Edgar Filing: NATIONAL FUEL GAS CO

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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 June 30, 2018

[ ] TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d)

OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from____ to_____

Commission File Number 1-3880

NATIONAL FUEL GAS COMPANY

(Exact name of registrant as specified in its charter)



New Jersey	13-1086010
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)

6363 Main Street
Williamsville, New York	14221
(Address of principal executive offices)	(Zip Code)

(716) 857-7000

(Registrant's telephone number, including area code)

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 and (2) has been subject to such filing requirements for the past 90 days. YES þ 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 ¨

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 July 31, 2018: 85,951,198 shares.

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GLOSSARY OF TERMS

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



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

* Effective August 1, 2018, the Company converted Seneca Resources Corporation and National Fuel Gas Midstream Corporation to limited liability companies (LLCs) for tax purposes. Both LLCs are wholly owned by a newly formed subsidiary named Pennsylvania Gas Holdings Corporation which in turn is wholly owned by the Company.



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

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Derivative	A financial instrument or other contract, the terms of which include an underlying variable (a price, interest rate, index rate, exchange rate, or other variable) and a notional amount (number of units, barrels, cubic feet, etc.). The terms also permit for the instrument or contract to be settled net and no initial net investment is required to enter into the financial instrument or contract. Examples include futures contracts, forward contracts, options, no cost collars and swaps.
Development costs	Costs incurred to obtain access to proved oil and gas reserves and to provide facilities for extracting, treating, gathering and storing the oil and gas
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act.
Dth	Decatherm; one Dth of natural gas has a heating value of 1,000,000 British thermal units, approximately equal to the heating value of 1 Mcf of natural gas.
Exchange Act	Securities Exchange Act of 1934, as amended
Expenditures for long-lived assets	Includes capital expenditures, stock acquisitions and/or investments in partnerships.
Exploration costs	Costs incurred in identifying areas that may warrant examination, as well as costs incurred in examining specific areas, including drilling exploratory wells.
Exploratory well	A well drilled in unproven or semi-proven territory for the purpose of ascertaining the presence underground of a commercial hydrocarbon deposit.
FERC 7(c) application	An application to the FERC under Section 7(c) of the federal Natural Gas Act for authority to construct, operate (and provide services through) facilities to transport or store natural gas in interstate commerce.
Firm transportation and/or storage	The transportation and/or storage service that a supplier of such service is obligated by contract to provide and for which the customer is obligated to pay whether or not the service is utilized.
GAAP	Accounting principles generally accepted in the United States of America
Goodwill	An intangible asset representing the difference between the fair value of a company and the price at which a company is purchased.
Hedging	A method of minimizing the impact of price, interest rate, and/or foreign currency exchange rate changes, often times through the use of derivative financial instruments.
Hub	Location where pipelines intersect enabling the trading, transportation, storage, exchange, lending and borrowing of natural gas.
ICE	Intercontinental Exchange. An exchange which maintains a futures market for crude oil and natural gas.
Interruptible transportation and/or storage	The transportation and/or storage service that, in accordance with contractual arrangements, can be interrupted by the supplier of such service, and for which the customer does not pay unless utilized.
LDC	Local distribution company
LIBOR	London Interbank Offered Rate
LIFO	Last-in, first-out
Marcellus Shale	A Middle Devonian-age geological shale formation that is present nearly a mile or more below the surface in the Appalachian region of the United States, including much of Pennsylvania and southern New York.
Mbbl	Thousand barrels (of oil)
Mcf	Thousand cubic feet (of natural gas)
MD&A	Management’s Discussion and Analysis of Financial Condition and Results of Operations
MDth	Thousand decatherms (of natural gas)
MMBtu	Million British thermal units (heating value of one decatherm of natural gas)
MMcf	Million cubic feet (of natural gas)
NEPA	National Environmental Policy Act of 1969, as amended

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

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INDEX		Page

Part I. Financial Information

Item 1. Financial Statements (Unaudited)		6

a. Consolidated Statements of Income and Earnings Reinvested in the Business - Three and Nine Months Ended June 30, 2018 and 2017		6
b. Consolidated Statements of Comprehensive Income – Three and Nine Months Ended June 30, 2018 and 2017		7
c. Consolidated Balance Sheets – June 30, 2018 and September 30, 2017		8
d. Consolidated Statements of Cash Flows – Nine Months Ended June 30, 2018 and 2017		10
e. Notes to Condensed Consolidated Financial Statements		11
Item 2. Management's Discussion and Analysis of Financial Condition and Results of Operations		27
Item 3. Quantitative and Qualitative Disclosures About Market Risk		47
Item 4. Controls and Procedures		47

Part II. Other Information

Item 1. Legal Proceedings		47
Item 1 A. Risk Factors		47
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds		48
Item 3. Defaults Upon Senior Securities		•
Item 4. Mine Safety Disclosures		•
Item 5. Other Information		•
Item 6. Exhibits		48
Signatures		49

• The Company has nothing to report under this item.

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

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Part I. Financial Information

Item 1. Financial Statements

National Fuel Gas Company

Consolidated Statements of Income and Earnings

Reinvested in the Business

(Unaudited)



	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands of Dollars, Except Per Common Share Amounts)	2018			2017			2018			2017
INCOME
Operating Revenues:
Utility and Energy Marketing Revenues	$	154,088		$	146,360		$	719,234		$	663,029
Exploration and Production and Other Revenues	137,492			151,925			425,811			473,617
Pipeline and Storage and Gathering Revenues	51,332			50,083			158,428			156,298
	342,912			348,368			1,303,473			1,292,944

Operating Expenses:
Purchased Gas	52,211			46,135			322,854			264,349
Operation and Maintenance:
Utility and Energy Marketing	45,618			44,467			158,397			158,796
Exploration and Production and Other	31,141			34,098			106,268			102,153
Pipeline and Storage and Gathering	24,770			23,250			67,450			69,016
Property, Franchise and Other Taxes	20,595			21,447			64,245			64,368
Depreciation, Depletion and Amortization	60,817			55,617			177,802			168,812
	235,152			225,014			897,016			827,494
Operating Income	107,760			123,354			406,457			465,450
Other Income (Expense):
Interest Income	1,632			853			4,907			2,844
Other Income	999			1,370			3,492			4,728
Interest Expense on Long-Term Debt	(27,177		)	(29,225		)	(82,412		)	(87,241		)
Other Interest Expense	(1,006		)	(846		)	(2,742		)	(2,680		)
Income Before Income Taxes	82,208			95,506			329,702			383,101
Income Tax Expense (Benefit)	19,183			35,792			(23,825		)	145,195

