UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

FORM 10-Q

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

OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended~~December 31, 2017~~June 30, 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)~~ (716) 857-7000

(Registrant's telephone number, including area code)



Securities registered pursuant to Section 12(b) of the Act:
Title of Each Class	Trading Symbol	Name of Each Exchange on Which Registered
Common Stock, par value $1.00 per share	NFG	New York Stock Exchange

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

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

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



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

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

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

Indicate the number of shares outstanding of each of the issuer's classes of common stock, as of the latest practicable date: Common stock, par value $1.00 per share, outstanding at ~~January~~July 31, ~~2018: 85,801,778~~2019: 86,314,863 shares.

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GLOSSARY OF TERMS

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



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



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



Other
~~2017~~2018 Form 10-K	The Company’s Annual Report on Form 10-K for the year ended September 30, 2018
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.
Degree day	A measure of the coldness of the weather experienced, based on the extent to which the daily average temperature falls below a reference temperature, usually 65 degrees Fahrenheit.
Derivative	A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, forward contracts, options, no cost collars and swaps.

Table of Contents



Development costs	Costs incurred to obtain access to proved oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act.

~~Table of Contents~~



Dth	Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
Exchange Act	Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets	Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploration costs	Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
Exploratory well	A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
FERC 7(c) application	An application to the FERC under Section 7(c) of the federal Natural Gas Act for authority to construct, operate (and provide services through) facilities to transport or store natural gas in interstate commerce.
Firm transportation and/or storage	The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP	Accounting principles generally accepted in the United States of America
Goodwill	An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging	A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
Hub	Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
ICE	Intercontinental Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Interruptible transportation and/or storage	The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LDC	Local distribution company
LIBOR	London Interbank Offered Rate
LIFO	Last-in, first-out
Marcellus Shale	A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.
Mbbl	Thousand barrels (of oil)
Mcf	Thousand cubic feet (of natural gas)
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth	Thousand decatherms (of natural gas)
MMBtu	Million British thermal units (heating value of one decatherm of natural gas)
MMcf	Million cubic feet (of natural gas)
NEPA	National Environmental Policy Act of 1969, as amended
NGA	The Natural Gas Act of 1938, as amended; the federal law regulating interstate natural gas pipeline and storage companies, among other things, codified beginning at 15 U.S.C. Section 717.
NYMEX	New York Mercantile Exchange. An exchange which maintains a futures market for crude oil and natural gas.

Table of Contents



Open Season	A bidding procedure used by pipelines to allocate firm transportation or storage capacity among prospective shippers, in which all bids submitted during a defined time period are evaluated as if they had been submitted simultaneously.

~~Table of Contents~~



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

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INDEX		Page

Part I. Financial Information

Item 1. Financial Statements (Unaudited)		6

a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Nine Months Ended ~~December 31, 2017~~June 30, 2019 and ~~2016~~ 2018		6
b. Consolidated Statements of Comprehensive Income – Three and Nine Months Ended ~~December 31, 2017~~June 30, 2019 and ~~2016~~ 2018		7
c. Consolidated Balance Sheets – ~~December 31, 2017~~June 30, 2019 and September 30, ~~2017~~2018		8
d. Consolidated Statements of Cash Flows – ~~Three~~Nine Months Ended ~~December 31, 2017~~June 30, 2019 and ~~2016~~ 2018		10
e. Notes to Condensed Consolidated Financial Statements		11
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		2531
Item 3. Quantitative and Qualitative Disclosures About Market Risk		4250
Item 4. Controls and Procedures		4250

Part II. Other Information

Item 1. Legal Proceedings		4250
Item 1 A. Risk Factors		4350
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		4551
Item 3. Defaults Upon Senior Securities		•
Item 4. Mine Safety Disclosures		•
Item 5. Other Information		•
Item 6. Exhibits		4651
Signatures		4752

• The Company has nothing to report under this item.

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

Table of Contents

Part I. Financial Information

Item 1. Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)


	Three Months Ended December 31,						Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands of Dollars, Except Per Common Share Amounts)	2017			2016
(Thousands of U.S. Dollars, Except Per Common Share Amounts)							2019			2018			2019			2018
INCOME
Operating Revenues:
Utility and Energy Marketing Revenues	$	225,725		$	207,780		$	151,312		$	154,088		$	781,059		$	719,234
Exploration and Production and Other Revenues	140,450			161,694			159,864			137,492			470,267			425,811
Pipeline and Storage and Gathering Revenues	53,480			53,026			46,024			51,332			148,665			158,428
	419,655			422,500			357,200			342,912			1,399,991			1,303,473

Operating Expenses:
Purchased Gas	94,034			70,243			47,839			52,211			381,537			322,854
Operation and Maintenance:
Utility and Energy Marketing	51,369			50,422			39,607			39,560			132,082			130,348
Exploration and Production and Other	35,542			30,461			35,674			30,682			108,610			104,891
Pipeline and Storage and Gathering	20,037			22,660			28,675			25,044			80,857			68,272
Property, Franchise and Other Taxes	20,848			20,379			21,506			20,595			68,046			64,245
Depreciation, Depletion and Amortization	55,830			56,196			71,072			60,817			200,990			177,802
	277,660			250,361			244,373			228,909			972,122			868,412
Operating Income	141,995			172,139			112,827			114,003			427,869			435,061
Other Income (Expense):
Interest Income	2,249			1,600
Other Income	1,722			1,614
Other Income (Deductions)							(1,456		)	(3,612		)	(16,977		)	(20,205		)
Interest Expense on Long-Term Debt	(28,087		)	(29,103		)	(25,303		)	(27,177		)	(76,016		)	(82,412		)
Other Interest Expense	(502		)	(910		)	(1,202		)	(1,006		)	(4,061		)	(2,742		)
Income Before Income Taxes	117,377			145,340			84,866			82,208			330,815			329,702
Income Tax Expense (Benefit)	(81,277		)	56,432			21,113			19,183			73,806			(23,825		)

Net Income Available for Common Stock	198,654			88,908			63,753			63,025			257,009			353,527

EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	851,669			676,361			1,236,657			1,070,939			1,098,900			851,669
	1,050,323			765,269			1,300,410			1,133,964			1,355,909			1,205,196

Dividends on Common Stock	(35,590		)	(34,544		)	(37,543		)	(36,526		)	(110,885		)	(107,758		)
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation	—			31,916
Balance at December 31	$	1,014,733		$	762,641
Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities							—			—			7,437			—
Cumulative Effect of Adoption of Authoritative Guidance for Reclassification of Stranded Tax Effects							—			—			10,406			—
Balance at June 30							$	1,262,867		$	1,097,438		$	1,262,867		$	1,097,438

Earnings Per Common Share:
Basic:
Net Income Available for Common Stock	$	2.32		$	1.04		$	0.74		$	0.73		$	2.98		$	4.12
Diluted:
Net Income Available for Common Stock	$	2.30		$	1.04		$	0.73		$	0.73		$	2.96		$	4.09
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	85,630,296			85,189,851			86,306,434			85,930,289			86,208,766			85,789,279
Used in Diluted Calculation	86,325,537			85,797,989			86,839,841			86,501,194			86,765,781			86,370,900
Dividends Per Common Share:
Dividends Declared	$	0.415		$	0.405		$	0.435		$	0.425		$	1.285		$	1.255

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)


	Three Months Ended December 31,						Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands of Dollars)	2017			2016
(Thousands of U.S. Dollars)							2019			2018			2019			2018
Net Income Available for Common Stock	$	198,654		$	88,908		$	63,753		$	63,025		$	257,009		$	353,527
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	(44		)	(883		)	—			(121		)	—			(843		)
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(5,499		)	(52,501		)	34,211			(37,452		)	53,619			(55,534		)
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income	(430		)	(741		)	—			—			—			(430		)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	(12,548		)	(30,717		)	(3,869		)	3,771			20,498			(5,577		)
Other Comprehensive Loss, Before Tax	(18,521		)	(84,842		)
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							30,342			(33,802		)	62,379			(62,384		)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	(65		)	(344		)	—			42			—			(275		)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(2,305		)	(22,052		)	9,835			(10,416		)	15,434			(16,240		)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income	(158		)	(273		)	—			—			—			(158		)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	(5,197		)	(12,954		)	(1,113		)	1,208			5,756			(3,438		)
Reclassification Adjustment for Income Tax Benefit (Expense) on the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities to Earnings Reinvested in the Business							—			—			(4,301		)	—
Reclassification Adjustment for Stranded Tax Effects Related to the 2017 Tax Reform Act to Earnings Reinvested in the Business							—			—			10,406			—
Income Taxes – Net	(7,725		)	(35,623		)	8,722			(9,166		)	27,295			(20,111		)
Other Comprehensive Loss	(10,796		)	(49,219		)
Other Comprehensive Income (Loss)							21,620			(24,636		)	35,084			(42,273		)
Comprehensive Income	$	187,858		$	39,689		$	85,373		$	38,389		$	292,093		$	311,254

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	December 31, 2017		September 30, 2017		June 30, 2019		September 30, 2018
(Thousands of Dollars)
(Thousands of U.S. Dollars)
ASSETS
Property, Plant and Equipment	$	10,023,252	$	9,945,560	$	10,988,435	$	10,439,839
Less - Accumulated Depreciation, Depletion and Amortization	5,294,211		5,271,486		5,636,065		5,462,696
	4,729,041		4,674,074		5,352,370		4,977,143
Current Assets
Cash and Temporary Cash Investments	166,289		555,530		87,515		229,606
Hedging Collateral Deposits	4,465		1,741		6,835		3,441
Receivables – Net of Allowance for Uncollectible Accounts of $24,511 and $22,526, Respectively	161,029		112,383
Receivables – Net of Allowance for Uncollectible Accounts of $29,137 and $24,537, Respectively					178,762		141,498
Unbilled Revenue	74,790		22,883		18,047		24,182
Gas Stored Underground	24,139		35,689		17,075		37,813
Materials and Supplies - at average cost	35,139		33,926		39,010		35,823
Unrecovered Purchased Gas Costs	7,787		4,623		—		4,204
Other Current Assets	47,914		51,505		56,052		68,024
	521,552		818,280		403,296		544,591

Other Assets
Recoverable Future Taxes	116,792		181,363		113,619		115,460
Unamortized Debt Expense	8,148		1,159		14,432		15,975
Other Regulatory Assets	174,577		174,433		107,206		112,918
Deferred Charges	34,063		30,047		33,627		40,025
Other Investments	123,368		125,265		137,847		132,545
Goodwill	5,476		5,476		5,476		5,476
Prepaid Post-Retirement Benefit Costs	57,054		56,370		88,939		82,733
Fair Value of Derivative Financial Instruments	21,107		36,111		36,803		9,518
Other	754		742		42,632		102
	541,339		610,966		580,581		514,752

Total Assets	$	5,791,932	$	6,103,320	$	6,336,247	$	6,036,486

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)


	December 31, 2017			September 30, 2017			June 30, 2019			September 30, 2018
(Thousands of Dollars)
(Thousands of U.S. Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued And Outstanding – 85,760,846 Shares and 85,543,125 Shares, Respectively	$	85,761		$	85,543
Authorized - 200,000,000 Shares; Issued And Outstanding – 86,306,593 Shares and 85,956,814 Shares, Respectively							$	86,307		$	85,957
Paid in Capital	800,348			796,646			827,243			820,223
Earnings Reinvested in the Business	1,014,733			851,669			1,262,867			1,098,900
Accumulated Other Comprehensive Loss	(40,919		)	(30,123		)	(32,666		)	(67,750		)
Total Comprehensive Shareholders’ Equity	1,859,923			1,703,735			2,143,751			1,937,330
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	2,084,465			2,083,681			2,133,101			2,131,365
Total Capitalization	3,944,388			3,787,416			4,276,852			4,068,695

Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	—			—			—			—
Current Portion of Long-Term Debt	—			300,000			—			—
Accounts Payable	132,409			126,443			112,782			160,031
Amounts Payable to Customers	251			—			14,546			3,394
Dividends Payable	35,590			35,500			37,543			36,532
Interest Payable on Long-Term Debt	27,962			35,031			29,461			19,062
Customer Advances	18,398			15,701			166			13,609
Customer Security Deposits	22,503			20,372			16,801			25,703
Other Accruals and Current Liabilities	121,596			111,889			180,063			132,693
Fair Value of Derivative Financial Instruments	6,579			1,103			4,563			49,036
	365,288			646,039			395,925			440,060

Deferred Credits
Deferred Income Taxes	453,285			891,287			647,602			512,686
Taxes Refundable to Customers	366,768			95,739			366,184			370,628
Cost of Removal Regulatory Liability	205,554			204,630			218,340			212,311
Other Regulatory Liabilities	118,551			113,716			159,259			146,743
Pension and Other Post-Retirement Liabilities	125,055			149,079			53,142			66,103
Asset Retirement Obligations	106,516			106,395			104,732			108,235
Other Deferred Credits	106,527			109,019			114,211			111,025
	1,482,256			1,669,865			1,663,470			1,527,731
Commitments and Contingencies (Note 6)	—			—
Commitments and Contingencies (Note 7)							—			—

Total Capitalization and Liabilities	$	5,791,932		$	6,103,320		$	6,336,247		$	6,036,486

See Notes to Condensed Consolidated Financial Statements

Table of Contents

National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)


	Three Months Ended December 31,						Nine Months Ended June 30,
(Thousands of Dollars)	2017			2016
(Thousands of U.S. Dollars)							2019			2018
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	198,654		$	88,908		$	257,009		$	353,527
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization	55,830			56,196			200,990			177,802
Deferred Income Taxes	(94,676		)	44,852			111,123			(43,537		)
Stock-Based Compensation	3,905			2,482			16,144			11,770
Other	3,678			3,607			7,964			12,311
Change in:
Hedging Collateral Deposits	(2,724		)	1,484
Receivables and Unbilled Revenue	(83,357		)	(67,395		)	(31,584		)	(35,021		)
Gas Stored Underground and Materials and Supplies	10,337			10,597			17,551			18,832
Unrecovered Purchased Gas Costs	(3,164		)	(1,257		)	4,204			4,623
Other Current Assets	3,591			9,576			11,972			(1,185		)
Accounts Payable	13,173			18,805			(16,132		)	2,327
Amounts Payable to Customers	251			(16,306		)	11,152			16,833
Customer Advances	2,697			(983		)	(13,443		)	(15,504		)
Customer Security Deposits	2,131			673			(8,902		)	(1,904		)
Other Accruals and Current Liabilities	11,532			5,919			36,040			26,538
Other Assets	(5,275		)	(8,389		)	(34,594		)	(10,770		)
Other Liabilities	(21,775		)	(4,122		)	1,061			1,441
Net Cash Provided by Operating Activities	94,808			144,647			570,555			518,083

INVESTING ACTIVITIES
Capital Expenditures	(142,613		)	(106,053		)	(587,442		)	(403,994		)
Net Proceeds from Sale of Oil and Gas Producing Properties	—			5,759			—			55,506
Other	2,612			(4,297		)	(3,071		)	(1,759		)
Net Cash Used in Investing Activities	(140,001		)	(104,591		)	(590,513		)	(350,247		)

FINANCING ACTIVITIES
Reduction of Long-Term Debt	(307,047		)	—			—			(307,047		)
Dividends Paid on Common Stock	(35,500		)	(34,473		)	(109,875		)	(106,732		)
Net Proceeds from Issuance (Repurchase) of Common Stock	(1,501		)	938			(8,864		)	4,262
Net Cash Used in Financing Activities	(344,048		)	(33,535		)	(118,739		)	(409,517		)
Net Increase (Decrease) in Cash and Temporary Cash Investments	(389,241		)	6,521

Cash and Temporary Cash Investments at October 1	555,530			129,972
Cash and Temporary Cash Investments at December 31	$	166,289		$	136,493
Net Decrease in Cash, Cash Equivalents, and Restricted Cash							(138,697		)	(241,681		)
Cash, Cash Equivalents, and Restricted Cash at October 1							233,047			557,271
Cash, Cash Equivalents, and Restricted Cash at June 30							$	94,350		$	315,590

Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$	56,116		$	48,965		$	79,425		$	71,410
Receivable from Sale of Oil and Gas Producing Properties	$	17,310		$	20,795

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 - Summary of Significant Accounting Policies

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

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

Reclassifications. In November 2016, the FASB issued authoritative guidance related to the presentation of restricted cash on the statement of cash flows. The new guidance requires restricted cash and cash equivalents be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows, and requires disclosure of how cash and cash equivalents on the statement of cash flows reconciles to the balance sheet. The Company considers Hedging Collateral Deposits to be restricted cash. The Company adopted this guidance effective October 1, 2018 on a retrospective basis. As a result, prior periods have been reclassified to conform to the current year presentation. Additional discussion is provided below at Consolidated Statement of Cash Flows.

In March 2017, the FASB issued authoritative guidance related to the presentation of net periodic pension cost and net periodic postretirement benefit cost. The new guidance requires segregation of the service cost component from the other components of net periodic pension cost and net periodic postretirement benefit cost for financial reporting purposes. The service cost component is to be presented on the income statement in the same line items as other compensation costs included within Operating Expenses and the other components of net periodic pension cost and net periodic postretirement benefit cost are to be presented on the income statement below the subtotal labeled Operating Income (Loss). Under this guidance, the service cost component is eligible to be capitalized as part of the cost of inventory or property, plant and equipment while the other components of net periodic pension cost and net periodic postretirement benefit cost are generally not eligible for capitalization, unless allowed by a regulator. The Company adopted this guidance effective October 1, 2018. The Company applied the guidance retrospectively for the pension and postretirement benefit costs using amounts disclosed in prior period financial statement notes as estimates for the reclassifications in accordance with a practical expedient allowed under the guidance. For the quarter and nine months ended June 30, 2018, Operating Income increased $6.2 million and $28.6 million, respectively, and Other Income (Deductions) decreased by the same amounts as a result of the reclassifications. For the quarter and nine months ended June 30, 2019, Other Income (Deductions) includes $5.7 million and $25.5 million, respectively, of pension and postretirement benefit costs.

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

The earnings for the ~~three~~nine months ended ~~December 31, 2017~~June 30, 2019 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, ~~2018~~2019. Most of the business of the Utility and Energy Marketing segments is seasonal in nature and is influenced by weather conditions. Due to the seasonal nature of the heating business in the Utility and Energy Marketing segments, earnings during the winter months normally represent a substantial part of the earnings that those segments are expected to achieve for the entire fiscal year. The Company’s business segments are discussed more fully in Note 78 – Business Segment Information.

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



	Nine Months Ended June 30, 2019				Nine Months Ended June 30, 2018
	Balance at October 1, 2018		Balance at June 30, 2019		Balance at October 1, 2017		Balance at June 30, 2018

Cash and Temporary Cash Investments	$	229,606	$	87,515	$	555,530	$	313,307
Hedging Collateral Deposits	3,441		6,835		1,741		2,283
Cash, Cash Equivalents, and Restricted Cash	$	233,047	$	94,350	$	557,271	$	315,590

The Company considers all highly liquid debt instruments purchased with a maturity date of generally three months or less to be cash equivalents.

The Company’s restricted cash is composed entirely of amounts reported as Hedging Collateral Deposits~~. This~~ on the Consolidated Balance Sheets. Hedging Collateral Deposits is an account title for cash held in margin accounts funded by the Company to serve as collateral for hedging positions. In accordance with its accounting policy, the Company does not offset hedging collateral deposits paid or received against related derivative financial instruments liability or asset balances.

Gas Stored Underground. In the Utility segment, gas stored underground is carried at lower of cost or net realizable value, on a LIFO method. Gas stored underground normally declines during the first and second quarters of the year and is replenished during the third and fourth quarters. In the Utility segment, the current cost of replacing gas withdrawn from storage is recorded in the Consolidated Statements of Income and a reserve for gas replacement is recorded in the Consolidated Balance Sheets under the caption “Other Accruals and Current Liabilities.” Such reserve, which amounted to ~~$1.7~~$16.3 million at ~~December 31, 2017,~~June 30, 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 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.

Capitalized costs include costs related to unproved properties, which are excluded from amortization until proved reserves are found or it is determined that the unproved properties are impaired. Such costs amounted to ~~$77.1~~$82.0 million and ~~$80.9~~$62.2 million at ~~December 31, 2017~~June 30, 2019 and September 30, ~~2017,~~2018, respectively. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.

Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with

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settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed by applying prices of oil and gas (as adjusted for hedging) to estimated future production of proved oil and gas reserves as of the date of the latest balance sheet, less estimated future expenditures, plus (b) the cost of unevaluated properties not being depleted, less (c) income tax effects related to the differences between the book and tax basis of the properties. The natural gas and oil prices used to calculate the full cost ceiling are based on an unweighted arithmetic average of the first day of the month oil and gas prices for each month within the twelve-month period prior to the end of the reporting period. If capitalized costs, net of accumulated depreciation, depletion and amortization and related deferred income taxes, exceed the ceiling at the end of any quarter, a permanent impairment is required to be charged to earnings in that quarter. At ~~December 31, 2017,~~June 30, 2019, the ceiling exceeded the book value of the oil and gas properties by approximately ~~$334.6~~$566.8 million. In adjusting estimated future cash flows for hedging under the ceiling test at ~~December 31, 2017,~~June 30, 2019, estimated future net cash flows were ~~increased~~decreased by ~~$18.0~~$23.9 million.

~~On December 1, 2015, Seneca and IOG - CRV Marcellus, LLC (IOG), an affiliate~~

Table of IOG Capital, LP, and funds managed by affiliates of Fortress Investment Group, LLC, executed a joint development agreement that allows IOG to participate in the development of certain oil and gas interests owned by Seneca in Elk, McKean and Cameron Counties, Pennsylvania. On June 13, 2016, Seneca and IOG executed an extension of the joint development agreement. Under the terms of the extended agreement, Seneca and IOG will jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG will hold an 80% working interest in all of the joint development wells. In total, IOG is expected to fund approximately $305 million for its 80% working interest in the 75 joint development wells. Of this amount, IOG has funded $267.1 million as of December 31, 2017, which includes $163.9 million of cash ($137.3 million in fiscal 2016 and $26.6 million in fiscal 2017) shown as Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statements of Cash Flows for fiscal 2016 and fiscal 2017. Such proceeds from sale represent funding received from IOG for costs previously incurred by Seneca to develop a portion of the 75 joint development wells. A receivable of $17.3 million has been recorded at December 31, 2017 in recognition of additional IOG funding that is due to Seneca for costs incurred by Seneca to develop a portion of the 75 joint development wells. This receivable has been shown as a Non-Cash Investing Activity on the Consolidated Statement of Cash Flows for the quarter ended December 31, 2017. As the fee-owner of the property’s mineral rights, Seneca currently retains a 7.5% royalty interest and the remaining 20% working interest (26% net revenue interest) in 56 of the joint development wells. In the remaining 19 wells, Seneca retains a 20% working and net revenue interest. Seneca’s working interest under the agreement will increase to 85% after IOG achieves a 15% internal rate of return.Contents

Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss and changes for the ~~three~~nine months ended ~~December 31, 2017~~June 30, 2019 and ~~2016,~~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, 2017
Balance at October 1, 2017 $ 20,801
$ 7,562
$ (58,486 ) $ (30,123 )
Other Comprehensive Gains and Losses Before Reclassifications (3,194 ) 21
—
(3,173 )
Amounts Reclassified From Other Comprehensive Loss (7,351 ) (272 ) —
(7,623 )
Balance at December 31, 2017 $ 10,256
$ 7,311
$ (58,486 ) $ (40,919 )
Three Months Ended December 31, 2016
Balance at October 1, 2016 $ 64,782
$ 6,054
$ (76,476 ) $ (5,640 )
Other Comprehensive Gains and Losses Before Reclassifications (30,449 ) (539 ) —
(30,988 )
Amounts Reclassified From Other Comprehensive Loss (17,763 ) (468 ) —
(18,231 )
Balance at December 31, 2016 $ 16,570
$ 5,047
$ (76,476 ) $ (54,859 )



	Gains and Losses on Derivative Financial Instruments			Gains and Losses on Securities Available for Sale			Funded Status of the Pension and Other Post-Retirement Benefit Plans			Total
Three Months Ended June 30, 2019
Balance at April 1, 2019	$	4,562		$	—		$	(58,848	)	$	(54,286	)
Other Comprehensive Gains and Losses Before Reclassifications	24,376			—			—			24,376
Amounts Reclassified From Other Comprehensive Income (Loss)	(2,756		)	—			—			(2,756		)
Balance at June 30, 2019	$	26,182		$	—		$	(58,848	)	$	(32,666	)
Nine Months Ended June 30, 2019
Balance at October 1, 2018	$	(28,611	)	$	7,437		$	(46,576	)	$	(67,750	)
Other Comprehensive Gains and Losses Before Reclassifications	38,185			—			—			38,185
Amounts Reclassified From Other Comprehensive Income (Loss)	14,742			—			—			14,742
Reclassification Adjustment for the Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities	—			(7,437		)	—			(7,437		)
Reclassification of Stranded Tax Effects Related to the 2017 Tax Reform Act	1,866			—			(12,272		)	(10,406		)
Balance at June 30, 2019	$	26,182		$	—		$	(58,848	)	$	(32,666	)
Three Months Ended June 30, 2018
Balance at April 1, 2018	$	3,841		$	6,885		$	(58,486	)	$	(47,760	)
Other Comprehensive Gains and Losses Before Reclassifications	(27,036		)	(163		)	—			(27,199		)
Amounts Reclassified From Other Comprehensive Income (Loss)	2,563			—			—			2,563
Balance at June 30, 2018	$	(20,632	)	$	6,722		$	(58,486	)	$	(72,396	)
Nine Months Ended June 30, 2018
Balance at October 1, 2017	$	20,801		$	7,562		$	(58,486	)	$	(30,123	)
Other Comprehensive Gains and Losses Before Reclassifications	(39,294		)	(568		)	—			(39,862		)
Amounts Reclassified From Other Comprehensive Income (Loss)	(2,139		)	(272		)	—			(2,411		)
Balance at June 30, 2018	$	(20,632	)	$	6,722		$	(58,486	)	$	(72,396	)

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

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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 Outof Accumulated Other Comprehensive Loss. The details about the reclassification adjustments out of accumulated other comprehensive loss for the ~~three~~nine months ended ~~December 31, 2017~~June 30, 2019 and ~~2016~~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	Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss												Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended December 31,
	2017			2016
Details About Accumulated Other Comprehensive Loss Components								Three Months Ended June 30,						Nine Months Ended June 30,						Affected Line Item in the Statement Where Net Income is Presented
								2019			2018			2019			2018

Commodity Contracts		$12,842			$31,320		Operating Revenues		$4,091			($3,249	)		($18,692	)		$6,125		Operating Revenues
Commodity Contracts	196			(460		)	Purchased Gas	—			5			(1,182		)	952			Purchased Gas
Foreign Currency Contracts	(490		)	(143		)	Operation and Maintenance Expense	(222		)	(527		)	(624		)	(1,500		)	Operating Revenues
Gains (Losses) on Securities Available for Sale	430			741			Other Income	—			—			—			430			Other Income (Deductions)
	12,978			31,458			Total Before Income Tax	3,869			(3,771		)	(20,498		)	6,007			Total Before Income Tax
	(5,355		)	(13,227		)	Income Tax Expense	(1,113		)	1,208			5,756			(3,596		)	Income Tax Expense
		$7,623			$18,231		Net of Tax		$2,756			($2,563	)		($14,742	)		$2,411		Net of Tax

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



	At June 30, 2019		At September 30, 2018

Prepayments	$	13,777	$	10,770
Prepaid Property and Other Taxes	11,501		14,444
Federal Income Taxes Receivable	6,554		22,457
State Income Taxes Receivable	8,773		8,822
Fair Values of Firm Commitments	5,618		1,739
Regulatory Assets	9,829		9,792
	$	56,052	$	68,024

At December 31, 2017 At September 30, 2017

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

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



	At June 30, 2019		At September 30, 2018

Federal Income Taxes Receivable	$	42,546	$	—
Other	86		102
	$	42,632	$	102

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



	At June 30, 2019		At September 30, 2018

Accrued Capital Expenditures	$	60,082	$	38,354
Regulatory Liabilities	50,233		57,425
Reserve for Gas Replacement	16,251		—
Liability for Royalty and Working Interests	19,846		12,062
Other	33,651		24,852
	$	180,063	$	132,693

At December 31, 2017 At September 30, 2017

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

Earnings Per Common Share. Basic earnings per common share is computed by dividing income or loss by the weighted average number of common shares outstanding for the period. Diluted earnings per common share reflects the potential dilution that could occur if securities or other contracts to issue common stock were exercised or converted into common stock. For purposes of determining earnings per common share, the potentially dilutive securities the Company ~~has~~had outstanding ~~are stock options,~~were SARs, restricted stock units and performance shares. For the quarter and nine months ended ~~December 31, 2017,~~June 30, 2019, the diluted weighted average shares outstanding shown on the Consolidated Statements of Income reflects the potential dilution as a result of these securities as determined using the Treasury Stock Method. ~~Stock options,~~ SARs, restricted stock units and performance shares that are antidilutive are excluded from the calculation of diluted earnings per common share. There were ~~157,603~~120,546 securities and ~~317,686~~122,327 securities excluded as being antidilutive for the ~~quarters~~quarter and nine months ended ~~December 31, 2017~~June 30, 2019, respectively. There were 1,095,838 securities and ~~December 31, 2016,~~316,279 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2018, respectively.

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Stock-Based Compensation. The Company granted ~~208,588~~244,734 performance shares during the ~~quarter~~nine months ended ~~December 31, 2017.~~June 30, 2019. The weighted average fair value of such performance shares was ~~$50.95~~$55.67 per share for the ~~quarter~~nine months ended ~~December 31, 2017.~~June 30, 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~~nine months ended ~~December 31, 2017~~June 30, 2019 must meet a performance goal related to relative return on capital over ~~the~~a three-year performance ~~cycle of October 1, 2017 to September 30, 2020.~~cycle. The performance goal over the performance cycle is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”). Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database. The number of these performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value of these performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award. The other half of the performance shares granted during the ~~quarter~~nine months ended ~~December 31, 2017~~June 30, 2019 must meet a performance goal related to relative total shareholder return over ~~the~~a three-year performance ~~cycle of October 1, 2017 to September 30, 2020.~~cycle. The performance goal over the performance cycle is the Company’s three-year total shareholder return relative to the three-year total shareholder return of the other companies in the Report Group. Three-year total shareholder return for a given company will be based on the data reported for that company (with the starting and ending stock prices over the performance cycle calculated as the average closing stock price for the prior calendar month and with dividends reinvested in that company’s securities at each ex-dividend date) in the Bloomberg database. The number of these total shareholder return performance shares ("TSR performance shares") that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value price at the date of grant for the TSR performance shares is determined using a Monte Carlo simulation technique, which includes a reduction in value for the present value of forgone dividends over the vesting term of the award. This price is multiplied by the number of TSR performance shares awarded, the result of which is recorded as compensation expense over the vesting term of the award.

The Company granted ~~89,672 non-performance based~~112,608 nonperformance-based restricted stock units during the ~~quarter~~nine months ended ~~December 31, 2017.~~June 30, 2019. The weighted average fair value of such ~~non-performance based~~nonperformance-based restricted stock units was ~~$51.23~~$49.70 per share for the ~~quarter~~nine months ended ~~December 31, 2017.~~June 30, 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 ~~non-performance based~~nonperformance-based restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for ~~non-performance based~~nonperformance-based restricted stock units is the same as the accounting for restricted share awards, except that the fair value at the date of grant of the restricted stock units must be reduced by the present value of forgone dividends over the vesting term of the award.

New Authoritative Accounting and Financial Reporting Guidance. In May 2014, the FASB issued authoritative guidance regarding revenue recognition. The authoritative guidance provides a single, comprehensive revenue recognition model for all contracts with customers to improve comparability. The revenue standard contains principles that an entity will apply to determine the measurement of revenue and timing of when it is recognized. The original effective date of this authoritative guidance was as of the Company's first quarter of fiscal 2018. However, the FASB has delayed the effective date of the new revenue standard by one year, and the guidance will now be effective as of the Company's first quarter of fiscal 2019. Working towards this implementation date, the Company is currently evaluating the guidance and the various issues identified by industry based revenue recognition task forces. The Company does not believe that its revenue recognition policies will change materially, although the Company is still assessing the impact. The Company will need to enhance its financial statement disclosures to comply with the new authoritative guidance.

In February 2016, the FASB issued authoritative guidance, which has subsequently been amended, requiring organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by all leases, regardless of whether they are considered to be capital leases or operating leases. The FASB’s previous authoritative guidance required organizations that lease assets to recognize on the balance sheet the assets and liabilities for the rights and obligations created by capital leases while excluding operating leases from balance sheet recognition. The new authoritative guidance will be effective as of the Company’s first quarter of fiscal 2020, with early adoption permitted. The Company does not anticipate early adoption.

The Company will adopt the new authoritative guidance using the optional transition method, which permits an entity to initially apply the new lease accounting standard at the adoption date and recognize a cumulative-effect adjustment to the opening balance of retained earnings in the period of adoption. The Company plans to apply practical expedients provided in the authoritative guidance that allow, among other things, an entity not to reassess contracts that commenced prior to the adoption date and to exclude all land easement arrangements that exist prior to the adoption date from treatment under the guidance. The Company also expects to elect a policy not to recognize right of use assets and lease liabilities related to short-term leases.

The Company has finalized a plan for the adoption and ~~is currently evaluating the provisions~~implementation of the ~~revised guidance.~~authoritative guidance and performed an initial assessment of its existing leasing arrangements and other contractual obligations. The Company also continues to evaluate and document technical accounting issues, policy considerations, financial reporting and disclosure implications, and changes to internal controls and businesses processes. While the Company continues to assess the impact on its financial statements, the Company expects that adoption of the authoritative guidance will result in an increase to its assets and liabilities on its consolidated balance sheet.

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In March 2016, the FASB issued authoritative guidance simplifying several aspects of the accounting for stock-based compensation. The Company adopted this guidance effective as of October 1, 2016, recognizing a cumulative effect adjustment that increased retained earnings by $31.9 million. The cumulative effect represents the tax benefit of previously unrecognized tax deductions in excess of stock compensation recorded for financial reporting purposes. On a prospective basis, the tax effect of all future differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation will be recognized upon vesting or settlement as income tax expense or benefit in the income statement. From a statement of cash flows perspective, the tax benefits relating to differences between stock compensation recorded for financial reporting purposes and actual tax deductions for stock compensation are now included in cash provided by operating activities instead of cash provided by financing activities. The changes to the statement of cash flows were applied prospectively at the time of adoption.

~~In March~~August 2017, the FASB issued authoritative guidance ~~related to~~which changes the presentation of net periodic pension cost and net periodic postretirement benefit cost. The new guidance requires segregation of the service cost component from the other components of net periodic pension cost and net periodic postretirement benefit cost for financial reporting ~~purposes. The service cost component is~~of hedging relationships to ~~be presented on~~better portray the ~~income statement in~~economic results of an entity's risk management activities and to simplify the ~~same line items as other compensation costs included within Operating Expenses and the other components~~application of net periodic pension cost and net periodic postretirement benefit cost are to be presented on the income statement below the subtotal labeled Operating Income (Loss). Under this guidance, the service cost component shall be the only component eligible to be capitalized as part of the cost of inventory or property, plant and equipment.hedge accounting. The new guidance will be effective as of the Company’s first quarter of fiscal ~~2019,~~2020, with early adoption permitted. The Company does not ~~anticipate early~~expect adoption of this guidance to have a significant impact on its consolidated financial statements and is currently evaluating the ~~interaction~~impact of this guidance.

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 the Energy Marketing segment. 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.

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The following tables provide a disaggregation of the Company's revenues for the quarter and nine months ended June 30, 2019, presented by type of service from each reportable segment.



Quarter Ended June 30, 2019 (Thousands)
Revenues By Type of Service	Exploration and Production		Pipeline and Storage		Gathering		Utility		Energy Marketing			All Other		Corporate and Intersegment Eliminations			Total Consolidated
Production of Natural Gas	$	113,975	$	—	$	—	$	—	$	—		$	—	$	—		$	113,975
Production of Crude Oil	38,823		—		—		—		—			—		—			38,823
Natural Gas Processing	731		—		—		—		—			—		—			731
Natural Gas Gathering Services	—		—		32,875		—		—			—		(32,875		)	—
Natural Gas Transportation Service	—		50,001		—		23,010		—			—		(17,672		)	55,339
Natural Gas Storage Service	—		18,598		—		—		—			—		(8,060		)	10,538
Natural Gas Residential Sales	—		—		—		96,146		—			—		—			96,146
Natural Gas Commercial Sales	—		—		—		12,107		—			—		—			12,107
Natural Gas Industrial Sales	—		—		—		1,032		—			—		—			1,032
Natural Gas Marketing	—		—		—		—		22,212			—		(681		)	21,531
Other	152		368		—		161		5			854		(20		)	1,520
Total Revenues from Contracts with Customers	153,681		68,967		32,875		132,456		22,217			854		(59,308		)	351,742
Alternative Revenue Programs	—		—		—		465		—			—		—			465
Derivative Financial Instruments	5,194		—		—		—		(201		)	—		—			4,993
Total Revenues	$	158,875	$	68,967	$	32,875	$	132,921	$	22,016		$	854	$	(59,308	)	$	357,200



Nine Months Ended June 30, 2019 (Thousands)
Revenues By Type of Service	Exploration and Production			Pipeline and Storage		Gathering		Utility			Energy Marketing		All Other		Corporate and Intersegment Eliminations			Total Consolidated
Production of Natural Gas	$	371,710		$	—	$	—	$	—		$	—	$	—	$	—		$	371,710
Production of Crude Oil	111,256			—		—		—			—		—		—			111,256
Natural Gas Processing	2,676			—		—		—			—		—		—			2,676
Natural Gas Gathering Services	—			—		91,931		—			—		—		(91,931		)	—
Natural Gas Transportation Service	—			158,376		—		103,723			—		—		(54,556		)	207,543
Natural Gas Storage Service	—			56,887		—		—			—		—		(24,367		)	32,520
Natural Gas Residential Sales	—			—		—		492,267			—		—		—			492,267
Natural Gas Commercial Sales	—			—		—		68,408			—		—		—			68,408
Natural Gas Industrial Sales	—			—		—		4,400			—		—		—			4,400
Natural Gas Marketing	—			—		—		—			130,015		—		(1,056		)	128,959
Other	1,028			3,112		2		(8,662		)	15		2,170		(529		)	(2,864		)
Total Revenues from Contracts with Customers	486,670			218,375		91,933		660,136			130,030		2,170		(172,439		)	1,416,875
Alternative Revenue Programs	—			—		—		(1,528		)	—		—		—			(1,528		)
Derivative Financial Instruments	(18,817		)	—		—		—			3,461		—		—			(15,356		)
Total Revenues	$	467,853		$	218,375	$	91,933	$	658,608		$	133,491	$	2,170	$	(172,439	)	$	1,399,991

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Exploration and Production Segment Revenue

The Company’s Exploration and Production segment records revenue from the sale of the natural gas and oil that it produces and natural gas liquids (NGLs) processed based on entitlement, which means that revenue is recorded based on the actual amount of natural gas or oil that is delivered to a pipeline, or upon pick-up in the case of NGLs, and the Company’s ownership interest. Natural gas production occurs primarily in the Appalachian region of the United States and crude oil production occurs primarily in the West Coast region of the United States. If a production imbalance occurs between what was supposed to be delivered to a pipeline and what was actually produced and delivered, the Company accrues the difference as an imbalance. The sales contracts generally require the Company to deliver a specific quantity of a commodity per day for a specific number of days at a price that is either fixed or variable and considers the delivery of each unit (MMBtu or Bbl) to be a separate performance obligation that is satisfied upon delivery.

The transaction price for the sale of natural gas, oil and NGLs is contractually agreed upon based on prevailing market pricing (primarily tied to a market index with certain adjustments based on factors such as delivery location and prevailing supply and demand conditions) or fixed pricing. The Company allocates the transaction price to each performance obligation on the basis of the relative standalone selling price of each distinct unit sold. Revenue is recognized at a point in time when the transfer of the commodity occurs at the delivery point per the contract. The amount billable, as determined by the contracted quantity and price, indicates the value to the customer, and is used for revenue recognition purposes by the Exploration and Production segment as specified by the “invoice practical expedient” (the amount that the Exploration and Production segment has the right to invoice) under the authoritative guidance for revenue recognition. The contracts typically require payment within 30 days of the end of the calendar month in which the natural gas and oil is delivered, or picked up in the case of NGLs.

The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment related to sales of the natural gas and oil that it produces. Gains or losses on such derivative financial instruments are recorded as adjustments to revenue; however, they are not considered to be revenue from contracts with customers.

