NATIONAL FUEL GAS CO - Quarter Report: 2019 December (Form 10-Q)

Three Months Ended
December 31,

Increase (Decrease)

Gathered Volume - (MMcf)

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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 December 31, 2019

☐ 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 January 31, 2020: 86,560,898 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
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 Months Ended December 31, 2019 and 2018		6
b. Consolidated Statements of Comprehensive Income – Three Months Ended December 31, 2019 and 2018		7
c. Consolidated Balance Sheets – December 31, 2019 and September 30, 2019		8
d. Consolidated Statements of Cash Flows – Three Months Ended December 31, 2019 and 2018		10
e. Notes to Condensed Consolidated Financial Statements		11
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		29
Item 3. Quantitative and Qualitative Disclosures About Market Risk		44
Item 4. Controls and Procedures		44

Part II. Other Information

Item 1. Legal Proceedings		45
Item 1 A. Risk Factors		45
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		45
Item 3. Defaults Upon Senior Securities		•
Item 4. Mine Safety Disclosures		•
Item 5. Other Information		•
Item 6. Exhibits		46
Signatures		47

• 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 December 31,
(Thousands of U.S. Dollars, Except Per Common Share Amounts)	2019			2018
INCOME
Operating Revenues:
Utility and Energy Marketing Revenues	$	228,026		$	272,092
Exploration and Production and Other Revenues	167,193			163,937
Pipeline and Storage and Gathering Revenues	48,969			54,218
	444,188			490,247

Operating Expenses:
Purchased Gas	92,272			138,660
Operation and Maintenance:
Utility and Energy Marketing	43,256			43,915
Exploration and Production and Other	36,693			32,795
Pipeline and Storage and Gathering	25,885			24,934
Property, Franchise and Other Taxes	23,144			24,005
Depreciation, Depletion and Amortization	74,918			64,255
	296,168			328,564
Operating Income	148,020			161,683
Other Income (Expense):
Other Income (Deductions)	(3,040		)	(9,602		)
Interest Expense on Long-Term Debt	(25,443		)	(25,439		)
Other Interest Expense	(1,551		)	(1,073		)
Income Before Income Taxes	117,986			125,569
Income Tax Expense	31,395			22,909

Net Income Available for Common Stock	86,591			102,660

EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	1,272,601			1,098,900
	1,359,192			1,201,560

Dividends on Common Stock	(37,650		)	(36,663		)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	(950		)	—
Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities	—			7,437
Balance at December 31	$	1,320,592		$	1,172,334

Earnings Per Common Share:
Basic:
Net Income Available for Common Stock	$	1.00		$	1.19
Diluted:
Net Income Available for Common Stock	$	1.00		$	1.18
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	86,378,450			86,032,729
Used in Diluted Calculation	86,883,152			86,708,814
Dividends Per Common Share:
Dividends Declared	$	0.435		$	0.425

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)



	Three Months Ended December 31,
(Thousands of U.S. Dollars)	2019			2018
Net Income Available for Common Stock	$	86,591		$	102,660
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	495			44,518
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	(7,352		)	20,517
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	(5,544		)	53,297
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	119			12,744
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	(2,031		)	5,794
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		)
Income Taxes – Net	(1,549		)	14,237
Other Comprehensive Income (Loss)	(3,995		)	39,060
Comprehensive Income	$	82,596		$	141,720

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)



	December 31, 2019		September 30, 2019
(Thousands of U.S. Dollars)
ASSETS
Property, Plant and Equipment	$	11,402,308	$	11,204,838
Less - Accumulated Depreciation, Depletion and Amortization	5,756,084		5,695,328
	5,646,224		5,509,510
Current Assets
Cash and Temporary Cash Investments	34,966		20,428
Hedging Collateral Deposits	9,666		6,832
Receivables – Net of Allowance for Uncollectible Accounts of $26,717and $25,788, Respectively	158,944		139,956
Unbilled Revenue	58,306		18,758
Gas Stored Underground	29,991		36,632
Materials and Supplies - at average cost	40,373		40,717
Unrecovered Purchased Gas Costs	1,619		2,246
Other Current Assets	96,831		97,054
	430,696		362,623

Other Assets
Recoverable Future Taxes	116,188		115,197
Unamortized Debt Expense	13,578		14,005
Other Regulatory Assets	165,409		167,320
Deferred Charges	56,936		33,843
Other Investments	141,229		144,917
Goodwill	5,476		5,476
Prepaid Post-Retirement Benefit Costs	64,999		60,517
Fair Value of Derivative Financial Instruments	40,569		48,669
Other	21,354		80
	625,738		590,024

Total Assets	$	6,702,658	$	6,462,157

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)



	December 31, 2019			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 – 86,551,528 Shares and 86,315,287 Shares, Respectively	$	86,552		$	86,315
Paid in Capital	831,146			832,264
Earnings Reinvested in the Business	1,320,592			1,272,601
Accumulated Other Comprehensive Loss	(56,150		)	(52,155		)
Total Comprehensive Shareholders’ Equity	2,182,140			2,139,025
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,134,339			2,133,718
Total Capitalization	4,316,479			4,272,743

Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	139,800			55,200
Current Portion of Long-Term Debt	—			—
Accounts Payable	126,985			132,208
Amounts Payable to Customers	3,444			4,017
Dividends Payable	37,650			37,547
Interest Payable on Long-Term Debt	29,461			18,508
Customer Advances	13,727			13,044
Customer Security Deposits	15,510			16,210
Other Accruals and Current Liabilities	173,603			139,600
Fair Value of Derivative Financial Instruments	6,282			5,574
	546,462			421,908

Deferred Credits
Deferred Income Taxes	708,774			653,382
Taxes Refundable to Customers	361,556			366,503
Cost of Removal Regulatory Liability	222,172			221,699
Other Regulatory Liabilities	148,350			142,367
Pension and Other Post-Retirement Liabilities	129,616			133,729
Asset Retirement Obligations	128,382			127,458
Other Deferred Credits	140,867			122,368
	1,839,717			1,767,506
Commitments and Contingencies (Note 8)	—			—

Total Capitalization and Liabilities	$	6,702,658		$	6,462,157

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)



	Three Months Ended December 31,
(Thousands of U.S. Dollars)	2019			2018
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	86,591		$	102,660
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization	74,918			64,255
Deferred Income Taxes	51,366			64,175
Stock-Based Compensation	3,266			5,311
Other	1,911			2,182
Change in:
Receivables and Unbilled Revenue	(58,655		)	(101,541		)
Gas Stored Underground and Materials and Supplies	6,985			8,353
Unrecovered Purchased Gas Costs	627			(4,496		)
Other Current Assets	14			(1,195		)
Accounts Payable	8,280			1,502
Amounts Payable to Customers	(573		)	(3,394		)
Customer Advances	683			(6,258		)
Customer Security Deposits	(700		)	(1,861		)
Other Accruals and Current Liabilities	15,438			38,412
Other Assets	(28,259		)	(42,400		)
Other Liabilities	5,857			(21,333		)
Net Cash Provided by Operating Activities	167,749			104,372

INVESTING ACTIVITIES
Capital Expenditures	(198,495		)	(177,567		)
Other	5,212			(2,549		)
Net Cash Used in Investing Activities	(193,283		)	(180,116		)

FINANCING ACTIVITIES
Changes in Notes Payable to Banks and Commercial Paper	84,600			—
Dividends Paid on Common Stock	(37,547		)	(36,532		)
Net Repurchases of Common Stock	(4,147		)	(8,233		)
Net Cash Provided by (Used in) Financing Activities	42,906			(44,765		)
Net Increase (Decrease) in Cash, Cash Equivalents, and Restricted Cash	17,372			(120,509		)
Cash, Cash Equivalents, and Restricted Cash at October 1	27,260			233,047
Cash, Cash Equivalents, and Restricted Cash at December 31	$	44,632		$	112,538

Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$	93,838		$	86,175

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 three months ended December 31, 2019 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):



	Three Months Ended December 31, 2019				Three Months Ended December 31, 2018
	Balance at October 1, 2019		Balance at December 31, 2019		Balance at October 1, 2018		Balance at December 31, 2018

Cash and Temporary Cash Investments	$	20,428	$	34,966	$	229,606	$	109,754
Hedging Collateral Deposits	6,832		9,666		3,441		2,784
Cash, Cash Equivalents, and Restricted Cash	$	27,260	$	44,632	$	233,047	$	112,538

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.

