.1		~~Form of Award Notice for Return on Capital Performance Shares under the~~ National Fuel Gas Company ~~2010~~2009 Non-Employee Director Equity Compensation ~~Plan.~~

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

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

12		~~Statements regarding Computation of Ratios:~~ ~~Ratio of Earnings to Fixed Charges for the Three Months Ended December 31, 2017~~Plan, as amended and ~~the Fiscal Years Ended September 30, 2014 through 2017.~~restated March 11, 2020.

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

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

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

99		National Fuel Gas Company Consolidated Statements of Income for the Twelve Months Ended ~~December~~March 31, ~~2017~~2020 and ~~2016.~~2019.

101		Interactive data files submitted pursuant to Regulation ~~S-T:~~S-T, formatted in Inline XBRL (eXtensible Business Reporting Language): (i) the Consolidated Statements of Income and Earnings Reinvested in the Business for the three and six months ended ~~December~~March 31, ~~2017~~2020 and ~~2016,~~2019, (ii) the Consolidated Statements of Comprehensive Income for the three and six months ended ~~December~~March 31, ~~2017~~2020 and ~~2016,~~2019, (iii) the Consolidated Balance Sheets at ~~December~~March 31, ~~2017~~2020 and September 30, ~~2017,~~2019, (iv) the Consolidated Statements of Cash Flows for the ~~three~~six months ended ~~December~~March 31, ~~2017~~2020 and ~~2016~~2019 and (v) the Notes to Condensed Consolidated Financial Statements.

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

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

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SIGNATURES

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



NATIONAL FUEL GAS COMPANY
(Registrant)





/s/ ~~D. P. Bauer~~K. M. Camiolo
~~D. P. Bauer~~K. M. Camiolo
Treasurer and Principal Financial Officer





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

Date: ~~February 2, 2018~~May 1, 2020

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