Pipeline and Storage Segment Revenue

The Company’s Pipeline and Storage segment records revenue for natural gas transportation and storage services in New York and Pennsylvania at tariff-based rates regulated by the FERC. Customers secure their own gas supply and the Pipeline and Storage segment provides transportation and/or storage services to move the customer-supplied gas to the intended location, including injections into or withdrawals from the storage field. This performance obligation is satisfied over time. The rate design for the Pipeline and Storage segment’s customers generally includes a combination of volumetric or commodity charges as well as monthly “fixed” charges (including charges commonly referred to as capacity charges, demand charges, or reservation charges). These types of fixed charges represent compensation for standing ready over the period of the month to deliver quantities of gas, regardless of whether the customer takes delivery of any quantity of gas. The performance obligation under these circumstances is satisfied based on the passage of time and meter reads, if applicable, which correlates to the period for which the charges are eligible to be invoiced. The amount billable, as determined by the meter read and the “fixed” monthly charge, indicates the value to the customer, and is used for revenue recognition purposes by the Pipeline and Storage segment as specified by the “invoice practical expedient” (the amount that the Pipeline and Storage segment has the right to invoice) under the authoritative guidance for revenue recognition. Customers are billed after the end of each calendar month, with payment typically due by the 25th day of the month in which the invoice is received.

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: $41.8 million for the remainder of fiscal 2019; $158.9 million for fiscal 2020; $135.3 million for fiscal 2021; $114.1 million for fiscal 2022; $82.3 million for fiscal 2023; and $370.5 million thereafter.

Gathering Segment Revenue

The Company’s Gathering segment provides gathering and processing services in the Appalachian region of Pennsylvania, primarily for Seneca. The Gathering segment’s primary performance obligation is to deliver gathered natural gas volumes from Seneca’s wells into interstate pipelines at contractually agreed upon per unit rates. This obligation is satisfied over time. The performance obligation is satisfied based on the passage of time and meter reads, which correlates to the period for which the charges are eligible to be invoiced. The amount billable, as determined by the meter read and the contracted volumetric rate, indicates the value to the customer, and is used for revenue recognition purposes by the Gathering segment as specified by the “invoice practical expedient” (the amount that the Gathering segment has the right to invoice) under the authoritative guidance for revenue recognition. Customers are billed after the end of each calendar month, with payment typically due by the 10th day after the invoice is received.

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Utility Segment Revenue

The Company’s Utility segment records revenue for natural gas sales and natural gas transportation services in western New York and northwestern Pennsylvania at tariff-based rates regulated by the NYPSC and the PaPUC. Natural gas sales and transportation services are provided largely to residential, commercial and industrial customers. The Utility segment’s performance obligation to its customers is to deliver natural gas, an obligation which is satisfied over time. This obligation generally remains in effect as long as the customer consumes the natural gas provided by the Utility segment. The Utility segment recognizes revenue when it satisfies its performance obligation by delivering natural gas to the customer. Natural gas is delivered and consumed by the customer simultaneously. The satisfaction of the performance obligation is measured by the turn of the meter dial. The amount billable, as determined by the meter read and the tariff-based rate, indicates the value to the customer, and is used for revenue recognition purposes by the Utility segment as specified by the “invoice practical expedient” (the amount that the Utility segment has the right to invoice) under the authoritative guidance for revenue recognition. Since the Utility segment bills its customers in cycles having billing dates that do not generally coincide with the ~~various regulatory provisions concerning pension~~end of a calendar month, a receivable is recorded for natural gas delivered but not yet billed to customers based on an estimate of the amount of natural gas delivered between the last meter reading date and ~~postretirement benefit costs~~the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets. The Utility segment’s tariffs allow customers to utilize budget billing. In this situation, since the amount billed may differ from the amount of natural gas delivered to the customer in any given month, revenue is recognized monthly based on the amount of natural gas consumed. The differential between the amount billed and the amount consumed is recorded as a component of Receivables or Customer Advances on the Consolidated Balance Sheets. All receivables or advances related to budget billing are settled within one year.

Utility Segment Alternative Revenue Programs

As indicated in the revenue table shown above, the Company’s Utility segment has alternative revenue programs that are excluded from the scope of the new authoritative guidance regarding revenue recognition. The NYPSC has authorized alternative revenue programs that are designed to mitigate the impact that weather and ~~Pipeline~~conservation have on margin. The NYPSC has also authorized additional alternative revenue programs that adjust billings for the effects of broad external factors or to compensate the Company for demand-side management initiatives. These alternative revenue programs primarily allow the Company and ~~Storage segments.~~customer to share in variances from imputed margins due to migration of transportation customers, allow for adjustments to the gas cost recovery mechanism for fluctuations in uncollectible expenses associated with gas costs, and allow the Company to pass on to customers costs associated with customer energy efficiency programs. In general, revenue is adjusted monthly for these programs and is collected from or passed back to customers within 24 months of the annual reconciliation period.

Energy Marketing Segment Revenue

The Company’s Energy Marketing segment records revenue for competitively priced natural gas sales in western and central New York and northwestern Pennsylvania. Sales are provided largely to industrial, wholesale, commercial, public authority and residential customers. The Energy Marketing segment’s performance obligation to its customers is to deliver natural gas, an obligation which is satisfied over time. This obligation generally remains in effect as long as the customer consumes the natural gas provided by the Energy Marketing segment. The Energy Marketing segment recognizes revenue when it satisfies its performance obligation by delivering natural gas to the customer. Natural gas is delivered and consumed by the customer simultaneously. The satisfaction of the performance obligation is measured by the turn of the meter dial. The amount billable, as determined by the meter read and the contracted or market based rate, indicates the value to the customer, and is used for revenue recognition purposes by the Energy Marketing segment as specified by the “invoice practical expedient” (the amount that the Energy Marketing segment has the right to invoice) under the authoritative guidance for revenue recognition. Since the Energy Marketing segment bills its residential customers in cycles having billing dates that do not generally coincide with the end of a calendar month, a receivable is recorded for natural gas delivered but not yet billed to customers based on an estimate of the amount of natural gas delivered between the last meter reading date and the end of the accounting period. Such receivables are a component of Unbilled Revenue on the Consolidated Balance Sheets. The Energy Marketing segment also allows customers to utilize budget billing. In this situation, since the amount billed may differ from the amount of natural gas delivered to the customer in any given month, revenue is recognized monthly based on the amount of natural gas consumed. The differential between the amount billed and the amount consumed is recorded as a component of Receivables or Customer Advances on the Consolidated Balance Sheets. All receivables or advances related to budget billing are settled within one year.

The Company uses derivative financial instruments to manage commodity price risk in the Energy Marketing segment related to the sale of natural gas to its customers. Gains or losses on such derivative financial instruments are recorded as adjustments to revenue; however, they are not considered to be revenue from contracts with customers.

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Note 23 – 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, 2017~~June 30, 2019 and September 30, ~~2017~~2018. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over the counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company.


Recurring Fair Value Measures	At fair value as of December 31, 2017												At fair value as of June 30, 2019
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾			Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾
Assets:
Cash Equivalents – Money Market Mutual Funds	$	132,231	$	—	$	—	$	—		$	132,231		$	75,375	$	—	$	—	$	—		$	75,375
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	1,374		—		—		(1,374		)	—			1,367		—		—		(1,367		)	—
Over the Counter Swaps – Gas and Oil	—		30,853		—		(10,312		)	20,541			—		44,929		—		(6,850		)	38,079
Foreign Currency Contracts	—		1,232		—		(666		)	566			—		78		—		(1,500		)	(1,422		)
Other Investments:
Balanced Equity Mutual Fund	36,979		—		—		—			36,979			40,313		—		—		—			40,313
Fixed Income Mutual Fund	44,232		—		—		—			44,232			55,034		—		—		—			55,034
Common Stock – Financial Services Industry	3,239		—		—		—			3,239			1,841		—		—		—			1,841
Hedging Collateral Deposits	4,465		—		—		—			4,465			6,835		—		—		—			6,835
Total	$	222,520	$	32,085	$	—	$	(12,352	)	$	242,253		$	180,765	$	45,007	$	—	$	(9,717	)	$	216,055

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	2,190	$	—	$	—	$	(1,374	)	$	816		$	5,686	$	—	$	—	$	(1,367	)	$	4,319
Over the Counter Swaps – Gas and Oil	—		16,312		—		(10,312		)	6,000			—		7,071		—		(6,850		)	221
Foreign Currency Contracts	—		429		—		(666		)	(237		)	—		1,523		—		(1,500		)	23
Total	$	2,190	$	16,741	$	—	$	(12,352	)	$	6,579		$	5,686	$	8,594	$	—	$	(9,717	)	$	4,563
Total Net Assets/(Liabilities)	$	220,330	$	15,344	$	—	$	—		$	235,674		$	175,079	$	36,413	$	—	$	—		$	211,492

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Recurring Fair Value Measures	At fair value as of September 30, 2017											At fair value as of September 30, 2018
(Thousands of Dollars)	Level 1		Level 2		Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾		Level 1		Level 2			Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾
Assets:
Cash Equivalents – Money Market Mutual Funds	$	527,978	$	—	$	—	$	—		$	527,978	$	215,272	$	—		$	—	$	—		$	215,272
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	1,483		—		—		(963		)	520		1,075		—			—		(1,075		)	—
Over the Counter Swaps – Gas and Oil	—		38,977		—		(4,206		)	34,771		—		26,074			—		(17,041		)	9,033
Foreign Currency Contracts	—		1,227		—		(407		)	820		—		443			—		(443		)	—
Other Investments:
Balanced Equity Mutual Fund	37,033		—		—		—			37,033		38,468		—			—		—			38,468
Fixed Income Mutual Fund	45,727		—		—		—			45,727		51,331		—			—		—			51,331
Common Stock – Financial Services Industry	3,150		—		—		—			3,150		2,776		—			—		—			2,776
Hedging Collateral Deposits	1,741		—		—		—			1,741		3,441		—			—		—			3,441
Total	$	617,112	$	40,204	$	—	$	(5,576	)	$	651,740	$	312,363	$	26,517		$	—	$	(18,559	)	$	320,321

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	963	$	—	$	—	$	(963	)	$	—	$	2,412	$	—		$	—	$	(1,075	)	$	1,337
Over the Counter Swaps – Gas and Oil	—		5,309		—		(4,206		)	1,103		—		64,224			—		(17,041		)	47,183
Foreign Currency Contracts	—		407		—		(407		)	—		—		959			—		(443		)	516
Total	$	963	$	5,716	$	—	$	(5,576	)	$	1,103	$	2,412	$	65,183		$	—	$	(18,559	)	$	49,036
Total Net Assets/(Liabilities)	$	616,149	$	34,488	$	—	$	—		$	650,637	$	309,951	$	(38,666	)	$	—	$	—		$	271,285


⁽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, 2017~~June 30, 2019 and September 30, ~~2017,~~2018, the derivative financial instruments reported in Level 1 consist of natural gas NYMEX and ICE futures contracts used in the Company’s Energy Marketing segment. Hedging collateral deposits were ~~$4.5~~$6.8 million at ~~December 31, 2017~~June 30, 2019 and ~~$1.7~~$3.4 million at September 30, ~~2017,~~2018, which were associated with these futures contracts and have been reported in Level 1 as well. The derivative financial instruments reported in Level 2 at ~~December 31, 2017~~June 30, 2019 and September 30, ~~2017~~2018 consist of natural gas price swap agreements used in the Company’s Exploration and Production and Energy Marketing segments, crude oil price swap agreements used in the Company’s Exploration and Production segment, basis hedge swap agreements used in the Company's Energy Marketing segment and foreign currency contracts used in the Company's Exploration and Production ~~segment. The derivative financial instruments reported in Level 2 at December 31, 2017 also include basis hedge swap agreements used in the Company's Energy Marketing~~ segment. The fair value of the Level 2 price swap agreements 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, 2017~~,June 30, 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, 2017~~June 30, 2019 and ~~December 31, 2016,~~June 30, 2018, there were no assets or liabilities measured at fair value and classified as Level 3. For the quarters ended ~~December 31, 2017~~June 30, 2019 and ~~December 31, 2016~~,June 30, 2018, no transfers in or out of Level 1 or Level 2 occurred.

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Note 34 – Financial Instruments

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



	June 30, 2019				September 30, 2018
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,133,101	$	2,252,231	$	2,131,365	$	2,121,861

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

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

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

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



	At June 30, 2019		At September 30, 2018

Life Insurance Contracts	$	40,659	$	39,970
Equity Mutual Fund	40,313		38,468
Fixed Income Mutual Fund	55,034		51,331
Marketable Equity Securities	1,841		2,776
	$	137,847	$	132,545

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

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

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the quarter ended December 31, 2017 resulted in $1.5 million of cash proceeds and a realized gain of $0.4 million. The fair value of the fixed income mutual fund was $44.2 million at December 31, 2017 and $45.7 million at September 30, 2017. The gross unrealized loss on this fixed income mutual fund was $0.2 million at December 31, 2017 and was less than $0.1 million at September 30, 2017. A sale of shares in the fixed income mutual fund during the quarter ended December 31, 2017 resulted in $1.5 million of cash proceeds and a realized loss of less than $0.1 million. The fair value of the stock of an insurance company was $3.2 million at both December 31, 2017 and September 30, 2017. The gross unrealized gain on this stock was $2.3 million at December 31, 2017 and $2.2 million at September 30, 2017.net income. The insurance contracts and marketable equity and fixed income securities are primarily informal funding mechanisms for various benefit obligations the Company has to certain employees.

Derivative Financial Instruments. The Company uses derivative financial instruments to manage commodity price risk in the Exploration and Production segment as well as the Energy Marketing segment. 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 87 years. The Exploration and Production segment holds the majority of the Company’s derivative financial instruments.

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at ~~December 31, 2017~~June 30, 2019 and September 30, ~~2017~~2018. 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.

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Cash Flow Hedges

For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains and losses on the derivative representing either hedge ineffectiveness or hedge components excluded from the assessment of effectiveness are recognized in current earnings.

As of ~~December 31, 2017~~June 30, 2019, the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding:



Commodity	Units
Natural Gas	~~99.1~~80.2	Bcf (short positions)
Natural Gas	~~1.6~~3.7	Bcf (long positions)
Crude Oil	~~3,645,000~~3,225,000	Bbls (short positions)

As of ~~December 31, 2017,~~June 30, 2019, the Company was hedging a total of ~~$94.7~~$79.7 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions).

As of ~~December 31, 2017,~~June 30, 2019, the Company had ~~$17.5~~$36.7 million ($~~10.3~~26.2 million after tax) of net hedging gains included in the accumulated other comprehensive income (loss) balance. It is expected that ~~$5.0~~$28.7 million ($~~3.0~~20.5 million after tax) of ~~such~~ unrealized gains will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged ~~transaction~~transactions are recorded in earnings.



The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended June 30, 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) (Effective Portion) for the Three Months Ended June 30,					Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Three Months Ended June 30,						Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Three Months Ended June 30,
	2019		2018				2019			2018				2019		2018
Commodity Contracts	$	33,531	$	(35,976	)	Operating Revenue	$	4,091		$	(3,249	)	Operating Revenue	$	1,020	$	(339	)
Commodity Contracts	150		124			Purchased Gas	—			5			Not Applicable	—		—
Foreign Currency Contracts	530		(1,600		)	Operating Revenue	(222		)	(527		)	Not Applicable	—		—
Total	$	34,211	$	(37,452	)		$	3,869		$	(3,771	)		$	1,020	$	(339	)

1823

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The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Nine Months Ended June 30, 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) (Effective Portion) for the Nine Months Ended June 30,						Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Nine Months Ended June 30,						Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Nine Months Ended June 30,
	2019			2018				2019			2018				2019		2018
Commodity Contracts	$	56,356		$	(52,440	)	Operating Revenue	$	(18,692	)	$	6,125		Operating Revenue	$	783	$	(436	)
Commodity Contracts	(1,183		)	737			Purchased Gas	(1,182		)	952			Not Applicable	—		—
Foreign Currency Contracts	(1,554		)	(3,831		)	Operating Revenue	(624		)	(1,500		)	Not Applicable	—		—
Total	$	53,619		$	(55,534	)		$	(20,498	)	$	5,577			$	783	$	(436	)

The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended December 31, 2017 and 2016 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Three Months Ended December 31, Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Three Months Ended December 31, Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Three Months Ended December 31,
2017 2016 2017 2016 2017 2016
Commodity Contracts $ (5,948 ) $ (50,444 ) Operating Revenue $ 12,842
$ 31,320
Operating Revenue $ (433 ) $ (100 )
Commodity Contracts 956
(1,536 ) Purchased Gas 196
(460 ) Not Applicable —
—
Foreign Currency Contracts (507 ) (521 ) Operation and Maintenance Expense (490 ) (143 ) Not Applicable —
—
Total $ (5,499 ) $ (52,501 ) $ 12,548
$ 30,717
$ (433 ) $ (100 )

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, 2017,~~June 30, 2019, the Company’s Energy Marketing segment had fair value hedges covering approximately ~~21.2~~24.8 Bcf ~~(20.6~~(24.3 Bcf of fixed price sales commitments and ~~0.6~~0.5 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, 2017 (In Thousands)			Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the Three Months Ended December 31, 2017 (In Thousands)			Location of Gain or (Loss) on Derivative and Hedged Item Recognized in the Consolidated Statement of Income	Amount of Gain or (Loss) on Derivative Recognized in the Consolidated Statement of Income for the Nine Months Ended June 30, 2019 (In Thousands)			Amount of Gain or (Loss) on the Hedged Item Recognized in the Consolidated Statement of Income for the Nine Months Ended June 30, 2019 (In Thousands)
Commodity Contracts	Operating Revenues	$	(1,753	)	$	1,753		Operating Revenues	$	(3,507	)	$	3,507
Commodity Contracts	Purchased Gas	$	137		$	(137	)	Purchased Gas	$	240		$	(240	)
		$	(1,616	)	$	1,616			$	(3,267	)	$	3,267

Credit Risk

The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly

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basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy

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traders. The Company has over-the-counter swap positions and applicable foreign currency forward contracts with ~~sixteen~~eighteen counterparties of which ~~ten~~seventeen are in a net gain position. On average, the Company had $2.1 million of credit exposure per counterparty in a gain position at ~~December 31, 2017.~~June 30, 2019. The maximum credit exposure per counterparty in a gain position at ~~December 31, 2017~~June 30, 2019 was ~~$8.1~~$6.1 million. As of ~~December 31, 2017,~~June 30, 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, 2017, thirteen~~June 30, 2019, fifteen of the ~~sixteen~~eighteen 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, 2017,~~June 30, 2019, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was ~~$19.2~~$27.3 million according to the Company’s internal model (discussed in Note 23 — Fair Value Measurements). At ~~December 31, 2017,~~June 30, 2019, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was ~~$4.2~~$0.2 million according to the Company's internal ~~model (discussed in Note 2 - Fair Value Measurements).~~model. For its over-the-counter swap agreements and foreign currency forward contracts, no hedging collateral deposits were required to be posted by the Company at ~~December 31, 2017.~~ June 30, 2019.

For its exchange traded futures contracts, the Company was required to post ~~$4.5~~$6.8 million in hedging collateral deposits as of ~~December 31, 2017.~~June 30, 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. ~~This is discussed in Note 1 under Hedging Collateral Deposits.~~

Note 45 - Income Taxes

The effective tax ~~rate~~rates for the quarters ended ~~December 31, 2017~~June 30, 2019 and ~~December 31, 2016~~June 30, 2018 were 24.9% and 23.3%, respectively. The increase in the effective tax rates was primarily the result of a one-time tax benefit recorded as part of an IRS settlement in fiscal 2018. The effective tax rates for the nine months ended June 30, 2019 and June 30, 2018 were 22.3% and negative ~~69.2% and 38.8%~~7.2%, respectively. The difference is a result of the impact of the one-time remeasurement of the deferred income tax liability ~~and a lower statutory rate of 24.5% as a result of~~under the 2017 Tax Reform ~~Act (as discussed below).~~Act.

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

The above changes had a material impact on the financial statements in the quarter ended December 31, 2017. Under GAAP, the tax effects of a change in tax law must be recognized in the period in which the law is enacted, or the quarter ending December 31, 2017 for the 2017 Tax Reform Act. GAAP also requires deferred income tax assets and liabilities to be measured at the enacted tax rate expected to apply when temporary differences are to be realized or settled. The Company’s accumulated deferred income taxes were remeasured based upon the new tax rates. For the non-rate regulated activities through the year ended September 30, 2018, the change in beginning of the year deferred income taxes ~~was $111.0~~of $103.5 million ~~and~~ was recorded as a reduction to income tax expense. For the Company's rate regulated activities, the reduction in

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deferred income taxes of $336.7 million was recorded as a decrease to Recoverable Future Taxes of $65.7 million and an increase to Taxes Refundable to Customers of $271.0 million. The 2017 Tax Reform Act includes provisions that stipulate how these excess deferred taxes are to be passed back to customers for certain accelerated tax depreciation benefits. Potential refunds of other deferred income taxes will be determined by the federal and state regulatory agencies. ~~The Company is awaiting regulatory guidance in the jurisdictions in which it operates.~~For further discussion, refer to Note 10 — Regulatory Matters.

