NATIONAL FUEL GAS CO - Quarter Report: 2020 June (Form 10-Q)

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UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended June 30, 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) 857-7000

(Registrant's telephone number, including area code)

Securities registered pursuant to Section 12(b) of the Act:

Title of Each Class

Trading Symbol

Name of Each Exchange

on Which Registered

Common Stock, par value $1.00 per share

NFG

New York Stock Exchange

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

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

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


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

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

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Common stock, par value $1.00 per share, outstanding at July 31, 2020: 90,954,272 shares.

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GLOSSARY OF TERMS

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


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


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


Other
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.

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Derivative			A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, forward contracts, options, no cost collars and swaps.
Development costs			Costs incurred to obtain access to proved oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas
Dodd-Frank Act			Dodd-Frank Wall Street Reform and Consumer Protection Act.
Dth			Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
Exchange Act			Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets			Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploration costs			Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
Exploratory well			A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
FERC 7(c) application			An application to the FERC under Section 7(c) of the federal Natural Gas Act for authority to construct, operate (and provide services through) facilities to transport or store natural gas in interstate commerce.
Firm transportation and/or storage			The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP			Accounting principles generally accepted in the United States of America
Goodwill			An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging			A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
Hub			Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
ICE			Intercontinental Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Interruptible transportation and/or storage			The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LDC			Local distribution company
LIBOR			London Interbank Offered Rate
LIFO			Last-in, first-out
Marcellus Shale			A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.
Mbbl			Thousand barrels (of oil)
Mcf			Thousand cubic feet (of natural gas)
MD&A			Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth			Thousand decatherms (of natural gas)
MMBtu			Million British thermal units (heating value of one decatherm of natural gas)
MMcf			Million cubic feet (of natural gas)

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NGA			The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.
NYMEX			New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Open Season			A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.
Precedent Agreement			An agreement between a pipeline company and a potential customer to sign a service agreement after specified events (called “conditions precedent”) happen, usually within a specified time.
Proved developed reserves			Reserves that can be expected to be recovered through existing wells with existing equipment and operating methods.
Proved undeveloped (PUD) reserves			Reserves that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required to make these reserves productive.
Reserves			The unproduced but recoverable oil and/or gas in place in a formation which has been proven by production.
Revenue decoupling mechanism			A rate mechanism which adjusts customer rates to render a utility financially indifferent to throughput decreases resulting from conservation.
S&P			Standard & Poor’s Rating Service
SAR			Stock appreciation right
Service agreement			The binding agreement by which the pipeline company agrees to provide service and the shipper agrees to pay for the service.
Stock acquisitions			Investments in corporations
Utica Shale			A Middle Ordovician-age geological formation lying several thousand feet below the Marcellus Shale in the Appalachian region of the United States, including much of Ohio, Pennsylvania, West Virginia and southern New York.
VEBA			Voluntary Employees’ Beneficiary Association
WNC			Weather normalization clause; a clause in utility rates which adjusts customer rates to allow a utility to recover its normal operating costs calculated at normal temperatures. If temperatures during the measured period are warmer than normal, customer rates are adjusted upward in order to recover projected operating costs. If temperatures during the measured period are colder than normal, customer rates are adjusted downward so that only the projected operating costs will be recovered.

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INDEX						Page

Part I. Financial Information

Item 1. Financial Statements (Unaudited)						6

a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Nine Months Ended June 3 0 , 2020 and 2019						6
b. Consolidated Statements of Comprehensive Income – Three and Nine Months Ended June 3 0 , 2020 and 2019						7
c. Consolidated Balance Sheets – June 3 0 , 2020 and September 30, 2019						8
d. Consolidated Statements of Cash Flows – Nine Months Ended June 3 0 , 2020 and 2019						10
e. Notes to Condensed Consolidated Financial Statements						11
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations						34
Item 3. Quantitative and Qualitative Disclosures About Market Risk						55
Item 4. Controls and Procedures						56

Part II. Other Information

Item 1. Legal Proceedings						56
Item 1 A. Risk Factors						56
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds						58
Item 3. Defaults Upon Senior Securities						•
Item 4. Mine Safety Disclosures						•
Item 5. Other Information						•
Item 6. Exhibits						59
Signatures						60

• The Company has nothing to report under this item.

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

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Part I. Financial Information

Item 1. Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)


	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands of U.S. Dollars, Except Per Common Share Amounts)	2020		2019		2020		2019
INCOME
Operating Revenues:
Utility and Energy Marketing Revenues	$	139,661	$	151,312	$	650,320	$	781,059
Exploration and Production and Other Revenues	132,338		159,864		456,073		470,267
Pipeline and Storage and Gathering Revenues	51,020		46,024		151,908		148,665
	323,019		357,200		1,258,301		1,399,991

Operating Expenses:
Purchased Gas	29,121		47,839		239,663		381,537
Operation and Maintenance:
Utility and Energy Marketing	43,950		39,607		138,931		132,082
Exploration and Production and Other	32,404		35,674		109,056		108,610
Pipeline and Storage and Gathering	24,298		28,675		77,488		80,857
Property, Franchise and Other Taxes	21,381		21,506		67,268		68,046
Depreciation, Depletion and Amortization	73,232		71,072		226,062		200,990
Impairment of Oil and Gas Producing Properties	18,236		—		195,997		—
	242,622		244,373		1,054,465		972,122
Operating Income	80,397		112,827		203,836		427,869
Other Income (Expense):

Other Income (Deductions)	2,547		(1,456)		(17,971)		(16,977)
Interest Expense on Long-Term Debt	(27,140)		(25,303)		(77,853)		(76,016)
Other Interest Expense	(1,420)		(1,202)		(4,863)		(4,061)
Income Before Income Taxes	54,384		84,866		103,149		330,815
Income Tax Expense	13,134		21,113		81,376		73,806

Net Income Available for Common Stock	41,250		63,753		21,773		257,009

EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	1,176,870		1,236,657		1,272,601		1,098,900
	1,218,120		1,300,410		1,294,374		1,355,909

Dividends on Common Stock	(40,470)		(37,543)		(115,774)		(110,885)
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
Balance at June 30	$	1,177,650	$	1,262,867	$	1,177,650	$	1,262,867

Earnings Per Common Share:
Basic:
Net Income Available for Common Stock	$	0.47	$	0.74	$	0.25	$	2.98
Diluted:
Net Income Available for Common Stock	$	0.47	$	0.73	$	0.25	$	2.96
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	87,966,289		86,306,434		86,966,448		86,208,766
Used in Diluted Calculation	88,323,699		86,839,841		87,346,362		86,765,781
Dividends Per Common Share:
Dividends Declared	$	0.445	$	0.435	$	1.315	$	1.285

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)


	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands of U.S. Dollars)	2020		2019		2020		2019
Net Income Available for Common Stock	$	41,250	$	63,753	$	21,773	$	257,009
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	4,904		34,211		81,703		53,619
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	(36,347)		(3,869)		(68,733)		20,498
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	(31,443)		30,342		14,283		62,379
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	1,341		9,835		22,315		15,434
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	(9,907)		(1,113)		(18,756)		5,756
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
Income Taxes – Net	(8,566)		8,722		3,922		27,295
Other Comprehensive Income (Loss)	(22,877)		21,620		10,361		35,084
Comprehensive Income	$	18,373	$	85,373	$	32,134	$	292,093

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	June 30, 2020		September 30, 2019
(Thousands of U.S. Dollars)
ASSETS
Property, Plant and Equipment	$	11,710,155	$	11,204,838
Less - Accumulated Depreciation, Depletion and Amortization	6,088,803		5,695,328
	5,621,352		5,509,510
Current Assets
Cash and Temporary Cash Investments	556,264		20,428
Hedging Collateral Deposits	7,699		6,832
Receivables – Net of Allowance for Uncollectible Accounts of $26,462 and $25,778, Respectively	136,438		139,956
Unbilled Revenue	17,903		18,758
Gas Stored Underground	14,356		36,632
Materials and Supplies - at average cost	51,396		40,717
Unrecovered Purchased Gas Costs	—		2,246
Other Current Assets	47,652		97,054
	831,708		362,623

Other Assets
Recoverable Future Taxes	116,758		115,197
Unamortized Debt Expense	12,724		14,005
Other Regulatory Assets	160,294		167,320
Deferred Charges	87,956		33,843
Other Investments	144,584		144,917
Goodwill	5,476		5,476
Prepaid Post-Retirement Benefit Costs	75,235		60,517
Fair Value of Derivative Financial Instruments	62,817		48,669
Other	81		80
	665,925		590,024

Total Assets	$	7,118,985	$	6,462,157

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	June 30, 2020		September 30, 2019
(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 – 90,943,652 Shares and 86,315,287 Shares, Respectively	$	90,944	$	86,315
Paid in Capital	999,057		832,264
Earnings Reinvested in the Business	1,177,650		1,272,601
Accumulated Other Comprehensive Loss	(41,794)		(52,155)
Total Comprehensive Shareholders’ Equity	2,225,857		2,139,025
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,628,782		2,133,718
Total Capitalization	4,854,639		4,272,743

Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	—		55,200
Current Portion of Long-Term Debt	—		—
Accounts Payable	94,123		132,208
Amounts Payable to Customers	18,772		4,017
Dividends Payable	40,470		37,547
Interest Payable on Long-Term Debt	31,600		18,508
Customer Advances	561		13,044
Customer Security Deposits	15,226		16,210
Other Accruals and Current Liabilities	138,344		139,600
Fair Value of Derivative Financial Instruments	3,264		5,574
	342,360		421,908

Deferred Credits
Deferred Income Taxes	783,377		653,382
Taxes Refundable to Customers	357,945		366,503

Cost of Removal Regulatory Liability	227,043		221,699
Other Regulatory Liabilities	160,501		142,367
Pension and Other Post-Retirement Liabilities	127,237		133,729
Asset Retirement Obligations	128,666		127,458
Other Deferred Credits	137,217		122,368
	1,921,986		1,767,506
Commitments and Contingencies (Note 8)	—		—

Total Capitalization and Liabilities	$	7,118,985	$	6,462,157

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)


	Nine Months Ended June 30,
(Thousands of U.S. Dollars)	2020		2019
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	21,773	$	257,009
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Impairment of Oil and Gas Producing Properties	195,997		—
Depreciation, Depletion and Amortization	226,062		200,990
Deferred Income Taxes	116,332		111,123

Stock-Based Compensation	9,716		16,144
Other	5,645		7,964
Change in:
Receivables and Unbilled Revenue	4,045		(31,584)
Gas Stored Underground and Materials and Supplies	11,597		17,551
Unrecovered Purchased Gas Costs	2,246		4,204
Other Current Assets	49,312		11,972
Accounts Payable	(13,166)		(16,132)
Amounts Payable to Customers	14,755		11,152
Customer Advances	(12,483)		(13,443)
Customer Security Deposits	(984)		(8,902)
Other Accruals and Current Liabilities	6,774		36,040
Other Assets	(18,215)		(34,594)
Other Liabilities	4,464		1,061
Net Cash Provided by Operating Activities	623,870		570,555

INVESTING ACTIVITIES
Capital Expenditures	(551,004)		(587,442)

Acquisition of Upstream Assets and Midstream Gathering Assets	(27,050)		—
Other	4,126		(3,071)
Net Cash Used in Investing Activities	(573,928)		(590,513)

FINANCING ACTIVITIES
Changes in Notes Payable to Banks and Commercial Paper	(55,200)		—

Net Proceeds from Issuance of Long-Term Debt	493,108		—

Dividends Paid on Common Stock	(112,851)		(109,875)
Net Proceeds from Issuance (Repurchases) of Common Stock	161,704		(8,864)
Net Cash Provided by (Used in) Financing Activities	486,761		(118,739)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	536,703		(138,697)
Cash, Cash Equivalents, and Restricted Cash at October 1	27,260		233,047
Cash, Cash Equivalents, and Restricted Cash at June 30	$	563,963	$	94,350

Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$	58,134	$	79,425

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, 2019, 2018 and 2017 that are included in the Company's 2019 Form 10-K. The consolidated financial statements for the year ended September 30, 2020 will be audited by the Company's independent registered public accounting firm after the end of the fiscal year.

The earnings for the nine months ended June 30, 2020 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2020. Most of the business of both the Utility segment and the Company's NFR operations (included in the All Other category) is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility segment and in the Company's NFR operations, earnings during the winter months normally represent a substantial part of the earnings that those businesses are expected to achieve for the entire fiscal year. The Company’s business segments are discussed more fully in Note 9 — Business Segment Information.

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


	Nine Months Ended June 30, 2020						Nine Months Ended June 30, 2019
	Balance at October 1, 2019		Balance at June 30, 2020		Balance at October 1, 2018		Balance at June 30, 2019

Cash and Temporary Cash Investments	$	20,428	$	556,264	$	229,606	$	87,515
Hedging Collateral Deposits	6,832		7,699		3,441		6,835
Cash, Cash Equivalents, and Restricted Cash	$	27,260	$	563,963	$	233,047	$	94,350

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

Allowance for Uncollectible Accounts. The allowance for uncollectible accounts is the Company’s best estimate of the amount of probable credit losses in the existing accounts receivable. The allowance is determined based on historical experience, the age of customer accounts, other specific information about customer accounts, and the economic environment. Account balances are charged off against the allowance twelve months after the account is final billed or when it is anticipated that the receivable will not be recovered. As a result of the COVID-19 pandemic, governments in the Company’s service territories initially mandated the shut-down of a significant number of businesses, leaving many individuals out of work. While government mandated shut downs have slowly been lifted over the last few months, unemployment levels remain high and many businesses have not seen their business activity return to pre-pandemic levels. The financial strains on businesses and

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individuals resulting from the COVID-19 pandemic could have a significant impact on their ability to pay their bills. In addition, in its service territories, the Company has suspended collection and termination activity for non-payments in response to the COVID-19 pandemic. The combination of the current economic conditions and providing service to customers who otherwise would have been terminated could lead to a significant increase in uncollectible expense for customer receivables, primarily within the Utility segment. While the combination of the current low cost of natural gas service and the steps taken by the federal government to alleviate the financial burden on companies and individuals should act as an offset to the overall economic situation, the Company is anticipating that there will be some level of increase in uncollectible expense depending on the extent and duration of the COVID-19 pandemic. 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 $10.6 million at June 30, 2020, is reduced to zero by September 30 of each year as the inventory is replenished.