Net Income Available for Common Stock	63,025			59,714			353,527			237,906

EARNINGS REINVESTED IN THE BUSINESS
Balance at Beginning of Period	1,070,939			817,348			851,669			676,361
	1,133,964			877,062			1,205,196			914,267

Dividends on Common Stock	(36,526		)	(35,469		)	(107,758		)	(104,590		)
Cumulative Effect of Adoption of Authoritative Guidance for Stock-Based Compensation	—			—			—			31,916
Balance at June 30	$	1,097,438		$	841,593		$	1,097,438		$	841,593

Earnings Per Common Share:
Basic:
Net Income Available for Common Stock	$	0.73		$	0.70		$	4.12		$	2.79
Diluted:
Net Income Available for Common Stock	$	0.73		$	0.69		$	4.09		$	2.77
Weighted Average Common Shares Outstanding:
Used in Basic Calculation	85,930,289			85,422,313			85,789,279			85,315,154
Used in Diluted Calculation	86,501,194			86,064,464			86,370,900			85,950,742
Dividends Per Common Share:
Dividends Declared	$	0.425		$	0.415		$	1.255		$	1.225

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Comprehensive Income

(Unaudited)



	Three Months Ended June 30,						Nine Months Ended June 30,
(Thousands of Dollars)	2018			2017			2018			2017
Net Income Available for Common Stock	$	63,025		$	59,714		$	353,527		$	237,906
Other Comprehensive Income (Loss), Before Tax:
Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	(121		)	1,437			(843		)	2,280
Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(37,452		)	18,233			(55,534		)	9,829
Reclassification Adjustment for Realized (Gains) Losses on Securities Available for Sale in Net Income	—			—			(430		)	(741		)
Reclassification Adjustment for Realized (Gains) Losses on Derivative Financial Instruments in Net Income	3,771			(18,452		)	(5,577		)	(59,641		)
Other Comprehensive Income (Loss), Before Tax	(33,802		)	1,218			(62,384		)	(48,273		)
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Securities Available for Sale Arising During the Period	42			532			(275		)	832
Income Tax Expense (Benefit) Related to Unrealized Gain (Loss) on Derivative Financial Instruments Arising During the Period	(10,416		)	7,592			(16,240		)	3,892
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Securities Available for Sale in Net Income	—			—			(158		)	(272		)
Reclassification Adjustment for Income Tax Benefit (Expense) on Realized Losses (Gains) from Derivative Financial Instruments in Net Income	1,208			(7,693		)	(3,438		)	(25,061		)
Income Taxes – Net	(9,166		)	431			(20,111		)	(20,609		)
Other Comprehensive Income (Loss)	(24,636		)	787			(42,273		)	(27,664		)
Comprehensive Income	$	38,389		$	60,501		$	311,254		$	210,242

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)



	June 30, 2018		September 30, 2017
(Thousands of Dollars)
ASSETS
Property, Plant and Equipment	$	10,254,976	$	9,945,560
Less - Accumulated Depreciation, Depletion and Amortization	5,411,746		5,271,486
	4,843,230		4,674,074
Current Assets
Cash and Temporary Cash Investments	313,307		555,530
Hedging Collateral Deposits	2,283		1,741
Receivables – Net of Allowance for Uncollectible Accounts of $26,711 and $22,526, Respectively	151,005		112,383
Unbilled Revenue	18,930		22,883
Gas Stored Underground	16,090		35,689
Materials and Supplies - at average cost	34,693		33,926
Unrecovered Purchased Gas Costs	—		4,623
Other Current Assets	52,690		51,505
	588,998		818,280

Other Assets
Recoverable Future Taxes	115,688		181,363
Unamortized Debt Expense	7,587		1,159
Other Regulatory Assets	171,792		174,433
Deferred Charges	37,349		30,047
Other Investments	130,744		125,265
Goodwill	5,476		5,476
Prepaid Post-Retirement Benefit Costs	61,371		56,370
Fair Value of Derivative Financial Instruments	11,760		36,111
Other	108		742
	541,875		610,966

Total Assets	$	5,974,103	$	6,103,320

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Balance Sheets

(Unaudited)



	June 30, 2018			September 30, 2017
(Thousands of Dollars)
CAPITALIZATION AND LIABILITIES
Capitalization:
Comprehensive Shareholders’ Equity
Common Stock, $1 Par Value
Authorized - 200,000,000 Shares; Issued And Outstanding – 85,943,875 Shares and 85,543,125 Shares, Respectively	$	85,944		$	85,543
Paid in Capital	816,395			796,646
Earnings Reinvested in the Business	1,097,438			851,669
Accumulated Other Comprehensive Loss	(72,396		)	(30,123		)
Total Comprehensive Shareholders’ Equity	1,927,381			1,703,735
Long-Term Debt, Net of Current Portion and Unamortized Discount and Debt Issuance Costs	1,835,582			2,083,681
Total Capitalization	3,762,963			3,787,416

Current and Accrued Liabilities
Notes Payable to Banks and Commercial Paper	—			—
Current Portion of Long-Term Debt	250,000			300,000
Accounts Payable	111,812			126,443
Amounts Payable to Customers	16,833			—
Dividends Payable	36,526			35,500
Interest Payable on Long-Term Debt	28,357			35,031
Customer Advances	197			15,701
Customer Security Deposits	18,468			20,372
Other Accruals and Current Liabilities	161,252			111,889
Fair Value of Derivative Financial Instruments	38,012			1,103
	661,457			646,039

Deferred Credits
Deferred Income Taxes	491,520			891,287
Taxes Refundable to Customers	366,183			95,739
Cost of Removal Regulatory Liability	213,560			204,630
Other Regulatory Liabilities	128,184			113,716
Pension and Other Post-Retirement Liabilities	138,275			149,079
Asset Retirement Obligations	101,833			106,395
Other Deferred Credits	110,128			109,019
	1,549,683			1,669,865
Commitments and Contingencies (Note 6)	—			—

Total Capitalization and Liabilities	$	5,974,103		$	6,103,320

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Consolidated Statements of Cash Flows

(Unaudited)