The 2017 Tax Reform Act also ~~repealed the corporate alternative minimum tax (AMT) and~~ provides that the Company’s existing ~~AMT~~alternative minimum tax (AMT) credit carryovers are refundable, if not utilized to reduce tax, beginning in fiscal 2019. AsDuring fiscal 2018, the Department of ~~December 31, 2017,~~Treasury indicated that a portion of the ~~Company had $92.0 million of~~refundable AMT credit carryovers ~~that are expected~~would be subject to ~~be utilized or refunded between fiscal 2019 and fiscal 2022.~~

~~The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118) which provides for up~~sequestration. Accordingly, the Company recorded a $5.0 million valuation allowance related to a one year period (the measurement period) in which to complete the required analysis and income tax accounting for the 2017 Tax Reform Act. SAB 118 describes three scenarios associated with a company’s status of accounting for income tax reform: (1) a company is complete with its~~accounting for certain effects of tax reform, (2) a company is able to determine areasonable estimate for certain effects of tax reform and records that estimate as aprovisional amount, or (3) a company is not able to determine a reasonable estimate andtherefore continues to apply the provisions of the taxlaws that were in effect immediately prior to the 2017 Tax Reform Act being enacted.~~

The Company has determined a reasonable estimate for the measurement of the changes in deferred income taxes (noted above), which have been reflected as provisional amounts in the December 31, 2017 financial statements. The final determination of the impact of the income tax effects of these items will require additional analysis and further interpretation of the 2017 Tax Reform Act from yet to be issued U.S. Treasury regulations, state income tax guidance, federal and state regulatory guidance and technical corrections.

~~Note 5 -Capitalization~~

~~Common Stock.~~this sequestration. During the ~~three months~~quarter ended December 31, ~~2017,~~2018, the Office of Management and Budget determined that these AMT refunds would not be subject to sequestration. As such, the Company has removed the valuation allowance. In addition, the Company reclassified the estimated fiscal 2019 refund, approximately $42.5 million, from Deferred Income Taxes to Other Assets.

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Note 6 -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 April 1, 2019	86,301	$	86,301	$	821,837		$	1,236,657		$	(54,286	)
Net Income Available for Common Stock							63,753
Dividends Declared on Common Stock ($0.435 Per Share)							(37,543		)
Other Comprehensive Income, Net of Tax										21,620
Share-Based Payment Expense ⁽¹⁾				5,054
Common Stock Issued Under Stock and Benefit Plans	6	6		352
Balance at June 30, 2019	86,307	$	86,307	$	827,243		$	1,262,867		$	(32,666	)

Balance at October 1, 2018	85,957	$	85,957	$	820,223		$	1,098,900		$	(67,750	)
Net Income Available for Common Stock							257,009
Dividends Declared on Common Stock ($1.285 Per Share)							(110,885		)
Cumulative Effect of Adoption of Authoritative Guidance for Financial Assets and Liabilities							7,437
Cumulative Effect of Adoption of Authoritative Guidance for Reclassification of Stranded Tax Effects							10,406
Other Comprehensive Income, Net of Tax										35,084
Share-Based Payment Expense ⁽¹⁾				15,008
Common Stock Issued (Repurchased) Under Stock and Benefit Plans	350	350		(7,988		)
Balance at June 30, 2019	86,307	$	86,307	$	827,243		$	1,262,867		$	(32,666	)

Balance at April 1, 2018	85,882	$	85,882	$	810,126		$	1,070,939		$	(47,760	)
Net Income Available for Common Stock							63,025
Dividends Declared on Common Stock ($0.425 Per Share)							(36,526		)
Other Comprehensive Loss, Net of Tax										(24,636		)
Share-Based Payment Expense ⁽¹⁾				3,558
Common Stock Issued Under Stock and Benefit Plans	62	62		2,711
Balance at June 30, 2018	85,944	$	85,944	$	816,395		$	1,097,438		$	(72,396	)

Balance at October 1, 2017	85,543	$	85,543	$	796,646		$	851,669		$	(30,123	)
Net Income Available for Common Stock							353,527
Dividends Declared on Common Stock ($1.255 Per Share)							(107,758		)
Other Comprehensive Loss, Net of Tax										(42,273		)
Share-Based Payment Expense ⁽¹⁾				10,632
Common Stock Issued Under Stock and Benefit Plans	401	401		9,117
Balance at June 30, 2018	85,944	$	85,944	$	816,395		$	1,097,438		$	(72,396	)


⁽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 nine months ended June 30, 2019, the Company issued ~~63,082~~126,879 original issue shares of common stock as a result of SARs exercises, ~~68,534~~79,654 original issue shares of common stock for restricted stock units that vested and ~~79,079~~281,882 original issue shares of common stock for performance shares that vested. In addition, the Company issued 25,453 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 25,879 original issue shares of common stock for the Company’s 401(k) plans. The Company also issued ~~6,912~~20,501 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~~nine months ended ~~December 31, 2017.~~June 30, 2019. Holders of ~~stock options, SARs, restricted share~~stock-based compensation awards ~~or restricted stock units~~ will often tender shares of common stock to the Company for payment

Table of ~~option exercise prices and/or~~Contents

of applicable withholding taxes. During the ~~three~~nine months ended ~~December 31, 2017, 51,218~~June 30, 2019, 159,137 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 ~~at December 31, 2017 will mature~~as of June 30, 2019 and September 30, 2018 had a maturity date within the following twelve-month period. Current Portion of Long-Term Debt at September 30, 2017 consisted of $300.0 million of 6.50% notes scheduled to mature in April 2018. The Company redeemed these notes on October 18, 2017 for $307.0 million, plus accrued interest. The call premium was recorded to Unamortized Debt Expense on the Consolidated Balance Sheet in October 2017.

Note 67 - 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, 2017~~June 30, 2019, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately ~~$3.0 million. This~~$7.1 million, which includes a $3.9 million estimated minimum liability to remediate a former manufactured gas plant site located in New York. In March 2018, the NYDEC issued a Record of Decision for this New York site and the minimum liability reflects the remedy selected in the Record of Decision. The Company's liability for such clean-up costs has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at ~~December 31, 2017.~~June 30, 2019. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately ~~4 years. The Company~~3 years and is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company.

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Northern Access ~~2016~~ Project. On February 3, 2017, Supply Corporation and Empire received FERC approval of the Northern Access ~~2016~~ project described herein. On April 7, 2017, 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 on January 27, 2017). On April 21, 2017, Supply Corporation and Empire filed a Petition for Review in the United States Court of Appeals for the Second Circuit of the NYDEC's Notice of Denial with respect to National Fuel's application for the Water Quality Certification, and on May 11, 2017, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. ~~The Company also has pending with~~On August 6, 2018, the FERC ~~a proceeding asserting, among other things,~~issued an Order finding that the NYDEC exceeded the ~~reasonable and~~ statutory time ~~frames~~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. In light of these ~~pending~~ legal actions and the ~~Company has not yet determined a target~~need to complete necessary project development activities in advance of construction, the in-service ~~date. As a result of the decision of the NYDEC, Supply Corporation and Empire evaluated the capitalized project costs~~date for impairment as of December 31, 2017 and determined that an impairment charge was not required. The evaluation considered probability weighted scenarios of undiscounted future net cash flows, including a scenario assuming successful resolution with the NYDEC and construction of the pipeline, as well as a scenario where the project does not proceed. Further developments or indicators of an unfavorable resolution could result in the impairment of a significant portion of the project costs, which totaled $75.5 million at December 31, 2017. The project costs are included within Property, Plant and Equipment and Deferred Charges on the Consolidated Balance Sheet.is expected to be no earlier than fiscal 2022.

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

��

Note 78 – Business Segment Information

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

The data presented in the tables below reflect financial information for the segments and reconciliations to consolidated amounts. As stated in the ~~2017~~2018 Form 10-K, the Company evaluates segment performance based on income before discontinued operations, extraordinary items and cumulative effects of changes in accounting (when applicable). When these items are not applicable, the Company evaluates performance based on net income. There have not been any changes in the basis of segmentation nor in the basis of measuring segment profit or loss from those used in the Company’s ~~2017~~2018 Form 10-K. A listing of segment assets at ~~December 31, 2017~~June 30, 2019 and September 30, ~~2017~~2018 is shown in the tables below.

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Quarter Ended December 31, 2017 (Thousands)
Quarter Ended June 30, 2019 (Thousands)										Quarter Ended June 30, 2019 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Energy Marketing	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated	Exploration and Production	Pipeline and Storage	Gathering	Utility	Energy Marketing	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$139,141	$53,310	$170	$187,089	$38,636	$418,346	$1,096	$213	$419,655	$158,875	$46,024	$—	$129,977	$21,335	$356,211	$854	$135	$357,200
Intersegment Revenues	$—	$21,985	$23,665	$2,182	$126	$47,958	$—	$(47,958)	$—	$—	$22,943	$32,875	$2,944	$681	$59,443	$—	$(59,443)	$—
Segment Profit: Net Income (Loss)	$106,698	$38,462	$45,400	$20,993	$1,046	$212,599	$(719)	$(13,226)	$198,654	$26,512	$15,792	$14,638	$7,362	$(1,441)	$62,863	$(3)	$893	$63,753



Nine Months Ended June 30, 2019 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Energy Marketing	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$467,853	$148,663	$2	$648,624	$132,435	$1,397,577	$2,170	$244	$1,399,991
Intersegment Revenues	$—	$69,712	$91,931	$9,984	$1,056	$172,683	$—	$(172,683)	$—
Segment Profit: Net Income (Loss)	$86,599	$58,643	$41,511	$68,600	$(1,198)	$254,155	$252	$2,602	$257,009


(Thousands)	Exploration and Production	Pipeline and Storage	Gathering	Utility	Energy Marketing	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated	Exploration and Production	Pipeline and Storage	Gathering	Utility	Energy Marketing	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Segment Assets:
At December 31, 2017	$1,420,790	$1,793,848	$589,793	$1,988,758	$72,466	$5,865,655	$77,214	$(150,937)	$5,791,932
At September 30, 2017	$1,407,152	$1,929,788	$580,051	$2,013,123	$60,937	$5,991,051	$76,861	$35,408	$6,103,320
At June 30, 2019										$1,847,706	$1,894,824	$555,185	$1,967,123	$45,736	$6,310,574	$78,528	$(52,855)	$6,336,247
At September 30, 2018										$1,568,563	$1,848,180	$533,608	$1,921,971	$50,971	$5,923,293	$78,109	$35,084	$6,036,486

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Quarter Ended December 31, 2016 (Thousands)
Quarter Ended June 30, 2018 (Thousands)										Quarter Ended June 30, 2018 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Energy Marketing	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated	Exploration and Production	Pipeline and Storage	Gathering	Utility	Energy Marketing	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$160,932	$53,000	$26	$170,971	$36,809	$421,738	$554	$208	$422,500	$135,828	$51,363	$(31)	$128,628	$25,460	$341,248	$1,496	$168	$342,912
Intersegment Revenues	$—	$22,155	$27,840	$1,826	$19	$51,840	$—	$(51,840)	$—	$—	$22,496	$27,908	$3,519	$512	$54,435	$—	$(54,435)	$—
Segment Profit: Net Income (Loss)	$35,080	$19,368	$10,981	$21,175	$1,782	$88,386	$(179)	$701	$88,908	$27,817	$20,723	$11,566	$3,930	$(190)	$63,846	$297	$(1,118)	$63,025



Nine Months Ended June 30, 2018 (Thousands)
	Exploration and Production	Pipeline and Storage	Gathering	Utility	Energy Marketing	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Revenue from External Customers	$421,381	$158,387	$41	$599,495	$119,739	$1,299,043	$3,824	$606	$1,303,473
Intersegment Revenues	$—	$67,524	$79,404	$11,401	$589	$158,918	$—	$(158,918)	$—
Segment Profit: Net Income (Loss)	$161,052	$81,909	$68,736	$58,283	$1,434	$371,414	$(214)	$(17,673)	$353,527

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Note 89 – Retirement Plan and Other Post-Retirement Benefits

Components of Net Periodic Benefit Cost (in thousands):


	Retirement Plan						Other Post-Retirement Benefits						Retirement Plan						Other Post-Retirement Benefits
Three Months Ended December 31,	2017			2016			2017			2016
Three Months Ended June 30,													2019			2018			2019			2018

Service Cost	$	2,480		$	2,992		$	458		$	612		$	2,120		$	2,480		$	380		$	458
Interest Cost	8,252			9,596			3,700			4,752			9,594			8,252			4,286			3,700
Expected Return on Plan Assets	(15,429		)	(14,929		)	(7,871		)	(7,865		)	(15,591		)	(15,429		)	(7,539		)	(7,871		)
Amortization of Prior Service Cost (Credit)	235			264			(107		)	(107		)	206			235			(107		)	(107		)
Amortization of Losses	9,301			10,672			2,639			4,604			8,024			9,301			1,490			2,639
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾	1,721			535			3,608			1,312			(113		)	712			3,757			3,386

Net Periodic Benefit Cost	$	6,560		$	9,130		$	2,427		$	3,308		$	4,240		$	5,551		$	2,267		$	2,205




	Retirement Plan						Other Post-Retirement Benefits
Nine Months Ended June 30,	2019			2018			2019			2018

Service Cost	$	6,362		$	7,441		$	1,140		$	1,373
Interest Cost	28,783			24,754			12,858			11,101
Expected Return on Plan Assets	(46,775		)	(46,286		)	(22,618		)	(23,612		)
Amortization of Prior Service Cost (Credit)	619			703			(321		)	(322		)
Amortization of Losses	24,072			27,904			4,471			7,918
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) ⁽¹⁾	5,490			8,926			14,294			13,243

Net Periodic Benefit Cost	$	18,551		$	23,442		$	9,824		$	9,701


⁽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.

Employer Contributions. During the ~~three~~nine months ended ~~December 31, 2017,~~June 30, 2019, the Company contributed ~~$27.6~~$29.2 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and ~~$0.7~~$2.7 million to its VEBA trusts for its other post-retirement benefits. In the remainder of ~~2018,~~2019, the Company may contribute up to $5.0 million to the Retirement ~~Plan. In the remainder of 2018,~~Plan and the Company expects ~~its contributions~~ to ~~the VEBA trusts to be in the range of $2.0~~contribute approximately $0.2 million to ~~$3.0 million.~~its VEBA trusts.

Note 910– Regulatory Matters

New YorkJurisdiction

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

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 ~~Order also directs the implementation of an earnings sharing mechanism~~rate settlement does not specify any requirement to ~~be in place beginning on April 1, 2018.~~file a future rate case.

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

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~~On December 22, 2017,~~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 proposed rate increases are expected to be suspended, with an effective date of February 1, 2020, subject to refund. If the ~~federal Tax Cuts and Jobs Act (the 2017 Tax Reform Act) was enacted into law. On December 29, 2017,~~proposed rate increases finally approved at the ~~NYPSC issued an order instituting a proceeding to study the potential effects~~end of the ~~enactment~~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 ~~2017 Tax Reform Act on~~proceeding are lower than the ~~tax expenses~~rates in effect at July 31, 2019, such lower rates will become effective prospectively from the date of the applicable FERC order, and ~~liabilities of New York utilities,~~refunds with interest will be limited to the difference between the rates collected subject to refund and the ~~“regulatory treatment of any windfalls resulting from same~~rates in ~~order~~effect at July 31, 2019. In response to ~~preserve~~ the ~~benefits for ratepayers.” In~~FERC’s July 2018 Final Rule in RM18-11-000, et. al (Order No. 849), on December 6, 2018, Supply Corporation filed its order, the NYPSC stated that the effect of the 2017 Tax Reform Act on utilities’ taxation is likely to be material and complex and that the proceeding was needed to begin the process of addressing the impact on the State’s utilities and ratepayers. The order establishes that the first steps in such process will be soliciting information from its regulated utilities to quantifyForm 501-G, which addresses the impact of the 2017 Tax Reform Act, ~~scheduling a technical conference with~~and advised the utilities, and the issuance of a NY Department of Public Service Staff (Staff) proposal for accounting and ratemaking treatment of the tax changes. The order further states that once Staff’s proposal is issued, utilities and other interested parties will be invited to comment on Staff’s recommendation. The order also declares that utilities are “put on noticeCommission that it iswould make a Section 4 rate filing no later than July 31, 2019, which it has done, thereby obviating the ~~[NYPSC]’s intent~~need for FERC to ensure that net benefits accruing from the Tax Act are preserved for ratepayers, either through deferral accounting or another method, from the first day the Tax Act is put into effect. Utilities acting contrary to this intent do so at their own risk.” The Company cannot predict the outcome of this proceeding at this time.take any further action. Refer to Note 45 - Income Taxes for further discussion of the 2017 Tax Reform Act.

~~FERC Rate Proceedings~~

~~Supply Corporation currently has no active~~Empire filed a Section 4 rate case on ~~file. Supply Corporation's~~June 29, 2018, proposing rate increases to be effective August 1, 2018. Empire and its customers reached a settlement in principle in December 2018, and Empire’s subsequent motion to put in place those interim settlement rates, effective January 1, 2019, was approved by FERC’s Chief Administrative Law Judge on December 31, 2018. The settlement was approved May 3, 2019. The “black box” settlement provides for new, system-wide rates, and which, based on current ~~rate~~contracts, is estimated to increase Empire’s revenues on a yearly basis by approximately $4.6 million. The settlement ~~requires~~also provides new depreciation rates and a tiered transportation revenue sharing mechanism, beginning with Empire sharing 35% of transportation only revenues (net of certain excluded items) over $64.4 million up to Empire sharing 55% of those revenues over $68.4 million. Empire has also committed to undertake certain improvements to its electronic bulletin board and will convene regular customer meetings to address these and other improvements. Under the settlement, Empire and the other parties may not file to change rates until March 31, 2021, except that Empire may make a filing (to be effective November 1, 2020) under limited circumstances for contract changes with a large customer. Empire must file a Section 4 rate case ~~filing~~ no later than ~~December 31, 2019.~~May 1, 2025.

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

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

OVERVIEW

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

The Company is a diversified energy company engaged principally in the production, gathering, transportation, distribution and marketing of natural gas. The Company operates an integrated business, with assets centered in western New York and Pennsylvania, being utilized for, and benefiting from, the production and transportation of natural gas from the Appalachian basin. Current development activities are focused primarily in the Marcellus and Utica Shale. 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 five business segments.

For the quarter ended December 31, 2017 compared to the quarter ended December 31, 2016, the Company experienced an increase in earnings of $109.8 million. On December 22, 2017, the tax legislation referred to as the “Tax Cuts and Jobs Act” (the 2017 Tax Reform Act) was enacted. The 2017 Tax Reform Act significantly changes the taxation of business entities and includes specific provisions related to rate regulated companies. The more significant changes that impact the Company are the reduction in the corporate federal income tax rate from 35% to a blended 24.5% for fiscal 2018 and 21% for fiscal 2019 and beyond. As a fiscal year taxpayer, the Company is required to use a blended tax rate for fiscal 2018. As a result of the 2017 Tax Reform Act, the effective tax rate for the three months ended December 31, 2017 (negative 69.2%) reflects the impact of a one-time remeasurement of the Company's accumulated deferred income tax liability, a $111.0 million reduction to income tax expense. The effective tax rate also reflects a lower statutory rate of 24.5%. Without the one-time remeasurement of the Company's accumulated deferred income tax liability, the effective tax rate would have been 25.3%. For further discussion of the ~~impact of the 2017 Tax Reform Act to the Company, refer to Item 1 at Note 4 — Income Taxes. For further discussion of the Company’s~~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 second half of fiscal 2020 and an estimated cost of approximately $142 million. Another project on Supply Corporation’s system, referred to as the FM100 Project, will upgrade 1950’s era pipeline in northwestern Pennsylvania and create approximately 330,000 Dth per day of additional transportation capacity on Supply Corporation’s system in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County, Pennsylvania to the Transcontinental Gas Pipe Line Company, LLC system at Leidy, Pennsylvania. The FM100 Project has a target in-service date in late calendar 2021 and a preliminary cost estimate of approximately $280 million. These and other projects are discussed in more detail in the Capital Resources and Liquidity section that follows.

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

From a rate perspective, Supply Corporation filed a Section ~~401 Water Quality Certification~~4 rate case on July 31, 2019 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 on January 27, 2017). On April 21, 2017, the Company appealed the NYDEC's decisionEmpire reached a settlement in principle with its customers in December 2018 with regard to ~~the Water Quality Certification to the United States Court of Appeals for the Second Circuit, and~~Empire's Section 4 rate case. The Empire settlement was approved on May ~~11, 2017,~~3, 2019. Empire received permission to implement the ~~Company commenced legal action~~new rates effective January 1, 2019. This resulted in $1.2 million and $2.3 million of additional revenue during the quarter and nine months ended June 30, 2019, respectively. Based on current contracts, the settlement is estimated to increase Empire's revenues on a yearly basis by approximately $4.6 million. For further discussion of Supply Corporation and Empire rate matters, refer to Rate and Regulatory Matters below.