Property, Plant and Equipment. In the Company’s Exploration and Production segment, oil and gas property acquisition, exploration and development costs are capitalized under the full cost method of accounting. Under this methodology, all costs associated with property acquisition, exploration and development activities are capitalized, including internal costs directly identified with acquisition, exploration and development activities. The internal costs that are capitalized do not include any costs related to production, general corporate overhead, or similar activities. The Company does not recognize any gain or loss on the sale or other disposition of oil and gas properties unless the gain or loss would significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to a cost center. The Company's capitalized costs relating to oil and gas producing activities, net of accumulated depreciation, depletion and amortization, were $1.6 billion and $1.7 billion at June 30, 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 $81.2 million and $53.5 million at June 30, 2020 and September 30, 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 settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. The book value of the oil and gas properties exceeded the ceiling at June 30, 2020 as well as March 31, 2020. As such, the Company recognized pre-tax impairment charges of $18.2 million and $196.0 million for the quarter and nine months ended June 30, 2020, respectively. Deferred income tax benefits of $5.0 million and $53.5 million related to the impairment charges were also recognized for the quarter and nine months ended June 30, 2020, respectively. In adjusting estimated future cash flows for hedging under the ceiling test at June 30, 2020 and March 31, 2020, estimated future net cash flows were increased by $125.6 million and $32.7 million, respectively.

The principal assets of the Utility, Pipeline and Storage and Gathering segments, consisting primarily of gas plant in service, are recorded at the historical cost when originally devoted to service. As a result of the COVID-19 pandemic, governments in the Company’s service territories initially mandated the shut-down of a significant number of businesses, leaving many individuals out of work. While government mandated shut downs have slowly been lifted over the last few months, unemployment levels remain high and many businesses have not seen their business activity return to pre-pandemic levels. It is possible that the extent and duration of this COVID-19 pandemic could reduce projected cash flows associated with the use of these assets, which could in turn lead to a decrease in fair value and result in a potential impairment of the recorded

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value of such assets. While there were no indications of any conditions that could result in impairments at June 30, 2020, management will continue to monitor the situation on a quarterly basis.

Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss and changes for the nine months ended June 30, 2020 and 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 June 30, 2020
Balance at April 1, 2020	$	67,913	$	—	$	(86,830)	$	(18,917)
Other Comprehensive Gains and Losses Before Reclassifications	3,563		—		—		3,563
Amounts Reclassified From Other Comprehensive Income (Loss)	(26,440)		—		—		(26,440)

Balance at June 30, 2020	$	45,036	$	—	$	(86,830)	$	(41,794)
Nine Months Ended June 30, 2020
Balance at October 1, 2019	$	34,675	$	—	$	(86,830)	$	(52,155)
Other Comprehensive Gains and Losses Before Reclassifications	59,388		—		—		59,388
Amounts Reclassified From Other Comprehensive Income (Loss)	(49,977)		—		—		(49,977)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	950		—		—		950
Balance at June 30, 2020	$	45,036	$	—	$	(86,830)	$	(41,794)
Three Months Ended June 30, 2019
Balance at April 1, 2019	$	4,562	$	—	$	(58,848)	$	(54,286)
Other Comprehensive Gains and Losses Before Reclassifications	24,376		—		—		24,376
Amounts Reclassified From Other Comprehensive Income (Loss)	(2,756)		—		—		(2,756)

Balance at June 30, 2019	$	26,182	$	—	$	(58,848)	$	(32,666)
Nine Months Ended June 30, 2019
Balance at October 1, 2018	$	(28,611)	$	7,437	$	(46,576)	$	(67,750)
Other Comprehensive Gains and Losses Before Reclassifications	38,185		—		—		38,185
Amounts Reclassified From Other Comprehensive Income (Loss)	14,742		—		—		14,742
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 June 30, 2019	$	26,182	$	—	$	(58,848)	$	(32,666)

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.

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In January 2016, the FASB issued authoritative guidance regarding the recognition and measurement of financial assets and liabilities. The authoritative guidance primarily affects the accounting for equity investments and the presentation and disclosure requirements for financial instruments. All equity investments in unconsolidated entities will be measured at fair value through earnings rather than through accumulated other comprehensive income. The Company adopted this authoritative guidance effective October 1, 2018 and, as called for by the modified retrospective method of adoption, recorded a cumulative effect adjustment during the quarter ended December 31, 2018 to increase retained earnings by $7.4 million and decrease accumulated other comprehensive income by the same amount.

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

Reclassifications Out of Accumulated Other Comprehensive Loss. The details about the reclassification adjustments out of accumulated other comprehensive loss for the three and nine months ended June 30, 2020 and 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
		Three Months Ended June 30,						Nine Months Ended June 30,
		2020		2019		2020		2019
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts	$36,726		$4,091		$67,663		($18,692)		Operating Revenues
Commodity Contracts	(22)		—		1,890		(1,182)		Purchased Gas
Foreign Currency Contracts	(357)		(222)		(820)		(624)		Operating Revenues
	36,347		3,869		68,733		(20,498)		Total Before Income Tax
	(9,907)		(1,113)		(18,756)		5,756		Income Tax Expense
	$26,440		$2,756		$49,977		($14,742)		Net of Tax

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


	At June 30, 2020		At September 30, 2019

Prepayments	$	14,289	$	12,728
Prepaid Property and Other Taxes	11,684		14,361
Federal Income Taxes Receivable	—		42,388
State Income Taxes Receivable	3,106		8,579
Fair Values of Firm Commitments	4,384		7,538
Regulatory Assets	14,189		11,460
	$	47,652	$	97,054

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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 June 30, 2020		At September 30, 2019

Accrued Capital Expenditures	$	35,645	$	33,713
Regulatory Liabilities	42,598		50,332
Reserve for Gas Replacement	10,622		—
Liability for Royalty and Working Interests	12,061		18,057
Federal Income Taxes Payable	159		—



Non-Qualified Benefit Plan Liability	13,194		13,194
Other	24,065		24,304
	$	138,344	$	139,600

Earnings Per Common Share. Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company had outstanding were SARs, restricted stock units and performance shares. For the quarter and nine months ended June 30, 2020, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 513,428 securities and 513,180 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2020, respectively. There were 120,546 securities and 122,327 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2019, respectively.

Stock-Based Compensation. The Company granted 254,608 performance shares during the nine months ended June 30, 2020. The weighted average fair value of such performance shares was $43.32 per share for the nine months ended June 30, 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 nine months ended June 30, 2020 must meet a performance goal related to relative return on capital over a three-year performance cycle. The performance goal over the performance cycle is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”). Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database. The number of these performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value of these performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award. The other half of the performance shares granted during the nine months ended June 30, 2020 must meet a performance goal related to relative total shareholder return over a three-year performance cycle. The performance goal over the performance cycle is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group. Three-year total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these total shareholder return performance shares ("TSR performance shares") that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value price at the date of grant for the TSR performance shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the present value of forgone dividends over the vesting term of the award. This price is multiplied by the number of TSR performance shares awarded, the result of which is recorded as compensation expense over the vesting term of the award.

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The Company granted 150,839 nonperformance-based restricted stock units during the nine months ended June 30, 2020. The weighted average fair value of such nonperformance-based restricted stock units was $40.38 per share for the nine months ended June 30, 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 nonperformance-based restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for nonperformance-based restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units must be reduced by the present value of forgone dividends over the vesting term of the award.

Note 2 – Revenue from Contracts with Customers

The Company adopted authoritative guidance regarding revenue 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 to the previous guidance. The Company records revenue related to its derivative financial instruments in the Exploration and Production segment as well as in its NFR operations (included in the All Other category). The Company also records revenue related to alternative revenue programs in its Utility segment. Revenue related to derivative financial instruments and alternative revenue programs are excluded from the scope of the new authoritative guidance since they are accounted for under other existing accounting guidance.

The following tables provide a disaggregation of the Company's revenues for the quarter and nine months ended June 30, 2020 and 2019, presented by type of service from each reportable segment. As reported in the Company's 2019 Form 10-K, the Company's NFR operations were previously reported as the Energy Marketing segment, however the Company is no longer reporting the energy marketing operations as a separate reportable segment. Prior year disaggregation of revenue information shown below has been restated to reflect this change in presentation.


Quarter Ended June 30, 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	$	76,831	$	—	$	—	$	—	$	—	$	—	$	76,831
Production of Crude Oil	17,018		—		—		—		—		—		17,018
Natural Gas Processing	435		—		—		—		—		—		435
Natural Gas Gathering Services	—		—		33,299		—		—		(33,299)		—
Natural Gas Transportation Service	—		57,563		—		22,473		—		(20,445)		59,591
Natural Gas Storage Service	—		20,016		—		—		—		(8,802)		11,214
Natural Gas Residential Sales	—		—		—		93,853		—		—		93,853
Natural Gas Commercial Sales	—		—		—		10,264		—		—		10,264
Natural Gas Industrial Sales	—		—		—		616		—		—		616
Natural Gas Marketing	—		—		—		—		19,149		(341)		18,808
Other	218		234		—		(661)		1,015		(98)		708
Total Revenues from Contracts with Customers	94,502		77,813		33,299		126,545		20,164		(62,985)		289,338
Alternative Revenue Programs	—		—		—		492		—		—		492
Derivative Financial Instruments	36,726		—		—		—		(3,537)		—		33,189
Total Revenues	$	131,228	$	77,813	$	33,299	$	127,037	$	16,627	$	(62,985)	$	323,019

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Nine Months Ended June 30, 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	$	297,481	$	—	$	—	$	—	$	—	$	—	$	297,481
Production of Crude Oil	84,949		—		—		—		—		—		84,949
Natural Gas Processing	1,838		—		—		—		—		—		1,838
Natural Gas Gathering Services	—		—		103,355		—		—		(103,355)		—
Natural Gas Transportation Service	—		169,469		—		95,112		—		(59,408)		205,173
Natural Gas Storage Service	—		58,966		—		—		—		(25,881)		33,085
Natural Gas Residential Sales	—		—		—		423,547		—		—		423,547
Natural Gas Commercial Sales	—		—		—		56,401		—		—		56,401
Natural Gas Industrial Sales	—		—		—		3,029		—		—		3,029
Natural Gas Marketing	—		—		—		—		89,662		(598)		89,064
Other	797		843		—		(7,509)		2,985		(216)		(3,100)
Total Revenues from Contracts with Customers	385,065		229,278		103,355		570,580		92,647		(189,458)		1,191,467
Alternative Revenue Programs	—		—		—		7,775		—		—		7,775
Derivative Financial Instruments	67,663		—		—		—		(8,604)		—		59,059
Total Revenues	$	452,728	$	229,278	$	103,355	$	578,355	$	84,043	$	(189,458)	$	1,258,301


Quarter Ended June 30, 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	$	113,975	$	—	$	—	$	—	$	—	$	—	$	113,975
Production of Crude Oil	38,823		—		—		—		—		—		38,823
Natural Gas Processing	731		—		—		—		—		—		731
Natural Gas Gathering Services	—		—		32,875		—		—		(32,875)		—
Natural Gas Transportation Service	—		50,001		—		23,010		—		(17,672)		55,339
Natural Gas Storage Service	—		18,598		—		—		—		(8,060)		10,538
Natural Gas Residential Sales	—		—		—		96,146		—		—		96,146
Natural Gas Commercial Sales	—		—		—		12,107		—		—		12,107
Natural Gas Industrial Sales	—		—		—		1,032		—		—		1,032
Natural Gas Marketing	—		—		—		—		22,212		(681)		21,531
Other	152		368		—		161		859		(20)		1,520
Total Revenues from Contracts with Customers	153,681		68,967		32,875		132,456		23,071		(59,308)		351,742
Alternative Revenue Programs	—		—		—		465		—		—		465
Derivative Financial Instruments	5,194		—		—		—		(201)		—		4,993
Total Revenues	$	158,875	$	68,967	$	32,875	$	132,921	$	22,870	$	(59,308)	$	357,200

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Nine Months Ended June 30, 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	$	371,710	$	—	$	—	$	—	$	—	$	—	$	371,710
Production of Crude Oil	111,256		—		—		—		—		—		111,256
Natural Gas Processing	2,676		—		—		—		—		—		2,676
Natural Gas Gathering Services	—		—		91,931		—		—		(91,931)		—
Natural Gas Transportation Service	—		158,376		—		103,723		—		(54,556)		207,543
Natural Gas Storage Service	—		56,887		—		—		—		(24,367)		32,520
Natural Gas Residential Sales	—		—		—		492,267		—		—		492,267
Natural Gas Commercial Sales	—		—		—		68,408		—		—		68,408
Natural Gas Industrial Sales	—		—		—		4,400		—		—		4,400
Natural Gas Marketing	—		—		—		—		130,015		(1,056)		128,959
Other	1,028		3,112		2		(8,662)		2,185		(529)		(2,864)
Total Revenues from Contracts with Customers	486,670		218,375		91,933		660,136		132,200		(172,439)		1,416,875
Alternative Revenue Programs	—		—		—		(1,528)		—		—		(1,528)
Derivative Financial Instruments	(18,817)		—		—		—		3,461		—		(15,356)
Total Revenues	$	467,853	$	218,375	$	91,933	$	658,608	$	135,661	$	(172,439)	$	1,399,991

The Company’s Pipeline and Storage segment expects to recognize the following revenue amounts in future periods related to “fixed” charges associated with remaining performance obligations for transportation and storage contracts: $47.0 million for the remainder of fiscal 2020; $175.3 million for fiscal 2021; $143.3 million for fiscal 2022; $98.2 million for fiscal 2023; $86.4 million for fiscal 2024; and $361.5 million thereafter.