	Nine Months Ended June 30,
(Thousands of Dollars)	2018			2017
OPERATING ACTIVITIES
Net Income Available for Common Stock	$	353,527		$	237,906
Adjustments to Reconcile Net Income to Net Cash Provided by Operating Activities:
Depreciation, Depletion and Amortization	177,802			168,812
Deferred Income Taxes	(43,537		)	105,073
Stock-Based Compensation	11,770			8,857
Other	12,311			11,084
Change in:
Hedging Collateral Deposits	(542		)	(658		)
Receivables and Unbilled Revenue	(35,021		)	(15,885		)
Gas Stored Underground and Materials and Supplies	18,832			15,699
Unrecovered Purchased Gas Costs	4,623			(1,317		)
Other Current Assets	(1,185		)	8,502
Accounts Payable	2,327			5,046
Amounts Payable to Customers	16,833			(6,467		)
Customer Advances	(15,504		)	(14,538		)
Customer Security Deposits	(1,904		)	1,503
Other Accruals and Current Liabilities	26,538			25,423
Other Assets	(10,770		)	(3,548		)
Other Liabilities	1,441			5,638
Net Cash Provided by Operating Activities	517,541			551,130

INVESTING ACTIVITIES
Capital Expenditures	(403,994		)	(314,774		)
Net Proceeds from Sale of Oil and Gas Producing Properties	55,506			26,554
Other	(1,759		)	(10,186		)
Net Cash Used in Investing Activities	(350,247		)	(298,406		)

FINANCING ACTIVITIES
Reduction of Long-Term Debt	(307,047		)	—
Dividends Paid on Common Stock	(106,732		)	(103,594		)
Net Proceeds from Issuance of Common Stock	4,262			6,223
Net Cash Used in Financing Activities	(409,517		)	(97,371		)
Net Increase (Decrease) in Cash and Temporary Cash Investments	(242,223		)	155,353
Cash and Temporary Cash Investments at October 1	555,530			129,972
Cash and Temporary Cash Investments at June 30	$	313,307		$	285,325

Supplemental Disclosure of Cash Flow Information
Non-Cash Investing Activities:
Non-Cash Capital Expenditures	$	71,410		$	47,508

See Notes to Condensed Consolidated Financial Statements

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National Fuel Gas Company

Notes to Condensed Consolidated Financial Statements

(Unaudited)

Note 1 - Summary of Significant Accounting Policies

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

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

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

The earnings for the nine months ended June 30, 2018 should not be taken as a prediction of earnings for the entire fiscal year ending September 30, 2018. 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 7 – Business Segment Information.

Consolidated Statements of Cash Flows. For purposes of the Consolidated Statements of Cash Flows, the Company considers all highly liquid debt instruments purchased with a maturity of generally three months or less to be cash equivalents.

Hedging Collateral Deposits. This 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 $14.7 million at June 30, 2018, 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 $96.3 million and $80.9 million at June 30, 2018 and September 30, 2017, respectively. All costs related to unproved properties are reviewed quarterly to determine if impairment has occurred. The amount of any impairment is transferred to the pool of capitalized costs being amortized.

Capitalized costs are subject to the SEC full cost ceiling test. The ceiling test, which is performed each quarter, determines a limit, or ceiling, on the amount of property acquisition, exploration and development costs that can be capitalized. The ceiling under this test represents (a) the present value of estimated future net cash flows, excluding future cash outflows associated with settling asset retirement obligations that have been accrued on the balance sheet, using a discount factor of 10%, which is computed

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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 June 30, 2018, the ceiling exceeded the book value of the oil and gas properties by approximately $462.3 million. In adjusting estimated future cash flows for hedging under the ceiling test at June 30, 2018, estimated future net cash flows were decreased by $6.7 million.

The Company entered into a purchase and sale agreement to sell its oil and gas properties in the Sespe Field area of Ventura County, California in October 2017 for $43.0 million. The Company completed the sale on May 1, 2018, effective as of October 1, 2017, receiving net proceeds of $38.2 million (included in Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statement of Cash Flows for the nine months ended June 30, 2018). The net proceeds received by the Company were adjusted for production revenue and production expenses retained by the Company between the effective date of the sale and the closing date, resulting in lower proceeds from sale at the closing date. The divestiture of the Company’s oil and gas properties in the Sespe Field reflects continuing efforts to focus West Coast development activities in the San Joaquin basin, particularly at the Midway Sunset field in Kern County, California. Under the full cost method of accounting for oil and natural gas properties, the sale proceeds were accounted for as a reduction of capitalized costs. Since the disposition did not significantly alter the relationship between capitalized costs and proved reserves of oil and gas attributable to the cost center, the Company did not record any gain or loss from this sale.

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 jointly participate in a program to develop up to 75 Marcellus wells, with Seneca serving as program operator. IOG holds an 80% working interest in all of the joint development wells. In total, IOG has funded $305.3 million as of June 30, 2018 for its 80% working interest in the 75 joint development wells, which includes $181.2 million of cash ($137.3 million in fiscal 2016, $26.6 million in fiscal 2017 and $17.3 million in the nine months ended June 30, 2018) included in Net Proceeds from Sale of Oil and Gas Producing Properties on the Consolidated Statements of Cash Flows for fiscal 2016, fiscal 2017 and for the nine months ended June 30, 2018, respectively. 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. 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.

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Accumulated Other Comprehensive Loss. The components of Accumulated Other Comprehensive Loss and changes for the quarter and nine months ended June 30, 2018 and 2017, net of related tax effect, are as follows (amounts in parentheses indicate debits) (in thousands):



	Gains and Losses on Derivative Financial Instruments			Gains and Losses on Securities Available for Sale			Funded Status of the Pension and Other Post-Retirement Benefit Plans			Total
Three Months Ended June 30, 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	)
Three Months Ended June 30, 2017
Balance at April 1, 2017	$	36,257		$	6,128		$	(76,476	)	$	(34,091	)
Other Comprehensive Gains and Losses Before Reclassifications	10,641			905			—			11,546
Amounts Reclassified From Other Comprehensive Income (Loss)	(10,759		)	—			—			(10,759		)
Balance at June 30, 2017	$	36,139		$	7,033		$	(76,476	)	$	(33,304	)
Nine Months Ended June 30, 2017
Balance at October 1, 2016	$	64,782		$	6,054		$	(76,476	)	$	(5,640	)
Other Comprehensive Gains and Losses Before Reclassifications	5,937			1,448			—			7,385
Amounts Reclassified From Other Comprehensive Income (Loss)	(34,580		)	(469		)	—			(35,049		)
Balance at June 30, 2017	$	36,139		$	7,033		$	(76,476	)	$	(33,304	)

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Reclassifications Out of Accumulated Other Comprehensive Loss. The details about the reclassification adjustments out of accumulated other comprehensive loss for the quarter and nine months ended June 30, 2018 and 2017 are as follows (amounts in parentheses indicate debits to the income statement) (in thousands):