From a legislation perspective, in July 2019, New York State ~~Supreme Court challenging~~enacted legislation known as the ~~NYDEC's actions with regard~~Climate Leadership & Community Protection Act (CLCPA). This climate legislation mandates reduced greenhouse gas emissions to ~~various state permits. The Company also has pending with FERC a proceeding asserting, among other things, that the NYDEC exceeded the reasonable~~60% of 1990 levels by 2030, and statutory time frames to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. The Company remains committed to the project. Approximately $75.5 million in costs have been incurred on this project through December 31, 2017,15% of 1990 levels by 2050, with the ~~costs residing either in Construction Work in Progress,~~remaining emission reduction achieved by controlled offsets. The legislation also requires electric generators to meet 70% of demand with renewable energy by 2030 and 100% by 2040. In the near-term, the CLCPA establishes a ~~component~~series of ~~Property, Plant~~working groups to study how the state will achieve the aggressive emission reduction targets. It remains to be seen how state agencies will design and ~~Equipment on~~implement the ~~Consolidated Balance Sheet, or Deferred Charges.~~actual mechanisms for achieving the CLCPA's ambitious goals.

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

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

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its capital expenditure needs for ~~the remainder of~~ fiscal ~~2018~~2019 and may issue short-term and/or long-term debt during fiscal ~~2018~~2019 as needed.

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CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's ~~2017~~2018 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, 2017,~~June 30, 2019, the ceiling exceeded the book value of the oil and gas properties by approximately ~~$334.6~~$566.8 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, 2017,~~June 30, 2019, based on posted Midway Sunset prices, was ~~$48.41~~$64.69 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, 2017,~~June 30, 2019, based on the quoted Henry Hub spot price for natural gas, was ~~$2.98~~$3.02 per MMBtu. (Note – because actual pricing of the Company’s various producing properties varies depending on their location and hedging, the prices used to calculate the ceiling may differ from the Midway Sunset and HenryHub prices, which are only indicative of the 12-month average prices for the twelve months ended ~~December 31, 2017.~~June 30, 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 amounts the ceiling would have exceeded the book value of the Company's oil and gas properties at ~~December 31, 2017 (which would not have resulted in an impairment charge)~~June 30, 2019 if natural gas prices were $0.25 per MMBtu lower than the average prices used at ~~December 31, 2017,~~June 30, 2019, if crude oil prices were $5 per Bbl lower than the average prices used at ~~December 31, 2017,~~June 30, 2019, and 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, 2017~~June 30, 2019 (all amounts are presented after-tax). In all cases, these price decreases would not have resulted in an impairment charge. These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.


Ceiling Testing Sensitivity to Commodity Price Changes
�� Ceiling Testing Sensitivity to Commodity Price Changes							�� Ceiling Testing Sensitivity to Commodity Price Changes
(Millions)	$0.25/MMBtu Decrease in Natural Gas Prices		$5.00/Bbl Decrease in Crude Oil Prices		$0.25/MMBtu Decrease in Natural Gas Prices and $5.00/Bbl Decrease in Crude Oil Prices		$0.25/MMBtu Decrease in Natural Gas Prices		$5.00/Bbl Decrease in Crude Oil Prices		$0.25/MMBtu Decrease in Natural Gas Prices and $5.00/Bbl Decrease in Crude Oil Prices

Excess of Ceiling over Book Value under Sensitivity Analysis	$	188.4	$	295.4	$	149.2	$	336.9	$	533.3	$	303.3

It is difficult to predict what factors could lead to future impairments under the SEC's full cost ceiling test. Fluctuations in or subtractions from proved reserves, increases in development costs for undeveloped reserves and significant fluctuations in oil and gas prices have an impact on the amount of the ceiling at any point in time. For a more complete discussion of the full cost method of accounting, refer to "Oil and Gas Exploration and Development Costs" under "Critical Accounting Estimates" in Item 7 of the Company's ~~2017~~2018 Form 10-K.

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

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

The Company has determined a reasonable estimate under SAB 118 for the measurement of the changes in deferred income taxes in the December 31, 2017 financial statements. The final determination of the impact of the income tax effects of these items will require additional analysis and further interpretation of the 2017 Tax Reform Act from yet to be issued U.S. Treasury regulations, state income tax guidance, federal and state regulatory guidance and technical corrections. For further discussion of the impact of the 2017 Tax Reform Act to the Company, refer to Item 1 at Note 45 — Income Taxes.

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RESULTS OF OPERATIONS

Earnings

The Company's earnings were ~~$198.7~~$63.8 million for the quarter ended ~~December 31, 2017~~June 30, 2019 compared to earnings of ~~$88.9~~$63.0 million for the quarter ended ~~December 31, 2016.~~June 30, 2018. The increase in earnings of ~~$109.8~~$0.8 million is primarily a result of higher earnings in the ~~Exploration and Production~~Utility segment, Gathering segment and ~~Pipeline and Storage segment.~~Corporate category. Lower earnings in the ~~Energy Marketing~~Pipeline and Storage segment and ~~Utility~~Exploration and Production segment, as well as losses in the ~~Corporate~~Energy Marketing segment and All Other ~~categories~~category, partially offset these increases.

The Company's earnings were $257.0 million for the ~~quarter~~nine months ended ~~December 31, 2017 include~~June 30, 2019 compared to earnings of $353.5 million for the nine months ended June 30, 2018. The decrease in earnings of $96.5 million is primarily a ~~$111.0 million remeasurement~~result of a decrease in favorable remeasurements of accumulated deferred income taxes of $5.0 million and $107.0 million recorded during the ~~quarter~~nine months ended ~~December 31, 2017~~June 30, 2019 and ~~a lower statutory rate of 24.5%~~nine months ended June 30, 2018, respectively, as a result of the 2017 Tax Reform Act, as discussed above. Excluding these remeasurements, earnings were up $5.5 million year over year. Additional discussion of earnings in each of the business segments, including the impact of the 2017 Tax Reform Act, can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.

Earnings (Loss) by Segment


	Three Months Ended December 31,									Three Months Ended June 30,									Nine Months Ended June 30,
(Thousands)	2017			2016			Increase (Decrease)			2019			2018			Increase (Decrease)			2019			2018			Increase (Decrease)
Exploration and Production	$	106,698		$	35,080		$	71,618		$	26,512		$	27,817		$	(1,305	)	$	86,599		$	161,052		$	(74,453	)
Pipeline and Storage	38,462			19,368			19,094			15,792			20,723			(4,931		)	58,643			81,909			(23,266		)
Gathering	45,400			10,981			34,419			14,638			11,566			3,072			41,511			68,736			(27,225		)
Utility	20,993			21,175			(182		)	7,362			3,930			3,432			68,600			58,283			10,317
Energy Marketing	1,046			1,782			(736		)	(1,441		)	(190		)	(1,251		)	(1,198		)	1,434			(2,632		)
Total Reportable Segments	212,599			88,386			124,213			62,863			63,846			(983		)	254,155			371,414			(117,259		)
All Other	(719		)	(179		)	(540		)	(3		)	297			(300		)	252			(214		)	466
Corporate	(13,226		)	701			(13,927		)	893			(1,118		)	2,011			2,602			(17,673		)	20,275
Total Consolidated	$	198,654		$	88,908		$	109,746		$	63,753		$	63,025		$	728		$	257,009		$	353,527		$	(96,518	)

Exploration and Production

Exploration and Production Operating Revenues


	Three Months Ended December 31,								Three Months Ended June 30,								Nine Months Ended June 30,
(Thousands)	2017			2016		Increase (Decrease)			2019		2018			Increase (Decrease)			2019		2018		Increase (Decrease)
Gas (after Hedging)	$	98,115		$	120,564	$	(22,449	)	$	120,735	$	99,621		$	21,114		$	357,447	$	303,732	$	53,715
Oil (after Hedging)	40,214			39,457		757			36,238		35,312			926			105,921		114,190		(8,269		)
Gas Processing Plant	1,065			761		304			731		957			(226		)	2,676		3,095		(419		)
Other	(253		)	150		(403		)	1,171		(62		)	1,233			1,809		364		1,445
	$	139,141		$	160,932	$	(21,791	)	$	158,875	$	135,828		$	23,047		$	467,853	$	421,381	$	46,472

2733

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Production Volumes


	Three Months Ended December 31,				Three Months Ended June 30,				Nine Months Ended June 30,
	2017	2016	Increase (Decrease)		2019	2018	Increase (Decrease)		2019	2018	Increase (Decrease)
Gas Production (MMcf)
Appalachia	35,414	39,807	(4,393	)	50,766	40,444	10,322		140,954	117,261	23,693
West Coast	695	776	(81	)	494	526	(32	)	1,483	1,896	(413	)
Total Production	36,109	40,583	(4,474	)	51,260	40,970	10,290		142,437	119,157	23,280

Oil Production (Mbbl)
Appalachia	1	—	1		1	1	—		2	3	(1	)
West Coast	672	721	(49	)	575	600	(25	)	1,710	1,934	(224	)
Total Production	673	721	(48	)	576	601	(25	)	1,712	1,937	(225	)

Average Prices


	Three Months Ended December 31,							Three Months Ended June 30,							Nine Months Ended June 30,
	2017		2016		Increase (Decrease)			2019		2018		Increase (Decrease)			2019		2018		Increase (Decrease)
Average Gas Price/Mcf
Appalachia	$	2.35	$	2.35	$	—		$	2.21	$	2.30	$	(0.09	)	$	2.58	$	2.37	$	0.21
West Coast	$	5.00	$	4.24	$	0.76		$	3.84	$	4.41	$	(0.57	)	$	5.55	$	4.62	$	0.93
Weighted Average	$	2.40	$	2.39	$	0.01		$	2.22	$	2.32	$	(0.10	)	$	2.61	$	2.40	$	0.21
Weighted Average After Hedging	$	2.72	$	2.97	$	(0.25	)	$	2.36	$	2.43	$	(0.07	)	$	2.51	$	2.55	$	(0.04	)

Average Oil Price/Bbl
Appalachia	$	43.85	N/M		N/M			$	55.45	$	64.37	$	(8.92	)	$	55.80	$	55.06	$	0.74
West Coast	$	57.88	$	43.69	$	14.19		$	67.43	$	71.53	$	(4.10	)	$	65.01	$	64.69	$	0.32
Weighted Average	$	57.86	$	43.82	$	14.04		$	67.41	$	71.52	$	(4.11	)	$	65.00	$	64.68	$	0.32
Weighted Average After Hedging	$	59.79	$	54.71	$	5.08		$	62.92	$	58.74	$	4.18		$	61.88	$	58.96	$	2.92

~~N/M - Not Meaningful~~

~~2017~~2019 Compared with ~~2016~~2018

Operating revenues for the Exploration and Production segment ~~decreased $21.8~~increased $23.0 million for the quarter ended ~~December 31, 2017~~June 30, 2019 as compared with the quarter ended ~~December 31, 2016.~~June 30, 2018. Gas production revenue after hedging ~~decreased $22.4~~increased $21.1 million primarily due to a ~~decrease~~10.3 Bcf increase in gas production ~~coupled with~~partially offset by a ~~$0.25~~$0.07 per Mcf decrease in the weighted average price of gas after hedging. The ~~decrease~~increase in gas production was ~~primarily~~largely due to ~~natural declines from Marcellus wells in the Eastern Development Area. This was partially offset by production increases in the Western Development Area from~~ new Marcellus and Utica wells ~~coupled with a decrease~~completed and connected to sales in ~~price-related curtailments~~the Western and Eastern Development Areas in the Appalachian region during the quarter ended ~~December 31, 2017~~June 30, 2019 as compared towith the quarter ended ~~December 31, 2016. This decrease~~June 30, 2018. Seneca added a third rig in the Appalachian region in May 2018, which contributed to ~~operating revenues was partially offset by an~~the increase in ~~oil~~production. Oil production revenue after hedging ~~of $0.8 million. The increase in oil production revenue was~~increased $0.9 million primarily due to a ~~$5.08~~$4.18 per Bbl increase in the weighted average price of oil after hedging ~~which was largely~~partially offset by a 25 Mbbl decrease in crude oil production. In addition, other revenue increased $1.2 million primarily due to the impact of mark-to-market adjustments related to ineffectiveness on oil hedges.

Operating revenues for the Exploration and Production segment increased $46.5 million for the nine months ended June 30, 2019 as compared with the nine months ended June 30, 2018. Gas production revenue after hedging increased $53.7 million due to a 23.3 Bcf increase in gas production partially offset by a $0.04 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 nine months ended June 30, 2019 as compared with the nine months ended June 30, 2018. In addition, other revenue increased $1.4 million primarily due to the impact of mark-to-market adjustments related to ineffectiveness on oil hedges. These increases to operating revenues were partially offset by a

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decrease in oil production revenue after hedging of $8.3 million. The decrease in oil production revenue was primarily due to a 225 Mbbl decrease in crude oil production partially offset by a $2.92 per Bbl increase in the weighted average price of oil after hedging. The decrease in crude oil production was largely due to lower production in the West Coast region ~~was largely due to~~as a result of the ~~lagging current year impact~~sale of ~~decreased steam operations and well workover activity at its North Midway Sunset field~~Seneca’s Sespe properties in ~~prior years (due to lower crude oil prices) coupled with oil production losses due to temporary shut-in production in Ventura County, California in response to the wildfires occurring in fiscal~~May 2018. During the quarter ended December 31, 2017, there was an increase in steam operations and well workover activity versus the quarter ended December 31, 2016, which will stimulate future crude oil production.

~~Table of Contents~~

The Exploration and Production segment's earnings for the quarter ended ~~December 31, 2017~~June 30, 2019 were ~~$106.7~~$26.5 million, ~~an increase~~a decrease of ~~$71.6~~$1.3 million when compared with earnings of ~~$35.1~~$27.8 million for the quarter ended ~~December 31, 2016.~~June 30, 2018. The decrease in earnings was due to the lower crude oil production ($1.1 million), lower natural gas prices after hedging ($3.0 million), higher depletion expense ($6.6 million), higher production expenses ($7.6 million), higher interest expense ($0.5 million), and a higher effective tax rate ($3.3 million). The increase in ~~earnings~~depletion expense, which is computed using the units of production method, was primarily ~~reflects~~due to the ~~remeasurement of accumulated deferred~~increase in production coupled with a $0.03 per Mcfe increase in the depletion rate.The increase in production expenses was primarily due to increased gathering and transportation costs in the Appalachian region coupled with increased well workover costs in the West Coast region. The increase in the effective tax rate was primarily due to higher state income taxes ~~($77.3 million) combined with~~and the ~~current period earnings impact~~non-recurrence of a tax benefit realized in the ~~change in federal~~quarter ended June 30, 2018 related to the blended 24.5% tax rate impact on temporary differences, which were partially offset by the reduction in the Company’s federal statutory rate from ~~35% to~~ a blended ~~rate of~~ 24.5% ~~for~~in fiscal 2018 ~~on current income taxes~~to 21% in fiscal 2019. These factors, which decreased earnings during the quarter ended June 30, 2019, were partially offset by higher natural gas production ($~~4.1~~18.9 million), ~~both of which were the result of the 2017 Tax Reform Act. It also reflects~~ higher crude oil prices after hedging ($~~2.2~~1.8 million), ~~lower depletion expense~~and the impact of mark-to-market adjustments related to hedging ineffectiveness ($1.1 million).

The Exploration and ~~lower income tax expense, excluding~~Production segment's earnings for the nine months ended June 30, 2019 were $86.6 million, a decrease of $74.5 million when compared with earnings of $161.1 million for the nine months ended June 30, 2018. The decrease in earnings was primarily attributable to the impact of the 2017 Tax Reform Act, which resulted in a remeasurement of the segment’s accumulated deferred income taxes that lowered income tax expense during the nine months ended June 30, 2018 ($~~3.9~~76.5 million). A removal of a valuation allowance related to the 2017 Tax Reform Act during the nine months ended June 30, 2019 resulted in an adjustment to the remeasurement of the segment’s accumulated deferred income taxes and lowered income tax expense ($1.0 million). The ~~decrease~~reduction in the Company’s federal statutory rate from a blended 24.5% in fiscal 2018 to 21% in fiscal 2019 lowered income tax expense on current period earnings ($3.6 million), which was more than offset by the non-recurrence of a tax benefit realized in the nine months ended June 30, 2018 related to the blended tax rate impact on temporary differences ($6.3 million) coupled with higher state income taxes ($0.5 million).

Additionally, earnings decreased due to lower natural gas prices after hedging ($4.2 million), lower crude oil production ($10.0 million), higher depletion expense ($15.1 million), higher production expenses ($11.4 million), higher other operating expenses ($1.6 million), higher other taxes ($2.1 million), and higher interest expense ($0.4 million). The increase in depletion expense was primarily due to ~~a decrease~~the increase in production coupled with ana $0.03 per Mcfe increase in ~~reserves (an~~the depletion rate. The increase in ~~reserves lowers~~production expenses was primarily due to increased gathering and transportation costs in the ~~per mcf/barrel depletion rate)~~Appalachian region coupled with increased well workover and steam fuel costs in the West Coast region, partially offset by anthe aforementioned sale of Seneca’s Sespe properties in May 2018 and lower compression costs following the sale of compressor units to Midstream Company in March 2018. The increase in ~~capitalized costs. The decrease in income tax expense, excluding the impact of the 2017 Tax Reform Act,~~other operating expenses was largely due to an increase in ~~the enhanced oil recovery tax credit related~~personnel and compensation costs. The increase in other taxes was primarily due to ~~Seneca's California properties coupled with~~ a ~~decrease in state income taxes~~higher Pennsylvania impact fee as a result of ~~lower pre-tax net income~~additional wells drilled and a higher average natural gas price for calendar 2018, which is the basis for the ~~Exploration and Production segment.~~impact fee determination. These factors, which ~~contributed to increased~~decreased earnings during the ~~quarter~~nine months ended ~~December 31, 2017 compared to the quarter ended December 31, 2016,~~June 30, 2019, were partially offset by ~~lower~~higher natural gas production ($44.8 million) and higher crude oil prices after hedging ($~~6.0~~3.8 million)~~, lower natural gas production ($8.6 million), lower crude oil production ($1.7 million) and higher other operating expenses ($0.6 million)~~. ~~The increase in other operating expenses was primarily due to an increase in personnel costs.~~

Pipeline and Storage

Pipeline and Storage Operating Revenues


	Three Months Ended December 31,							Three Months Ended June 30,							Nine Months Ended June 30,
(Thousands)	2017		2016		Increase (Decrease)			2019		2018		Increase (Decrease)			2019		2018		Increase (Decrease)
Firm Transportation	$	56,756	$	56,749	$	7		$	49,744	$	54,227	$	(4,483	)	$	157,322	$	168,546	$	(11,224	)
Interruptible Transportation	340		646		(306		)	257		380		(123		)	1,054		1,108		(54		)
	57,096		57,395		(299		)	50,001		54,607		(4,606		)	158,376		169,654		(11,278		)
Firm Storage Service	17,839		17,273		566			18,597		18,951		(354		)	56,884		55,316		1,568
Interruptible Storage Service	19		12		7			1		3		(2		)	3		23		(20		)
Other	341		475		(134		)	368		298		70			3,112		918		2,194
	$	75,295	$	75,155	$	140		$	68,967	$	73,859	$	(4,892	)	$	218,375	$	225,911	$	(7,536	)

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Pipeline and Storage Throughput


	Three Months Ended December 31,				Three Months Ended June 30,				Nine Months Ended June 30,
(MMcf)	2017	2016	Increase (Decrease)		2019	2018	Increase (Decrease)		2019	2018	Increase (Decrease)
Firm Transportation	206,701	190,781	15,920		158,739	177,071	(18,332	)	550,262	583,452	(33,190	)
Interruptible Transportation	882	3,046	(2,164	)	309	1,107	(798	)	1,974	3,153	(1,179	)
	207,583	193,827	13,756		159,048	178,178	(19,130	)	552,236	586,605	(34,369	)

~~2017~~2019 Compared with ~~2016~~2018

Operating revenues for the Pipeline and Storage segment ~~remained relatively flat~~decreased $4.9 million for the quarter ended ~~December 31, 2017~~June 30, 2019 as compared with the quarter ended ~~December 31, 2016. An increase~~June 30, 2018. The decrease in operating revenues was primarily due to demand charges for transportation service from Supply Corporation's Line D Expansion, which was placed in service on November 1, 2017, and an increase in both transportation and storage revenues due to Supply Corporation's greenhouse gas and pipeline safety surcharge effective November 1, 2017, were largely offset by a ~~decline~~decrease in transportation revenues ~~due partially~~of $4.6 million. The decrease in transportation revenues was primarily attributable to an ~~additional 2% reduction~~Empire system transportation contract termination in ~~Supply Corporation's rates effective November 1, 2016, which was required by the rate case settlement approved by FERC on November 13, 2015, and~~December 2018 combined with a decline in demand charges for Supply Corporation's transportation services as a result of contract terminations. Partially offsetting these decreases was an increase in transportation revenues due to an increase in Empire's rates efffective January 1, 2019 in accordance with Empire's rate case settlement, which was approved by the FERC on May 3, 2019.