Gas Stored Underground. In the Utility segment, gas stored underground is carried at lower of cost or net realizable value, on a LIFO method. Gas stored underground normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to $1.1 million at December 31, 2019, 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

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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 $1.7 billion at both December 31, 2019 and September 30, 2019.

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 $57.9 million and $53.5 million at December 31, 2019 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. At December 31, 2019, the ceiling exceeded the book value of the oil and gas properties by approximately $59.1 million. In adjusting estimated future cash flows for hedging under the ceiling test at December 31, 2019, estimated future net cash flows were increased by $9.1 million.

Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss and changes for the three months ended December 31, 2019 and 2018, 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 December 31, 2019
Balance at October 1, 2019	$	34,675		$	—		$	(86,830	)	$	(52,155	)
Other Comprehensive Gains and Losses Before Reclassifications	376			—			—			376
Amounts Reclassified From Other Comprehensive Income (Loss)	(5,321		)	—			—			(5,321		)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging	950			—			—			950
Balance at December 31, 2019	$	30,680		$	—		$	(86,830	)	$	(56,150	)
Three Months Ended December 31, 2018
Balance at October 1, 2018	$	(28,611	)	$	7,437		$	(46,576	)	$	(67,750	)
Other Comprehensive Gains and Losses Before Reclassifications	31,774			—			—			31,774
Amounts Reclassified From Other Comprehensive Income (Loss)	14,723			—			—			14,723
Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities	—			(7,437		)	—			(7,437		)
Balance at December 31, 2018	$	17,886		$	—		$	(46,576	)	$	(28,690	)

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.

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The Company adopted this authoritative guidance effective October 1, 2019, recognizing a cumulative effect adjustment that decreased retained earnings by $1.0 million and increased accumulated other comprehensive income by the same amount.

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

Reclassifications Out of Accumulated Other Comprehensive Loss. The details about the reclassification adjustments out of accumulated other comprehensive loss for the three months ended December 31, 2019 and 2018 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 December 31,
	2019			2018
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts		$7,541			($18,522	)	Operating Revenues
Commodity Contracts	2			(902		)	Purchased Gas
Foreign Currency Contracts	(191		)	(1,093		)	Operating Revenues
	7,352			(20,517		)	Total Before Income Tax
	(2,031		)	5,794			Income Tax Expense
		$5,321			($14,723	)	Net of Tax

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



	At December 31, 2019		At September 30, 2019

Prepayments	$	9,135	$	12,728
Prepaid Property and Other Taxes	15,340		14,361
Federal Income Taxes Receivable	42,389		42,388
State Income Taxes Receivable	5,576		8,579
Fair Values of Firm Commitments	9,803		7,538
Regulatory Assets	14,588		11,460
	$	96,831	$	97,054

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



	At December 31, 2019		At September 30, 2019

Federal Income Taxes Receivable	$	21,273	$	—
Other	81		80
	$	21,354	$	80

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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 December 31, 2019		At September 30, 2019

Accrued Capital Expenditures	$	59,933	$	33,713
Regulatory Liabilities	50,713		50,332
Reserve for Gas Replacement	1,100		—
Liability for Royalty and Working Interests	20,052		18,057
Non-Qualified Benefit Plan Liability	13,194		13,194
Other	28,611		24,304
	$	173,603	$	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 ended December 31, 2019, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were 733,617 securities and 318,106 securities excluded as being antidilutive for the quarter ended December 31, 2019 and December 31, 2018 respectively.

Stock-Based Compensation. The Company granted 254,608 performance shares during the quarter ended December 31, 2019. The weighted average fair value of such performance shares was $43.32 per share for the quarter ended December 31, 2019. Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period.

Half of the performance shares granted during the quarter ended December 31, 2019 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 quarter ended December 31, 2019 must meet a performance goal related to relative total shareholder return over a three-year performance cycle. The performance goal over the performance cycle is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group. Three-year total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these total shareholder return performance shares ("TSR performance shares") that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value price at the date of grant for the TSR performance shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the present value of forgone dividends over the vesting term of the award. This price is multiplied by the number of TSR performance shares awarded, the result of which is recorded as compensation expense over the vesting term of the award.

The Company granted 150,839 nonperformance-based restricted stock units during the quarter ended December 31, 2019. The weighted average fair value of such nonperformance-based restricted stock units was $40.38 per share for the quarter ended December 31, 2019. Restricted stock units represent the right to receive shares of common stock of the Company (or the

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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 three months ended December 31, 2019 and 2018, 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 December 31, 2019 (Thousands)
Revenues By Type of Service	Exploration and Production		Pipeline and Storage		Gathering		Utility			All Other			Corporate and Intersegment Eliminations			Total Consolidated
Production of Natural Gas	$	119,874	$	—	$	—	$	—		$	—		$	—		$	119,874
Production of Crude Oil	37,664		—		—		—			—			—			37,664
Natural Gas Processing	688		—		—		—			—			—			688
Natural Gas Gathering Services	—		—		34,788		—			—			(34,788		)	—
Natural Gas Transportation Service	—		53,452		—		32,808			—			(16,986		)	69,274
Natural Gas Storage Service	—		18,426		—		—			—			(7,993		)	10,433
Natural Gas Residential Sales	—		—		—		144,370			—			—			144,370
Natural Gas Commercial Sales	—		—		—		18,841			—			—			18,841
Natural Gas Industrial Sales	—		—		—		1,270			—			—			1,270
Natural Gas Marketing	—		—		—		—			34,108			(177		)	33,931
Other	172		342		—		(3,324		)	1,120			(52		)	(1,742		)
Total Revenues from Contracts with Customers	158,398		72,220		34,788		193,965			35,228			(59,996		)	434,603
Alternative Revenue Programs	—		—		—		2,860			—			—			2,860
Derivative Financial Instruments	7,541		—		—		—			(816		)	—			6,725
Total Revenues	$	165,939	$	72,220	$	34,788	$	196,825		$	34,412		$	(59,996	)	$	444,188

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Quarter Ended December 31, 2018 (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	$	135,911		$	—	$	—	$	—		$	—	$	—		$	135,911
Production of Crude Oil	37,555			—		—		—			—		—			37,555
Natural Gas Processing	975			—		—		—			—		—			975
Natural Gas Gathering Services	—			—		29,690		—			—		(29,690		)	—
Natural Gas Transportation Service	—			56,135		—		35,631			—		(17,065		)	74,701
Natural Gas Storage Service	—			18,929		—		—			—		(7,973		)	10,956
Natural Gas Residential Sales	—			—		—		166,867			—		—			166,867
Natural Gas Commercial Sales	—			—		—		22,047			—		—			22,047
Natural Gas Industrial Sales	—			—		—		1,501			—		—			1,501
Natural Gas Marketing	—			—		—		—			49,287		(332		)	48,955
Other	382			2,005		—		(2,861		)	1,007		(404		)	129
Total Revenues from Contracts with Customers	174,823			77,069		29,690		223,185			50,294		(55,464		)	499,597
Alternative Revenue Programs	—			—		—		(528		)	—		—			(528		)
Derivative Financial Instruments	(11,947		)	—		—		—			3,125		—			(8,822		)
Total Revenues	$	162,876		$	77,069	$	29,690	$	222,657		$	53,419	$	(55,464	)	$	490,247

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: $125.6 million for the remainder of fiscal 2020; $148.7 million for fiscal 2021; $121.8 million for fiscal 2022; $87.6 million for fiscal 2023; $77.4 million for fiscal 2024; and $318.6 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 December 31, 2019, the Company did not have any finance leases. Aside from a sublease of office space at the Company’s corporate headquarters, the Company does not have any material arrangements where the Company is the lessor.