Note 3 – Leases

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

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 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.

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Nature of Leases

The Company primarily leases building space and drilling rigs, and on a limited basis compressor equipment and other miscellaneous assets. The Company determines if an arrangement is a lease at the inception of the arrangement. To the extent that an arrangement represents a lease, the Company classifies that lease as an operating or a finance lease in accordance with the authoritative guidance. As of June 30, 2020, the Company did not have any material finance leases. Aside from a sublease of office space at the Company’s corporate headquarters, the Company does not have any material arrangements where the Company is the lessor.

Buildings and Property

The Company enters into building and property rental agreements with third parties for office space, certain field locations and other properties used in the Company’s operations. Building and property leases include the Company’s corporate headquarters in Williamsville, New York, and Exploration and Production segment offices in Houston, Texas, and Pittsburgh, Pennsylvania. The primary non-cancelable terms of the Company’s building and property leases range from two 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 October 2020. 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 rig basis depending on market and operating conditions present at the time the contract expires, including prices for natural gas and oil.

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

Significant Judgments

Lease Identification

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

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.

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Firm Transportation and Storage Contracts

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

Oil and Gas Leases

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

Amounts Recognized in the Financial Statements

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


	Three Months Ended June 30, 2020		Nine Months Ended June 30, 2020

Operating Lease Expense	$	956	$	2,872
Variable Lease Expense⁽¹⁾	108		380
Short-Term Lease Expense⁽²⁾	46		186
Sublease Income	(41)		(202)
Total Lease Expense	$	1,069	$	3,236

Short-Term Lease Costs Recorded to Property, Plant and Equipment⁽³⁾	$	3,174	$	17,463

⁽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 a leasing arrangement based on the present value of lease payments over the lease term. As of June 30, 2020, the weighted average remaining lease term was 8.5 years and the weighted average discount rate was 3.53%.

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

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


	At June 30, 2020
Assets:
Deferred Charges	$	17,504

Liabilities:
Other Accruals and Current Liabilities	$	3,116
Other Deferred Credits	$	14,298

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For the nine months ended June 30, 2020, cash paid for operating liabilities, and reported in cash flows provided by operating activities on the Company’s Consolidated Statement of Cash Flows, was $3.2 million. During the nine months ended June 30, 2020, the Company did not record any right-of-use assets in exchange for new lease liabilities.

The following schedule of operating lease liability maturities summarizes the undiscounted lease payments owed by the Company to lessors pursuant to contractual agreements in effect as of June 30, 2020 (in thousands):


	At June 30, 2020

2020 (remaining 3 months)	$	843
2021	2,900
2022	2,278
2023	2,270
2024	2,237
Thereafter	9,717
Total Lease Payments	20,245
Less: Interest	(2,831)
Total Lease Liability	$	17,414

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


	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 4 – Fair Value Measurements

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

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The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of June 30, 2020 and September 30, 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 June 30, 2020
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾		Total⁽¹⁾
Assets:
Cash Equivalents – Money Market Mutual Funds	$	540,659	$	—	$	—	$	—	$	540,659
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	1,369		—		—		(1,369)		—
Over the Counter Swaps – Gas and Oil	—		83,401		—		(15,654)		67,747
Over the Counter No Cost Collars - Gas	—		249		—		(2,083)		(1,834)
Foreign Currency Contracts	—		107		—		(3,264)		(3,157)
Other Investments:
Balanced Equity Mutual Fund	37,291		—		—		—		37,291
Fixed Income Mutual Fund	64,840		—		—		—		64,840
Common Stock – Financial Services Industry	626		—		—		—		626

Hedging Collateral Deposits	7,699		—		—		—		7,699
Total	$	652,484	$	83,757	$	—	$	(22,370)	$	713,871

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	3,925	$	—	$	—	$	(1,369)	$	2,556
Over the Counter Swaps – Gas and Oil	—		16,270		—		(15,654)		616
Over the Counter No Cost Collars – Gas	—		2,083		—		(2,083)		—
Foreign Currency Contracts	—		3,319		—		(3,264)		55
Total	$	3,925	$	21,672	$	—	$	(22,370)	$	3,227

Total Net Assets/(Liabilities)	$	648,559	$	62,085	$	—	$	—	$	710,644


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

Hedging Collateral Deposits	6,832		—		—		—		6,832
Total	$	123,251	$	52,081	$	—	$	(5,590)	$	169,742

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

Total Net Assets/(Liabilities)	$	116,102	$	48,066	$	—	$	—	$	164,168

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

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Derivative Financial Instruments

At June 30, 2020 and September 30, 2019, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used by NFR (included in the All Other category). Hedging collateral deposits of $7.7 million (at June 30, 2020) and $6.8 million (at September 30, 2019), which were associated with these futures contracts, have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at June 30, 2020 and September 30, 2019 consist of natural gas price swap agreements used in the Company’s Exploration and Production segment and in its NFR operations, natural gas no cost collars used in the Company's Exploration and Production segment, crude oil price swap agreements used in the Company’s Exploration and Production segment, basis hedge swap agreements used by NFR and foreign currency contracts used in the Company's Exploration and Production segment. The fair value of the Level 2 price swap agreements and no cost collars is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates.

The 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 June 30, 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 June 30, 2020 and June 30, 2019, there were no assets or liabilities measured at fair value and classified as Level 3. For the quarters ended June 30, 2020 and June 30, 2019, no transfers in or out of Level 1 or Level 2 occurred.

Note 5 – Financial Instruments

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


	June 30, 2020						September 30, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,628,782	$	2,713,775	$	2,133,718	$	2,257,085

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 June 30, 2020		At September 30, 2019

Life Insurance Contracts	$	41,827	$	41,074
Equity Mutual Fund	37,291		40,660
Fixed Income Mutual Fund	64,840		62,339
Marketable Equity Securities	626		844
	$	144,584	$	144,917

Investments in life insurance contracts are stated at their cash surrender values or net present value. Investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (marketable equity securities) are stated at fair value based on quoted market prices with changes in fair value recognized in net income. The insurance contracts and marketable equity and fixed income securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.

Derivative Financial Instruments. The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment as well as by NFR (included in the All Other category). 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 7 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 June 30, 2020 and September 30, 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 gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Prior to October 1, 2019, gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness were recognized in current earnings rather than as a component of other comprehensive income (loss). During the quarter and nine months ended June 30, 2019, the Company recorded $1.0 million and $0.8 million, respectively, of hedging ineffectiveness gains 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 June 30, 2020, the Company had the following commodity derivative contracts (swaps, no cost collars and futures contracts) outstanding:


Commodity	Units
Natural Gas	245.7	Bcf (short positions)
Natural Gas	28.9	Bcf (long positions)
Crude Oil	1,734,000	Bbls (short positions)

As of June 30, 2020, the Company was hedging a total of $82.3 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions).

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As of June 30, 2020, the Company had $61.7 million ($45.0 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $49.4 million ($36.1 million after tax) of unrealized gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transactions are recorded in earnings.


The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended June 30, 2020 and 2019 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships	Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) for the Three Months Ended June 30,					Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income		Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Three Months Ended June 30,
	2020		2019			2020		2019
Commodity Contracts	$	3,273	$	33,531	Operating Revenue	$	36,726	$	4,091
Commodity Contracts	(427)		150		Purchased Gas	(22)		—
Foreign Currency Contracts	2,058		530		Operating Revenue	(357)		(222)
Total	$	4,904	$	34,211		$	36,347	$	3,869


The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Nine Months Ended June 30, 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 Nine Months Ended June 30,					Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income		Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income for the Nine Months Ended June 30,
	2020		2019			2020		2019
Commodity Contracts	$	82,825	$	56,356	Operating Revenue	$	67,663	$	(18,692)
Commodity Contracts	571		(1,183)		Purchased Gas	1,890		(1,182)
Foreign Currency Contracts	(1,693)		(1,554)		Operating Revenue	(820)		(624)
Total	$	81,703	$	53,619		$	68,733	$	(20,498)

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 June 30, 2020, NFR had fair value hedges covering approximately 21.2 Bcf on its fixed price sales commitments. For derivative instruments that are designated and qualify as a fair value hedge, the gain or loss on the derivative as well as the offsetting gain or loss on the hedged item attributable to the hedged risk completely offset each other in current earnings, as shown below.

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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 Nine Months Ended June 30, 2020 (In Thousands)		Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the Nine Months Ended June 30, 2020 (In Thousands)
Commodity Contracts	Operating Revenues	$	(8,528)	$	8,528
Commodity Contracts	Purchased Gas	$	(30)	$	30
		$	(8,558)	$	8,558

Credit Risk

The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions, no cost collars and applicable foreign currency forward contracts with fifteen counterparties of which fourteen are in a net gain position. On average, the Company had $4.4 million of credit exposure per counterparty in a gain position at June 30, 2020. The maximum credit exposure per counterparty in a gain position at June 30, 2020 was $11.6 million. As of June 30, 2020, no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral.

As of June 30, 2020, twelve of the fifteen 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 June 30, 2020, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $62.8 million according to the Company’s internal model (discussed in Note 4 — Fair Value Measurements). At June 30, 2020, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $0.6 million according to the Company's internal model. For its over-the-counter swap agreements and foreign currency forward contracts, no hedging collateral deposits were required to be posted by the Company at June 30, 2020.

For its exchange traded futures contracts, the Company was required to post $7.7 million in hedging collateral deposits as of June 30, 2020. As these are exchange traded futures contracts, there are no specific credit-risk related contingency features. The Company posts or receives hedging collateral based on open positions and margin requirements it has with its counterparties.

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

Note 6 – Income Taxes

The effective tax rates for the quarters ended June 30, 2020 and June 30, 2019 were 24.1% and 24.9%, respectively. The decrease in the tax rate for the quarter is mainly due to an increase in the allowance for funds used during construction

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(which is not taxable) as a result of certain ongoing projects in our Pipeline and Storage segment. The effective tax rates for the nine months ended June 30, 2020 and June 30, 2019 were 78.9% and 22.3%, respectively. The increase in the tax rate is primarily the result of the valuation allowance recorded against certain state deferred tax assets, discussed below, as well as the elimination of the Enhanced Oil Recovery tax credit in fiscal 2020.

A valuation allowance for deferred tax assets, including net operating losses and tax credits, is recognized when it is more likely than not that some or all of the benefit from the deferred tax assets will not be realized. Consistent with the prior quarter, as of June 30, 2020, the Company recorded a valuation allowance against certain state deferred tax assets in the amount of $57.7 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. 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.

Prior to the “Coronavirus Aid, Relief and Economic Security (CARES) Act" (discussed below), the 2017 Tax Reform Act repealed the corporate alternative minimum tax (AMT) and provided that the Company’s existing AMT credit carryovers were refundable, if not utilized to reduce tax, beginning in fiscal 2019. As of September 30, 2018, the Company had $85.0 million of AMT credit carryovers that were expected to be refunded between fiscal 2020 and fiscal 2023, if not previously utilized. The Company received the first installment for $42.5 million of AMT credit refunds related to fiscal 2019 in January 2020.

On March 27, 2020, the CARES Act was signed into law. The CARES Act, among other things, includes provisions relating to 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 filed for the acceleration of the remaining AMT credit refunds (under CARES) of $42.5 million, which were received in June 2020.

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Note 7 – Capitalization

Summary of Changes in Common Stock Equity


	Common Stock							Paid In Capital		Earnings Reinvested in the Business		Accumulated Other Comprehensive Income (Loss)
		Shares			Amount
	(Thousands, except per share amounts)
Balance at April 1, 2020	86,562		$	86,562		$	835,444	$	1,176,870	$	(18,917)
Net Income Available for Common Stock								41,250
Dividends Declared on Common Stock ($0.445 Per Share)								(40,470)

Other Comprehensive Loss, Net of Tax										(22,877)
Share-Based Payment Expense ⁽¹⁾						1,699
Common Stock Issued from Sale of Common Stock	4,370		4,370			161,488
Common Stock Issued Under Stock and Benefit Plans	12		12			426
Balance at June 30, 2020	90,944		$	90,944		$	999,057	$	1,177,650	$	(41,794)

Balance at October 1, 2019	86,315		$	86,315		$	832,264	$	1,272,601	$	(52,155)
Net Income Available for Common Stock								21,773
Dividends Declared on Common Stock ($1.315 Per Share)								(115,774)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging								(950)
Other Comprehensive Income, Net of Tax										10,361
Share-Based Payment Expense ⁽¹⁾						8,403
Common Stock Issued from Sale of Common Stock	4,370		4,370			161,488
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	259		259			(3,098)
Balance at June 30, 2020	90,944		$	90,944		$	999,057	$	1,177,650	$	(41,794)

Balance at April 1, 2019	86,301		$	86,301		$	821,837	$	1,236,657	$	(54,286)
Net Income Available for Common Stock								63,753
Dividends Declared on Common Stock ($0.435 Per Share)								(37,543)

Other Comprehensive Income, Net of Tax										21,620
Share-Based Payment Expense ⁽¹⁾						5,054
Common Stock Issued Under Stock and Benefit Plans	6		6			352
Balance at June 30, 2019	86,307		$	86,307		$	827,243	$	1,262,867	$	(32,666)

Balance at October 1, 2018	85,957		$	85,957		$	820,223	$	1,098,900	$	(67,750)
Net Income Available for Common Stock								257,009
Dividends Declared on Common Stock ($1.285 Per Share)								(110,885)
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										35,084
Share-Based Payment Expense ⁽¹⁾						15,008
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	350		350			(7,988)
Balance at June 30, 2019	86,307		$	86,307		$	827,243	$	1,262,867	$	(32,666)

⁽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. On June 2, 2020, the Company completed a public offering and sale of 4,370,000 shares of the Company's common stock, par value $1.00 per share, at a price of $39.50 per share. After deducting fees, commissions and other issuance costs, the net proceeds to the Company amounted to $165.9 million. The proceeds of this issuance were used to fund a portion of the purchase price of the acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from SWEPI LP, a subsidiary of Royal Dutch Shell plc (“Shell”) that closed on July 31, 2020. Refer to Note 12 – Subsequent Events for further discussion.