Operating revenues for the Pipeline and Storage segment decreased $7.5 million for the nine months ended June 30, 2019 as compared with the nine months ended June 30, 2018. The decrease in operating revenues was primarily due to a decrease in transportation revenues of $11.3 million attributable to an Empire system transportation contract termination in December 2018 combined with a decline in demand charges for Supply Corporation's transportation services as a result of contract terminations, partly offset by an increase in transportation revenues due to an increase in Empire's rates effective January 1, 2019 related to the rate case settlement mentioned above. For the remainder of fiscal 2019, the Pipeline and Storage segment expects transportation revenues to be negatively impacted in an amount up to approximately $3.7 million as a result of the Empire system transportation contract termination mentioned above. The contract was not renewed due to a change in market dynamics. Partially offsetting these decreases was an increase in storage revenues of $1.6 million combined with an increase in other revenues of $2.2 million. The increase in storage revenues was due to reservation charges for storage service from new storage contracts as a result of Supply Corporation's acquisition of the remaining interest in a jointly owned storage field in the third quarter of fiscal 2018. The increase 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.

Transportation volume for the quarter ended ~~December 31, 2017 increased~~June 30, 2019 decreased by ~~13.8~~19.1 Bcf from the prior ~~year’s~~year's quarter. For the nine months ended June 30, 2019, transportation volume decreased by 34.4 Bcf from the prior year's nine-month period ended June 30, 2018. The ~~increase~~decrease in transportation volume for the quarter and nine-month period primarily reflects ~~the impact of the Line D Expansion project being placed~~a reduction in ~~service~~capacity utilization by certain contract shippers combined with ~~colder weather quarter over quarter.~~contract terminations. 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.

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The Pipeline and Storage segment’s earnings for the quarter ended ~~December 31, 2017~~June 30, 2019 were ~~$38.5~~$15.8 million, ~~an increase~~a decrease of ~~$19.1~~$4.9 million when compared with earnings of ~~$19.4~~$20.7 million for the quarter ended ~~December 31, 2016.~~June 30, 2018. The ~~increase~~decrease in earnings was primarily due to the earnings impact of lower ~~income tax expense ($17.6 million)~~operating revenues of $3.7 million, as discussed above, combined with ~~lower~~higher operating expenses ($~~1.9 million) and a decrease in interest expense ($0.3~~2.6 million). ~~Income tax expense was lower due to the remeasurement of accumulated deferred income taxes ($14.1 million) combined with~~The increase in operating expenses primarily reflects an increase in pipeline integrity program expenses and increased personnel costs. These earnings decreases were slightly offset by the current period earnings impact of the change in the federal tax rate from ~~35% to~~ a blended rate of 24.5% in fiscal 2018 to 21% for fiscal ~~2018~~2019 ($~~3.5~~0.6 million)~~, both a result of the 2017 Tax Reform Act. The decrease in operating expenses primarily reflects lower pension and other post-retirement benefit costs~~ combined with a decrease in ~~the reserve for preliminary project costs.~~interest expense ($0.3 million). The decrease in interest expense was largely due to lower intercompany long-term borrowing interest rates for the Pipeline and Storage segment. ~~These~~

The Pipeline and Storage segment’s earnings ~~increases~~for the nine months ended June 30, 2019 were ~~slightly offset by~~$58.6 million, a decrease of $23.3 million when compared with earnings of $81.9 million for the nine months ended June 30, 2018. The decrease in earnings was primarily due to higher income tax expense ($10.0 million) combined with higher operating expenses ($8.0 million), the earnings impact of lower operating revenues of $5.7 million, as discussed above, an increase in depreciation expense ($~~0.6~~0.9 million) and an increase in property taxes ($0.9 million). Income tax expense was higher due to the remeasurement of accumulated deferred income taxes in the quarter ended December 31, 2017 as a result of the 2017 Tax Reform Act, recorded as a $14.1 million reduction to income tax expense in the prior year, which did not recur in the nine months ended June 30, 2019. Partially offsetting this

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income tax increase was the current period earnings impact of the change in the federal tax rate from a blended rate of 24.5% in fiscal 2018 to 21% for fiscal 2019 ($2.2 million) combined with lower income tax expense ($1.9 million) primarily due to permanent differences related to stock awards during the quarter ended December 31, 2018. The increase in operating expenses primarily reflects an increase in compressor station costs, including overhaul costs, as well as pipeline integrity program expenses, increased personnel costs and a reversal of reserves for preliminary project costs recorded in the quarter ended December 31, 2017 that did not recur. The increase in depreciation expense was due to incremental depreciation expense related to ~~expansion~~ projects that were placed in service within the last ~~year combined with the non-recurrence of~~year. The increase in property taxes was due to 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 ~~reduction~~decrease in interest expense ($1.1 million) and an increase in other income ($1.6 million). The decrease in interest expense was largely due to ~~depreciation expense recorded in the quarter ended December 31, 2016 to reflect a reduction in depreciation~~lower intercompany long-term borrowing interest rates ~~retroactive to July 1, 2016 in accordance with Empire's rate case settlement. The FERC issued an order approving the settlement on December 13, 2016.~~

~~Looking ahead,~~for the Pipeline and Storage ~~segment expects transportation revenues to be negatively impacted~~segment. The increase in ~~fiscal 2019 in an amount up to approximately $14 million as~~other income was a result of ~~an Empire system transportation contract reaching its termination date in December 2018. Management does not expect to renew the contract at existing rates given a change in market dynamics.~~higher non-service pension and post-retirement benefit income.

Gathering

Gathering Operating Revenues


	Three Months Ended December 31,							Three Months Ended June 30,							Nine Months Ended June 30,
(Thousands)	2017		2016		Increase (Decrease)			2019		2018			Increase (Decrease)		2019		2018		Increase (Decrease)
Gathering	$	23,802	$	27,840	$	(4,038	)	$	32,875	$	27,908		$	4,967	$	91,931	$	79,404	$	12,527
Processing and Other Revenues	33		26		7			—		(31		)	31		2		41		(39		)
	$	23,835	$	27,866	$	(4,031	)	$	32,875	$	27,877		$	4,998	$	91,933	$	79,445	$	12,488

Gathering Volume

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



	Three Months Ended June 30,			Nine Months Ended June 30,
	2019	2018	Increase (Decrease)	2019	2018	Increase (Decrease)
Gathered Volume - (MMcf)	60,745	51,392	9,353	169,590	145,928	23,662

~~2017~~2019 Compared with ~~2016~~2018

Operating revenues for the Gathering segment ~~decreased $4.0~~increased $5.0 million for the quarter ended ~~December 31, 2017~~June 30, 2019 as compared with the quarter ended ~~December 31, 2016,~~June 30, 2018. The increase was primarily due to a 9.4 Bcf net increase in gathered volume resulting from a 4.9 Bcf, 3.6 Bcf and 2.6 Bcf increase in volume on Midstream Company's Wellsboro, Clermont and Trout Run gathering systems, respectively, offset by a 1.7 Bcf decline on the Covington gathering system. The 9.4 Bcf net increase in gathered volumes can be attributed to the increase in Seneca's gas production quarter over quarter.

Operating revenues for the Gathering segment increased $12.5 million for the nine months ended June 30, 2019 as compared with the nine months ended June 30, 2018, which was driven by a ~~7.4~~23.7 Bcf ~~decrease~~increase in gathered volume. ~~The overall decrease~~Midstream Company experienced an 11.7 Bcf increase in gathered volume ~~was due to~~at its Clermont gathering system, an 8.6 Bcf increase in gathered volume at its Trout Run gathering system and a ~~5.2~~6.0 Bcf increase in gathered volume at its Wellsboro gathering system. These increases were partially offset by a 2.2 Bcf decrease in gathered volume on ~~Midstream Corporation’s Trout Run Gathering System (Trout Run),~~the Covington gathering system and a ~~2.0~~0.4 Bcf decrease in gathered volume collectively from the Mt. Jewett, Owl's Nest and Tionesta gathering systems, which were sold on ~~Midstream Corporation's Covington Gathering System (Covington), a 0.6~~February 1, 2018. The 23.7 Bcf decrease in gathered volume on Midstream Corporation's Wellsboro Gathering System (Wellsboro), and a 0.1 Bcf decrease in gathered volumes spread across numerous Midstream systems. These decreases were partially offset by a 0.5 Bcfnet increase in gathered volume ~~on Midstream Corporation's Clermont Gathering System (Clermont). The decreases in~~can be attributed to the ~~aforementioned volumes were largely due to a decrease~~increase in Seneca's ~~production.~~gas production for the nine months ended June 30, 2019 compared to the nine months ended June 30, 2018.

The Gathering segment’s earnings for the quarter ended ~~December 31, 2017~~June 30, 2019 were ~~$45.4~~$14.6 million, an increase of ~~$34.4~~$3.0 million when compared with earnings of ~~$11.0~~$11.6 million for the quarter ended ~~December 31, 2016.~~June 30, 2018. The increase in earnings was mainly due to the impact of higher gathering revenues ($3.8 million) and the impact of the 2017 Tax Reform Act, which ~~led~~reduced the Company’s federal statutory rate from a blended 24.5% in fiscal 2018 to ~~the remeasurement of accumulated deferred taxes ($34.9 million)~~21% in fiscal 2019 and ~~the impact of the~~lowered income tax ~~rate change~~expense on current ~~income tax~~quarter earnings ($~~1.5~~0.8 million). These earnings increases were partially offset by ~~lower gathering revenue~~higher depreciation expense ($~~2.6~~0.8 million), ~~as discussed above.~~driven mostly by an impairment recorded during the quarter ended June 30, 2019 relating to Midstream Company’s minority ownership in a non-operated gas processing facility, and other items that increased Midstream Company’s effective tax rate during the quarter ($0.8 million).

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The Gathering segment’s earnings for the nine months ended June 30, 2019 were $41.5 million, a decrease of $27.2 million when compared with earnings of $68.7 million for the nine months ended June 30, 2018. The decrease in earnings was primarily attributable to the impact of the 2017 Tax Reform Act passed in the prior year, which resulted in a remeasurement of the segment’s accumulated deferred taxes that lowered income tax expense during the nine months ended June 30, 2018 ($34.5 million). This earnings impact was partially offset by the positive impacts of the Company’s lower federal statutory rate on current period earnings ($2.0 million) and the removal of a valuation allowance on the segment’s accumulated deferred income taxes during the nine months ended June 30, 2019, that also lowered current year-to-date income tax expense ($0.5 million). Additionally, earnings decreased due to higher operating expenses ($1.7 million), higher depreciation expense ($1.6 million) and other items that increased Midstream Company’s effective income tax rate ($1.4 million). The increase in operating expenses was largely due to the completion of compressor unit overhauls on Clermont gathering system compressor stations during the current year and higher costs related to the operation of compressor units on the Covington gathering system that were acquired from Seneca in March 2018. The increase in depreciation expense was due to higher plant balances at the Covington, Trout Run and Clermont gathering systems and an impairment recorded during the current fiscal year relating to Midstream Company’s minority ownership in a non-operated gas processing facility. These earnings decreases were partially offset by the impact of higher gathering revenues ($9.5 million).

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Utility

Utility Operating Revenues


	Three Months Ended December 31,								Three Months Ended June 30,							Nine Months Ended June 30,
(Thousands)	2017			2016		Increase (Decrease)			2019		2018		Increase (Decrease)			2019			2018			Increase (Decrease)
Retail Sales Revenues:
Residential	$	134,739		$	116,387	$	18,352		$	96,297	$	93,560	$	2,737		$	489,691		$	435,388		$	54,303
Commercial	19,633			15,979		3,654			11,892		10,809		1,083			67,315			61,119			6,196
Industrial	872			517		355			1,024		890		134			4,384			3,590			794
	155,244			132,883		22,361			109,213		105,259		3,954			561,390			500,097			61,293
Transportation	36,309			36,661		(352		)	23,547		25,070		(1,523		)	105,880			113,224			(7,344		)
Off-System Sales	41			627		(586		)	—		—		—			—			359			(359		)
Other	(2,323		)	2,626		(4,949		)	161		1,818		(1,657		)	(8,662		)	(2,784		)	(5,878		)
	$	189,271		$	172,797	$	16,474		$	132,921	$	132,147	$	774		$	658,608		$	610,896		$	47,712

Utility Throughput


	Three Months Ended December 31,				Three Months Ended June 30,				Nine Months Ended June 30,
(MMcf)	2017	2016	Increase (Decrease)		2019	2018	Increase (Decrease)		2019	2018	Increase (Decrease)
Retail Sales:
Residential	17,847	15,764	2,083		9,895	10,052	(157	)	60,581	56,468	4,113
Commercial	2,596	2,299	297		1,441	1,525	(84	)	8,999	8,621	378
Industrial	144	77	67		151	128	23		639	559	80
	20,587	18,140	2,447		11,487	11,705	(218	)	70,219	65,648	4,571
Transportation	21,427	19,565	1,862		14,716	15,348	(632	)	65,914	66,398	(484	)
Off-System Sales	22	173	(151	)	—	—	—		—	141	(141	)
	42,036	37,878	4,158		26,203	27,053	(850	)	136,133	132,187	3,946

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Degree Days


Three Months Ended December 31,				Percent Colder (Warmer) Than
	Normal	2017	2016	Normal⁽¹⁾		Prior Year⁽¹⁾
Three Months Ended June 30,											Percent Colder (Warmer) Than
								Normal	2019	2018	Normal⁽¹⁾		Prior Year⁽¹⁾
Buffalo	2,253	2,227	1,966	(1.2	)%	13.3	%	912	957	873	4.9	%	9.6	%
Erie	2,044	2,029	1,750	(0.7	)%	15.9	%	871	773	825	(11.3	)%	(6.3	)%

Nine Months Ended June 30,
Buffalo								6,455	6,654	6,308	3.1	%	5.5	%
Erie								6,023	5,899	5,929	(2.1	)%	(0.5	)%


⁽¹⁾	Percents compare actual ~~2017~~2019 degree days to normal degree days and actual ~~2017~~2019 degree days to actual ~~2016~~2018 degree days.

~~2017~~2019 Compared with ~~2016~~2018

Operating revenues for the Utility segment increased ~~$16.5~~$0.8 million for the quarter ended ~~December 31, 2017~~June 30, 2019 as compared with the quarter ended ~~December 31, 2016.~~June 30, 2018. The increase ~~largely~~primarily resulted from a ~~$22.4~~$4.0 million increase in retail gas sales revenue. The increase in retail gas sales revenue was largely due to an increase in retail accounts due mostly to transportation customer migration, and $1.4 million of revenues related to the system modernization tracker that commenced during the current fiscal year in the segment's New York service territory. The tracker, which was approved by the NYPSC, is designed to recover increased investment in utility system modernization. These increases were partially offset by a $1.5 million decrease in transportation revenues and a $1.7 million decrease in other revenues. The decline in transportation revenues was primarily due to the migration of residential customers from transportation sales to retail. The decrease in other revenues was largely due to a larger refund provision recorded during the quarter ended June 30, 2019 to refund the net effect of the reduction in the federal income tax rate resulting from the 2017 Tax Reform Act to the Utility segment’s customers in accordance with NYPSC and PaPUC regulatory orders.

Operating revenues for the Utility segment increased $47.7 million for the nine months ended June 30, 2019 as compared with the nine months ended June 30, 2018. The increase primarily resulted from a $61.3 million increase in retail gas sales revenue. The increase in retail gas sales revenue was largely a result of ~~higher volumes (due to colder weather) and~~ an increase in the cost of gas sold (per Mcf)., higher throughput (due primarily to impacts of higher usage and an increase in retail accounts from transportation customer migration), and $3.4 million of revenues related to the aforementioned system modernization tracker. The increase in operating revenues was partially offset by a ~~$0.4~~$7.3 million decrease in transportation revenues, a ~~$4.9~~$5.9 million decrease in other revenues and a ~~$0.6~~$0.4 million decrease in off-system ~~sales (due to lower volumes).~~sales. The ~~$0.4 million~~ decrease in transportation revenues was primarily due to the ~~impact~~migration of ~~regulatory adjustments, which more than offset the impact of larger volumes and colder weather.~~residential customers from transportation sales to retail. The ~~$4.9 million~~ decrease in other revenues was largely due to ana larger estimated refund provision recorded during the nine months ended June 30, 2019 for the current income tax benefits resulting from the 2017 Tax Reform Act. ~~Due to profit sharing with retail customers, the margins related to off-system sales are minimal.~~

~~Table of Contents~~

The Utility segment’s earnings for the quarter ended ~~December 31, 2017~~June 30, 2019 were ~~$21.0~~$7.4 million, ~~a decrease~~an increase of ~~$0.2~~$3.5 million when compared with earnings of ~~$21.2~~$3.9 million for the quarter ended ~~December 31, 2016. Higher~~June 30, 2018. The increase in earnings ~~associated with~~was largely attributable to the ~~new rate order issued by~~impacts of usage and weather on customer margins ($1.4 million), the ~~NYPSC effective April 1, 2017~~system modernization tracker revenues discussed above ($1.0 million) ~~combined with~~, the impact of ~~colder weather~~regulatory adjustments on customer margins ($1.1 million), lower interest expense ($0.6 million) and a lower effective tax rate ($0.5 million). The decrease in interest expense was largely due to lower interest rates on intercompany long-term borrowings resulting from the Company’s early redemption of 8.75% notes that were set to mature in May 2019.

The 2017 Tax Reform Act lowered the Company’s statutory federal income tax rate from a blended 24.5% in fiscal 2018 to 21% in fiscal 2019, which contributed to the lower effective tax rate quarter over quarter. In accordance with NYPSC and PaPUC regulatory orders, the Utility segment has been recording a refund provision to return the net effect of the lower income tax rate to the segment’s customers. The estimated refund provision recorded for the quarter ended June 30, 2019 was $1.8 million higher than the refund provision recorded for the quarter ended June 30, 2018, reducing current quarter earnings by $1.4 million.

The Utility segment’s earnings for the nine months ended June 30, 2019 were $68.6 million, an increase of $10.3 million when compared with earnings of $58.3 million for the nine months ended June 30, 2018. The increase in earnings was largely attributable to ~~fiscal 2017~~the impacts of higher usage and weather on customer margins ($3.7 million), the system modernization tracker revenues discussed above ($2.6 million), the impact of regulatory adjustments on customer margins ($1.2 million), lower other deductions ($2.4 million), lower interest expense due largely to lower interest rates on intercompany long-term borrowing as discussed above ($1.7 million), and the impact of lower income tax expense primarily related to the 2017 Tax Reform Act as discussed above ($3.0 million). The increase in earnings related to other deductions was a result of an increase in unrealized gains on other investments and lower non-service pension and post-retirement benefit costs. These increases in earnings were partially offset by an increase in ~~operating expense ($0.7 million) and~~ the ~~impact of regulatory adjustments ($1.2 million). The increase in operating expense is primarily due~~refund provision related to ~~higher amortization of environmental remediation costs that resulted from the new rate order. The current tax benefit associated with~~ the 2017 Tax Reform Act ~~was completely offset by the aforementioned refund provision.~~($3.8 million).

~~The impact~~

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

Energy Marketing

Energy Marketing Operating Revenues


	Three Months Ended December 31,							Three Months Ended June 30,							Nine Months Ended June 30,
(Thousands)	2017		2016		Increase (Decrease)			2019		2018		Increase (Decrease)			2019		2018		Increase (Decrease)
Natural Gas (after Hedging)	$	38,730	$	36,790	$	1,940		$	22,011	$	25,970	$	(3,959	)	$	133,476	$	120,289	$	13,187
Other	32		38		(6		)	5		2		3			15		39		(24		)
	$	38,762	$	36,828	$	1,934		$	22,016	$	25,972	$	(3,956	)	$	133,491	$	120,328	$	13,163

Energy Marketing Volume

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



	Three Months Ended June 30,				Nine Months Ended June 30,
	2019	2018	Increase (Decrease)		2019	2018	Increase (Decrease)
Natural Gas – (MMcf)	7,429	8,322	(893	)	36,039	36,413	(374	)

~~2017~~2019 Compared with ~~2016~~2018

Operating revenues for the Energy Marketing segment ~~increased $1.9~~decreased $4.0 million for the quarter ended ~~December 31, 2017~~June 30, 2019 as compared with the quarter ended ~~December 31, 2016. The increase was~~June 30, 2018. This decrease primarily ~~due to an increase~~reflects a decrease in gas sales revenue due to ~~an increase in volume sold to retail customers as a result of colder weather, offset slightly by~~ a lower average price of natural gas period over period. A decrease in volume sold to retail customers also slightly contributed to the decline in operating revenues.