Details About Accumulated Other Comprehensive Loss Components	Amount of Gain or (Loss) Reclassified from Accumulated Other Comprehensive Loss												Affected Line Item in the Statement Where Net Income is Presented
	Three Months Ended June 30,						Nine Months Ended June 30,
	2018			2017			2018			2017
Gains (Losses) on Derivative Financial Instrument Cash Flow Hedges:
Commodity Contracts		($3,249	)		$18,600			$6,125			$62,030		Operating Revenues
Commodity Contracts	5			21			952			(1,938		)	Purchased Gas
Foreign Currency Contracts	(527		)	(169		)	(1,500		)	(451		)	Operation and Maintenance Expense
Gains (Losses) on Securities Available for Sale	—			—			430			741			Other Income
	(3,771		)	18,452			6,007			60,382			Total Before Income Tax
	1,208			(7,693		)	(3,596		)	(25,333		)	Income Tax Expense
		($2,563	)		$10,759			$2,411			$35,049		Net of Tax

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



	At June 30, 2018		At September 30, 2017

Prepayments	$	10,594	$	10,927
Prepaid Property and Other Taxes	11,177		13,974
Federal Income Taxes Receivable	17,216		—
State Income Taxes Receivable	5,065		9,689
Fair Values of Firm Commitments	1,350		1,031
Regulatory Assets	7,288		15,884
	$	52,690	$	51,505

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



	At June 30, 2018		At September 30, 2017

Accrued Capital Expenditures	$	53,534	$	37,382
Regulatory Liabilities	43,167		34,059
Reserve for Gas Replacement	14,651		—
Federal Income Taxes Payable	—		1,775
2017 Tax Reform Act Regulatory Refund	11,817		—
Other	38,083		38,673
	$	161,252	$	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 had outstanding were stock options, SARs, restricted stock units and performance shares. For the quarter and nine months ended June 30, 2018, 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

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antidilutive are excluded from the calculation of diluted earnings per common share. There were 1,095,838 securities and 316,279 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2018, respectively. There were 172,500 securities and 157,638 securities excluded as being antidilutive for the quarter and nine months ended June 30, 2017, respectively.

Stock-Based Compensation. The Company granted 208,588 performance shares during the nine months ended June 30, 2018. The weighted average fair value of such performance shares was $50.95 per share for the nine months ended June 30, 2018. Performance shares are an award constituting units denominated in common stock of the Company, the number of which may be adjusted over a performance cycle based upon the extent to which performance goals have been satisfied. Earned performance shares may be distributed in the form of shares of common stock of the Company, an equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company. The performance shares do not entitle the participant to receive dividends during the vesting period.

Half of the performance shares granted during the nine months ended June 30, 2018 must meet a performance goal related to relative return on capital over the performance cycle of October 1, 2017 to September 30, 2020. The performance goal over the performance cycle is the Company’s total return on capital relative to the total return on capital of other companies in a group selected by the Compensation Committee (“Report Group”). Total return on capital for a given company means the average of the Report Group companies’ returns on capital for each twelve month period corresponding to each of the Company’s fiscal years during the performance cycle, based on data reported for the Report Group companies in the Bloomberg database. The number of these performance shares that will vest and be paid will depend upon the Company’s performance relative to the Report Group and not upon the absolute level of return achieved by the Company. The fair value of these performance shares is calculated by multiplying the expected number of shares that will be issued by the average market price of Company common stock on the date of grant reduced by the present value of forgone dividends over the vesting term of the award. The fair value is recorded as compensation expense over the vesting term of the award. The other half of the performance shares granted during the nine months ended June 30, 2018 must meet a performance goal related to relative total shareholder return over the performance cycle of October 1, 2017 to September 30, 2020. 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 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 restricted stock units during the nine months ended June 30, 2018. The weighted average fair value of such non-performance based restricted stock units was $51.23 per share for the nine months ended June 30, 2018. Restricted stock units represent the right to receive shares of common stock of the Company (or the equivalent value in cash or a combination of cash and shares of common stock of the Company, as determined by the Company) at the end of a specified time period. These non-performance based restricted stock units do not entitle the participant to receive dividends during the vesting period. The accounting for non-performance 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 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. The Company has substantially completed its detailed review of the impact of the guidance on each of its revenue streams. Based on this review, the Company has not currently identified any changes to net income, cash flows or the timing of revenue recognition, although the Company will continue to assess the impact of the guidance through the date of adoption. The Company will also need to review its internal controls and enhance its financial statement disclosures to comply with the new authoritative guidance. The Company expects to adopt the guidance using the modified retrospective method of adoption on October 1, 2018. Under the modified retrospective approach, the cumulative effect of initially applying the new guidance is recognized as an adjustment to the opening balance of retained earnings in the period of adoption.

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In February 2016, the FASB issued authoritative guidance 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 and is currently evaluating the provisions of the revised guidance.

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 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 new guidance will be effective as of the Company’s first quarter of fiscal 2019. Refer to Note 8 - Retirement Plan and Other Post-Retirement Benefits for the components of the Company's net periodic pension cost and net periodic postretirement benefit cost.

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 new guidance will be effective as of the Company’s first quarter of fiscal 2020, with early adoption permitted. The Company anticipates early adoption and is currently awaiting regulatory approval of the reclassification to retained earnings from the FERC for the Company’s Pipeline and Storage segment.

Note 2 – Fair Value Measurements

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

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The following table sets forth, by level within the fair value hierarchy, the Company's financial assets and liabilities (as applicable) that were accounted for at fair value on a recurring basis as of June 30, 2018 and September 30, 2017. Financial assets and liabilities are classified in their entirety based on the lowest level of input that is significant to the fair value measurement. The fair value presentation for over the counter swaps combines gas and oil swaps because a significant number of the counterparties enter into both gas and oil swap agreements with the Company.