During the nine months ended June 30, 2020, the Company also issued 87,135 original issue shares of common stock for restricted stock units that vested and 231,246 original issue shares of common stock for performance shares that vested. The Company also issued 31,253 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 nine months ended June 30, 2020. Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes. During the nine months ended June 30, 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 of the Company's long-term debt as of June 30, 2020 and September 30, 2019 had a maturity date within the following twelve-month period.

Long-Term Debt. On June 3, 2020, the Company issued $500.0 million of 5.50% notes due January 15, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $493.1 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to a maximum adjustment of 2.00% such that the coupon will not exceed 7.5%, if there is a downgrade of the credit rating assigned to the notes (or if the credit rating assigned to the notes is subsequently upgraded). The proceeds of this debt issuance were used for general corporate purposes, which included the payment of a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020 and the repayment and refinancing of short-term debt.

Short-Term Borrowings. On May 4, 2020, the Company entered into a 364-Day credit facility with a syndicate of 10 banks, all of which are also lenders under the Company's existing $750.0 million multi-year credit facility. The 364-Day credit facility provides an additional $200.0 million unsecured revolving credit facility.

Note 8 – Commitments and Contingencies

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

At June 30, 2020, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $6.6 million, which includes a $3.5 million estimated minimum liability to remediate a former manufactured gas plant site located in New York. In March 2018, the NYDEC issued a Record of Decision for this New York site and the minimum liability reflects the remedy selected in the Record of Decision. The Company's liability for such clean-up costs has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at June 30, 2020. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 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.

Northern Access Project. On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access project described herein. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). The United States Court of Appeals for the Second Circuit (the “Second Circuit Court of Appeals”) held in the Company’s favor in its appeal of this decision, vacating the NYDEC denial and remanding to the NYDEC. The NYDEC subsequently issued a second denial, which the Company has appealed to the Second Circuit Court of Appeals. The court has held this appeal in abeyance pending the outcome of the FERC waiver appeal, described below. While the Company’s initial appeal was pending before the Second

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Circuit Court of Appeals, the FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order and FERC's decisions have been appealed and are pending in a separate action before the Second Circuit Court of Appeals. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project. In light of these pending legal actions and the need to complete necessary project development activities in advance of construction, the in-service date for the project is expected to be no earlier than fiscal 2022.

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

Note 9 – Business Segment Information

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

The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. As stated in the 2019 Form 10-K, the Company evaluates segment performance based on income before discontinued operations (when applicable). When this is not applicable, the Company evaluates performance based on net income. There have not been any changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s 2019 Form 10-K. A listing of segment assets at June 30, 2020 and September 30, 2019 is shown in the tables below.


Quarter Ended June 30, 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	$131,228	$51,020	$—	$124,390	$306,638	$16,286	$95	$323,019
Intersegment Revenues	$—	$26,793	$33,299	$2,647	$62,739	$341	$(63,080)	$—
Segment Profit: Net Income (Loss)	$(6,434)	$22,623	$15,239	$6,254	$37,682	$(9)	$3,577	$41,250


Nine Months Ended June 30, 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	$452,728	$151,908	$—	$569,856	$1,174,492	$83,445	$364	$1,258,301
Intersegment Revenues	$—	$77,370	$103,355	$8,499	$189,224	$598	$(189,822)	$—
Segment Profit: Net Income (Loss)	$(157,733)	$62,815	$51,081	$64,335	$20,498	$1,532	$(257)	$21,773

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(Thousands)	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Segment Assets:
At June 30, 2020	$1,886,791	$2,184,289	$706,760	$2,048,181	$6,826,021	$123,666	$169,298	$7,118,985
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 June 30, 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	$158,875	$46,024	$—	$129,977	$334,876	$22,189	$135	$357,200
Intersegment Revenues	$—	$22,943	$32,875	$2,944	$58,762	$681	$(59,443)	$—
Segment Profit: Net Income (Loss)	$26,512	$15,792	$14,638	$7,362	$64,304	$(1,444)	$893	$63,753


Nine Months Ended June 30, 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	$467,853	$148,663	$2	$648,624	$1,265,142	$134,605	$244	$1,399,991
Intersegment Revenues	$—	$69,712	$91,931	$9,984	$171,627	$1,056	$(172,683)	$—
Segment Profit: Net Income (Loss)	$86,599	$58,643	$41,511	$68,600	$255,353	$(946)	$2,602	$257,009

Note 10 – Retirement Plan and Other Post-Retirement Benefits

Components of Net Periodic Benefit Cost (in thousands):


	Retirement Plan						Other Post-Retirement Benefits
Three Months Ended June 30,	2020		2019		2020		2019

Service Cost	$	2,330	$	2,120	$	402	$	380
Interest Cost	7,483		9,594		3,228		4,286
Expected Return on Plan Assets	(15,016)		(15,591)		(7,308)		(7,539)
Amortization of Prior Service Cost (Credit)	182		206		(107)		(107)

Amortization of Losses	9,846		8,024		134		1,490
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾	604		(113)		6,036		3,757

Net Periodic Benefit Cost	$	5,429	$	4,240	$	2,385	$	2,267

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	Retirement Plan						Other Post-Retirement Benefits
Nine Months Ended June 30,	2020		2019		2020		2019

Service Cost	$	6,989	$	6,362	$	1,206	$	1,140
Interest Cost	22,448		28,783		9,685		12,858
Expected Return on Plan Assets	(45,048)		(46,775)		(21,924)		(22,618)
Amortization of Prior Service Cost (Credit)	547		619		(322)		(321)

Amortization of Losses	29,538		24,072		401		4,471
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾	7,651		5,490		21,131		14,294

Net Periodic Benefit Cost	$	22,125	$	18,551	$	10,177	$	9,824

⁽¹⁾The Company’s policy is to record retirement plan and other post-retirement benefit costs in the Utility segment on a volumetric basis to reflect the fact that the Utility segment experiences higher throughput of natural gas in the winter months and lower throughput of natural gas in the summer months.

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

Employer Contributions. During the nine months ended June 30, 2020, the Company contributed $23.5 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $2.7 million to its VEBA trusts for its other post-retirement benefits. In the remainder of 2020, the Company expects its contributions to the Retirement Plan to be in the range of $1.0 million to $6.0 million. In the remainder of 2020, the Company expects to contribute approximately $0.2 million to its VEBA trusts.

While the market turbulence resulting from the COVID-19 pandemic has had a negative impact on the funded status of the Retirement Plan and VEBA trusts, near-term funding requirements have not changed. The Company will continue to monitor the performance of its Retirement Plan and VEBA trusts during the COVID-19 pandemic to determine if funding requirements will need to increase during the remainder of 2020.

Note 11 – Regulatory Matters

New York Jurisdiction

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

In New York, on March 13, 2020, the Company agreed to NYPSC Staff’s request that the Company suspend service terminations and disconnections. Thereafter, on June 17, 2020, New York enacted a new law that prohibits utilities from terminating or disconnecting services to any residential customer for non-payment for the duration of the state disaster emergency. In addition, the law prohibits residential terminations for nonpayment for a period of 180 days running from the end of the state disaster emergency for customers that have experienced a change in financial circumstances due to the COVID-19 state of emergency. The duration of these aforementioned suspensions in New York and their related impact on the Company is uncertain. The Company is anticipating that there will be some level of deterioration in the collectability of customer receivable balances depending on the depth and duration of the COVID-19 pandemic. It is uncertain at this point as to whether there would be any regulatory relief for utilities with regard to an increase in costs associated with the COVID-19 pandemic, but it is one of many issues currently being considered in a generic NYPSC proceeding entitled “Proceeding on Motion of the Commission Regarding the Effects of COVID-19 on Utility Service” (Case No. 20-M-0266).

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.

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On March 26, 2020, the PaPUC ratified an Emergency Order that established a Service Termination Moratorium intended to continue during the pendency of Governor Wolf’s March 6, 2020 Proclamation of Disaster Emergency associated with the COVID-19 pandemic. The duration of this moratorium in Pennsylvania and its related impacts on the Company are uncertain. On May 13, 2020, the Company (and other Pennsylvania local distribution companies) received a Secretarial Letter from the PaPUC regarding COVID-19 pandemic cost tracking and regulatory assets. The Secretarial Letter directs utilities to track “extraordinary, nonrecurring incremental COVID-19 related expenses” so the Commission can understand the impact of these expenses on the utilities’ finances. It also authorizes the creation of a utility regulatory asset, but only for incremental uncollectible expenses incurred above those embedded in rates (and incurred since the issuance of the Emergency Order). The Company continues to monitor this item for potential deferral opportunity.

FERC Jurisdiction

Supply Corporation filed a Section 4 rate case on July 31, 2019 proposing rate increases to be effective September 1, 2019. On February 4, 2020, Supply Corporation and the parties in the case reached a settlement in principle (the Settlement) to resolve the rate case. Supply Corporation’s subsequent motion to put in place Interim Settlement Rates effective February 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. An order approving the Settlement as filed was issued on June 1, 2020. The 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 May 1, 2025. Empire has no rate case currently on file.

Note 12 – Subsequent Events

On July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from SWEPI LP, a subsidiary of Royal Dutch Shell plc (“Shell”) for total consideration of $503.9 million, including a down payment of $27.1 million paid at the signing of the purchase and sale agreement in May 2020. The purchase price reflects an effective date of January 1, 2020. The acquisition was financed with a combination of debt and equity, as discussed above in Note 7 — Capitalization. As part of the transaction, the Company acquired over 400,000 net acres in Appalachia, with approximately 200,000 net acres in Tioga County. The net proved developed natural gas reserves associated with this acquisition are estimated to be approximately 700 Bcf. In addition, the Company acquired gathering pipelines and related compression, water pipelines, and associated water handling infrastructure, all of which currently support Shell’s Tioga County production operations. These gathering facilities are interconnected with various interstate pipelines, including the Company’s Empire pipeline systems, with the potential to tie into the Company’s existing Covington gathering system. Given the contiguous nature of the assets, the Company expects to fully integrate the assets into its existing operations in Tioga County, Pennsylvania. This will drive operating cost synergies in both the Exploration and Production and Gathering segments.

The Company also completed the sale of NFR's commercial and industrial gas contracts in New York and Pennsylvania and certain other assets to Marathon Power LLC on August 1, 2020. The sale did not have a material impact to the Company's financial statements. The divestiture reflects the Company's decision to focus on other strategic areas of the energy market.

On August 5, 2020, the Company entered into a purchase and sale agreement to sell certain timber and other assets in Pennsylvania to Lyme Emporium Highlands III LLC and Lyme Allegheny Land Company II LLC for approximately $115.7 million, subject to closing adjustments. The transaction is expected to close on or before November 1, 2020. The Company intends to use the proceeds from this sale to complete the permanent financing of the acquisition of upstream assets and midstream gathering assets from Shell, which is discussed above.

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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 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 four business segments. For a 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. While most operational employees have returned to work, a significant number of employees from the Company’s headquarters and other administrative offices are still 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 COVID-19 pandemic will determine how significant the additional costs associated with combating the COVID-19 pandemic will be. In addition to measures to protect its 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 its supply chains, contractor work, counterparties and customer service functions and has had no material issues occur to date. The length of the COVID-19 pandemic 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. A significant number of commercial and industrial customers were forced to shut down operations based on government mandates starting in March 2020. While government mandated shut downs have slowly been lifted over the last few months, the COVID-19 pandemic has not ended and many businesses have not seen their business activity return to pre-pandemic levels. This has resulted in lower demand for natural gas and oil, which in turn has depressed prices for those commodities, exacerbating a pricing trend that had started before the COVID-19 pandemic began. Lower prices have contributed to lower revenues in the Company’s Exploration and Production segment. While the Company’s Pipeline and Storage segment has not been significantly impacted by the COVID-19 pandemic at this point, it is possible that future transportation and storage service revenues could be impacted if customers reduce or eliminate their contractual commitments for such services. In the Company’s Utility segment, 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. While no discernible impact has been experienced to date, the Company is increasing its allowance for uncollectible accounts given the current economic environment and the expectation that there will be some level of increase in customer nonpayment, depending, once again, on the depth and duration of the COVID-19 pandemic.

One of the steps taken by the federal government to help companies during the COVID-19 pandemic 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 filed for the acceleration of the remaining AMT credit refunds (under CARES) of $42.5 million, which were received in June 2020. The Company continues to evaluate other elements of the CARES Act for potential adoption by the Company.

As discussed above, the current COVID-19 pandemic has exacerbated the low natural gas and oil price environment that existed before the pandemic began. The Company uses the full cost method of accounting for determining the book value of its oil and natural gas properties in the Exploration and Production segment and that book value is subject to a quarterly ceiling test. This is discussed in more detail in the Critical Accounting Estimates section that follows. The Company recorded cumulative impairment charges under the ceiling test during the nine months ended June 30, 2020 of $196.0 million ($142.5

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million after-tax), including an impairment charge of $18.2 million ($13.2 million after-tax) during the quarter ended June 30, 2020. It is anticipated that the current low commodity price environment will lead to a significant impairment during the quarter ended September 30, 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 subsequently moved to a single-rig development program in June 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, partially driven by the Company’s recent acquisition of flowing net production described below.