Operating revenues for the Energy Marketing segment increased $13.2 million for the nine months ended June 30, 2019 as compared with the nine months ended June 30, 2018. The increase reflects an increase in gas sales revenue due to a higher average price of natural gas period over period, partially offset by a slight decline in volume sold to retail customers.

The Energy Marketing segment ~~earnings for the quarter ended December 31, 2017 were $1.0 million,~~recorded a ~~decrease~~loss of ~~$0.8 million when compared with earnings of $1.8~~$1.4 million for the quarter ended ~~December 31, 2016. This decrease in earnings~~June 30, 2019, which was $1.2 million higher than the loss of $0.2 million recorded for the quarter ended June 30, 2018. The higher loss was primarily attributable to lower margin of ~~$0.8 million. The decrease in margin largely~~$1.3 million, which reflects a decline in average margin per Mcf primarily due to stronger natural gas prices at local purchase points relative to NYMEX-based sales contracts. A decline in the benefit the Energy Marketing segment realized from its contracts for storage capacity also contributed to the decline in average margin per Mcf.

The Energy Marketing segment recorded a loss for the nine months ended June 30, 2019 of $1.2 million, a decrease of $2.6 million when compared with earnings of $1.4 million for the nine months ended June 30, 2018. This decrease was primarily attributable to lower margin of $3.4 million. The decrease in margin largely reflects a decline in average margin per Mcf primarily due to a decline in the benefit the Energy Marketing segment realized from its contracts for storage capacity. Stronger natural gas prices at local purchase points relative to NYMEX-based sales contracts also contributed to the decline in margin. The earnings decrease was partially offset by lower income tax expense of $0.7 million. Income tax expense was lower primarily due to adjustments to remeasure accumulated deferred income taxes as a result of the 2017 Tax Reform ~~Act did not have a significant impact on Energy Marketing segment earnings for the quarter ended December 31, 2017.~~Act.

Corporate and All Other

~~2017~~2019 Compared with ~~2016~~2018

Corporate and All Other operations had ~~a loss~~earnings of ~~$13.9~~$0.9 million for the quarter ended ~~December 31, 2017, a decrease~~June 30, 2019, an increase of ~~$14.4~~$1.7 million when compared with ~~earnings~~a loss of ~~$0.5~~$0.8 million for the quarter ended ~~December 31, 2016.~~June 30, 2018. The increase in earnings ~~decrease~~was primarily attributable to lower interest expense ($0.6 million), lower income tax expense ($0.7 million) and the impact of unrealized gains on investments in equity securities ($1.1 million). Unrealized gains and losses on investments in equity securities are now recognized in earnings following the adoption of authoritative accounting guidance effective October 1, 2018. Unrealized gains and losses on these investments had previously been recorded as other comprehensive income. These increases in earnings were partially offset by lower operating revenues from the sale of standing timber by Seneca’s land and timber division ($0.5 million).

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For the nine months ended June 30, 2019, Corporate and All Other operations had earnings of $2.9 million, an increase of $20.8 million when compared with a loss of $17.9 million for the ~~quarter~~nine months ended June 30, 2018. The increase in earnings is primarily ~~attributed~~attributable to the impact of the 2017 Tax Reform Act, which resulted in a remeasurement of accumulated deferred income taxes ~~under~~that increased income tax expense for the nine months ended June 30, 2018 ($17.8 million). During the nine months ended June 30, 2019, the removal of a valuation allowance related to the 2017 Tax Reform Act resulted in an adjustment to the remeasurement of the Corporate and All Other category's accumulated deferred income taxes and lowered current fiscal year-to-date income tax expense ($~~15.1~~3.3 million). ~~This decrease~~Lower interest expense ($1.2 million) and a lower effective tax rate ($0.6 million) also contributed to the earnings increase. These increases in earnings ~~was~~were partially offset by ~~higher margins ($0.4 million)~~lower operating revenues from the sale of standing timber by Seneca's land and timber division ($1.2 million) and the ~~current tax benefit~~impact of ~~tax rate changes associated with~~a net unrealized loss recognized on investments in equity securities for the ~~2017 Tax Reform Act~~nine months ended June 30, 2019 ($~~0.1~~0.9 million).

~~Table of Contents~~

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

Interest on long-term debt decreased ~~$1.0~~$1.9 million for the quarter ended ~~December 31, 2017~~June 30, 2019 as compared with the quarter ended ~~December 31, 2016. This decrease is~~June 30, 2018. For the nine months ended June 30, 2019, interest on long-term debt decreased $6.4 million as compared with the nine months ended June 30, 2018. These decreases are due to a decrease in the weighted average interest rate on long-term debt outstanding. The Company issued $300 million of ~~3.95%~~4.75% notes in August 2018 and repaid $250 million of 8.75% notes in September ~~2017 and repaid $300 million of 6.5% notes in October 2017.~~2018.

CAPITAL RESOURCES AND LIQUIDITY

The Company’s primary source of cash during the ~~three-month~~nine-month period ended ~~December 31, 2017~~June 30, 2019 consisted of cash provided by operating activities. The ~~Company’s~~Company's primary sources of cash during the ~~three-month~~nine-month period ended ~~December 31, 2016~~June 30, 2018 consisted of cash provided by operating activities and net proceeds from the sale of oil and gas producing properties.

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 and Energy Marketing segments, revenues in these segments 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 ~~$94.8~~$570.6 million for the ~~three~~nine months ended ~~December 31, 2017, a decrease~~June 30, 2019, an increase of ~~$49.8~~$52.5 million compared with ~~$144.6~~$518.1 million provided by operating activities for the ~~three~~nine months ended ~~December 31, 2016.~~June 30, 2018. The increase in cash provided by operating activities primarily reflects higher cash provided by operating activities in the Pipeline and Storage and Exploration and Production segments due to the receipt of federal tax refunds during the nine months ended June 30, 2019. During the nine months ended June 30, 2018, these segments experienced cash outflows for federal tax payments. While the Utility segment experienced a decrease in cash provided by operating activities ~~reflects lower cash provided by operating activities in the Exploration and Production and Energy Marketing segments. The decrease in the Exploration and Production segment was primarily~~ due to ~~lower cash receipts from crude oil and natural~~the timing of gas ~~production, primarily a result~~cost recovery, this impact was partially offset by the receipt of ~~lower natural gas prices and lower production. The decrease in~~federal tax refunds during the Energy Marketing segment was primarily a result of higher purchased gas costs and an increase in hedging collateral deposits. Hedging collateral deposits serve as collateral for open positions on exchange-trade futures contracts and over-the-counter swaps.nine months ended June 30, 2019.

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Investing Cash Flow

Expenditures for Long-Lived Assets

The Company’s expenditures for long-lived assets totaled ~~$126.5~~$578.1 million during the ~~three~~nine months ended ~~December 31, 2017~~June 30, 2019 and ~~$94.6~~$403.2 million during the ~~three~~nine months ended ~~December 31, 2016.~~June 30, 2018. The table below presents these expenditures:


Total Expenditures for Long-Lived Assets
Three Months Ended December 31,	2017			2016			Increase (Decrease)
Nine Months Ended June 30,						2019					2018			Increase (Decrease)
(Millions)	2017				2016					Increase (Decrease)
Exploration and Production:
Capital Expenditures	$	74.7	(1)	$	40.7	(2)	$	34.0		$	391.7	(1)	$		269.9		(2)	$	121.8
Pipeline and Storage:
Capital Expenditures	22.3		(1)	25.4		(2)	(3.1		)	88.1		(1)	53.4			(2)	34.7
Gathering:
Capital Expenditures	12.9		(1)	11.3		(2)	1.6			39.4		(1)	47.8			(2)	(8.4		)
Utility:
Capital Expenditures	16.5		(1)	17.1		(2)	(0.6		)	58.4		(1)	52.0			(2)	6.4
All Other:
Capital Expenditures	0.1		(1)	0.1		(2)	—			0.5			—				0.5
Eliminations										—			(19.9		)		19.9
	$	126.5		$	94.6		$	31.9		$	578.1		$	403.2			$	174.9

(1)

At ~~December 31, 2017~~June 30, 2019, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment include $51.0 million, $14.0 million, $8.3 million and $6.1 million, respectively, of non-cash capital expenditures. At September 30, 2018, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment ~~include $37.1~~included $51.3 million, ~~$10.7~~$21.9 million, ~~$4.7~~$6.1 million and ~~$3.6~~$9.5 million, respectively, of non-cash capital expenditures.

(2)

At June 30, 2018, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $49.0 million, $10.9 million, $8.2 million and $3.3 million, respectively, of non-cash capital expenditures. At September 30, 2017, capital expenditures for the Exploration and Production segment, the Pipeline and Storage segment, the Gathering segment and the Utility segment included $36.5 million, $25.1 million, $3.9 million and $6.7 million, respectively, of non-cash capital expenditures. ~~The capital expenditures for the Exploration and Production segment do not include any proceeds received from the sale of oil and gas assets to IOG under the joint development agreement.~~

~~(2)~~

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

Exploration and Production

The Exploration and Production segment capital expenditures for the ~~three~~nine months ended ~~December 31, 2017~~June 30, 2019 were primarily well drilling and completion expenditures and included approximately ~~$70.6~~$365.6 million for the Appalachian region (including ~~$58.7~~$160.4 million in the Marcellus Shale area and $194.3 million in the Utica Shale area) and ~~$4.1~~$26.1 million for the West Coast region. These amounts included approximately ~~$40.7~~$210.6 million spent to develop proved undeveloped reserves.

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

~~Table of Contents~~

The Exploration and Production segment capital expenditures for the ~~three~~nine months ended ~~December 31, 2016~~June 30, 2018 were primarily well drilling and completion expenditures and included approximately ~~$29.8~~$250.5 million for the Appalachian region (including ~~$16.4~~$186.3 million in the Marcellus Shale area and $56.0 million in the Utica Shale area) and ~~$10.9~~$19.4 million for the West Coast region. These amounts included approximately ~~$8.3~~$132.8 million spent to develop proved undeveloped reserves.

Pipeline and Storage

The Pipeline and Storage segment capital expenditures for the ~~three~~nine months ended ~~December 31, 2017~~June 30, 2019 were ~~partially related to~~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~~nine months ended ~~December 31, 2017~~June 30, 2019 include expenditures related to Empire's Empire North Project ($11.5 million) and Supply Corporation's Line ~~D Expansion~~N to Monaca Project ($~~12.4~~10.5 million), as discussed below. The Pipeline and Storage capital expenditures for the ~~three~~nine months ended~~December 31, 2016~~ June 30, 2018 were ~~mainly~~partially for ~~expenditures related to Empire and Supply Corporation's Northern Access 2016 Project ($13.5 million) and Supply Corporation's Line D Expansion Project ($4.2 million) and also included~~ additions, improvements and replacements to this segment’s transmission and gas storage systems. In addition, the Pipeline and Storage segment capital expenditures for the nine months ended June 30, 2018 include expenditures related to Supply Corporation's Line D Expansion Project ($14.3 million).

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In light of the continuing demand for pipeline capacity to move natural gas from new wells being drilled in Appalachia — specifically in the Marcellus and Utica Shale producing areas — Supply Corporation and Empire have ~~recently~~ completed and ~~are actively pursuing~~continue to pursue several expansion projects designed to move anticipated Marcellus and Utica production gas to other interstate pipelines 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 and Empire are developing a project which would move significant prospective Marcellus production from Seneca's Western Development Area at Clermont to an Empire interconnection with TransCanada Pipeline at Chippawa and an interconnection with TGP's 200 Line in East Aurora, New York ~~(“Northern~~(the “Northern Access ~~2016”~~project”). The Northern Access ~~2016~~ project would provide an outlet to Dawn-indexed markets in Canada and to the TGP line serving the U.S. Northeast. The Northern Access ~~2016~~ project involves the construction of approximately 99 miles of largely 24” pipeline and approximately 27,500 horsepower of compression on the two systems. ~~The preliminary cost estimate for the Northern Access 2016 project is approximately $500 million.~~ Supply Corporation, Empire and Seneca executed anchor shipper agreements for 350,000 Dth per day of firm transportation delivery capacity to Chippawa and 140,000 Dth per day of firm transportation capacity to a new interconnection with TGP's 200 Line on this project. On February 3, 2017, the Company received FERC approval of the project. On April 7, 2017, 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 on January 27, 2017). On April 21, 2017, the Company appealed the NYDEC's decision with regard to the Water Quality Certification to the United States Court of Appeals for the Second Circuit, and on May 11, 2017, the Company commenced legal action in New York State Supreme Court challenging the NYDEC's actions with regard to various state permits. ~~The Company also has pending with~~On August 6, 2018, the FERC ~~a proceeding asserting, among other things,~~issued an Order finding that the NYDEC exceeded the ~~reasonable and~~ statutory time ~~frames~~frame to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. ~~In light of these pending legal actions, the Company has not yet determined a target in-service date.~~FERC denied rehearing requests associated with its Order. The Company remains committed to the project. In light of these 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, 2017,~~June 30, 2019, approximately ~~$75.5~~$57.1 million has been spent on the Northern Access ~~2016~~ project, including ~~$21.9~~$22.9 million that has been spent to study the project, for which no reserve has been established. The remaining ~~$53.6~~$34.2 million spent on the project has been capitalized as Construction Work in Progress.

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

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Empire concluded an Open Season on November 18, 2015, and has designed a project that would allow for the transportation of 205,000 Dth per day of additional shale supplies from interconnections in Tioga County, Pennsylvania, to TransCanada Pipeline, and the TGP 200 Line (“Empire North Project”). ~~Empire has executed a Precedent Agreement with a foundation shipper for 150,000 Dth per day of transportation capacity~~This project is fully subscribed under long term agreements and ~~with two other shippers for 35,000 Dth per day and 5,000 Dth per day, respectively. Empire continues to negotiate precedent agreements with other prospective shippers. Empire expects to file a~~received the FERC Section 7(c) ~~application with the FERC in the second quarter of fiscal 2018.~~certificate on March 7, 2019. Project construction is under way. The Empire North ~~project~~Project has a projected in-service date in the second half of ~~November 1, 2019~~fiscal 2020 and an estimated capital cost of approximately ~~$140 million to $145~~$142 million. As of ~~December 31, 2017,~~June 30, 2019, approximately ~~$1.1~~$30.7 million has been ~~spent to study~~capitalized as Construction Work in Progress for this project, ~~all~~including $19.9 million of ~~which has been included in Deferred Charges on~~costs transferred from the ~~Consolidated Balance Sheet at December 31, 2017.~~Northern Access Project.

Supply Corporation has entered into a foundation shipper Precedent Agreement to provide incremental natural gas transportation services from Line N to the ethylene cracker facility being constructed by Shell Chemical Appalachia, LLC in Potter Township, ~~Pennsylvania.~~Pennsylvania ("Line N to Monaca Project"). Supply Corporation has completed an Open Season for the project and has secured incremental firm transportation capacity commitments totaling 133,000 Dth per day on Line N and on the proposed pipeline extension of approximately 4.5 miles from Line N to the facility. Supply Corporation filed a prior notice application with the FERC on March 23, 2018 and was authorized to pursue the project under its blanket certificate as of May 30, 2018. Project construction is under way. The proposed in-service date for this project is as early as ~~July 1,~~late September 2019 at an estimated capital cost of approximately $24.5 million. As of June 30, 2019, approximately $12.7 million has been capitalized as Construction Work in Progress for this project.

Supply Corporation has developed its FM100 Project, which will upgrade 1950's era pipeline in northwestern Pennsylvania and ~~capital costs are~~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 ~~$17~~leased by Transco and become part of a Transco expansion project ("Leidy South") that will create incremental

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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, 2017,~~June 30, 2019, approximately ~~$0.5~~$2.3 million has been spent to study this project, all of which has been included in Deferred Charges on the Consolidated Balance Sheet at ~~December 31, 2017.~~June 30, 2019.

Gathering

The majority of the Gathering segment capital expenditures for the ~~three~~nine months ended ~~December 31, 2017~~June 30, 2019 were for the continued buildout of Midstream ~~Corporation’s~~Company’s Trout Run Gathering System, Clermont Gathering System and ~~Midstream Corporation's Trout Run~~Wellsboro Gathering System, as discussed below. The majority of the Gathering segment capital expenditures for the ~~three~~nine months ended ~~December 31, 2016~~June 30, 2018 were for the ~~construction~~purchase of two compressor stations for Midstream Company's Covington Gathering System, as well as the continued buildout of the Trout Run Gathering System and the Clermont Gathering System.

NFG Midstream Clermont, LLC, a wholly owned subsidiary of Midstream ~~Corporation, is building~~Company, continues to develop an extensive gathering system with compression in the Pennsylvania counties of McKean, Elk and Cameron. The Clermont Gathering System was initially placed in service in July 2014. The current system consists of approximately 78 miles of backbone and in-field gathering pipelines. The total cost estimate for the continued buildout will be dependent on the nature and timing of ~~the shippers', including~~ Seneca's long-term plans. As of ~~December 31, 2017,~~June 30, 2019, approximately ~~$285.4~~$306.1 million has been spent on the Clermont Gathering System, including approximately ~~$4.0~~$8.2 million spent during the ~~three~~nine months ended ~~December 31, 2017,~~June 30, 2019, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at ~~December 31, 2017.~~June 30, 2019.

NFG Midstream Trout Run, LLC, a wholly owned subsidiary of Midstream ~~Corporation,~~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 approximately 4876 miles of backbone and in-field gathering pipelines, two compressor stations and a dehydration and metering station. As of ~~December 31, 2017,~~June 30, 2019, approximately ~~$183.6~~$226.1 million has been spent on the Trout Run Gathering System, including approximately ~~$6.3~~$19.4 million spent during the ~~three~~nine months ended ~~December 31, 2017,~~June 30, 2019, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at ~~December 31, 2017.~~June 30, 2019.

NFG Midstream Wellsboro, LLC, a wholly owned subsidiary of Midstream ~~Corporation,~~Company, continues to develop its Wellsboro Gathering System in Tioga County, Pennsylvania. The current system consists of approximately three miles of backbone and in-field gathering pipelines and a dehydration and metering station. As of ~~December 31, 2017,~~June 30, 2019, the Company has spent approximately ~~$6.9~~$19.6 million in costs related to this project, including approximately $10.1 million spent during the nine months ended June 30, 2019, all of which is included in Property, Plant and Equipment on the Consolidated Balance Sheet at ~~December 31, 2017.~~June 30, 2019.

Utility

The majority of the Utility segment capital expenditures for the ~~three~~nine months ended~~December 31, 2017~~June 30, 2019 and ~~December 31, 2016~~June 30, 2018 were made for main and service line improvements and replacements, as well as main extensions.

Project Funding

~~The~~Over the past two years, the Company has been financing the Pipeline and Storage segment and Gathering segment projects mentioned above, as well as the Exploration and Production segment capital expenditures, with cash from operations as well as proceeds received from the sale of oil and ~~both short and long-term borrowings.~~gas assets. Going forward, while the Company expects to use cash on hand and cash from operations as the first means of financing these projects, the Company may issue short-term and/or long-term debt as necessary during fiscal ~~2018~~2019 to help meet its capital expenditures needs. The level of short-term and long-term borrowings will depend upon the ~~amounts~~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.

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

The Company did not have any consolidated short-term debt outstanding at ~~December 31, 2017~~June 30, 2019 or September 30, ~~2017, nor was there any~~2018. The maximum amount of short-term debt outstanding during the ~~quarter~~nine months ended ~~December 31, 2017.~~June 30, 2019 was $5.0 million. The Company continues to consider short-term debt (consisting of short-term notes payable to banks and commercial paper) an important source of cash for temporarily financing capital expenditures, gas-in-storage inventory, unrecovered purchased gas costs, margin calls on derivative financial instruments, exploration and development expenditures, other working capital needs and repayment of long-term debt. Fluctuations in these items can have a significant impact on the amount and timing of short-term debt.