Recurring Fair Value Measures	At fair value as of June 30, 2018
(Thousands of Dollars)	Level 1		Level 2			Level 3		Netting Adjustments⁽¹⁾			Total⁽¹⁾
Assets:
Cash Equivalents – Money Market Mutual Funds	$	291,994	$	—		$	—	$	—		$	291,994
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	1,022		—			—		(1,022		)	—
Over the Counter Swaps – Gas and Oil	—		28,180			—		(17,567		)	10,613
Foreign Currency Contracts	—		155			—		(155		)	—
Other Investments:
Balanced Equity Mutual Fund	37,300		—			—		—			37,300
Fixed Income Mutual Fund	51,201		—			—		—			51,201
Common Stock – Financial Services Industry	2,790		—			—		—			2,790
Hedging Collateral Deposits	2,283		—			—		—			2,283
Total	$	386,590	$	28,335		$	—	$	(18,744	)	$	396,181

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	1,785	$	—		$	—	$	(1,022	)	$	763
Over the Counter Swaps – Gas and Oil	—		53,305			—		(17,567		)	35,738
Foreign Currency Contracts	—		1,666			—		(155		)	1,511
Total	$	1,785	$	54,971		$	—	$	(18,744	)	$	38,012
Total Net Assets/(Liabilities)	$	384,805	$	(26,636	)	$	—	$	—		$	358,169



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

Liabilities:
Derivative Financial Instruments:
Commodity Futures Contracts – Gas	$	963	$	—	$	—	$	(963	)	$	—
Over the Counter Swaps – Gas and Oil	—		5,309		—		(4,206		)	1,103
Foreign Currency Contracts	—		407		—		(407		)	—
Total	$	963	$	5,716	$	—	$	(5,576	)	$	1,103
Total Net Assets/(Liabilities)	$	616,149	$	34,488	$	—	$	—		$	650,637


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

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Derivative Financial Instruments

At June 30, 2018 and September 30, 2017, 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 $2.3 million at June 30, 2018 and $1.7 million at September 30, 2017, 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 June 30, 2018 and September 30, 2017 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 and foreign currency contracts used in the Company's Exploration and Production segment. The derivative financial instruments reported in Level 2 at June 30, 2018 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 June 30, 2018, 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 and nine months ended June 30, 2018 and June 30, 2017, there were no assets or liabilities measured at fair value and classified as Level 3. For the quarters and nine months ended June 30, 2018 and June 30, 2017, no transfers in or out of Level 1 or Level 2 occurred.

Note 3 – 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, 2018				September 30, 2017
	Carrying Amount		Fair Value		Carrying Amount		Fair Value
Long-Term Debt	$	2,085,582	$	2,116,994	$	2,383,681	$	2,523,639

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

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

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



	At June 30, 2018		At September 30, 2017

Life Insurance Contracts	$	39,453	$	39,355
Equity Mutual Fund	37,300		37,033
Fixed Income Mutual Fund	51,201		45,727
Marketable Equity Securities	2,790		3,150
	$	130,744	$	125,265

Investments in life insurance contracts are stated at their cash surrender values or net present value. Investments in an equity mutual fund, a fixed income mutual fund and the stock of an insurance company (marketable equity securities) are stated at fair value based on quoted market prices. The gross unrealized gain on the equity mutual fund was $9.6 million at June 30, 2018 and $9.9 million at September 30, 2017. A sale of shares in the equity mutual fund during the nine months ended June 30, 2018 resulted in $1.5 million of cash proceeds and a realized gain of $0.4 million. The gross unrealized loss on the fixed income mutual fund was $0.6 million at June 30, 2018 and was less than $0.1 million at September 30, 2017. A sale of shares in the fixed income mutual fund during the nine months ended June 30, 2018 resulted in $1.5 million of cash proceeds and a realized loss of less than $0.1 million. The gross unrealized gain on the marketable equity securities was $1.8 million at June 30, 2018 and $2.2 million at September 30, 2017. 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 8 years. The Exploration and Production segment holds the majority of the Company’s derivative financial instruments.

The Company has presented its net derivative assets and liabilities as “Fair Value of Derivative Financial Instruments” on its Consolidated Balance Sheets at June 30, 2018 and September 30, 2017. Substantially all of the derivative financial instruments reported on those line items relate to commodity contracts and a small portion relates to foreign currency forward contracts.

Cash Flow Hedges

For derivative instruments that are designated and qualify as a cash flow hedge, the effective portion of the gain or loss on the derivative is reported as a component of other comprehensive income (loss) and reclassified into earnings in the period or periods during which the hedged transaction affects earnings. Gains 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 June 30, 2018, the Company had the following commodity derivative contracts (swaps and futures contracts) outstanding:



Commodity	Units
Natural Gas	131.6	Bcf (short positions)
Natural Gas	1.3	Bcf (long positions)
Crude Oil	4,314,000	Bbls (short positions)

As of June 30, 2018, the Company was hedging a total of $90.8 million of forecasted transportation costs denominated in Canadian dollars with foreign currency forward contracts (long positions).

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As of June 30, 2018, the Company had $25.6 million ($20.6 million after tax) of net hedging losses included in the accumulated other comprehensive income (loss) balance. It is expected that $21.9 million ($14.9 million after tax) of unrealized losses will be reclassified into the Consolidated Statement of Income within the next 12 months as the underlying hedged transaction are recorded in earnings.



The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Three Months Ended June 30, 2018 and 2017 (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,
	2018			2017			2018			2017				2018			2017
Commodity Contracts	$	(35,976	)	$	17,342	Operating Revenue	$	(3,249	)	$	18,600		Operating Revenue	$	(339	)	$	1,040
Commodity Contracts	124			240		Purchased Gas	5			21			Not Applicable	—			—
Foreign Currency Contracts	(1,600		)	651		Operation and Maintenance Expense	(527		)	(169		)	Not Applicable	—			—
Total	$	(37,452	)	$	18,233		$	(3,771	)	$	18,452			$	(339	)	$	1,040



The Effect of Derivative Financial Instruments on the Statement of Financial Performance for the
Nine Months Ended June 30, 2018 and 2017 (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,
	2018			2017				2018			2017				2018			2017
Commodity Contracts	$	(52,440	)	$	9,382		Operating Revenue	$	6,125		$	62,030		Operating Revenue	$	(436	)	$	940
Commodity Contracts	737			(252		)	Purchased Gas	952			(1,938		)	Not Applicable	—			—
Foreign Currency Contracts	(3,831		)	699			Operation and Maintenance Expense	(1,500		)	(451		)	Not Applicable	—			—
Total	$	(55,534	)	$	9,829			$	5,577		$	59,641			$	(436	)	$	940

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

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to mitigate the risk of price decreases that could result in a lower of cost or net realizable value writedown of the value of natural gas in storage that is recorded in the Company’s financial statements. As of June 30, 2018, the Company’s Energy Marketing segment had fair value hedges covering approximately 24.8 Bcf (24.2 Bcf of fixed price sales commitments and 0.6 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 Nine Months Ended June 30, 2018 (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, 2018 (In Thousands)
Commodity Contracts	Operating Revenues	$	(824	)	$	824
Commodity Contracts	Purchased Gas	$	(223	)	$	223
		$	(1,047	)	$	1,047

Credit Risk

The Company may be exposed to credit risk on any of the derivative financial instruments that are in a gain position. Credit risk relates to the risk of loss that the Company would incur as a result of nonperformance by counterparties pursuant to the terms of their contractual obligations. To mitigate such credit risk, management performs a credit check, and then on a quarterly basis monitors counterparty credit exposure. The majority of the Company’s counterparties are financial institutions and energy traders. The Company has over-the-counter swap positions and applicable foreign currency forward contracts with eighteen counterparties of which three are in a net gain position. On average, the Company had $3.5 million of credit exposure per counterparty in a gain position at June 30, 2018. The maximum credit exposure per counterparty in a gain position at June 30, 2018 was $6.7 million. As of June 30, 2018, no collateral was received from the counterparties by the Company. The Company's gain position on such derivative financial instruments had not exceeded the established thresholds at which the counterparties would be required to post collateral, nor had the counterparties' credit ratings declined to levels at which the counterparties were required to post collateral.