While the current low commodity price environment has had a negative impact on the Company’s earnings and drilling plans, it has also created a favorable environment to buy natural gas assets. On July 31, 2020, the Company completed its acquisition of certain upstream assets and midstream gathering assets in Pennsylvania from SWEPI LP, a subsidiary of Royal Dutch Shell plc (“Shell”) for total consideration of $503.9 million, including a down payment of $27.1 million paid at the signing of the purchase and sale agreement in May 2020. The purchase price reflects an effective date of January 1, 2020. The acquisition was financed with a combination of debt and equity, as discussed in the paragraphs that follow. As part of the transaction, the Company acquired over 400,000 net acres in Appalachia, with approximately 200,000 net acres in Tioga County. The net proved developed natural gas reserves associated with this acquisition are estimated to be approximately 700 Bcf. In addition, the Company acquired gathering pipelines and related compression, water pipelines, and associated water handling infrastructure, all of which currently support Shell’s Tioga County production operations. These gathering facilities are interconnected with various interstate pipelines, including the Company’s Empire pipeline systems, with the potential to tie into the Company’s existing Covington gathering system. Given the contiguous nature of the assets, the Company expects to fully integrate the assets into its existing operations in Tioga County, Pennsylvania. This will drive operating cost synergies in both the Exploration and Production and Gathering segments.

In June 2020, the Company issued $500.0 million of 5.50% notes due January 15, 2026. The proceeds of the debt issuance were used for general corporate purposes, which included the payment of a portion of the purchase price of the acquisition of Shell’s upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020 and the repayment and refinancing of short-term debt. In June 2020, the Company also completed a public offering and sale of 4,370,000 shares of the Company’s common stock, par value $1.00 per share, at a price of $39.50 per share. The proceeds from this issuance were used to fund a portion of the purchase price of the aforementioned acquisition of Shell’s upstream assets and midstream gathering assets in Pennsylvania.

In May 2020, the Company entered into a 364-Day credit facility with a syndicate of 10 banks, all of which are also lenders under the Company’s existing $750.0 million multi-year credit facility. The 364-Day credit facility provides an additional $200.0 million unsecured committed revolving credit facility.

The common stock issuance and the long-term debt issuance discussed above, combined with cash from operations and short-term borrowings, are expected to meet the Company’s financing needs for the remainder of fiscal 2020. Completion of the sale of timber properties before September 30, 2020 would reduce any short-term borrowings drawn during the fourth quarter of fiscal 2020.

The Company continues to pursue development projects to expand its Pipeline and Storage segment. The Company is monitoring the impacts of the COVID-19 pandemic on its supply chains and development projects in this segment. To date, the COVID-19 pandemic has not had a material impact on the target in-service dates of these development projects. However, the unpredictable extent and duration of the outbreak, 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,

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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. In July 2020, Empire placed the Jackson compressor station in service to begin partial, interim service. The remaining Empire North facilities have a projected in-service date late in the fourth quarter of fiscal 2020 and an estimated cost of approximately $135 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.

From a rate perspective, Supply Corporation filed a Section 4 rate case on July 31, 2019. The new rates became effective on February 1, 2020 under a proposed settlement, and the settlement was approved on June 1, 2020. This increased earnings in the quarter and nine months ended June 30, 2020 by $5.5 million and $9.4 million, respectively. For further discussion of Supply Corporation's rate matters, refer to the Rate and Regulatory Matters section below.

From a legislation perspective, in July 2019, New York State enacted legislation known as the Climate Leadership & Community Protection Act (CLCPA). This climate legislation mandates reducing greenhouse gas emissions to 60% of 1990 levels by 2030, and to 15% of 1990 levels by 2050, with the remaining emission reduction achieved by controlled offsets. The legislation also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% by 2040. In the near-term, the CLCPA establishes a climate action council and a series of advisory panels and working groups to study how the state will achieve the aggressive emission reduction targets.

CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 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, the Company is required to perform a quarterly ceiling test. Under the ceiling test, the present value of future revenues from the Company's oil and gas reserves based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period (the “ceiling”) is compared with the book value of the Company’s oil and gas properties at the balance sheet date. The present value of future revenues is calculated using a 10% discount factor. If the book value of the oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling. The book value of the oil and gas properties exceeded the ceiling at March 31, 2020 and June 30, 2020, resulting in cumulative impairment charges of $196.0 million ($142.5 million after-tax) for the nine months ended June 30, 2020. The impairment charge for the quarter ended June 30, 2020 was $18.2 million ($13.2 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 June 30, 2020, based on posted Midway Sunset prices, was $48.47 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 June 30, 2020, based on the quoted Henry Hub spot price for natural gas, was $2.07 per MMBtu. (Note: Because actual pricing of the Company’s producing properties vary depending on their location and hedging, the prices used to calculate the ceiling may differ from the Midway Sunset and Henry Hub prices, which are only indicative of 12-month average prices for the twelve months ended June 30, 2020. Actual realized pricing includes adjustments for regional market differentials, transportation fees and contractual arrangements.) The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the additional impairment that the Company would have recorded at June 30, 2020 if natural gas prices were $0.25 per MMBtu lower than the average prices used at June 30, 2020, the additional impairment that the Company would have recorded at June 30, 2020 if crude oil prices were $5 per Bbl lower than the average prices used at June 30, 2020, and the additional impairment that the Company would have recorded at June 30, 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 June 30, 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.

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Ceiling Testing Sensitivity to Commodity Price Changes
(Millions)	$0.25/MMBtu Decrease in Natural Gas Prices		$5.00/Bbl Decrease in Crude Oil Prices		$0.25/MMBtu Decrease in Natural Gas Prices and $5.00/Bbl Decrease in Crude Oil Prices
Calculated Impairment under Sensitivity Analysis	$	221.4	$	52.8	$	260.9
Actual Impairment Recorded at June 30, 2020	13.2		13.2		13.2
Additional Impairment	$	208.2	$	39.6	$	247.7

Looking ahead, the first day of the month Midway Sunset prices for crude oil in July 2020 and August 2020 were $37.84 per Bbl and $38.12 per Bbl, respectively. The first day of the month Henry Hub spot prices for natural gas in July 2020 and August 2020 were $1.69 per MMBtu and $1.75 per MMBtu, respectively. Given these July and August 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 September 30, 2020, the Company expects to experience a significant ceiling test impairment in the quarter ended September 30, 2020, and likely in the first quarter of fiscal 2021 as well. For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's 2019 Form 10-K.

RESULTS OF OPERATIONS

Earnings

The Company's earnings were $41.3 million for the quarter ended June 30, 2020 compared to earnings of $63.8 million for the quarter ended June 30, 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 also contributed to the decrease. Higher earnings in the Pipeline and Storage segment, Gathering segment and Corporate category, as well as a lower loss in the All Other category, partially offset these decreases.

The Company's earnings were $21.8 million for the nine months ended June 30, 2020 compared to earnings of $257.0 million for the nine months ended June 30, 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, as well as 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's earnings for the quarter and nine months ended June 30, 2020 included non-cash impairment charges of $18.2 million ($13.2 million after-tax) and $196.0 million ($142.5 million after tax), respectively, recorded during the quarter and nine months ended June 30, 2020 for the Exploration and Production segment's oil and gas producing properties, as discussed above. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.

Earnings (Loss) by Segment


	Three Months Ended June 30,										Nine Months Ended June 30,
(Thousands)	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
Exploration and Production	$	(6,434)	$	26,512	$	(32,946)	$	(157,733)	$	86,599	$	(244,332)
Pipeline and Storage	22,623		15,792		6,831		62,815		58,643		4,172
Gathering	15,239		14,638		601		51,081		41,511		9,570
Utility	6,254		7,362		(1,108)		64,335		68,600		(4,265)
Total Reportable Segments	37,682		64,304		(26,622)		20,498		255,353		(234,855)
All Other	(9)		(1,444)		1,435		1,532		(946)		2,478
Corporate	3,577		893		2,684		(257)		2,602		(2,859)
Total Consolidated	$	41,250	$	63,753	$	(22,503)	$	21,773	$	257,009	$	(235,236)

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Exploration and Production

Exploration and Production Operating Revenues


	Three Months Ended June 30,										Nine Months Ended June 30,
(Thousands)	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
Gas (after Hedging)	$	100,951	$	120,735	$	(19,784)	$	347,327	$	357,447	$	(10,120)
Oil (after Hedging)	29,624		36,238		(6,614)		102,766		105,921		(3,155)
Gas Processing Plant	435		731		(296)		1,838		2,676		(838)
Other	218		1,171		(953)		797		1,809		(1,012)
	$	131,228	$	158,875	$	(27,647)	$	452,728	$	467,853	$	(15,125)

Production Volumes


	Three Months Ended June 30,					Nine Months Ended June 30,
	2020	2019	Increase (Decrease)	2020	2019	Increase (Decrease)
Gas Production (MMcf)
Appalachia	52,043	50,766	1,277	161,965	140,954	21,011
West Coast	468	494	(26)	1,434	1,483	(49)
Total Production	52,511	51,260	1,251	163,399	142,437	20,962

Oil Production (Mbbl)
Appalachia	—	1	(1)	2	2	—
West Coast	584	575	9	1,790	1,710	80
Total Production	584	576	8	1,792	1,712	80

Average Prices


	Three Months Ended June 30,										Nine Months Ended June 30,
	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
Average Gas Price/Mcf
Appalachia	$	1.45	$	2.21	$	(0.76)	$	1.80	$	2.58	$	(0.78)
West Coast	$	2.58	$	3.84	$	(1.26)	$	3.98	$	5.55	$	(1.57)
Weighted Average	$	1.46	$	2.22	$	(0.76)	$	1.82	$	2.61	$	(0.79)
Weighted Average After Hedging	$	1.92	$	2.36	$	(0.44)	$	2.13	$	2.51	$	(0.38)

Average Oil Price/Bbl
Appalachia	$	27.50	$	55.45	$	(27.95)	$	50.28	$	55.80	$	(5.52)
West Coast	$	29.13	$	67.43	$	(38.30)	$	47.40	$	65.01	$	(17.61)
Weighted Average	$	29.12	$	67.41	$	(38.29)	$	47.41	$	65.00	$	(17.59)
Weighted Average After Hedging	$	50.70	$	62.92	$	(12.22)	$	57.35	$	61.88	$	(4.53)

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2020 Compared with 2019

Operating revenues for the Exploration and Production segment decreased $27.6 million for the quarter ended June 30, 2020 as compared with the quarter ended June 30, 2019. Gas production revenue after hedging decreased $19.8 million due to a $0.44 per Mcf decrease in the weighted average price of gas after hedging, which was partially offset by the impact of a 1.3 Bcf increase in gas production. The increase in gas production, despite 7.3 Bcf of price-related curtailments, was largely due to new Marcellus and Utica wells in the Western and Eastern Development Area in the Appalachian region included in the quarter ended June 30, 2020 as compared with the quarter ended June 30, 2019. Oil production revenue after hedging decreased $6.6 million due to a $12.22 per Bbl decrease in the weighted average price of oil after hedging, which was partially offset by the impact of an 8 Mbbl increase in oil production. The increase in oil production was largely due to higher production in the West Coast region. In addition, other revenue decreased $1.0 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 decreased $15.1 million for the nine months ended June 30, 2020 as compared with the nine months ended June 30, 2019. Gas production revenue after hedging decreased $10.1 million due to a $0.38 per Mcf decrease in the weighted average price of gas after hedging, which was partially offset by the impact of a 21.0 Bcf increase in gas production. The increase in gas production, despite 10.4 Bcf of price-related curtailments, 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 nine months ended June 30, 2020 as compared with the nine months ended June 30, 2019. Oil production revenue after hedging decreased $3.2 million due to a $4.53 per Bbl decrease in the weighted average price of oil after hedging, which was partially offset by the impact of an 80 Mbbl increase in oil production. The increase in oil production was largely due to higher production in the West Coast region. Other revenue decreased $1.0 million primarily due to mark-to-market adjustments related to hedge ineffectiveness on oil hedges recorded in the prior year. In addition, gas processing plant revenue decreased $0.8 million.

The Exploration and Production segment's loss for the quarter ended June 30, 2020 was $6.4 million, a decrease of $32.9 million when compared with earnings of $26.5 million for the quarter ended June 30, 2019. The loss can be attributed to an impairment of oil and gas properties ($13.2 million), lower natural gas prices after hedging ($18.0 million) and lower oil prices after hedging ($5.6 million). These decreases in earnings were partially offset by higher natural gas production ($2.3 million), higher oil production ($0.4 million), the impact of mark-to-market adjustments related to oil hedge ineffectiveness recorded in the prior year quarter ($0.8 million), a decrease in depletion expense ($0.5 million) and a decrease in lease operating and transportation expenses ($1.2 million). Depletion expense decreased due largely to the ceiling test impairment recorded in the second quarter, partially offset by higher production. The decrease in lease operating and transportation expenses was primarily due to lower well repair and workover costs and steam fuel costs in California, partially offset by higher transportation costs in Appalachia.