On ~~September 9, 2016,~~October 25, 2018, the Company entered into a ~~Third~~Fourth Amended and Restated Credit Agreement (Credit Agreement) with a syndicate of ~~what now numbers 13~~12 banks. This Credit Agreement provides a $750.0 million multi-year unsecured committed revolving credit facility through ~~December 5, 2019.~~October 25, 2023. The Company also has ~~a number of individual~~an uncommitted ~~or discretionary lines~~line of credit with ~~certain~~a financial ~~institutions~~institution for general corporate purposes. Borrowings under ~~the~~this uncommitted ~~lines~~line of credit ~~are~~would be made at competitive market rates. The uncommitted credit ~~lines are~~line is revocable at the option of the financial ~~institutions~~institution and ~~are~~is reviewed on an annual basis. The Company anticipates that its uncommitted ~~lines~~line of credit generally will be renewed or substantially replaced by a similar ~~lines.~~line. 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~~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 ~~October~~any ceiling test impairment occurring on or after July 1, ~~2017 through December 5, 2019.~~2018, not to exceed $250 million. At ~~December 31, 2017,~~June 30, 2019, the Company’s debt to capitalization ratio (as calculated under the facility) was ~~.53.~~.50. The constraints specified in the Credit Agreement would have permitted an additional ~~$1.36~~$1.84 billion in short-term and/or long-term debt to be outstanding at June 30, 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, 2017,~~June 30, 2019, the Company did not have any debt outstanding under the Credit Agreement.

None of the ~~Company’s~~Company's long-term debt ~~at December 31, 2017~~as of June 30, 2019 and September 30, 2018 had a maturity date within the following twelve-month period. ~~The Current Portion of Long-Term Debt at September~~

During the nine months ended June 30, ~~2017 consisted of~~2018, the Company redeemed $300.0 million ~~aggregate principal amount~~ of the Company's 6.50% notes that were scheduled to mature in April 2018. The Company redeemed ~~these~~those notes on October 18, 2017 for $307.0 million, plus accrued interest.

The Company’s embedded cost of long-term debt was ~~5.17%~~4.69% and ~~5.53%~~5.16% at ~~December 31, 2017~~June 30, 2019 and ~~December 31, 2016,~~June 30, 2018, respectively.

Under the Company’s existing indenture covenants at ~~December 31, 2017,~~June 30, 2019, the Company would have been permitted to issue up to a maximum of ~~$654.0 million~~$1.03 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

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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.

The Company’s 1974 indenture pursuant to which ~~$98.7~~$99.0 million (or ~~4.7%~~4.6%) of the Company’s long-term debt (as of ~~December 31, 2017)~~June 30, 2019) was issued, contains a cross-default provision whereby the failure by the Company to perform certain obligations under

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other borrowing arrangements could trigger an obligation to repay the debt outstanding under the indenture. In particular, a repayment obligation could be triggered if the Company fails (i) to pay any scheduled principal or interest on any debt under any other indenture or agreement or (ii) to perform any other term in any other such indenture or agreement, and the effect of the failure causes, or would permit the holders of the debt to cause, the debt under such indenture or agreement to become due prior to its stated maturity, unless cured or waived.

OFF-BALANCE SHEET ARRANGEMENTS

The Company has entered into certain off-balance sheet financing arrangements. These financing arrangements are primarily operating leases. The Company’s consolidated subsidiaries have operating leases, the majority of which are with the Exploration and Production segment and Corporate operations, having a remaining lease commitment of approximately ~~$27.4~~$41.7 million. These leases have been entered into for the use of compressors, drilling rigs, buildings and other items and are accounted for as operating leases.

OTHER MATTERS

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

During the ~~three~~nine months ended ~~December 31, 2017,~~June 30, 2019, the Company contributed ~~$27.6~~$29.2 million to its tax-qualified, noncontributory defined-benefit retirement plan (Retirement Plan) and ~~$0.7~~$2.7 million to its VEBA trusts for its other post-retirement benefits. In the remainder of ~~2018,~~2019, the Company may contribute up to $5.0 million to the Retirement ~~Plan. In~~Plan and the ~~remainder~~Company expects to contribute approximately $0.2 million to its VEBA trusts.

The Company, in its Exploration and Production segment, has entered into contractual obligations of $29.6 million during the quarter ended June 30, 2019 associated with hydraulic fracturing and fuel. Since September 30, 2018, the Company ~~expects its contributions to the VEBA trusts to be in the range~~has added $119.2 million of ~~$2.0 million to $3.0 million.~~contractual obligations associated with hydraulic fracturing and fuel. These contractual commitments extend through fiscal 2021.

Market Risk Sensitive Instruments

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

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~~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 ~~we reduce our~~the Company reduces its use of hedging transactions as a result of final regulations to be issued by the CFTC, ~~our~~ results of operations may become more volatile and ~~our~~ cash flows may be less predictable. There may be other rules developed by the CFTC and other regulators that could impact the Company. While many of those rules place specific conditions on the operations of swap dealers and major swap participants, concern remains that swap dealers and major swap participants will pass along their increased costs stemming from final rules through higher transaction costs and prices or other direct or indirect costs.

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

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The accounting rules for fair value measurements and disclosures require consideration of the impact of nonperformance risk (including credit risk) from a market participant perspective in the measurement of the fair value of assets and liabilities. At ~~December 31, 2017,~~June 30, 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 a complete discussion of market risk sensitive instruments, refer to "Market Risk Sensitive Instruments" in Item 7 of the Company's ~~2017~~2018 Form 10-K. There have been no subsequent material changes to the Company’s exposure to market risk sensitive instruments.

Rate and Regulatory Matters

Utility Operation

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

New YorkJurisdiction

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

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

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.

Pipeline and Storage

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 proposed rate increases are expected to be suspended, with an effective date of February 1, 2020, subject to refund. If the proposed rate increases finally approved at the end of the ~~2017 Tax Reform Act~~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 ~~tax expenses and liabilities of New York utilities,~~difference between the rates collected subject to refund and the ~~“regulatory treatment of any windfalls resulting from same in order to preserve~~final approved rates, with interest at the ~~benefits for ratepayers.” In its order,~~FERC-approved rate. If the ~~NYPSC stated that~~rates approved at the ~~effect~~end of the ~~2017 Tax Reform Act on utilities’ taxation is likely to be material~~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 ~~complex and that the proceeding was needed to begin the process of addressing the impact on the State’s utilities and ratepayers. The order establishes that the first steps in such process~~refunds with interest will be ~~soliciting information from~~limited to the difference between the rates collected subject to refund and the rates in effect at July 31, 2019. In response to the FERC’s July 2018 Final Rule in RM18-11-000, et. al (Order No. 849), on December 6, 2018, Supply Corporation filed its ~~regulated utilities to quantify~~Form 501-G, which addresses the impact of the 2017 Tax Reform Act, ~~scheduling a technical conference with~~and advised the utilities, and the issuance of a NY Department of Public Service Staff (Staff) proposal for accounting and ratemaking treatment of the tax changes. The order further states that once Staff’s proposal is issued, utilities and other interested parties will be invited to comment on Staff’s recommendation. The order also declares that utilities are “put on noticeCommission that it iswould make a Section 4 rate filing no later than July 31, 2019, which it has done, thereby obviating the ~~[NYPSC]’s intent~~need for FERC to ensure that net benefits accruing from the Tax Act are preserved for ratepayers, either through deferral accounting or another method, from the first day the Tax Act is put into effect. Utilities acting contrary to this intent do so at their own risk.” The Company cannot predict the outcome of this proceeding at this time.take any further action. Refer to Item 1 at Note 45 - Income Taxes for a further discussion of the 2017 Tax Reform Act.

Empire filed a Section 4 rate case on June 29, 2018, proposing rate increases to be effective August 1, 2018. Empire and its customers reached a settlement in principle in December 2018, and Empire’s subsequent motion to put in place those interim settlement rates, effective January 1, 2019, was approved by FERC’s Chief Administrative Law Judge on December 31, 2018. The settlement was approved May 3, 2019. The “black box” settlement provides for new, system-wide rates, and which, based on current contracts, is estimated to increase Empire’s revenues on a yearly basis by approximately $4.6 million. The settlement also provides new depreciation rates and a tiered transportation revenue sharing mechanism, beginning with Empire sharing 35%

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~~Pennsylvania Jurisdiction~~

~~Distribution Corporation’s current delivery charges in~~of transportation only revenues (net of certain excluded items) over $64.4 million up to Empire sharing 55% of those revenues over $68.4 million. Empire has also committed to undertake certain improvements to its ~~Pennsylvania jurisdiction were approved by~~electronic bulletin board and will convene regular customer meetings to address these and other improvements. Under the ~~PaPUC on~~settlement, Empire and the other parties may not file to change rates until March 31, 2021, except that Empire may make a filing (to be effective November ~~30, 2006 as part of~~1, 2020) under limited circumstances for contract changes with a ~~settlement agreement that became effective January 1, 2007.~~

~~Pipeline and Storage~~

~~Supply Corporation currently has no active~~large customer. Empire must file a Section 4 rate case ~~on file. Supply Corporation's current rate settlement requires a rate case filing~~ no later than ~~December 31, 2019.~~May 1, 2025.

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

Environmental Matters

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

For further discussion of the Company's environmental exposures, refer to Item 1 at Note 67 — 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 EPA regulations at the federal level, actions at the state level, and private party litigation related to greenhouse gas emissions. While the U.S. Congress has from time to time considered legislation aimed at reducing emissions of greenhouse gases, Congress has not yet passed any federal climate change legislation and we cannot predict when or if Congress will pass such legislation and in what form. In the absence of such legislation, the EPA is regulating greenhouse gas emissions pursuant to the authority granted to it by the federal Clean Air Act. For example, in April 2012, the EPA adopted rules which restrict emissions associated with oil and natural gas drilling. The EPA previously adopted final regulations that set methane and volatile organic compound emissions standards for new or modified oil and gas emissions sources. These rules impose more stringent leak detection and repair requirements, and further address reporting and control of methane and volatile organic compound emissions. The current administration has issued executive orders to review and potentially roll back many of these regulations, and, in turn, litigation (not involving the Company) has been instituted to challenge the administration's efforts. The Company must continue to comply with all applicable regulations. In addition, the U.S. Congress has from time to time considered bills that would establish a cap-and-trade program to reduce emissions of greenhouse gases. A number of states have adopted energy strategies or plans with goals that include the reduction of greenhouse gas emissions. For example, New York’s State Energy Plan includes Reforming the Energy Vision (REV) initiatives which set greenhouse gas emission reduction targets of 40% by 2030 and 80% by 2050. Additionally, the Plan targets that 50% of electric generation must come from renewable energy sources by 2030. Similarly, Pennsylvania has a methane reduction framework for the oil and gas industry which ~~will result~~has resulted in permitting changes with the stated goal of reducing methane emissions from well sites, compressor stations and pipelines. With respect to its operations in California, the Company currently complies with California cap-and-trade guidelines, which increases the Company's cost of environmental compliance in its Exploration and Production segment operations. Legislation or regulation that aims to reduce greenhouse gas emissions could also include greenhouse gas emissions limits and reporting requirements, carbon taxes, restrictive permitting, increased efficiency standards, and incentives or mandates to conserve energy or use renewable energy sources. Federal, state or local governments may ~~for example,~~ provide tax advantages and other subsidies to support alternative energy sources, mandate the use of specific fuels or technologies, or promote research into new technologies to reduce the cost and increase the scalability of alternative energy sources. New York State, for example, passed climate legislation that mandates reduced greenhouse gas emissions to 60% of 1990 levels by 2030, and 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. These climate change and greenhouse gas initiatives could impact the Company's customer base and assets if appropriate regulatory treatment is not afforded in the process. The initiatives could also increase the Company’s cost of environmental compliance by increasing reporting requirements and requiring the Company to retrofit existing equipment, install new equipment to reduce emissions from larger facilities and/or purchase emission allowances. They could also delay or otherwise negatively affect efforts to obtain permits and other regulatory approvals with regard to existing and new facilities, and impose additional monitoring and reporting requirements. Changing market conditions and new regulatory requirements, as well as unanticipated or inconsistent application of existing laws and ~~reduce demand for oil and natural gas. But legislation~~regulations by administrative agencies, make it difficult to predict a long-term business impact across twenty or regulation that sets a price on or otherwise restricts carbon emissions could also benefit the Company by increasing demand for natural gas, because substantially fewer carbon emissions per Btu of heat generated are associated with the use of natural gas than with certain alternate fuels such as coal and oil. The effect (material or not) on the Company of any new legislative or regulatory measures will depend on the particular provisions that are ultimately adopted.more years.

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New Authoritative Accounting and Financial Reporting Guidance

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

Safe Harbor for Forward-Looking Statements

The Company is including the following cautionary statement in this Form 10-Q to make applicable and take advantage of the safe harbor provisions of the Private Securities Litigation Reform Act of 1995 for any forward-looking statements made

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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 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;


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


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


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


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


5.	~~Changes in the price of natural gas or oil;~~


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


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


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

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


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


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


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

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11.	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;

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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, cyber attacks or pest infestation;~~war;


~~20.~~21.	Significant differences between the Company’s projected and actual capital expenditures and operating expenses; or


~~21.~~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 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, 2017.~~ June 30, 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, 2017~~June 30, 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

On September 13, 2017, the PaDEP sent a draft Consent Assessment of Civil Penalty (CACP) to Seneca, in relation to an alleged violation of the Pennsylvania Oil and Gas Act, as well as PaDEP rules and regulations regarding gas migration relating to Seneca’s drilling activities. The amount of the penalty sought by the PaDEP is not material to the Company. The draft CACP

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

For a discussion of various environmental and other matters, refer to Part I, Item 1 at Note 67 — 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 910 — Regulatory Matters.

Item 1A. Risk Factors

The risk factors in Item 1A of the Company’s ~~2017~~2018 Form 10-K have not materially changed other than as set forth below. The risk factor presented below supersedes the risk factor having the same caption in the 2017 Form 10-K and should otherwise be read in conjunction with all of the risk factors disclosed in the 2017 Form 10-K.changed.

The Company’s need to comply with comprehensive, complex, and the sometimes unpredictable enforcement of government regulations may increase its costs and limit its revenue growth, which may result in reduced earnings.

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

In the Company's Utility segment, the operations of Distribution Corporation are subject to the jurisdiction of the NYPSC, the PaPUC and, with respect to certain transactions, the FERC. The NYPSC and the PaPUC, among other things, approve the rates that Distribution Corporation may charge to its utility customers. Those approved rates also impact the returns that Distribution Corporation may earn on the assets that are dedicated to those operations. If Distribution Corporation is required in a rate proceeding to reduce the rates it charges its utility customers, or to the extent Distribution Corporation is unable to obtain approval for rate increases from these regulators, particularly when necessary to cover increased costs (including costs that may be incurred in connection with governmental investigations or proceedings or mandated infrastructure inspection, maintenance or replacement programs), earnings may decrease.

In addition to their historical methods of utility regulation, both the PaPUC and NYPSC have established competitive markets in which customers may purchase gas commodity from unregulated marketers, in addition to utility companies. Retail competition for gas commodity service does not pose an acute competitive threat for Distribution Corporation because in both jurisdictions it recovers its cost of service through delivery rates and charges, and not through any mark-up on the gas commodity purchased by its customers. Over the longer run, however, rate design changes resulting from customer migration to marketer service ("unbundling") can expose utilities such as Distribution Corporation to stranded costs and revenue erosion in the absence of compensating rate relief.

Both the NYPSC and the PaPUC have, from time-to-time, instituted proceedings for the purpose of promoting conservation of energy commodities, including natural gas. In New York, Distribution Corporation implemented a Conservation Incentive Program that promotes conservation and efficient use of natural gas by offering customer rebates for the installation of high-efficiency appliances, among other things. The intent of conservation and efficiency programs is to reduce customer usage of natural gas. Under traditional volumetric rates, reduced usage by customers results in decreased revenues to the Utility. To prevent revenue erosion caused by conservation, the NYPSC approved a "revenue decoupling mechanism" that renders Distribution Corporation's New York division financially indifferent to the effects of conservation. In Pennsylvania, the PaPUC has not directed Distribution Corporation to implement a conservation program. If the NYPSC were to revoke the revenue decoupling mechanism in a future proceeding or the PaPUC were to adopt a conservation program without revenue decoupling mechanism or other changes in rate design, reduced customer usage could decrease revenues, forcing Distribution Corporation to file for rate relief. If Distribution Corporation were unable to obtain adequate rate relief, its financial condition, results of operations and cash flows would be adversely affected.

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

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

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

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

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

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

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

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

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

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

It is the Company’s practice that the use of commodity derivatives contracts comply with various policies in effect in respective business segments. For example, in the Exploration and Production segment, commodity derivatives contracts must be confined to the price hedging of existing and forecast production, and in the Energy Marketing segment, commodity derivatives with respect to fixed price purchase and sales commitments must be matched against commitments reasonably certain to be fulfilled. The Company maintains a system of internal controls to monitor compliance with its policy. However, unauthorized speculative trades, if they were to occur, could expose the Company to substantial losses to cover positions in its derivatives contracts. In addition, in the event the Company’s actual production of oil and natural gas falls short of hedged forecast production, the Company may incur substantial losses to cover its hedges.

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

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

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

On ~~October 2, 2017,~~April 1, 2019, the Company issued a total of ~~6,912~~5,752 unregistered shares of Company common stock to ~~nine~~eight non-employee directors of the Company then serving on the Board of Directors of the Company, ~~768~~consisting of 719 shares to each such director. On June 27, 2019, the Company issued 166 unregistered shares of Company common stock to David H. Anderson, who joined the Board on June 13, 2019 as a non-employee director. All of these unregistered shares were issued under the Company’s 2009 Non-Employee Director Equity Compensation Plan as partial consideration for such directors’ services during the quarter ended ~~December 31, 2017~~June 30, 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.

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Issuer Purchases of Equity Securities

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



Period	Total Number of Shares Purchased ^(a)	Average Price Paid per Share	Total Number of Shares Purchased as Part of Publicly Announced Share Repurchase Plans or Programs	Maximum Number of Shares That May Yet Be Purchased Under Share Repurchase Plans or Programs ^(b)
Apr. 1 - 30, 2019	9,133	$60.40	—	6,971,019
May 1 - 31, 2019	9,400	$57.13	—	6,971,019
June 1 - 30, 2019	10,316	$53.77	—	6,971,019
Total	28,849	$56.96	—	6,971,019

^(a)

Represents shares of common stock of the Company ~~tendered to~~purchased on the open market with Company ~~by holders of stock options, SARs, restricted stock units or shares of restricted stock~~“matching contributions” for the ~~payment~~accounts of ~~option exercise prices or applicable withholding taxes.~~participants in the Company’s 401(k) plans. During the quarter ended ~~December 31, 2017~~,June 30, 2019, the Company did not purchase any shares of its common stock pursuant to its publicly announced share repurchase ~~program.~~

program, nor did the Company purchase shares as a result of holders of stock-based compensation awards tendering shares to the Company.


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

Item 6. Exhibits



Exhibit Number		Description of Exhibit
~~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.~~

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

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

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, 2017~~June 30, 2019 and ~~2016.~~2018.

101		Interactive data files submitted pursuant to Regulation S-T: (i) the Consolidated Statements of Income and Earnings Reinvested in the Business for the three and nine months ended ~~December 31, 2017~~June 30, 2019 and ~~2016,~~2018, (ii) the Consolidated Statements of Comprehensive Income for the three and nine months ended ~~December 31, 2017~~June 30, 2019 and ~~2016,~~2018, (iii) the Consolidated Balance Sheets at ~~December 31, 2017~~June 30, 2019 and September 30, ~~2017,~~2018, (iv) the Consolidated Statements of Cash Flows for the ~~three~~nine months ended ~~December 31, 2017~~June 30, 2019 and ~~2016~~2018 and (v) the Notes to Condensed Consolidated Financial Statements.

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

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SIGNATURES

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



NATIONAL FUEL GAS COMPANY
(Registrant)





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





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

Date: ~~February~~August 2, ~~2018~~2019

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



The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended December 31, 2017 and 2016 (Thousands of Dollars)
Derivatives in Cash Flow Hedging Relationships	Amount of Derivative Gain or (Loss) Recognized in Other Comprehensive Income (Loss) on the Consolidated Statement of Comprehensive Income (Loss) (Effective Portion) for the Three Months Ended December 31,						Location of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion)	Amount of Derivative Gain or (Loss) Reclassified from Accumulated Other Comprehensive Income (Loss) on the Consolidated Balance Sheet into the Consolidated Statement of Income (Effective Portion) for the Three Months Ended December 31,						Location of Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing)	Derivative Gain or (Loss) Recognized in the Consolidated Statement of Income (Ineffective Portion and Amount Excluded from Effectiveness Testing) for the Three Months Ended December 31,
	2017			2016				2017			2016				2017			2016
Commodity Contracts	$	(5,948	)	$	(50,444	)	Operating Revenue	$	12,842		$	31,320		Operating Revenue	$	(433	)	$	(100	)
Commodity Contracts	956			(1,536		)	Purchased Gas	196			(460		)	Not Applicable	—			—
Foreign Currency Contracts	(507		)	(521		)	Operation and Maintenance Expense	(490		)	(143		)	Not Applicable	—			—
Total	$	(5,499	)	$	(52,501	)		$	12,548		$	30,717			$	(433	)	$	(100	)