Buildings and Property

The Company enters into building and property rental agreements with third parties for office space, certain field locations and other properties used in the Company’s operations. Building and property leases include the Company’s corporate headquarters in Williamsville, New York, and Exploration and Production segment offices in Houston, Texas, and Pittsburgh, Pennsylvania. The primary non-cancelable terms of the Company’s building and property leases range from six months to eleven 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.

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.

Firm Transportation and Storage Contracts

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

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Oil and Gas Leases

The new authoritative guidance 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 December 31, 2019

Operating Lease Expense	$	974
Variable Lease Expense ⁽¹⁾	134
Short-Term Lease Expense ⁽²⁾	64
Sublease Income	(80		)
Total Lease Expense	$	1,092

Short-Term Lease Costs Recorded to Property, Plant and Equipment ⁽³⁾	$	7,512


⁽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 December 31, 2019, the weighted average remaining lease term was 8.7 years and the weighted average discount rate was 3.49%.

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 December 31, 2019
Assets:
Deferred Charges	$	18,940

Liabilities:
Other Accruals and Current Liabilities	$	3,298
Other Deferred Credits	$	15,434

For the three months ended December 31, 2019, cash paid for operating liabilities, and reported in cash flows provided by operating activities on the Company’s Consolidated Statement of Cash Flows, was $1.1 million. During the three months ended December 31, 2019, the Company did not record any right-of-use assets in exchange for new lease liabilities.

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The following schedule of operating lease liability maturities summarizes the undiscounted lease payments owed by the Company to lessors pursuant to contractual agreements in effect as of December 31, 2019 (in thousands):



	At December 31, 2019

2020 (remaining 9 months)	$	2,575
2021	2,813
2022	2,264
2023	2,270
2024	2,237
Thereafter	9,717
Total Lease Payments	21,876
Less: Interest	(3,144		)
Total Lease Liability	$	18,732

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 December 31, 2019 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 December 31, 2019
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾
Assets:
Cash Equivalents – Money Market Mutual Funds	$	20,924	$	—	$	—	$	—		$	20,924
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	2,096		—		—		(2,096		)	—
Over the Counter Swaps – Gas and Oil	—		46,686		—		(5,031		)	41,655
Foreign Currency Contracts	—		118		—		(1,204		)	(1,086		)
Other Investments:
Balanced Equity Mutual Fund	36,740		—		—		—			36,740
Fixed Income Mutual Fund	62,220		—		—		—			62,220
Common Stock – Financial Services Industry	933		—		—		—			933
Hedging Collateral Deposits	9,666		—		—		—			9,666
Total	$	132,579	$	46,804	$	—	$	(8,331	)	$	171,052

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	7,741	$	—	$	—	$	(2,096	)	$	5,645
Over the Counter Swaps – Gas and Oil	—		5,524		—		(5,031		)	493
Foreign Currency Contracts	—		1,348		—		(1,204		)	144
Total	$	7,741	$	6,872	$	—	$	(8,331	)	$	6,282
Total Net Assets/(Liabilities)	$	124,838	$	39,932	$	—	$	—		$	164,770



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 December 31, 2019 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 $9.7 million (at December 31, 2019) 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 December 31, 2019 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, 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 is based on an internal, discounted cash flow model that uses observable inputs (i.e. LIBOR based discount rates and basis differential information, if applicable, at active natural gas and crude oil trading markets). The fair value of the Level 2 foreign currency contracts is determined using the market approach based on observable market transactions of forward Canadian currency rates.

The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At December 31, 2019, the Company determined that nonperformance risk would have no material impact on its financial position or results of operation. To assess nonperformance risk, the Company considered information such as any applicable collateral posted, master netting arrangements, and applied a market-based method by using the counterparty's (assuming the derivative is in a gain position) or the Company’s (assuming the derivative is in a loss position) credit default swaps rates.

For the quarters ended December 31, 2019 and December 31, 2018, there were no assets or liabilities measured at fair value and classified as Level 3. For the quarters ended December 31, 2019 and December 31, 2018, 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):



	December 31, 2019				September 30, 2019
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,134,339	$	2,253,232	$	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.

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



	At December 31, 2019		At September 30, 2019

Life Insurance Contracts	$	41,336	$	41,074
Equity Mutual Fund	36,740		40,660
Fixed Income Mutual Fund	62,220		62,339
Marketable Equity Securities	933		844
	$	141,229	$	144,917

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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 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 December 31, 2019 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 the assessment of effectiveness were recognized in current earnings rather than as a component of other comprehensive income (loss). During the quarter ended December 31, 2018, the Company recorded a $6.5 million hedging ineffectiveness gain that impacted operating revenue. With the October 1, 2019 adoption of the authoritative guidance that changes the financial reporting of hedging relationships and simplifies the application of hedge accounting, derivative instruments that are designated and qualify as a cash flow hedge will no longer have hedge ineffectiveness or a component excluded from the assessment of the effectiveness.

As of December 31, 2019, the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding:



Commodity	Units
Natural Gas	88.1	Bcf (short positions)
Natural Gas	2.7	Bcf (long positions)
Crude Oil	2,376,000	Bbls (short positions)

As of December 31, 2019, the Company was hedging a total of $77.3 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions).

As of December 31, 2019, the Company had $41.8 million ($30.7 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that $39.1 million ($28.7 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.

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The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended December 31, 2019 and 2018 (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 December 31,						Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income	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 December 31,
	2019			2018				2019			2018
Commodity Contracts	$	(1,555	)	$	50,052		Operating Revenue	$	7,541		$	(18,522	)
Commodity Contracts	1,131			(1,279		)	Purchased Gas	2			(902		)
Foreign Currency Contracts	919			(4,255		)	Operating Revenue	(191		)	(1,093		)
Total	$	495		$	44,518			$	7,352		$	(20,517	)

Fair Value Hedges

The Company utilizes fair value hedges to mitigate risk associated with fixed price sales commitments, fixed price purchase commitments and the decline in the value of certain natural gas held in storage. With respect to fixed price sales commitments, the Company enters into long positions to mitigate the risk of price increases for natural gas supplies that could occur after the Company enters into fixed price sales agreements with its customers. With respect to fixed price purchase commitments, the Company enters into short positions to mitigate the risk of price decreases that could occur after the Company locks into fixed price purchase deals with its suppliers. With respect to storage hedges, the Company enters into short positions to mitigate the risk of price decreases that could result in a lower of cost or net realizable value writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of December 31, 2019, NFR had fair value hedges covering approximately 23.5 Bcf (23.3 Bcf of fixed price sales commitments and 0.2 Bcf of commitments related to the withdrawal of storage gas). 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.