The Exploration and Production segment's loss for the nine months ended June 30, 2020 was $157.7 million, a decrease of $244.3 million when compared with earnings of $86.6 million for the nine months ended June 30, 2019. The loss was primarily attributable to impairments of oil and gas properties ($142.5 million), a deferred tax valuation allowance established during the quarter ended March 31, 2020, as discussed more completely in Item 1 at Note 6 — Income Taxes ($60.5 million), lower natural gas prices after hedging ($49.6 million), lower oil prices after hedging ($6.4 million), higher lease operating and transportation expenses ($9.9 million), higher depletion expense ($14.2 million), a higher effective tax rate ($3.1 million) and the impact of a remeasurement of the segment's accumulated deferred income taxes in the prior year that did not recur in fiscal 2020 ($1.0 million). The increase in lease operating and transportation expenses was primarily the result of increased gathering and transportation costs in the Appalachian region due to increased production. The increase in depletion expense was due largely to higher production, partially offset by the ceiling test impairment recorded in the second quarter. 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 decreases in earnings were partially offset by higher natural gas production ($41.6 million) and higher oil production ($3.9 million).

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Pipeline and Storage

Pipeline and Storage Operating Revenues


	Three Months Ended June 30,										Nine Months Ended June 30,
(Thousands)	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
Firm Transportation	$	57,346	$	49,744	$	7,602	$	168,777	$	157,322	$	11,455
Interruptible Transportation	217		257		(40)		692		1,054		(362)
	57,563		50,001		7,562		169,469		158,376		11,093
Firm Storage Service	19,999		18,597		1,402		58,942		56,884		2,058
Interruptible Storage Service	17		1		16		24		3		21
Other	234		368		(134)		843		3,112		(2,269)
	$	77,813	$	68,967	$	8,846	$	229,278	$	218,375	$	10,903

Pipeline and Storage Throughput


	Three Months Ended June 30,					Nine Months Ended June 30,
(MMcf)	2020	2019	Increase (Decrease)	2020	2019	Increase (Decrease)
Firm Transportation	172,579	158,739	13,840	577,025	550,262	26,763
Interruptible Transportation	757	309	448	2,002	1,974	28
	173,336	159,048	14,288	579,027	552,236	26,791

2020 Compared with 2019

Operating revenues for the Pipeline and Storage segment increased $8.8 million for the quarter ended June 30, 2020 as compared with the quarter ended June 30, 2019. The increase in operating revenues was primarily due to an increase in transportation revenues of $7.6 million and an increase in storage revenues of $1.4 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. The settlement was approved by the FERC on June 1, 2020. New demand charges for transportation service from Supply Corporation's Line N to Monaca Project, which was placed in service on November 1, 2019, also contributed to the increase in transportation revenues. The increases in transportation and storage revenues were partially offset by a decrease in greenhouse gas surcharge revenue due to a greenhouse gas surcharge terminating on February 1, 2020.

Operating revenues for the Pipeline and Storage segment increased $10.9 million for the nine months ended June 30, 2020 as compared with the nine months ended June 30, 2019. The increase in operating revenues was primarily due to an increase in transportation revenues of $11.1 million combined with an increase in storage revenues of $2.1 million, partially offset by a decrease in other revenues of $2.3 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 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 was partially offset by a decrease in storage revenues from a decline in demand charges from Supply Corporation’s storage service as a result of the termination of a temporary contract and higher discounts on storage service. 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 June 30, 2020 increased by 14.3 Bcf from the prior year's quarter, primarily a reflection of an increase in capacity utilization by certain contract shippers, as well as an increase in volume from weather that was colder than the prior year. For the nine months ended June 30, 2020, transportation volume increased by 26.8 Bcf from the prior year's nine-month period ended June 30, 2019. The increase in transportation volume for the nine-month

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period primarily reflects an increase in 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.

The Pipeline and Storage segment’s earnings for the quarter ended June 30, 2020 were $22.6 million, an increase of $6.8 million when compared with earnings of $15.8 million for the quarter ended June 30, 2019. The increase in earnings was primarily due to the earnings impact of higher operating revenues of $7.0 million, as discussed above, combined with a decrease in operating expenses ($3.8 million). The decrease in operating expenses primarily reflects lower pipeline integrity costs, lower compressor and facility maintenance costs and a decrease in personnel expense. These earnings increases were partially offset by an increase in depreciation expense ($2.5 million), a decrease in other income ($0.7 million) and higher interest expense ($0.4 million). The increase in depreciation expense was primarily due to an increase in Supply Corporation's depreciation rates associated with its rate case settlement mentioned above. The decrease in other income was mainly due to higher non-service pension and post-retirement benefit costs in the current quarter compared to non-service pension and post-retirement income in the quarter ended June 30, 2019, partially offset by an increase in allowance for funds used during construction (equity component) related to the construction of the Empire North Project. The increase in interest expense was primarily due to interest on additional intercompany long-term borrowings associated with the Company's June 2020 unsecured debt issuance.

The Pipeline and Storage segment’s earnings for the nine months ended June 30, 2020 were $62.8 million, an increase of $4.2 million when compared with earnings of $58.6 million for the nine months ended June 30, 2019. The increase in earnings was primarily due to the earnings impact of higher operating revenues of $8.6 million, as discussed above, combined with a decrease in operating expenses ($5.1 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. These earnings increases were partially offset by an increase in depreciation expense ($4.5 million), higher income tax expense ($2.4 million), an increase in property taxes ($1.6 million), as well as a decrease in other income ($1.6 million). The increase in depreciation expense was due to an increase in Supply Corporation's depreciation rates associated with its rate case settlement. Income tax expense was higher due to permanent differences related to stock compensation activity. The increase in property taxes was due to the scheduled phase-out of tax incentives in certain jurisdictions along the Empire system, as well as higher town, county and school taxes due to an increase in assessed values from new projects placed in service. The decrease in other income was primarily due to higher non-service pension and post-retirement benefit costs in the current nine-month period compared to non-service pension and post-retirement income in the nine months ended June 30, 2019, partially offset by an increase in allowance for funds used during construction (equity component) related to the construction of the Empire North Project.

Gathering

Gathering Operating Revenues


	Three Months Ended June 30,										Nine Months Ended June 30,
(Thousands)	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
Gathering Revenues	$	33,299	$	32,875	$	424	$	103,355	$	91,931	$	11,424
Processing and Other Revenues	—		—		—		—		2		(2)
	$	33,299	$	32,875	$	424	$	103,355	$	91,933	$	11,422

Gathering Volume


	Three Months Ended June 30,					Nine Months Ended June 30,
	2020	2019	Increase (Decrease)	2020	2019	Increase (Decrease)
Gathered Volume - (MMcf)	61,338	60,745	593	190,864	169,590	21,274

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2020 Compared with 2019

Operating revenues for the Gathering segment increased $0.4 million for the quarter ended June 30, 2020 as compared with the quarter ended June 30, 2019. The increase was primarily due to a 0.6 Bcf net increase in gathered volume resulting from a 2.2 Bcf and 2.7 Bcf increase in volume on Midstream Company's Trout Run and Clermont gathering systems, respectively, offset by a 3.2 Bcf and 1.1 Bcf decline in volume on its Wellsboro and Covington gathering systems. The net increase in gathered volume can be attributed to the increase in Seneca's gross natural gas production in the Appalachian region, which increased despite price-related curtailments initiated by Seneca, as discussed above.

Operating revenues for the Gathering segment increased $11.4 million for the nine months ended June 30, 2020 as compared with the nine months ended June 30, 2019. This increase was primarily due to a 21.3 Bcf net increase in gathered volume resulting from a 12.8 Bcf, 10.5 Bcf and 1.8 Bcf increase in gathered volume on its Trout Run, Clermont and Wellsboro gathering systems, respectively. These increases were partially offset by a 3.8 Bcf decrease in gathered volume on the Covington gathering system. The 21.3 Bcf net increase in gathered volume can be attributed to the net increase in Seneca's natural gas production, which increased despite price-related curtailments initiated by Seneca, for the nine months ended June 30, 2020 compared to the nine months ended June 30, 2019.

The Gathering segment’s earnings for the quarter ended June 30, 2020 were $15.2 million, an increase of $0.6 million when compared with earnings of $14.6 million for the quarter ended June 30, 2019. The increase in earnings was mainly due to lower income tax expense ($0.6 million) and the impact of higher gathering revenues discussed above ($0.3 million). The increase to earnings was partially offset by higher operating expenses ($0.3 million). The increase in operating expenses was due largely to increased preventative maintenance and overhaul activities at Trout Run compressor stations during the quarter ended June 30, 2020.

The Gathering segment’s earnings for the nine months ended June 30, 2020 were $51.1 million, an increase of $9.6 million when compared with earnings of $41.5 million for the nine months ended June 30, 2019. The increase in earnings was mainly due to the impact of higher gathering revenues discussed above ($9.0 million) and lower income tax expense ($0.4 million). Additionally, the 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 during the quarter ended March 31, 2020 as an offset to the valuation allowance established in the Exploration and Production segment. This offset is a result of the Gathering and Exploration and Production segments’ subsidiaries filing a combined state tax return. 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 earnings increases were partially offset by higher operating expenses ($2.4 million), higher depreciation expense ($0.6 million) and the impact of a nonrecurring income tax benefit recorded in the prior year 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 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.

Utility

Utility Operating Revenues


	Three Months Ended June 30,										Nine Months Ended June 30,
(Thousands)	2020		2019		Increase (Decrease)		2020		2019		Increase (Decrease)
Retail Sales Revenues:
Residential	$	93,329	$	96,297	$	(2,968)	$	426,877	$	489,691	$	(62,814)
Commercial	10,577		11,892		(1,315)		56,450		67,315		(10,865)
Industrial	616		1,024		(408)		3,045		4,384		(1,339)
	104,522		109,213		(4,691)		486,372		561,390		(75,018)
Transportation	23,176		23,547		(371)		99,492		105,880		(6,388)

Other	(661)		161		(822)		(7,509)		(8,662)		1,153
	$	127,037	$	132,921	$	(5,884)	$	578,355	$	658,608	$	(80,253)

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Utility Throughput


	Three Months Ended June 30,					Nine Months Ended June 30,
(MMcf)	2020	2019	Increase (Decrease)	2020	2019	Increase (Decrease)
Retail Sales:
Residential	11,312	9,895	1,417	56,943	60,581	(3,638)
Commercial	1,450	1,441	9	8,295	8,999	(704)
Industrial	106	151	(45)	506	639	(133)
	12,868	11,487	1,381	65,744	70,219	(4,475)
Transportation	13,520	14,716	(1,196)	59,233	65,914	(6,681)

	26,388	26,203	185	124,977	136,133	(11,156)

Degree Days


Three Months Ended June 30,				Percent Colder (Warmer) Than
		Normal	2020	2019		Normal⁽¹⁾		Prior Year⁽¹⁾
Buffalo, NY	912	1,032	957	13.2	%	7.8	%
Erie, PA	871	920	773	5.6	%	19.0	%
Nine Months Ended June 30,
Buffalo, NY	6,491	6,002	6,654	(7.5)	%	(9.8)	%
Erie, PA	6,057	5,381	5,899	(11.2)	%	(8.8)	%

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

2020 Compared with 2019

Operating revenues for the Utility segment decreased $5.9 million for the quarter ended June 30, 2020 as compared with the quarter ended June 30, 2019. The decrease primarily resulted from a $4.7 million decrease in retail gas sales revenue, a $0.4 million decrease in transportation revenues and a $0.8 million decrease in other revenues. The reduction in retail gas sales revenue was largely due to a decrease in the cost of gas sold (per Mcf). The decline in transportation revenues was primarily due to a 1.2 Bcf decrease in transportation throughput and the migration of residential transportation customers to retail. The decrease in other income was largely due to a favorable adjustment related to the estimated refund provision recorded during the nine months ended June 30, 2019 for the current income tax benefits resulting from the 2017 Tax Reform Act.

Operating revenues for the Utility segment decreased $80.3 million for the nine months ended June 30, 2020 as compared with the nine months ended June 30, 2019. The decrease largely resulted from a $75.0 million decrease in retail gas sales revenue and a $6.4 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 6.7 Bcf decrease in throughput due to warmer weather and the migration of residential transportation customers to retail. These decreases were partially offset by a $1.2 million increase in other revenues. The increase in other revenues was largely due to a favorable adjustment related to the estimated refund provision recorded during the nine months ended June 30, 2019 for the current income tax benefits resulting from the 2017 Tax Reform Act ($0.9 million).

The Utility segment’s earnings for the quarter ended June 30, 2020 were $6.3 million, a decrease of $1.1 million when compared with earnings of $7.4 million for the quarter ended June 30, 2019. The decrease in earnings was largely attributable to higher operating expenses ($3.6 million), which were a result of higher personnel costs, an increase to the allowance for uncollectible accounts, and the impact of regulatory true-up adjustments ($0.7 million). The increase in personnel costs can largely be attributed to the Company’s response to the COVID-19 pandemic as governmental pandemic restrictions forced the Company to reduce capital expenditure related activities and increase operating expense activities. The increase to the allowance for uncollectible accounts is also related to the COVID-19 pandemic as the Company recorded incremental expense due to the potential for future customer non-payment given the current economic environment. These decreases were slightly

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offset by the positive earnings impact related to a system modernization tracker in New York ($0.7 million), the impact of higher usage and weather on customer margins ($1.2 million), higher other income ($0.8 million), largely due to unrealized gains on trust investments, and lower income tax expense ($0.3 million).

The impact of weather variations on earnings in the Utility segment's New York rate jurisdiction is mitigated by that jurisdiction's weather normalization clause (WNC). The WNC in New York, which covers the eight-month period from October through May, has had a stabilizing effect on earnings for the New York rate jurisdiction. In addition, the periods of colder than normal weather, the WNC benefits the Utility segment's New York customers. For the quarter ended June 30, 2020, the WNC decreased earnings by approximately $0.1 million, as the weather was colder than normal. For the quarter ended June 30, 2019, the WNC decreased earnings by approximately $0.2 million, as the weather was colder than normal.