As of June 30, 2018, fifteen of the 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 June 30, 2018, the fair market value of the derivative financial instrument assets with a credit-risk related contingency feature was $10.6 million according to the Company’s internal model (discussed in Note 2 — Fair Value Measurements). At June 30, 2018, the fair market value of the derivative financial instrument liabilities with a credit-risk related contingency feature was $31.9 million according to the Company's internal model. For its over-the-counter swap agreements and foreign currency forward contracts, no hedging collateral deposits were required to be posted by the Company at June 30, 2018.

For its exchange traded futures contracts, the Company was required to post $2.3 million in hedging collateral deposits as of June 30, 2018. 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.

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Note 4 - Income Taxes

The effective tax rate for the quarters ended June 30, 2018 and June 30, 2017 was 23.3% and 37.4%, respectively. The difference was primarily a result of the lower statutory rate of 24.5% under the 2017 Tax Reform Act (as discussed below). The effective tax rate was negative 7.2% for the nine months ended June 30, 2018 and 37.9% for the nine months ended June 30, 2017. The difference was a result of the impact of the one-time remeasurement of the deferred income tax liability and a lower statutory rate of 24.5% under the 2017 Tax Reform Act.

On December 22, 2017, federal tax legislation referred to as the “Tax Cuts and Jobs Act” (the 2017 Tax Reform Act) was enacted. The 2017 Tax Reform Act significantly changed the taxation of business entities and 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. The changes had a material impact on the financial statements in the quarter and nine months ended June 30, 2018. The Company’s deferred income taxes were remeasured based upon the new tax rates. For the non-rate regulated activities through the nine months ended June 30, 2018, the change in deferred income taxes of $107.0 million was recorded as a reduction to income tax expense. For the Company's rate regulated activities, the reduction in 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 currently reviewing guidance issued by regulatory agencies in the jurisdictions in which it operates. For further discussion, refer to Note 9 - Regulatory Matters.

The 2017 Tax Reform Act also repealed the corporate alternative minimum tax (AMT) and provides that the Company’s existing AMT credit carryovers are refundable beginning in fiscal 2019. As of June 30, 2018, the Company had $90.2 million of AMT credit carryovers that are expected to be utilized or refunded between fiscal 2019 and fiscal 2022. During the quarter ended March 31, 2018, the Company recorded a $4.0 million estimate of the potential sequestration of the refunds of the AMT credits.

The SEC issued guidance in Staff Accounting Bulletin 118 (SAB 118) which provides for up to a one year period (the measurement period) in which to complete the required analysis and income tax accounting for the 2017 Tax Reform Act. 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 June 30, 2018 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/state regulatory guidance, and possible technical corrections. The Company expects to finalize the analysis within SAB 118’s one-year measurement period based upon existing guidance at that time. Any subsequent guidance will be accounted for in the period issued.

Note 5 - Capitalization

Common Stock. During the nine months ended June 30, 2018, the Company issued 68,619 original issue shares of common stock as a result of SARs exercises, 71,918 original issue shares of common stock for restricted stock units that vested and 79,079 original issue shares of common stock for performance shares that vested. In addition, the Company issued 138,997 original issue shares of common stock for the Direct Stock Purchase and Dividend Reinvestment Plan and 75,745 original issue shares of common stock for the Company’s 401(k) plans. The Company also issued 20,721 original issue shares of common stock to the non-employee directors of the Company who receive compensation under the Company’s 2009 Non-Employee Director Equity Compensation Plan, as partial consideration for the directors’ services during the nine months ended June 30, 2018. Holders of stock-based compensation awards will often tender shares of common stock to the Company for payment of applicable withholding taxes. During the nine months ended June 30, 2018, 54,329 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. Current Portion of Long-Term Debt at June 30, 2018 consists of $250.0 million of 8.75% notes that mature in May 2019. Current Portion of Long-Term Debt at September 30, 2017 consisted of $300.0 million of 6.50% notes that were scheduled to mature in April 2018. The Company redeemed the 6.50% 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.

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Note 6 - Commitments and Contingencies

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

At June 30, 2018, the Company has estimated its remaining clean-up costs related to former manufactured gas plant sites will be approximately $7.7 million, which includes a $4.2 million estimated minimum liability to remediate a former manufactured gas plant site located in New York. In March 2018, the NYDEC issued a Record of Decision for this New York site and the minimum liability reflects the remedy selected in the Record of Decision. The Company's liability for such clean-up costs has been recorded in Other Deferred Credits on the Consolidated Balance Sheet at June 30, 2018. The Company expects to recover its environmental clean-up costs through rate recovery over a period of approximately 4 years and is currently not aware of any material additional exposure to environmental liabilities. However, changes in environmental laws and regulations, new information or other factors could have an adverse financial impact on the Company.

Northern Access 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 FERC a proceeding asserting, among other things, that the NYDEC exceeded the reasonable and statutory time frames to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. In light of these pending legal actions, the Company has not yet determined a target in-service date. As a result of the decision of the NYDEC, Supply Corporation and Empire evaluated the capitalized project costs for impairment as of June 30, 2018 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 $75.6 million at June 30, 2018. The project costs are included within Property, Plant and Equipment and Deferred Charges on the Consolidated Balance Sheet.

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 7 – 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 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 Form 10-K. A listing of segment assets at June 30, 2018 and September 30, 2017 is shown in the tables below.