Derivatives in Fair Value Hedging Relationships	Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income	Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income for the Three Months Ended December 31, 2019 (In Thousands)			Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the Three Months Ended December 31, 2019 (In Thousands)
Commodity Contracts	Operating Revenues	$	(732	)	$	732
Commodity Contracts	Purchased Gas	$	—		$	—
		$	(732	)	$	732

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 and applicable foreign currency forward contracts with fourteen counterparties of which twelve are in a net gain position. On average, the Company had $3.4 million of credit exposure per counterparty in a gain position at December 31, 2019. The maximum credit exposure per counterparty in a gain position at

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December 31, 2019 was $6.9 million. As of December 31, 2019, 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 December 31, 2019, eleven of the fourteen counterparties to the Company’s outstanding derivative instrument contracts (specifically the over-the-counter swaps and applicable foreign currency forward contracts) had a common credit-risk related contingency feature. In the event the Company’s credit rating increases or falls below a certain threshold (applicable debt ratings), the available credit extended to the Company would either increase or decrease. A decline in the Company’s credit rating, in and of itself, would not cause the Company to be required to increase the level of its hedging collateral deposits (in the form of cash deposits, letters of credit or treasury debt instruments). If the Company’s outstanding derivative instrument contracts were in a liability position (or if the liability were larger) and/or the Company’s credit rating declined, then additional hedging collateral deposits may be required. At December 31, 2019, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $31.3 million according to the Company’s internal model (discussed in Note 4 — Fair Value Measurements). At December 31, 2019, 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 December 31, 2019.

For its exchange traded futures contracts, the Company was required to post $9.7 million in hedging collateral deposits as of December 31, 2019. 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 December 31, 2019 and December 31, 2018 were 26.6% and 18.2%, respectively. The increase in the effective tax rate was primarily the result of the reversal of a $5.0 million valuation allowance in fiscal 2019 related to sequestration of AMT credit refunds discussed below, differences between the book and tax treatment of stock compensation, as well as the elimination of the Enhanced Oil Recovery tax credit in fiscal 2020.

The 2017 Tax Reform Act repealed the corporate alternative minimum tax (AMT) and provides that the Company’s existing AMT credit carryovers are 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 are expected to be refunded between fiscal 2020 and fiscal 2023, if not previously utilized. During fiscal 2018, the Department of Treasury indicated that a portion of the refundable AMT credit carryovers would be subject to sequestration. Accordingly, the Company recorded a $5.0 million valuation allowance related to this sequestration in fiscal 2018. During the quarter ended December 31, 2018, the Office of Management and Budget determined that these AMT refunds would not be subject to sequestration. As such, the Company removed the valuation allowance. These amounts are recorded in Deferred Income Taxes and will be reclassified to a receivable when the amounts are expected to be realized in cash. The Company reclassified AMT credit refunds of $21.3 million and $42.1 million from Deferred Income Taxes to Other Assets at December 31, 2019 and 2018, respectively. The Company received $42.5 million of AMT credit refunds related to fiscal 2019 in January 2020.

The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118) which provides for up to a one year period (the measurement period) in which to complete the required analysis and income tax accounting for the 2017 Tax Reform Act. Based upon the available guidance, the Company completed the remeasurement of deferred income taxes as of December 31, 2018. Any subsequent guidance or clarification related to the 2017 Tax Reform Act will be accounted for in the period that the guidance is issued.

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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		Paid In Capital			Earnings Reinvested in the Business			Accumulated Other Comprehensive Income (Loss)
	(Thousands, except per share amounts)
Balance at October 1, 2019	86,315	$	86,315	$	832,264		$	1,272,601		$	(52,155	)
Net Income Available for Common Stock							86,591
Dividends Declared on Common Stock ($0.435 Per Share)							(37,650		)
Cumulative Effect of Adoption of Authoritative Guidance for Hedging							(950		)
Other Comprehensive Loss, Net of Tax										(3,995		)
Share-Based Payment Expense ⁽¹⁾				2,828
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	237	237		(3,946		)
Balance at December 31, 2019	86,552	$	86,552	$	831,146		$	1,320,592		$	(56,150	)

Balance at October 1, 2018	85,957	$	85,957	$	820,223		$	1,098,900		$	(67,750	)
Net Income Available for Common Stock							102,660
Dividends Declared on Common Stock ($0.425 Per Share)							(36,663		)
Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities							7,437
Other Comprehensive Income, Net of Tax										39,060
Share-Based Payment Expense ⁽¹⁾				4,917
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	314	314		(8,064		)
Balance at December 31, 2018	86,271	$	86,271	$	817,076		$	1,172,334		$	(28,690	)


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

Common Stock. During the three months ended December 31, 2019, the Company issued 86,635 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 9,480 original issue shares of common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, as partial consideration for the directors’ services during the three months ended December 31, 2019. Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes. During the three months ended December 31, 2019, 91,120 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 December 31, 2019 and September 30, 2019 had a maturity date within the following twelve-month period.

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 December 31, 2019, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $6.9 million, which includes a $3.7 million estimated minimum liability to remediate a former

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manufactured gas plant site located in New York. In March 2018, the NYDEC issued a Record of Decision for this New York site and the minimum liability reflects the remedy selected in the Record of Decision. The Company's liability for such clean-up costs has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at December 31, 2019. 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 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, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. 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 December 31, 2019 and September 30, 2019 is shown in the tables below.

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Quarter Ended December 31, 2019 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$165,939	$48,969	$—	$194,910	$409,818	$34,235	$135	$444,188
Intersegment Revenues	$—	$23,251	$34,788	$1,915	$59,954	$177	$(60,131)	$—
Segment Profit: Net Income	$23,977	$18,105	$15,944	$26,583	$84,609	$371	$1,611	$86,591



(Thousands)	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Segment Assets:
At December 31, 2019	$2,059,681	$1,926,766	$559,064	$2,043,246	$6,588,757	$143,890	$(29,989)	$6,702,658
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 December 31, 2018 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$162,876	$54,218	$—	$220,012	$437,106	$53,087	$54	$490,247
Intersegment Revenues	$—	$22,851	$29,690	$2,645	$55,186	$332	$(55,518)	$—
Segment Profit: Net Income (Loss)	$38,214	$25,102	$14,183	$25,649	$103,148	$82	$(570)	$102,660

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 December 31,	2019			2018			2019			2018

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⁾	1,527			819			6,249			3,971

Net Periodic Benefit Cost	$	6,352		$	5,172		$	2,598		$	2,481


⁽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.

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Employer Contributions. During the three months ended December 31, 2019, the Company contributed $7.8 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $0.7 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 $17.0 million to $22.0 million. In the remainder of 2020, the Company expects its contributions to its VEBA trusts to be in the range of $2.0 million to $2.5 million.

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.

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.

FERC Jurisdiction

Supply Corporation filed a Section 4 rate case on July 31, 2019 proposing rate increases to be effective September 1, 2019. The proposed rates reflect an annual cost of service of $295.4 million, a rate base of $970.8 million and a proposed cost of equity of 15%. The FERC has accepted the filed rates and suspended the effective date of the increases until February 1, 2020, when the rates will be made effective, subject to refund. If the rates finally approved at the end of the proceeding exceed the rates that were in effect at July 31, 2019, but are less than rates put into effect subject to refund on February 1, 2020, Supply Corporation would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at July 31, 2019, such lower rates will become effective prospectively from the date of the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at July 31, 2019.

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.