The Utility segment’s earnings for the nine months ended June 30, 2020 were $64.3 million, a decrease of $4.3 million when compared with earnings of $68.6 million for the nine months ended June 30, 2019. The decrease in earnings was largely attributable to the impacts of lower usage and weather on customer margins ($2.5 million) and higher operating expenses ($6.3 million), which were a result of higher personnel costs and an increase to the allowance for uncollectible accounts, both of which are discussed above, and higher depreciation expense ($0.8 million). The increase in depreciation expense is a reflection of an increase in property, plant and equipment balances year over year. These decreases were slightly offset by the positive earnings impact related to the system modernization tracker ($2.9 million), the impact of regulatory true-up adjustments ($0.8 million), a favorable impact associated with higher other income and lower other deductions ($0.7 million), largely due to higher interest income on regulatory deferrals and lower non-service pension costs, and lower interest expense ($0.9 million). The decrease in interest expense reflects lower short-term borrowings, lower interest costs on long-term borrowings and lower interest costs on customer deposits.

For the nine months ended June 30, 2020, the WNC increased earnings by approximately $3.5 million, as the weather was warmer than normal. For the nine months ended June 30, 2019, the WNC decreased earnings by approximately $1.0 million, as the weather was colder than normal.

Corporate and All Other

2020 Compared with 2019

Corporate and All Other operations had earnings of $3.6 million for the quarter ended June 30, 2020, an increase of $4.2 million when compared with a loss of $0.6 million for the quarter ended June 30, 2019. The increase in earnings was primarily attributable to the change in unrealized gains on investments in equity securities recorded during the quarter ended June 30, 2020, compared to the quarter ended June 30, 2019 ($3.3 million), the impact of higher energy marketing margins ($1.6 million), lower depreciation and depletion expense ($0.3 million) and lower other income ($0.3 million). These positive drivers of earnings were partially offset by the impact of higher interest expense ($1.2 million) largely due to short-term borrowings from the Company's committed credit facility and uncommitted lines of credit during the current year third quarter and higher income tax expense ($0.4 million).

For the nine months ended June 30, 2020, Corporate and All Other operations had earnings of $1.3 million, a decrease of $0.4 million when compared with earnings of $1.7 million for the nine months ended June 30, 2019. The decrease in earnings was primarily attributable to the impact of the prior year remeasurement of deferred income taxes under the 2017 Tax Reform Act that lowered income tax expense for the nine months ended June 30, 2019 ($3.5 million), coupled with higher interest expense ($1.9 million) largely due short-term borrowings from the Company's committed credit facility and uncommitted lines of credit during the current year and higher income tax expense ($0.7 million). These negative drivers of earnings were partially offset by the impact of higher energy marketing margins ($2.5 million), higher other income ($1.3 million) that was driven largely by an increase in realized gains on investments in equity securities sold in the current year, lower operating expenses ($0.8 million), lower depreciation and depletion expense ($0.4 million) and lower unrealized losses on investments in equity securities recorded during the nine months ended June 30, 2020 ($0.2 million).

Interest Expense on Long-Term Debt

Interest on long-term debt increased $1.8 million for both the quarter and nine months ended June 30, 2020, as compared to the quarter and nine months ended June 30, 2019 due in large part to the issuance of $500 million of $5.50% notes on June 3, 2020.

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CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary sources of cash during the nine-month period ended June 30, 2020 consisted of cash provided by operating activities and net proceeds from long-term borrowings and issuance of common stock. The Company's primary source of cash during the nine-month period ended June 30, 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 in the Company's NFR operations (included in the All Other category), revenues in these 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 $623.9 million for the nine months ended June 30, 2020, an increase of $53.3 million compared with $570.6 million provided by operating activities for the nine months ended June 30, 2019. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Exploration and Production segment. The increase in the Exploration and Production segment was primarily due to the impact of the 2017 Tax Reform Act that repealed the corporate alternative minimum tax and provided that the Company's existing AMT credit carryovers were refundable, if not utilized to reduce tax. Installments of AMT credit refunds were received in January 2020 and June 2020. The AMT credit refund received in June 2020 was an accelerated recovery provided by the federal government under the CARES Act. The receipt of the AMT credit refunds more than offset lower cash receipts from natural gas and oil production.

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Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $528.0 million during the nine months ended June 30, 2020 and $578.1 million during the nine months ended June 30, 2019. The table below presents these expenditures:


Total Expenditures for Long-Lived Assets
Nine Months Ended June 30,	2020			2019			Increase (Decrease)
(Millions)
Exploration and Production:
Capital Expenditures	$	295.0	(1)	$	391.7	(2)	$	(96.7)
Pipeline and Storage:
Capital Expenditures	124.1		(1)	88.1		(2)	36.0
Gathering:
Capital Expenditures	46.2		(1)	39.4		(2)	6.8
Utility:
Capital Expenditures	62.2		(1)	58.4		(2)	3.8
All Other:
Capital Expenditures	0.5			0.5			—

	$	528.0		$	578.1		$	(50.1)

(1)At June 30, 2020, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $26.5 million, $16.4 million, $6.5 million and $8.7 million, respectively, of non-cash capital expenditures. At September 30, 2019, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $38.0 million, $23.8 million, $6.6 million and $12.7 million, respectively, of non-cash capital expenditures.

(2)At June 30, 2019, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $51.0 million, $14.0 million, $8.3 million and $6.1 million, respectively, of non-cash capital expenditures. At September 30, 2018, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $51.3 million, $21.9 million, $6.1 million and $9.5 million, respectively, of non-cash capital expenditures.

Exploration and Production

The Exploration and Production segment capital expenditures for the nine months ended June 30, 2020 were primarily well drilling and completion expenditures and included approximately $270.1 million for the Appalachian region (including $93.8 million in the Marcellus Shale area and $166.9 million in the Utica Shale area) and $24.9 million for the West Coast region. These amounts included approximately $186.9 million spent to develop proved undeveloped reserves.

The Exploration and Production segment capital expenditures for the nine months ended June 30, 2019 were primarily well drilling and completion expenditures and included approximately $365.6 million for the Appalachian region (including $141.9 million in the Marcellus Shale area and $210.2 million in the Utica Shale area) and $26.1 million for the West Coast region. These amounts included approximately $210.6 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2020 were primarily for expenditures related to Empire's Empire North Project ($59.5 million), and also included expenditures related to Supply Corporation's Line N to Monaca Project ($3.8 million) and Supply Corporation's FM100 Project ($2.9 million). These projects are discussed below. In addition, the Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2020 included additions, improvements and replacements to this segment’s transmission and gas storage systems. The Pipeline and Storage capital expenditures for the nine months ended June 30, 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 nine months ended June 30, 2019 included expenditures related to Empire's Empire North Project ($11.5 million) and Supply Corporation's Line N to Monaca Project ($10.5 million).

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

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

Supply Corporation completed a project to provide incremental natural gas transportation services from Line N to the ethane cracker facility being constructed by Shell Chemical Appalachia, LLC in Potter Township, Pennsylvania ("Line N to Monaca Project"), with transportation service beginning on November 1, 2019. This project involved construction of a 4.5 mile pipeline extension from Line N to the facility and has resulted in Supply Corporation securing incremental firm transportation capacity commitments totaling 133,000 Dth per day on Line N and on the pipeline extension to the facility. Supply Corporation was authorized to pursue the project by FERC under its blanket certificate as of May 30, 2018. As of June 30, 2020, approximately $22.5 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 June 30, 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. On July 11, 2020, Empire placed the Jackson Compressor Station in service to begin partial, interim service. The remaining Empire North facilities have a projected in-service date late in the fourth quarter of fiscal 2020 and an estimated capital cost of approximately $135 million. As of June 30, 2020, approximately $104.9 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. FERC issued the Section 7(c) certificate on July 17, 2020. The FM100 Project has a target in-service date in late calendar 2021 and a preliminary cost estimate of approximately $280 million. As of June 30, 2020, approximately $9.6 million has been spent on the FM100 Project, including $6.5 million spent to study the project that is included in Deferred Charges on the Consolidated Balance Sheet. The remaining $3.1 million spent on the project has been capitalized as Construction Work in Progress.

Supply Corporation and Empire have developed a project which would move significant prospective Marcellus production from Seneca's Western Development Area at Clermont to an Empire interconnection with TransCanada Pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York (the “Northern Access project”). The Northern Access project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. On February 3, 2017, the Company received FERC approval of the project. Shortly thereafter, the NYDEC issued a Notice of Denial of the federal Clean Water Act Section 401 Water Quality Certification and other state stream and wetland permits for the New York portion of the project (the Water Quality Certification for the Pennsylvania portion of the project was received in January of 2017). The United States Court of Appeals for the Second Circuit (the “Second Circuit Court of Appeals”) held in the Company’s favor in its appeal of this decision, vacating the NYDEC denial and remanding to the NYDEC. The NYDEC subsequently issued a second denial, which the Company has appealed to the Second Circuit Court of Appeals. The court has held this appeal in

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abeyance pending the outcome of the FERC waiver appeal, described below. While the Company’s initial appeal was pending before the Second Circuit Court of Appeals, the FERC issued an Order finding that the NYDEC exceeded the statutory time frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. FERC denied rehearing requests associated with its Order, and FERC's decisions have been appealed and are pending in a separate action before the Second Circuit Court of Appeals. In addition, in the Company's state court litigation challenging the NYDEC's actions with regard to various state permits, the New York State Supreme Court issued a decision finding these permits to be preempted. The Company remains committed to the project. In light of these pending legal actions and the need to complete necessary project development activities in advance of construction, the in-service date for the project is expected to be no earlier than fiscal 2022. The Company will update the $500 million preliminary cost estimate when there is further clarity on that date. As of June 30, 2020, approximately $58.4 million has been spent on the Northern Access project, including $23.8 million that has been spent to study the project, for which no reserve has been established. The remaining $34.6 million spent on the project has been capitalized as Construction Work in Progress.

Gathering

The majority of the Gathering segment capital expenditures for the nine months ended June 30, 2020 were for the continued expansion of Midstream Company’s Trout Run, Clermont, and Wellsboro gathering systems, as discussed below. Midstream Company spent $24.5 million, $11.9 million and $9.5 million, respectively, during the nine months ended June 30, 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 and a new metering and regulation station 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 nine months ended June 30, 2019 were for the continued expansion of the Trout Run, Clermont and Wellsboro gathering systems. Midstream Company spent $19.4 million, $8.2 million and $10.1 million, respectively, during the nine months ended June 30, 2019 on the development of the Trout Run, Clermont and Wellsboro gathering systems.

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

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

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

Utility

The majority of the Utility segment capital expenditures for the nine months ended June 30, 2020 and June 30, 2019 were made for main and service line improvements and replacements, as well as main extensions.

Other Investing Activity

In May 2020, the Company signed a purchase and sale agreement with Shell for the acquisition of certain upstream assets and midstream gathering assets located primarily in Pennsylvania and paid a down payment of $27.1 million. The Exploration and Production segment contributed $15.8 million toward this down payment and the Gathering segment contributed the remaining $11.3 million. The Company completed this acquisition on July 31, 2020, as discussed above, and paid an additional $476.8 million at that date.

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Project Funding

Over the past two years, the Company has been financing capital expenditures with cash from operations and short-term debt, as well as with proceeds received from the sale of oil and gas assets. The Company also issued long-term debt and common stock in June 2020, as discussed below. The common stock issuance and the long-term debt issuance, combined with cash from operations and short-term borrowings, are expected to meet the Company’s financing needs for the remainder of fiscal 2020. Completion of the sale of timber properties, discussed above, before September 30, 2020 would reduce any short-term borrowings drawn during the fourth quarter of fiscal 2020.

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

Financing Cash Flow

Consolidated short-term debt decreased $55.2 million when comparing the balance sheet at June 30, 2020 to the balance sheet at September 30, 2019. The maximum amount of short-term debt outstanding during the nine months ended June 30, 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. Given the effects on credit markets of the COVID-19 pandemic, access to commercial paper markets became challenging and more expensive beginning in March 2020. As a result, the Company elected to draw on its Credit Agreement (as defined below) and its uncommitted lines of credit as alternative sources of short-term capital. Those balances remained until June 8, 2020, at which time the Company repaid the full $200.0 million outstanding with the proceeds from the Company's common stock and long-term debt issuances executed during the quarter. At June 30, 2020, the Company had no outstanding short-term notes payable to banks or commercial paper outstanding.

On October 25, 2018, the Company entered into a Fourth Amended and Restated Credit Agreement (Credit Agreement) with a syndicate of 12 banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through October 25, 2023. On May 4, 2020, the Company entered into a 364-Day Credit Agreement with a syndicate of 10 banks, all of which are also lenders under the Credit Agreement. The 364-Day Credit Agreement provides an additional $200.0 million unsecured committed revolving credit facility. The Company also has uncommitted lines of credit with financial institutions for general corporate purposes. Borrowings under these uncommitted lines of credit would be made at competitive market rates. The uncommitted credit lines are revocable at the option of the financial institution and are reviewed on an annual basis. The Company anticipates that its uncommitted lines of credit generally will be renewed or substantially replaced by similar lines. Other financial institutions may also provide the Company with uncommitted or discretionary lines of credit in the future.

The total amount available to be issued under the Company’s commercial paper program is $500.0 million. The commercial paper program is backed by the Credit Agreement, which provides that the Company's debt to capitalization ratio will not exceed .65 at the last day of any fiscal quarter. For purposes of calculating the debt to capitalization ratio, the Company's total capitalization will be increased by adding back 50% of the aggregate after-tax amount of non-cash charges directly arising from any ceiling test impairment occurring on or after July 1, 2018, not to exceed $250 million. Since July 1, 2018, the Company recorded after-tax ceiling test impairments totaling $142.5 million. As a result, at June 30, 2020, $71.3 million was added back to the Company's total capitalization for purposes of the facility, and the Company’s debt to capitalization ratio, as calculated under the facility, was .53. The constraints specified in the Credit Agreement would have permitted an additional $1.64 billion in short-term and/or long-term debt to be outstanding at June 30, 2020 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65.