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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
Revenue from External Customers	$135,828	$51,363	$(31)	$128,628	$25,460	$341,248	$1,496	$168	$342,912
Intersegment Revenues	$—	$22,496	$27,908	$3,519	$512	$54,435	$—	$(54,435)	$—
Segment Profit: Net Income (Loss)	$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



(Thousands)	Exploration and Production	Pipeline and Storage	Gathering	Utility	Energy Marketing	Total Reportable Segments	All Other	Corporate and Intersegment Eliminations	Total Consolidated
Segment Assets:
At June 30, 2018	$1,591,783	$1,763,620	$534,086	$1,904,189	$51,778	$5,845,456	$77,879	$50,768	$5,974,103
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



Quarter Ended June 30, 2017 (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	$151,161	$50,049	$34	$121,900	$24,460	$347,604	$538	$226	$348,368
Intersegment Revenues	$—	$21,643	$26,853	$3,391	$565	$52,452	$—	$(52,452)	$—
Segment Profit: Net Income (Loss)	$30,123	$16,031	$10,107	$4,348	$(564)	$60,045	$(98)	$(233)	$59,714



Nine Months Ended June 30, 2017 (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	$471,646	$156,212	$86	$550,819	$112,210	$1,290,973	$1,311	$660	$1,292,944
Intersegment Revenues	$—	$66,389	$82,629	$11,314	$600	$160,932	$—	$(160,932)	$—
Segment Profit: Net Income (Loss)	$98,972	$54,656	$31,373	$51,103	$2,122	$238,226	$(498)	$178	$237,906

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Note 8 – Retirement Plan and Other Post-Retirement Benefits

Components of Net Periodic Benefit Cost (in thousands):



	Retirement Plan						Other Post-Retirement Benefits
Three Months Ended June 30,	2018			2017			2018			2017

Service Cost	$	2,480		$	2,992		$	458		$	612
Interest Cost	8,252			9,596			3,700			4,752
Expected Return on Plan Assets	(15,429		)	(14,929		)	(7,871		)	(7,865		)
Amortization of Prior Service Cost (Credit)	235			264			(107		)	(107		)
Amortization of Losses	9,301			10,672			2,639			4,604
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments)⁽¹⁾	712			(3,193		)	3,386			1,302

Net Periodic Benefit Cost	$	5,551		$	5,402		$	2,205		$	3,298




	Retirement Plan						Other Post-Retirement Benefits
Nine Months Ended June 30,	2018			2017			2018			2017

Service Cost	$	7,441		$	8,977		$	1,373		$	1,837
Interest Cost	24,754			28,788			11,101			14,256
Expected Return on Plan Assets	(46,286		)	(44,788		)	(23,612		)	(23,594		)
Amortization of Prior Service Cost (Credit)	703			793			(322		)	(322		)
Amortization of Losses	27,904			32,015			7,918			13,811
Net Amortization and Deferral for Regulatory Purposes (Including Volumetric Adjustments) ⁽¹⁾	8,926			3,577			13,243			6,404

Net Periodic Benefit Cost	$	23,442		$	29,362		$	9,701		$	12,392


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

Note 9 – Regulatory Matters

New York Jurisdiction

Distribution Corporation's current delivery rates in its New York jurisdiction were approved by the NYPSC in an order issued on April 20, 2017 with rates becoming effective May 1, 2017. On July 28, 2017, Distribution Corporation filed an appeal with New York State Supreme Court, Albany County, seeking review of the Order. The appeal contends that portions of the Order should be invalidated because they fail to meet the applicable legal standard for agency decisions. On December 11, 2017, the appeal was transferred to the Supreme Court, Appellate Division, Third Department. The Company cannot predict the outcome of the appeal at this time.

On December 29, 2017, the NYPSC issued an order instituting a proceeding to study the potential effects of the enactment of the 2017 Tax Reform Act on the tax expenses and liabilities of New York utilities. The order stated the NYPSC’s intent to ensure that the net benefits resulting from tax reform were preserved for ratepayers. Pursuant to the order, a technical conference was held with the utilities in February 2018, and the New York Department of Public Service Staff subsequently issued a proposal for accounting and ratemaking treatment of the tax changes. The NYPSC has not yet acted on this proposal. On June 4, 2018,

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Distribution Corporation filed a petition with the NYPSC regarding Distribution Corporation’s proposed disposition of net federal income tax savings resulting from the 2017 Tax Reform Act seeking authorization to 1) implement a customer refund program to return the net effect of the recent federal income tax rate reduction to Distribution Corporation’s customers and 2) allow Distribution Corporation recovery for the improvements to the Company’s imputed equity ratio directly resulting from the recent federal tax rate reduction. Distribution Corporation has requested the NYPSC to act on its petition in advance of the 2018-2019 winter heating season, but cannot predict the timing or outcome of its petition at this time. Refer to Note 4 - Income Taxes for further discussion of the 2017 Tax Reform Act.

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.

By Secretarial Letter issued February 12, 2018, the PaPUC initiated a proceeding to determine the effects of the 2017 Tax Reform Act on the tax liabilities of PaPUC-regulated public utilities for 2018 and future years and the feasibility of reflecting such impacts on the rates charged to utility ratepayers. On March 15, 2018, the PaPUC issued a Temporary Rates Order making Distribution Corporation’s rates (along with the rates of other Pennsylvania public utilities not presently in a general rate increase proceeding) temporary for a period of six months. On May 17, 2018, the PaPUC issued an Order to Distribution Corporation, superceding and canceling Distribution Corporation’s temporary rates filed pursuant to the March 15, 2018 order and requiring that Distribution Corporation file a tariff supplement establishing temporary rates to implement refunds of 2.2% on customer rates beginning July 1, 2018. Distribution Corporation has filed the necessary tariff supplement to implement such refunds effective July 1, 2018. The May 17, 2018 PaPUC Order provides for a number of options regarding the permanent or temporary status of these rates and associated cost and rate deferral options. The Company is currently evaluating these specific options. Refer to Note 4 - Income Taxes for further discussion of the 2017 Tax Reform Act.

FERC Jurisdiction

Supply Corporation currently has no active rate case on file. Supply Corporation's current rate settlement requires a rate case filing no later than December 31, 2019.

Empire filed a Section 4 rate case on June 29, 2018, proposing rate increases to be effective August 1, 2018. The proposed rates reflect an annual cost of service of $71.5 million, a rate base of $246.8 million and a proposed return on equity of 14%. The proposed rate increases are expected to be suspended, with an effective date of January 1, 2019, subject to refund. Lower storage rates are expected to be effective August 1, 2018. If the proposed rate increases finally approved at the end of the proceeding exceed the rates that were in effect at June 29, 2018, but are less than rates put into effect subject to refund on January 1, 2019, Empire would be required to refund the difference between the rates collected subject to refund and the final approved rates, with interest at the FERC-approved rate. If the rates approved at the end of the proceeding are lower than the rates in effect at June 29, 2018, such lower rates will become effective prospectively from the date of the applicable FERC order, and refunds with interest will be limited to the difference between the rates collected subject to refund and the rates in effect at June 29, 2018.