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

OVERVIEW

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

The Company is a diversified energy company engaged principally in the production, gathering, transportation, distribution and marketing of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current development activities are focused primarily in the Marcellus and Utica Shale. 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 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 continues to pursue development projects to expand its Pipeline and Storage segment. One project on Empire’s system, referred to as the Empire North Project, would allow for the transportation of 205,000 Dth per day of additional shale supplies from interconnections in Tioga County, Pennsylvania, to TransCanada Pipeline, and the TGP 200 Line. Project construction is under way. The Empire North Project has a projected in-service date in the fourth quarter of fiscal 2020 and an estimated cost of approximately $145 million. Another project on Supply Corporation’s system, referred to as the FM100 Project, will upgrade a 1950’s era pipeline in northwestern Pennsylvania and create approximately 330,000 Dth per day of additional transportation capacity on Supply Corporation’s system in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County, Pennsylvania to the Transcontinental Gas Pipe Line Company, LLC system at Leidy, Pennsylvania. The FM100 Project has a target in-service date in late calendar 2021 and a preliminary cost estimate of approximately $280 million. These and other projects are discussed in more detail in the Capital Resources and Liquidity section that follows.

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

Given the current low commodity price environment, the Company's Exploration and Production segment moved from a 3-rig development program to a 2-rig development program in the Appalachian region in January 2020, and intends to move to a single-rig development program during the second half of fiscal 2020. While this will result in lower capital spending in this segment (expected to be in the range of $375 million to $410 million for fiscal 2020), Seneca still anticipates an increase in natural gas production when comparing fiscal 2020 to fiscal 2019.

As discussed in the following Critical Accounting Estimates section, the Company uses the full cost method of accounting for determining the book value of its oil and natural gas properties in the Exploration and Production segment and that book value is subject to a quarterly ceiling test. While the Company did not record an impairment under the ceiling test during the quarter ended December 31, 2019, it is anticipated that the current low commodity price environment will lead to impairments during the remaining quarters of fiscal 2020.

From a rate perspective, Supply Corporation filed a Section 4 rate case on July 31, 2019. The new rates are scheduled to become effective on February 1, 2020, subject to refund, if the case is not settled before then. 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,

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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.

From a financing perspective, the Company expects to use cash on hand, cash from operations and short-term debt to meet its capital expenditure needs for fiscal 2020 and may issue long-term debt during fiscal 2020 as needed.

CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 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. If the book value of the oil and gas properties exceeds the ceiling, a non-cash impairment charge must be recorded to reduce the book value of the oil and gas properties to the calculated ceiling. At December 31, 2019, the ceiling exceeded the book value of the oil and gas properties by approximately $59.1 million. The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended December 31, 2019, based on posted Midway Sunset prices, was $59.50 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended December 31, 2019, based on the quoted Henry Hub spot price for natural gas, was $2.58 per MMBtu. (Note – because actual pricing of the Company’s various producing properties varies depending on their location and hedging, the prices used to calculate the ceiling may differ from the Midway Sunset and Henry Hub prices, which are only indicative of the 12-month average prices for the twelve months ended December 31, 2019. Pricing differences would include adjustments for regional market differentials, transportation fees and contractual arrangements.) The following table illustrates the sensitivity of the ceiling test calculation to commodity price changes, specifically showing the amount the ceiling would have exceeded the book value of the Company's oil and gas properties at December 31, 2019 if crude oil prices were $5 per Bbl lower than the average prices used at December 31, 2019, as well as showing the impairment that the Company would have recorded at December 31, 2019 if natural gas prices were $0.25 per MMBtu lower than the average prices used at December 31, 2019, and the impairment that the Company would have recorded at December 31, 2019 if both natural gas prices and crude oil prices were $0.25 per MMBtu and $5 per Bbl lower than the average prices used at December 31, 2019 (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. Looking ahead, the first day of the month Henry Hub spot price for natural gas in January 2020 was $2.05 per MMBtu. Given these January 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 March 31, 2020, June 30, 2020 and September 30, 2020, the Company expects to experience ceiling test impairments in each of these quarters.



Ceiling Testing Sensitivity to Commodity Price Changes
(Millions)	$0.25/MMBtu Decrease in Natural Gas Prices		$5.00/Bbl Decrease in Crude Oil Prices		$0.25/MMBtu Decrease in Natural Gas Prices and $5.00/Bbl Decrease in Crude Oil Prices
Excess of Ceiling over Book Value under Sensitivity Analysis	$	—	$	22.9	$	—
Calculated Impairment under Sensitivity Analysis	$	186.2	$	—	$	222.4

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.

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RESULTS OF OPERATIONS

Earnings

The Company's earnings were $86.6 million for the quarter ended December 31, 2019 compared to earnings of $102.7 million for the quarter ended December 31, 2018. The decrease in earnings of $16.1 million is primarily a result of lower earnings in the Exploration and Production segment and Pipeline and Storage segment. Higher earnings in the Gathering segment, Utility segment and Corporate and All Other categories partially offset these decreases.

Earnings (Loss) by Segment



	Three Months Ended December 31,
(Thousands)	2019		2018			Increase (Decrease)
Exploration and Production	$	23,977	$	38,214		$	(14,237	)
Pipeline and Storage	18,105		25,102			(6,997		)
Gathering	15,944		14,183			1,761
Utility	26,583		25,649			934
Total Reportable Segments	84,609		103,148			(18,539		)
All Other	371		82			289
Corporate	1,611		(570		)	2,181
Total Consolidated	$	86,591	$	102,660		$	(16,069	)

Exploration and Production

Exploration and Production Operating Revenues



	Three Months Ended December 31,
(Thousands)	2019		2018		Increase (Decrease)
Gas (after Hedging)	$	127,238	$	119,750	$	7,488
Oil (after Hedging)	37,841		35,264		2,577
Gas Processing Plant	688		975		(287		)
Other	172		6,887		(6,715		)
	$	165,939	$	162,876	$	3,063

Production Volumes



	Three Months Ended December 31,
	2019	2018	Increase (Decrease)
Gas Production (MMcf)
Appalachia	54,284	45,305	8,979
West Coast	487	502	(15	)
Total Production	54,771	45,807	8,964

Oil Production (Mbbl)
Appalachia	—	1	(1	)
West Coast	601	571	30
Total Production	601	572	29

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Average Prices



	Three Months Ended December 31,
	2019		2018		Increase (Decrease)
Average Gas Price/Mcf
Appalachia	$	2.16	$	2.93	$	(0.77	)
West Coast	$	4.98	$	6.73	$	(1.75	)
Weighted Average	$	2.19	$	2.97	$	(0.78	)
Weighted Average After Hedging	$	2.32	$	2.61	$	(0.29	)

Average Oil Price/Bbl
Appalachia	$	54.49	$	66.31	$	(11.82	)
West Coast	$	62.63	$	65.71	$	(3.08	)
Weighted Average	$	62.63	$	65.71	$	(3.08	)
Weighted Average After Hedging	$	62.92	$	61.70	$	1.22

2019 Compared with 2018

Operating revenues for the Exploration and Production segment increased $3.1 million for the quarter ended December 31, 2019 as compared with the quarter ended December 31, 2018. Gas revenues after hedging increased $7.5 million due to a 9.0 Bcf increase in gas production, which was largely offset by the impact of a $0.29 per Mcf decrease in the weighted average price of gas after hedging. The increase in gas production was largely 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 quarter ended December 31, 2019 as compared with the quarter ended December 31, 2018. Oil revenues after hedging increased $2.6 million due to a 29 Mbbl increase in crude oil production coupled with the impact of a $1.22 per Bbl increase in the weighted average price of oil after hedging. The increase in oil production revenue was largely due to higher production in the West Coast region. These increases to operating revenues were partially offset by a $6.7 million decrease in other revenue primarily due to mark-to-market adjustments related to hedging ineffectiveness that were recorded during the quarter ended December 31, 2018 that did not recur during the quarter ended December 31, 2019.