On March 27, 2020, the Company was downgraded by S&P to a rating of BBB- with a negative outlook. S&P subsequently improved the Company's outlook to stable during the quarter ended June 30, 2020. 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

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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.

On June 3, 2020, the Company issued $500.0 million of 5.50% notes due January 15, 2026. After deducting underwriting discounts, commissions and other debt issuance costs, the net proceeds to the Company amounted to $493.1 million. The holders of the notes may require the Company to repurchase their notes at a price equal to 101% of the principal amount in the event of a change in control and a ratings downgrade to a rating below investment grade. Additionally, the interest rate payable on the notes will be subject to a maximum adjustment of 2.00% such that the coupon will not exceed 7.5%, if there is a downgrade of the credit rating assigned to the notes (or if the credit rating assigned to the notes is subsequently upgraded). The proceeds of this debt issuance were used for general corporate purposes, which included the payment of a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020 and the repayment and refinancing of short-term debt.

None of the Company's long-term debt as of June 30, 2020 and September 30, 2019 had a maturity date within the following twelve-month period.

The Company’s embedded cost of long-term debt was 4.85% and 4.69% at June 30, 2020 and June 30, 2019, respectively.

On June 2, 2020, the Company completed a public offering and sale of 4,370,000 shares of the Company's common stock, par value $1.00 per share, at a price of $39.50 per share. After deducting fees, commissions and other issuance costs, the net proceeds to the Company amounted to $165.9 million. The proceeds of this issuance were used to fund a portion of the purchase price of the acquisition of Shell's upstream assets and midstream gathering assets in Pennsylvania that closed on July 31, 2020.

The Company's present liquidity position is believed to be adequate to satisfy known demands. Under the Company’s existing indenture covenants at June 30, 2020, the Company would have been permitted to issue up to a maximum of $125 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. However, factors that reduce the Company's operating income and/or consolidated assets, including impairments (i.e. write-downs) of the Company's oil and natural gas properties, could contribute to the Company's inability to meet interest coverage or debt-to-assets indenture covenants, which would restrict the Company's ability to issue long-term 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 time beginning in fiscal 2021. The covenants 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. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

The Company’s 1974 indenture pursuant to which $99.0 million (or 3.7%) of the Company’s long-term debt (as of June 30, 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.

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OTHER MATTERS

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

During the nine months ended June 30, 2020, the Company contributed $23.5 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $2.7 million to its VEBA trusts for its other post-retirement benefits. In the remainder of 2020, the Company expects its contributions to the Retirement Plan to be in the range of $1.0 million to $6.0 million. In the remainder of 2020, the Company expects to contribute approximately $0.2 million to its VEBA trusts.

The Company, in its Exploration and Production segment, 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. During the quarter ended June 30, 2020, the Company, in its Exploration and Production segment, entered into a $10 million contractual obligation related to completion services. This contractual commitment extends through May 31, 2022.

Market Risk Sensitive Instruments

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

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

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

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(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 June 30, 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)	24.8		2.3		27.1
Weighted Average Ceiling Price (per Mcf)	$	2.89	$	2.89	$	2.89
Weighted Average Floor Price (per Mcf)	$	2.37	$	2.37	$	2.37

At June 30, 2020, the Company would have had to pay an aggregate of approximately $1.8 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 Risk Sensitive Instruments” in Item 7 of the Company’s 2019 Form 10-K.

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.” Neither the New York or Pennsylvania divisions currently have a rate case on file. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are recovered through operation of automatic adjustment clauses, and are collected primarily through a separately-stated “supply charge” on the customer bill.

New York Jurisdiction

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

Favorable regulatory developments in the second calendar quarter of 2020 clarified that (a) qualified costs associated with utility system modernization incurred through March 31, 2021 are eligible to be recovered through the tracker previously approved by the NYPSC, and (b) the March 31, 2021 date relates only to cost eligibility and does not impact ongoing recovery under the tracker.

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Company is uncertain. The Company is anticipating that there will be some level of deterioration in the collectability of customer receivable balances depending on the depth and duration of the COVID-19 pandemic. It is uncertain at this point as to whether there would be any regulatory relief for utilities with regard to an increase in costs associated with the COVID-19 pandemic, but it is one of many issues currently being considered in a generic NYPSC proceeding entitled “Proceeding on Motion of the Commission Regarding the Effects of COVID-19 on Utility Service” (Case No. 20-M-0266).

Pennsylvania Jurisdiction

Pipeline and Storage

Empire's 2019 rate settlement requires a Section 4 rate case filing no later than May 1, 2025. Empire has no rate case currently on file.

Environmental Matters

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

For further discussion of the Company's environmental exposures, refer to Item 1 at Note 8 — Commitments and Contingencies under the heading “Environmental Matters.”

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

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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. A number of states have adopted energy strategies or plans with aggressive goals for the reduction of greenhouse gas emissions. Pennsylvania has a methane reduction framework with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines and is in the process of evaluating cap-and-trade programs (e.g., Regional Greenhouse Gas Initiative). In California, the Company currently complies with California cap-and-trade rules, which increases the Company's cost of environmental compliance in its Exploration and Production 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 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 purchase of emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or more years.

Safe Harbor for Forward-Looking Statements

The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made by, or on behalf of, the Company. Forward-looking statements include statements concerning plans, objectives, goals, projections, strategies, future events or performance, and underlying assumptions and other statements which are other than statements of historical facts. From time to time, the Company may publish or otherwise make available forward-looking statements of this nature. All such subsequent forward-looking statements, whether written or oral and whether made by or on behalf of the Company, are also expressly qualified by these cautionary statements. Certain statements contained in this report, including, without limitation, statements regarding future prospects, plans, objectives, goals, projections, estimates of oil and gas quantities, strategies, future events or performance and underlying assumptions, capital structure, anticipated capital expenditures, completion of construction projects, projections for pension and other post-retirement benefit obligations, impacts of the adoption of new 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.The Company's ability to successfully integrate acquired assets, including Shell's upstream assets and midstream gathering assets in Pennsylvania, and achieve expected cost synergies;

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

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

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;

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

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

8.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;

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

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

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

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

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

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

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

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

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

18.Uncertainty of oil and gas reserve estimates;

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

20.Changes in demographic patterns and weather conditions;

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

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

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

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

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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

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Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

The term “disclosure controls and procedures” is defined in Rules 13a-15(e) and 15d-15(e) under the Exchange Act. These rules refer to the controls and other procedures of a company that are designed to ensure that information required to be disclosed by a company in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Disclosure controls and procedures include, without limitation, controls and procedures designed to ensure that information required to be disclosed is accumulated and communicated to the company’s management, including its principal executive and principal financial officers, as appropriate to allow timely decisions regarding required disclosure. The Company’s management, including the Chief Executive Officer and Principal Financial Officer, evaluated the effectiveness of the Company’s disclosure controls and procedures as of the end of the period covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of June 30, 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 June 30, 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

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

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

Item 1A. Risk Factors

The risk factors in Item 1A of the Company’s 2019 Form 10-K, as amended by Item 1A of Part II of the Company’s Form 10-Q for the quarter ended March 31, 2020, have not materially changed other than as set forth below. The risk factors presented below supersede the risk factors having the same caption in the 2019 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2019 Form 10-K and the March 31, 2020 Form 10-Q. The impact of the COVID-19 pandemic may also exacerbate other risks discussed in Item 1A of the Company’s 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 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 date the Company has not experienced any material negative effects as a result of the COVID-19 pandemic, the situation continues to rapidly evolve and could result in material negative effects on our business and results of operations. The Company and its Pandemic Response Team are closely monitoring the impacts of the pandemic on the Company’s workforce, customers, contractors, suppliers, business continuity, and liquidity.

The protracted slowdown of broad sectors of the economy as a result of the COVID-19 pandemic has decreased the current demand for natural gas and oil, reducing revenues generated in the Exploration and Production segment. Additionally, significant changes in legislation or regulatory policy to address the COVID-19 pandemic could adversely impact the Company. Although it is not possible to predict the ultimate impact of the COVID-19 pandemic, including on the Company’s business, results of operations, cash flows or financial positions, such impacts that may be material include, but are not limited to: (i) a significant reduction in near-term demand for natural gas and oil; (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, increased cybersecurity threats associated with work-from-home arrangements, and increased purchases of personal protective equipment as the Company prepares its return-to-work plan; (v)

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difficulties in obtaining financing on acceptable terms or at all for working capital, capital expenditures and other investments, or to refinance maturing debt; and (vi) impacts on natural gas and oil 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 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., 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 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 interest rate fluctuations in the absence of interest rate hedging transactions. The cost of long-term debt, the interest rates on the Company's short-term bank loans and commercial paper and the ability of the Company to issue commercial paper are affected by its 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 banks, commercial paper purchasers and other sources, and require the Company’s subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. On March 27, 2020, the Company was downgraded by S&P to a rating of BBB- with a negative outlook, which S&P revised on June 3, 2020 to a rating of BBB- with a stable outlook. Combined with current ratings from other credit rating agencies, that downgrade increased the Company's short-term borrowing costs under its Credit Agreement. Additionally, $600 million of the Company’s outstanding long-term debt would be subject to an interest rate increase if certain fundamental changes occur that involve a material subsidiary and result in a downgrade of a credit rating assigned to the notes below investment grade. In addition to the $600 million, another $500 million of the Company’s outstanding long-term debt would be subject to an interest rate increase based solely on a downgrade of a credit rating assigned to the notes below investment grade, regardless of any additional fundamental changes. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets.

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

Periods of slowed economic activity generally result in decreased energy consumption, particularly by industrial and large commercial companies. As a consequence, national or regional recessions or other downturns in economic activity, including the effects of the COVID-19 pandemic, could adversely affect the Company’s revenues and cash flows or restrict its future growth. The Company is monitoring the impacts of the COVID-19 pandemic across our businesses. To date, the COVID-19 pandemic has not had a material impact on the Company. However, the Company cannot predict the extent or duration of the outbreak or whether this rapidly evolving situation will have a material impact on the Company’s workforce,

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supply chain, operations or financial results, including potential regulatory responses to the financial impacts associated with the COVID-19 pandemic on the Company and its customers. Economic conditions in the Company’s utility service territories, along with legislative and regulatory prohibitions on terminations of service, also impact its collections of accounts receivable. For instance, New York enacted legislation in June 2020 that prohibits residential utility terminations for nonpayment for the duration of the New York State COVID Disaster Emergency (currently running until September 7, 2020), and for a period of 180 days thereafter for residential customers that have experienced a change in financial circumstances due to the COVID-19 state of emergency. All of the Company’s segments are exposed to risks associated with the creditworthiness or performance of key suppliers and customers, many of which may be adversely affected by volatile conditions in the financial markets, including volatility caused by the ongoing COVID-19 pandemic. These conditions could result in financial instability or other adverse effects at any of our suppliers or customers. For example, counterparties to the Company’s commodity hedging arrangements or commodity sales contracts might not be able to perform their obligations under these arrangements or contracts. Customers of the Company’s Utility segment may have particular trouble paying their bills during periods of declining economic activity or high commodity prices, potentially resulting in increased bad debt expense and reduced earnings, and it is unclear at this time whether the NYPSC or PaPUC will allow rate recovery for COVID-19 pandemic related expenses. Similarly, if reductions were to occur in funding of the federal Low Income Home Energy Assistance Program, bad debt expense could increase and earnings could decrease. In addition, oil and gas exploration and production companies that are customers of the Company’s Pipeline and Storage segment may decide not to renew contracts for the same transportation capacity during periods of reduced production due to persistent low commodity prices. Any of these events could have a material adverse effect on the Company’s results of operations, financial condition and cash flows.

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 material. Under the Company's existing indenture covenants, an impairment could restrict the Company's ability to issue additional long-term unsecured indebtedness for a period of time, beginning with the fourth calendar month following the impairment. For the quarters ended March 31, 2020 and June 30, 2020, the Company recognized pre-tax impairment charges on its oil and natural gas properties of $177.8 million and $18.2 million respectively. It is anticipated that the current low commodity price environment will lead to impairments during the remaining quarter of fiscal 2020 and likely into the first quarter of fiscal 2021 as well.

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

On April 1, 2020, the Company issued a total of 12,120 unregistered shares of Company common stock to ten non-employee directors of the Company then serving on the Board of Directors of the Company, consisting of 1,212 shares to each such director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended June 30, 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)
Apr. 1 - 30, 2020	14,384	$39.20	—	6,971,019
May 1 - 31, 2020	14,058	$40.78	—	6,971,019
June 1 - 30, 2020	14,239	$40.83	—	6,971,019
Total	42,681	$40.26	—	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. During the quarter ended June 30, 2020, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program, nor did the Company purchase shares as a result of holders of stock-based compensation awards tendering shares to the Company.

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

Item 6. Exhibits


Exhibit Number						Description of Exhibit
•						Purchase and Sale Agreement, dated as of May 4, 2020, by and among SWEPI LP, Seneca Resources Company, LLC, NFG Midstream Covington, LLC, National Fuel Gas Midstream Company, LLC and National Fuel Gas Company (Exhibit 10.1, Form 8-K dated May 4, 2020)

•						364-Day Credit Agreement, dated as of May 4, 2020, among the Company, the Lenders party thereto, and JPMorgan Chase Bank, N.A., as Administrative Agent (Exhibit 10.2, Form 8-K dated May 4, 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 June 3 0 , 2020 and 2019.

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

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

•						Incorporated herein by reference as indicated.

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

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SIGNATURES

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


NATIONAL FUEL GAS COMPANY
(Registrant)





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





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

Date: August 7, 2020