On July 18, 2018, the FERC issued a Final Rule in RM18-11-000, et. al, (Order No. 849) which requires pipelines to file a new form isolating the tax impact to each pipeline and also to make an election regarding the action the pipelines will take to address the lower tax rates, one of which is filing a Section 4 rate proceeding or Notice of Inquiry regarding treatment of accumulated deferred income taxes and other tax issues associated with the 2017 Tax Reform Act. Supply Corporation will be required to address the Order by December 6, 2018. At this point, the Company cannot predict the outcome of any action proposed pursuant to the Order. Refer to Note 4 - Income Taxes for further discussion of the 2017 Tax Reform Act.

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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 and nine months ended June 30, 2018 compared to the quarter and nine months ended June 30, 2017, the Company experienced an increase in earnings of $3.3 million and $115.6 million, respectively. As a result of the 2017 Tax Reform Act, the effective tax rates for the quarter and nine months ended June 30, 2018 of 23.3% and negative 7.2%, respectively, reflect a lower statutory rate of 24.5%. The effective tax rate for the nine months ended June 30, 2018 also reflects the impact of a remeasurement of the Company's accumulated deferred income tax liability based upon the new tax rates, recorded as a $107.0 million reduction to income tax expense. The Company's non-regulated operations are benefiting from the 2017 Tax Reform Act while the regulated operations anticipate future rate reductions. In this regard, the Company filed a petition on June 4, 2018 with the NYPSC regarding Distribution Corporation's proposed disposition of net federal income tax savings in Distribution Corporation's New York jurisdiction. In Distribution Corporation's Pennsylvania jurisdiction, the Company received an order from the PaPUC requiring the establishment of temporary rates to implement refunds of 2.2% on customer rates beginning July 1, 2018. For further discussion of the impact of the 2017 Tax Reform Act to the Company, refer to Rate and Regulatory Matters below and to Item 1 at Note 4 — Income Taxes. For further discussion of the Company’s earnings, refer to the Results of Operations section below.

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”). 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 FERC a proceeding asserting, among other things, that the NYDEC exceeded the reasonable and statutory time frames to take action under the Clean Water Act and, therefore, waived its opportunity to approve or deny the Water Quality Certification. The Company remains committed to the project. Approximately $75.6 million in costs have been incurred on this project through June 30, 2018, with the costs residing either in Construction Work in Progress, a component of Property, Plant and Equipment on the Consolidated Balance Sheet, or Deferred Charges.

While legal proceedings continue on Northern Access 2016, 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. The Empire North Project has a projected in-service date in the second half of fiscal 2020 and an estimated cost of approximately $145 million. Another project on Supply Corporation’s system, referred to as the FM 100 Project, is currently in the pre-filing process at FERC and will upgrade 1950’s era pipeline in northwestern Pennsylvania and create approximately 300,000 Dth per day of additional capacity on Supply Corporation’s system in Pennsylvania from a receipt point with NFG Midstream Clermont, LLC in McKean County to the Transcontinental Gas Pipe Line Company, LLC system at Leidy, Pennsylvania. The preliminary cost estimate for this project is approximately $280 million. These and other projects are discussed in more detail in the Capital Resources and Liquidity section that follows.

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

CRITICAL ACCOUNTING ESTIMATES

For a complete discussion of critical accounting estimates, refer to "Critical Accounting Estimates" in Item 7 of the Company's 2017 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 June 30, 2018, the ceiling exceeded the book value of the oil and gas properties by approximately $462.3 million. The 12-month average of the first day of the month price for crude oil for each month during the twelve months ended June 30, 2018, based on posted Midway Sunset prices, was $57.50 per Bbl. The 12-month average of the first day of the month price for natural gas for each month during the twelve months ended June 30, 2018, based on the quoted Henry Hub spot price for natural gas, was $2.92 per MMBtu. (Note – because actual pricing of the Company’s various producing properties varies depending on their location and hedging, the prices used to calculate the ceiling may differ from the Midway Sunset and Henry Hub prices, which are only indicative of the 12-month average prices for the twelve months ended June 30, 2018. 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 June 30, 2018 (which would not have resulted in an impairment charge) if natural gas prices were $0.25 per MMBtu lower than the average prices used at June 30, 2018, if crude oil prices were $5 per Bbl lower than the average prices used at June 30, 2018, 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 June 30, 2018 (all amounts are presented after-tax). These calculated amounts are based solely on price changes and do not take into account any other changes to the ceiling test calculation, including, among others, changes in reserve quantities and future cost estimates.



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

Excess of Ceiling over Book Value under Sensitivity Analysis	$	304.9	$	430.2	$	272.9

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 Form 10-K.

2017 Tax Reform Act. On December 22, 2017, the tax legislation referred to as the “Tax Cuts and Jobs Act” (the 2017 Tax Reform Act) was enacted. The 2017 Tax Reform Act significantly changes the taxation of business entities and includes 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.

The Company has determined a reasonable estimate under SAB 118 for the measurement of the changes in deferred income taxes in the June 30, 2018 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 possible technical corrections. The Company

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expects to finalize the analysis within SAB 118's one-year measurement period based upon existing guidance at that time. Any subsequent guidance will be accounted for in the period issued. For further discussion of the impact of the 2017 Tax Reform Act to the Company, refer to Item 1 at Note 4 — Income Taxes.

RESULTS OF OPERATIONS

Earnings

The Company's earnings were $63.0 million for the quarter ended June 30, 2018 compared to earnings of $59.7 million for the quarter ended June 30, 2017. The increase in earnings of $3.3 million is primarily a result of higher earnings in the Pipeline and Storage segment, Gathering segment and All Other category, as well as a lower loss in the Energy Marketing segment. Lower earnings in the Exploration and Production segment and Utility segment, as well as a loss in the Corporate category, partially offset these increases.

The Company's earnings were $353.5 million for the nine months ended June 30, 2018 compared to earnings of $237.9 million for the nine months ended June 30, 2017. The increase in earnings of $115.6 million is primarily a result of higher earnings in the Exploration and Production segment, Gathering segment, Pipeline and Storage segment and Utility segment, as well as a lower loss in the All Other category. Lower earnings in the Energy Marketing segment, as well as a loss in the Corporate category, partially offset these increases.

The Company's earnings for the nine months ended June 30, 2018 include a $107.0 million remeasurement of accumulated deferred income taxes and a lower statutory rate of 24.5% as a result of the 2017 Tax Reform Act, as discussed above. Additional discussion of earnings in each of the business segments can be found in the business segment information that follows. Note that all amounts used in the earnings discussions are after-tax amounts, unless otherwise noted.