The Exploration and Production segment's earnings for the quarter ended December 31, 2019 were $24.0 million, a decrease of $14.2 million when compared with earnings of $38.2 million for the quarter ended December 31, 2018. The decrease in earnings was due to lower natural gas prices after hedging ($12.6 million), higher depletion expense ($7.5 million), higher production expenses ($6.5 million), higher other operating expenses ($0.6 million), higher interest expense ($0.7 million), a higher effective income tax rate ($1.3 million), the impact of the aforementioned prior year quarter mark-to-market adjustments related to hedging ineffectiveness ($5.1 million) and the impact of a remeasurement of the segment's accumulated deferred income taxes in the prior year quarter that did not recur in fiscal 2020 ($1.0 million). The increase in depletion expense was primarily due to the increase in production coupled with a $0.06 per Mcfe increase in the depletion rate, which was driven by an increase in capitalized costs in Seneca’s full cost pool. The increase in production expenses was primarily due to increased gathering and transportation costs in the Appalachian region. The increase in other operating expenses was largely due to an increase in purchased emissions credits in the West Coast region. The increase in interest expense was largely due to increased intercompany borrowings. The increase in the effective income tax rate was primarily due to the impact of the Enhanced Oil Recovery tax credit that was applicable in the quarter ended December 31, 2018 but was not available in the quarter ended December 31, 2019. These factors, which decreased earnings during the quarter ended December 31, 2019, were partially offset by the positive impacts of higher natural gas production ($18.5 million), higher crude oil production ($1.5 million), higher crude oil prices after hedging ($0.6 million) and lower other taxes ($1.3 million). The decrease in other taxes was primarily due to a lower Pennsylvania impact fee accrual for the quarter ended December 31, 2019 as a result of lower NYMEX natural gas prices.

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Pipeline and Storage

Pipeline and Storage Operating Revenues



	Three Months Ended December 31,
(Thousands)	2019		2018		Increase (Decrease)
Firm Transportation	$	53,191	$	55,714	$	(2,523	)
Interruptible Transportation	261		421		(160		)
	53,452		56,135		(2,683		)
Firm Storage Service	18,420		18,928		(508		)
Interruptible Storage Service	6		1		5
Other	342		2,005		(1,663		)
	$	72,220	$	77,069	$	(4,849	)

Pipeline and Storage Throughput



	Three Months Ended December 31,
(MMcf)	2019	2018	Increase (Decrease)
Firm Transportation	208,648	191,901	16,747
Interruptible Transportation	714	916	(202	)
	209,362	192,817	16,545

2019 Compared with 2018

Operating revenues for the Pipeline and Storage segment decreased $4.8 million for the quarter ended December 31, 2019 as compared with the quarter ended December 31, 2018. The decrease in operating revenues was primarily due to a decrease in transportation revenues of $2.7 million and a decrease in other revenues of $1.7 million. The decrease in transportation revenues was primarily attributable to an Empire system transportation contract termination in December 2018. Partially offsetting this decrease was an increase in transportation revenues due to an increase in Empire's 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, which was placed in service on November 1, 2019. The decrease in other revenues was 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 in the first quarter of fiscal 2020.

Transportation volume for the quarter ended December 31, 2019 increased by 16.5 Bcf from the prior year's quarter. The increase in transportation volume for the quarter primarily reflects an increase in capacity utilization by certain contract shippers. Volume fluctuations, other than those caused by the addition or termination of contracts, generally do not have a significant impact on revenues as a result of the straight fixed-variable rate design utilized by Supply Corporation and Empire.

The Pipeline and Storage segment’s earnings for the quarter ended December 31, 2019 were $18.1 million, a decrease of $7.0 million when compared with earnings of $25.1 million for the quarter ended December 31, 2018. The decrease in earnings was primarily due to the earnings impact of lower operating revenues of $3.8 million, as discussed above, combined with higher income tax expense ($2.5 million) and higher property taxes ($0.8 million). The increase in income tax expense is primarily due to permanent differences related to stock compensation activity. The increase in property taxes was due to an increase in scheduled payments in lieu of taxes in accordance with agreements in place, as well as higher town, county and school taxes due to an increase in assessed values from new projects placed in service. These earnings decreases were slightly offset by a decrease in operating expenses ($0.6 million) primarily due to a decrease in personnel and compensation costs as well as costs associated with maintenance of compressor stations, partially offset by an increase in pipeline integrity program expenses.

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Gathering

Gathering Operating Revenues



	Three Months Ended December 31,
(Thousands)	2019		2018		Increase (Decrease)
Gathering Revenues	$	34,788	$	29,690	$	5,098

Gathering Volume

2019 Compared with 2018

Operating revenues for the Gathering segment increased $5.1 million for the quarter ended December 31, 2019 as compared with the quarter ended December 31, 2018. The increase was primarily due to a 9.7 Bcf net increase in gathered volume resulting from a 4.0 Bcf, 3.8 Bcf and 3.5 Bcf increase in volume on Midstream Company's Trout Run, Wellsboro and Clermont gathering systems, respectively, offset by a 1.6 Bcf decline on the Covington gathering system. The net increase in gathered volume can be attributed to the increase in Seneca's gross natural gas production in the Appalachian region.

The Gathering segment’s earnings for the quarter ended December 31, 2019 were $15.9 million, an increase of $1.7 million when compared with earnings of $14.2 million for the quarter ended December 31, 2018. The increase in earnings was mainly due to the impact of higher gathering revenues discussed above ($4.0 million), which was partially offset by higher operating expenses ($1.3 million), higher depreciation expense ($0.4 million), and the impact of a nonrecurring income tax benefit recorded in the prior year quarter to adjust the remeasurement of deferred income taxes resulting from the 2017 Tax Reform Act ($0.5 million). The increase in operating expenses was due largely to increased preventative maintenance and overhaul activities at Covington and Trout Run compressor stations during the quarter ended December 31, 2019. The increase in depreciation expense was due to an increase in the average gross property, plant and equipment assets in service as compared to the prior year.

Utility

Utility Operating Revenues



	Three Months Ended December 31,
(Thousands)	2019			2018			Increase (Decrease)
Retail Sales Revenues:
Residential	$	145,615		$	165,333		$	(19,718	)
Commercial	19,661			22,742			(3,081		)
Industrial	1,267			1,493			(226		)
	166,543			189,568			(23,025		)
Transportation	33,606			35,950			(2,344		)
Other	(3,324		)	(2,861		)	(463		)
	$	196,825		$	222,657		$	(25,832	)

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Utility Throughput



	Three Months Ended December 31,
(MMcf)	2019	2018	Increase (Decrease)
Retail Sales:
Residential	19,476	19,780	(304	)
Commercial	2,812	2,846	(34	)
Industrial	217	204	13
	22,505	22,830	(325	)
Transportation	20,556	22,270	(1,714	)
	43,061	45,100	(2,039	)

Degree Days



Three Months Ended December 31,				Percent Colder (Warmer) Than
Three Months Ended December 31,	Normal	2019	2018	Normal⁽¹⁾		Prior Year⁽¹⁾
Buffalo	2,253	2,232	2,325	(0.9	)%	(4.0	)%
Erie	2,044	1,906	2,030	(6.8	)%	(6.1	)%


⁽¹⁾	Percents compare actual 2019 degree days to normal degree days and actual 2019 degree days to actual 2018 degree days.

2019 Compared with 2018

Operating revenues for the Utility segment decreased $25.8 million for the quarter ended December 31, 2019 as compared with the quarter ended December 31, 2018. The decrease primarily resulted from a $23.0 million decrease in retail gas sales revenue, a $2.3 million decrease in transportation revenues and a $0.5 million decrease in other revenues. The decrease in retail gas sales revenue was largely due to a decrease in the cost of gas sold (per Mcf) coupled with slightly lower throughput due to warmer weather. The decline in transportation revenues was primarily due a 1.7 Bcf decrease in transportation throughput due to warmer weather and the migration of residential transportation customers to retail. The decrease in other revenues was largely due to the impact of regulatory adjustments, including an earnings sharing accrual recorded in fiscal 2020 for $0.5 million in the segment's New York service territory.

The Utility segment’s earnings for the quarter ended December 31, 2019 were $26.6 million, an increase of $1.0 million when compared with earnings of $25.6 million for the quarter ended December 31, 2018. The increase in earnings was largely attributable to the impact of regulatory adjustments ($0.9 million) and the positive earnings impact related to a system modernization tracker ($0.3 million). These increases were slightly offset by higher income tax expense ($0.8 million). The increase in income tax expense was primarily due to permanent differences related to stock compensation activity.

Corporate and All Other

2019 Compared with 2018

Corporate and All Other operations had earnings of $2.0 million for the quarter ended December 31, 2019, an increase of $2.5 million when compared with a loss of $0.5 million for the quarter ended December 31, 2018. The increase in earnings was primarily attributable to lower unrealized losses on investments in equity securities recorded during the quarter ended December 31, 2019 ($4.2 million) coupled with higher other income ($1.5 million) that was driven largely by an increase in realized gains on investments in equity securities sold in the current quarter. These positive drivers of earnings were partially offset by the impact of the prior year remeasurement of deferred income taxes under the 2017 Tax Reform Act that lowered income tax expense for the quarter ended December 31, 2018 ($3.5 million).

Interest Expense on Long-Term Debt

Interest on long-term debt was relatively flat for the quarter ended December 31, 2019 as compared with the quarter ended December 31, 2018. No new additional debt was issued or repaid during the quarters ended December 31, 2019 and

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December 31, 2018. In addition, amortization of debt premiums discount and expense and capitalized interest remained comparable year over year.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary sources of cash during the three-month period ended December 31, 2019 consisted of cash provided by operating activities and net proceeds from short-term borrowings. The Company's primary source of cash during the three-month period ended December 31, 2018 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, 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 and futures contracts in an attempt to manage this energy commodity price risk.

Net cash provided by operating activities totaled $167.7 million for the three months ended December 31, 2019, an increase of $63.3 million compared with $104.4 million provided by operating activities for the three months ended December 31, 2018. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Utility and Exploration and Production segments. The increase in the Utility segment is primarily due to the timing of gas cost recovery and the timing of receivable collections. The increase in the Exploration and Production segment is primarily due to higher cash receipts from natural gas production. The increase in cash provided by operating activities also reflects a decrease in contributions made to the Retirement Plan, primarily in the Utility and Pipeline and Storage segments.

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Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled $211.2 million during the three months ended December 31, 2019 and $174.9 million during the three months ended December 31, 2018. The table below presents these expenditures:



Total Expenditures for Long-Lived Assets
Three Months Ended December 31,	2019			2018			Increase (Decrease)
(Millions)	2019			2018			Increase (Decrease)
Exploration and Production:
Capital Expenditures	$	126.9	(1)	$	120.2	(2)	$	6.7
Pipeline and Storage:
Capital Expenditures	57.1		(1)	30.0		(2)	27.1
Gathering:
Capital Expenditures	9.8		(1)	8.8		(2)	1.0
Utility:
Capital Expenditures	17.2		(1)	15.9		(2)	1.3
All Other:
Capital Expenditures	0.2			—			0.2
	$	211.2		$	174.9		$	36.3

(1)

At December 31, 2019, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $62.3 million, $22.7 million, $5.3 million and $3.5 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 December 31, 2018, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $66.1 million, $12.9 million, $4.4 million and $2.8 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 three months ended December 31, 2019 were primarily well drilling and completion expenditures and included approximately $119.0 million for the Appalachian region (including $53.7 million in the Marcellus Shale area and $63.8 million in the Utica Shale area) and $7.9 million for the West Coast region. These amounts included approximately $86.2 million spent to develop proved undeveloped reserves.

The Exploration and Production segment capital expenditures for the three months ended December 31, 2018 were primarily well drilling and completion expenditures and included approximately $114.7 million for the Appalachian region (including $36.5 million in the Marcellus Shale area and $75.5 million in the Utica Shale area) and $5.5 million for the West Coast region. These amounts included approximately $61.1 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the three months ended December 31, 2019 were primarily for expenditures related to Empire's Empire North Project ($29.1 million) and Supply Corporation's Line N to Monaca Project ($3.3 million), as discussed below. In addition, the Pipeline and Storage segment capital expenditures for the three months ended December 31, 2019 include additions, improvements and replacements to this segment’s transmission and gas storage systems. The Pipeline and Storage capital expenditures for the three months ended December 31, 2018 were primarily for additions, improvements and replacements to this segment’s transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for the three months ended December 31, 2018 include expenditures related to Supply Corporation's Line N to Monaca Project ($1.1 million).

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

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

Supply Corporation completed a project to provide incremental natural gas transportation services from Line N to the ethane cracker facility being constructed by Shell Chemical Appalachia, LLC in Potter Township, Pennsylvania ("Line N to Monaca Project"), with transportation service beginning on November 1, 2019. This project involved construction of a 4.5 mile pipeline extension from Line N to the facility and has resulted in Supply Corporation securing incremental firm transportation capacity commitments totaling 133,000 Dth per day on Line N and on the pipeline extension to the facility. Supply Corporation was authorized to pursue the project by FERC under its blanket certificate as of May 30, 2018. As of December 31, 2019, approximately $22.1 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 December 31, 2019.

Empire concluded an Open Season on November 18, 2015, and has designed a project that would allow for the transportation of 205,000 Dth per day of additional shale supplies from interconnections in Tioga County, Pennsylvania, to TransCanada Pipeline, and the TGP 200 Line (“Empire North Project”). This project is fully subscribed under long term agreements and received the FERC Section 7(c) certificate on March 7, 2019. Project construction is under way. The Empire North Project has a projected in-service date in the fourth quarter of fiscal 2020 and an estimated capital cost of approximately $145 million. As of December 31, 2019, approximately $74.5 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 and Trout Run-Gamble areas. Supply Corporation filed a Section 7(c) application with the FERC in July 2019. The FM100 Project has a target in-service date in late calendar 2021 and a preliminary cost estimate of approximately $280 million. As of December 31, 2019, approximately $5.0 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at December 31, 2019.

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 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, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various

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state permits. 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 December 31, 2019, approximately $57.8 million has been spent on the Northern Access project, including $23.3 million that has been spent to study the project, for which no reserve has been established. The remaining $34.5 million spent on the project has been capitalized as Construction Work in Progress.

Gathering

The majority of the Gathering segment capital expenditures for the three months ended December 31, 2019 were for the continued expansion of Midstream Company’s Trout Run gathering system, Midstream Company's Clermont gathering system and Midstream Company's Wellsboro gathering system, as discussed below. Midstream Company spent $5.5 million, $3.2 million and $1.1 million, respectively, during the three months ended December 31, 2019 on the development of the Trout Run, Clermont and Wellsboro gathering systems. These expenditures were largely attributable to new gathering pipelines and the continued development of centralized station facilities, including increased compression horsepower at the Trout Run gathering system.

The majority of the Gathering segment capital expenditures for the three months ended December 31, 2018 were for the continued expansion of the Trout Run gathering system, Clermont gathering system and Wellsboro gathering system. Midstream Company spent $1.3 million, $3.0 million and $4.0 million, respectively, during the three months ended December 31, 2018 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. Midstream Company intends to extend this system in 2020. Combining this extension with reduced drilling activity in the Exploration and Production segment, the Gathering segment's capital expenditures are expected to be in the range of $50 million to $60 million for fiscal 2020.

Utility

The majority of the Utility segment capital expenditures for the three months ended December 31, 2019 and December 31, 2018 were made for main and service line improvements and replacements, as well as main extensions.

Project Funding

Over the past two years, the Company has been financing the Pipeline and Storage segment and Gathering segment projects mentioned above, as well as the Exploration and Production segment and Utility segment capital expenditures, with cash from operations as well as proceeds received from the sale of oil and gas assets. Going forward, while the Company expects to use cash on hand, cash from operations and short-term debt to finance these projects, the Company may issue long-term debt as necessary during fiscal 2020 to help meet its capital expenditures needs. The level of short-term and long-term borrowings will depend upon the amount of cash provided by operations, which, in turn, will likely be impacted by natural gas and crude oil prices combined with production from existing wells.

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.

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Financing Cash Flow

Consolidated short-term debt increased $84.6 million when comparing the balance sheet at December 31, 2019 to the balance sheet at September 30, 2019. The maximum amount of short-term debt outstanding during the quarter ended December 31, 2019 was $173.3 million. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt. At December 31, 2019, the Company had outstanding commercial paper of $139.8 million. The Company did not have any outstanding short-term notes payable to banks at December 31, 2019.

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. 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. At December 31, 2019, the Company’s debt to capitalization ratio (as calculated under the facility) was .51. The constraints specified in the Credit Agreement would have permitted an additional $1.77 billion in short-term and/or long-term debt to be outstanding at December 31, 2019 (further limited by the indenture covenants discussed below) before the Company’s debt to capitalization ratio exceeded .65.

A downgrade in the Company’s credit ratings could increase borrowing costs, negatively impact the availability of capital from banks, commercial paper purchasers and other sources, and require the Company's subsidiaries to post letters of credit, cash or other assets as collateral with certain counterparties. If the Company is not able to maintain investment-grade credit ratings, it may not be able to access commercial paper markets. However, the Company expects that it could borrow under its credit facilities or rely upon other liquidity sources, including cash provided by operations.

The Credit Agreement contains a cross-default provision whereby the failure by the Company or its significant subsidiaries to make payments under other borrowing arrangements, or the occurrence of certain events affecting those other borrowing arrangements, could trigger an obligation to repay any amounts outstanding under the Credit Agreement. In particular, a repayment obligation could be triggered if (i) the Company or any of its significant subsidiaries fails to make a payment when due of any principal or interest on any other indebtedness aggregating $40.0 million or more or (ii) an event occurs that causes, or would permit the holders of any other indebtedness aggregating $40.0 million or more to cause, such indebtedness to become due prior to its stated maturity. As of December 31, 2019, the Company did not have any debt outstanding under the Credit Agreement.

None of the Company's long-term debt as of December 31, 2019 and September 30, 2019 had a maturity date within the following twelve-month period.

The Company’s embedded cost of long-term debt was 4.69% at both December 31, 2019 and December 31, 2018.

Under the Company’s existing indenture covenants at December 31, 2019, the Company would have been permitted to issue up to a maximum of $1.05 billion in additional long-term indebtedness at then current market interest rates in addition to being able to issue new indebtedness to replace maturing debt. The Company's present liquidity position is believed to be adequate to satisfy known demands. However, if the Company were to experience a significant loss in the future (for example, as a result of an impairment of oil and gas properties), it is possible, depending on factors including the magnitude of the loss, that these indenture covenants would restrict the Company's ability to issue additional long-term unsecured indebtedness for a period of up to nine calendar months, beginning with the fourth calendar month following the loss. This would not preclude the Company from issuing new indebtedness to replace maturing debt. Please refer to the Critical Accounting Estimates section above for a sensitivity analysis concerning commodity price changes and their impact on the ceiling test.

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The Company’s 1974 indenture pursuant to which $99.0 million (or 4.6%) of the Company’s long-term debt (as of December 31, 2019) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

OTHER MATTERS

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

During the three months ended December 31, 2019, the Company contributed $7.8 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and $0.7 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 $17.0 million to $22.0 million. In the remainder of 2020, the Company expects its contributions to its VEBA trusts to be in the range of $2.0 million to $2.5 million.

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.

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

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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.” The Pennsylvania division does not have a rate case on file. See below for a description of the current rate proceedings affecting the New York division. In both jurisdictions, delivery rates do not reflect the recovery of purchased gas costs. Prudently-incurred gas costs are 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.

On April 24, 2019, the NYPSC issued an order extending the sunset provision of the tracker previously approved by the NYPSC that allows Distribution Corporation to recover increased investment in utility system modernization for one year (until March 31, 2021). The extension is contingent on a one year stay-out of a general rate case filing that would prevent new rates from becoming effective prior to April 1, 2021.

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 methane and volatile organic compound emissions. The current administration has issued executive orders to review and potentially roll back

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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.	Changes in the price of natural gas or oil;


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


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


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


5.	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;


6.	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;

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

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;


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


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


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


12.	Uncertainty of oil and gas reserve estimates;


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


14.	Changes in demographic patterns and weather conditions;


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


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


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


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


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


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


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


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

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

Item 3. Quantitative and Qualitative Disclosures About Market Risk

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

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

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

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covered by this report. Based upon that evaluation, the Company’s Chief Executive Officer and Principal Financial Officer concluded that the Company’s disclosure controls and procedures were effective as of December 31, 2019.

Changes in Internal Control Over Financial Reporting

There were no changes in the Company’s internal control over financial reporting that occurred during the quarter ended December 31, 2019 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 have not materially changed.

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

On October 1, 2019, the Company issued a total of 9,480 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 948 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 December 31, 2019. These transactions were exempt from registration under Section 4(a)(2) of the Securities Act of 1933, as transactions not involving a public offering.

Issuer Purchases of Equity Securities



Period	Total Number of Shares Purchased ^(a)	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under Share Repurchase Plans or Programs ^(b)
Oct. 1 - 31, 2019	11,920	$44.77	—	6,971,019
Nov. 1 - 30, 2019	11,875	$45.78	—	6,971,019
Dec. 1 - 31, 2019	102,783	$45.63	—	6,971,019
Total	126,578	$45.57	—	6,971,019

(a)

Represents shares of common stock of the Company purchased on the open market with Company “matching contributions” for the accounts of participants in the Company’s 401(k) plans, and (ii) shares of common stock of the Company tendered to the Company by holders of stock-based compensation awards for the payment of applicable withholding taxes. During the quarter ended December 31, 2019, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase program. Of the 126,578 shares purchased other than through a publicly announced share repurchase program, 35,458 were purchased for the Company’s 401(k) plans and 91,120 were purchased as a result of shares tendered to the Company by holders of stock-based compensation awards.


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

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Item 6. Exhibits



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

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

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

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

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

99		National Fuel Gas Company Consolidated Statements of Income for the Twelve Months Ended December 31, 2019 and 2018.

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 months ended December 31, 2019 and 2018, (ii) the Consolidated Statements of Comprehensive Income for the three months ended December 31, 2019 and 2018, (iii) the Consolidated Balance Sheets at December 31, 2019 and September 30, 2019, (iv) the Consolidated Statements of Cash Flows for the three months ended December 31, 2019 and 2018 and (v) the Notes to Condensed Consolidated Financial Statements.

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

•

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

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SIGNATURES

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



NATIONAL FUEL GAS COMPANY
(Registrant)





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





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

Date: January 31, 2020